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 April 30, 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). o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 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 June 1, 2010

Common Stock, no par value		71,937,812

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

April 30, 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	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	44

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 5.	Other Information	45
Item 6.	Exhibits	46

	Signatures	47
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Part I. Financial Information

Item 1. Financial Statements

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


	April 30,		October 31,
	2010		2009
ASSETS
Utility Plant:
Utility plant in service	$	3,087,695	$	3,071,742
Less accumulated depreciation		897,585		862,079

Utility plant in service, net		2,190,110		2,209,663
Construction work in progress		141,734		87,978
Plant held for future use		6,751		6,751

Total utility plant, net		2,338,595		2,304,392


Other Physical Property, at cost (net of accumulated depreciation of $2,069 in 2010 and $2,497 in 2009)		655		719


Current Assets:
Cash and cash equivalents		6,990		7,558
Trade accounts receivable (less allowance for doubtful accounts of $4,902 in 2010 and $990 in 2009)		135,995		70,979
Income taxes receivable		—		44,413
Other receivables		1,608		4,712
Unbilled utility revenues		19,621		33,925
Inventories:
Gas in storage		79,827		103,584
Materials, supplies and merchandise		8,117		5,262
Gas purchase derivative assets, at fair value		2,375		2,559
Amounts due from customers		48,555		196,130
Prepayments		14,918		43,930
Other current assets		96		96

Total current assets		318,102		513,148


Noncurrent Assets:
Equity method investments in non-utility activities		94,197		104,430
Goodwill		48,852		48,852
Marketable securities, at fair value		960		441
Overfunded postretirement asset		10,598		—
Regulatory asset for postretirement benefits		76,439		76,905
Unamortized debt expense		8,851		9,177
Regulatory cost of removal asset		17,105		16,293
Other noncurrent assets		45,643		44,462

Total noncurrent assets		302,645		300,560


Total	$	2,959,997	$	3,118,819

See notes to consolidated financial statements.


	April 30,			October 31,
(In thousands)	2010			2009

CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized	$	—		$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 71,922 in 2010 and 73,266 in 2009		436,016			471,569
Retained earnings		578,845			458,826
Accumulated other comprehensive loss		(1,340	)		(2,447	)

Total stockholders’ equity		1,013,521			927,948
Long-term debt		732,128			732,512

Total capitalization		1,745,649			1,660,460


Current Liabilities:
Current maturities of long-term debt		60,000			60,000
Short-term debt		35,500			306,000
Trade accounts payable		74,489			67,010
Other accounts payable		21,523			48,431
Income taxes accrued		41,793			—
Accrued interest		21,524			21,294
Customers’ deposits		27,032			25,202
Deferred income taxes		6,157			14,138
General taxes accrued		9,781			19,993
Gas purchase derivative liabilities, at fair value		22,683			30,603
Other current liabilities		9,369			7,540

Total current liabilities		329,851			600,211


Noncurrent Liabilities:
Deferred income taxes		401,262			377,562
Unamortized federal investment tax credits		2,241			2,422
Accumulated provision for postretirement benefits		21,148			31,641
Cost of removal obligations		423,408			408,955
Other noncurrent liabilities		36,438			37,568

Total noncurrent liabilities		884,497			858,148


Commitments and Contingencies (Note 13)


Total	$	2,959,997		$	3,118,819

See notes to consolidated financial statements.

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


	Three Months Ended						Six Months Ended
	April 30						April 30
	2010			2009			2010			2009

Operating Revenues	$	472,846		$	455,432		$	1,146,582		$	1,235,076
Cost of Gas		304,168			285,479			754,962			844,440


Margin		168,678			169,953			391,620			390,636


Operating Expenses:
Operations and maintenance		57,503			53,352			109,542			104,077
Depreciation		24,483			24,306			48,838			48,448
General taxes		8,758			8,657			17,343			17,394
Income taxes		25,709			28,287			75,871			77,235


Total operating expenses		116,453			114,602			251,594			247,154


Operating Income		52,225			55,351			140,026			143,482


Other Income (Expense):
Income from equity method investments		13,309			17,832			25,142			27,621
Gain on sale of interest in equity method investment		—			—			49,674			—
Non-operating income		221			(132	)		315			(98	)
Non-operating expense		(1,013	)		(857	)		(1,376	)		(1,206	)
Income taxes		(4,906	)		(6,757	)		(28,892	)		(10,473	)


Total other income (expense)		7,611			10,086			44,863			15,844


Utility Interest Charges:
Interest on long-term debt		13,251			13,817			26,526			27,671
Allowance for borrowed funds used during construction		(782	)		(532	)		(1,302	)		(1,227	)
Other		542			(1,373	)		(909	)		(1,519	)

Total utility interest charges		13,011			11,912			24,315			24,925


Net Income	$	46,825		$	53,525		$	160,574		$	134,401


Average Shares of Common Stock:
Basic		71,788			73,239			72,492			73,280
Diluted		72,118			73,514			72,842			73,582

Earnings Per Share of Common Stock:
Basic	$	0.65		$	0.73		$	2.22		$	1.83
Diluted	$	0.65		$	0.73		$	2.20		$	1.83

Cash Dividends Per Share of Common Stock	$	0.28		$	0.27		$	0.55		$	0.53

See notes to consolidated financial statements.

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


	Six Months Ended
	April 30
	2010			2009

Cash Flows from Operating Activities:
Net income	$	160,574		$	134,401
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		51,231			51,045
Amortization of investment tax credits		(181	)		(165	)
Allowance for doubtful accounts		3,912			2,525
Net gain on sale of interest in equity method investment, net of tax		(30,222	)		—
Gain on sale of property		(133	)		(155	)
Earnings from equity method investments		(25,142	)		(27,621	)
Distributions of earnings from equity method investments		27,433			21,885
Deferred income taxes		(4,447	)		36,178
Stock-based compensation expense		—			168
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(7,736	)		73,627
Receivables		(52,561	)		(43,998	)
Inventories		20,902			98,045
Amounts due from customers		147,575			(49,900	)
Settlement of legal asset retirement obligations		(634	)		(769	)
Overfunded postretirement asset		(10,598	)		199
Regulatory asset for postretirement benefits		466			(764	)
Other assets		71,578			61,627
Accounts payable		(18,610	)		(39,874	)
Regulatory liability for postretirement benefits		—			(5	)
Provision for postretirement benefits		(10,493	)		579
Other liabilities		37,664			287

Net cash provided by operating activities		360,578			317,315


Cash Flows from Investing Activities:
Utility construction expenditures		(70,039	)		(52,389	)
Allowance for funds used during construction		(1,302	)		(1,227	)
Distributions of capital from equity method investments		701			315
Proceeds from sale of interest in equity method investment		57,500			—
Proceeds from sale of property		1,210			127
Investments in marketable securities		(468	)		(365	)
Other		204			856

Net cash used in investing activities		(12,194	)		(52,683	)

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


	Six Months Ended
	April 30
	2010			2009
Cash Flows from Financing Activities:
Borrowings under short-term debt	$	558,000		$	632,000
Repayments under short-term debt		(828,500	)		(833,000	)
Retirement of long-term debt		(384	)		(790	)
Issuance of common stock through dividend reinvestment and employee stock plans		9,817			7,646
Repurchases of common stock		(47,282	)		(17,857	)
Dividends paid		(39,909	)		(38,922	)
Other		(694	)		(51	)

Net cash used in financing activities		(348,952	)		(250,974	)


Net Increase (Decrease) in Cash and Cash Equivalents		(568	)		13,658
Cash and Cash Equivalents at Beginning of Period		7,558			6,991

Cash and Cash Equivalents at End Period	$	6,990		$	20,649


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	819		$	2,404
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						Six Months Ended
	April 30						April 30
	2010			2009			2010			2009

Net Income	$	46,825		$	53,525		$	160,574		$	134,401

Other Comprehensive Income:
Unrealized loss from hedging activities of equity method investments, net of tax of ($540) and ($1,858) for the three months ended April 30, 2010 and 2009, respectively, and ($171) and ($3,369) for the six months ended April 30, 2010 and 2009, respectively		(838	)		(2,886	)		(265	)		(5,229	)
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $456 and $310 for the three months ended April 30, 2010 and 2009, respectively, and $884 and ($256) for the six months ended April 30, 2010 and 2009, respectively		708			480			1,372			(400	)


Total Comprehensive Income	$	46,695		$	51,119		$	161,681		$	128,772

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 April 30, 2010 and October 31, 2009, the results of operations for the three months and six months ended April 30, 2010 and 2009, and cash flows for the six months ended April 30, 2010 and 2009. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 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 six months ended April 30, 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 April 30, 2010 and October 31, 2009 are as follows.


	April 30,		October 31,
In thousands	2010		2009

Regulatory assets	$	191,862	$	337,543
Regulatory liabilities		423,981		409,323

Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For information on related party transactions, see Note 8 to the consolidated financial statements in this Form 10-Q.

Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (FASB) issued new accounting guidance for employers’ disclosures about plan assets of defined benefit pension and other postretirement plans. This guidance requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by current fair value guidance. The guidance is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since only additional disclosures about plan assets of defined benefit pension and other postretirement plans are required, 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.

2. Regulatory Matters

On August 3, 2009, we filed testimony with the North Carolina Utilities Commission (NCUC) in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2009. A hearing was held on October 6, 2009, and testimony was submitted by us and the North Carolina Public Staff with agreed upon adjustments for the 2009 gas cost review period. A joint proposed order was filed on November 12, 2009. On February 17, 2010, the NCUC issued an order approving our gas cost purchasing and accounting practices for the period under review.

On October 1, 2009, we filed a petition with the Public Service Commission of South Carolina (PSCSC) requesting approval to offer three energy efficiency programs to residential and commercial customers. The proposed programs in South Carolina are designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs and are similar to approved energy efficiency programs in North Carolina. 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 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. The deadline for the audit period has been extended from May 31, 2010 to July 30, 2010. We are unable to predict the outcome of this proceeding at this time.

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 six months ended April 30, 2010 and 2009 is presented below.


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

Net Income	$	46,825	$	53,525	$	160,574	$	134,401


Average shares of common stock outstanding for basic earnings per share		71,788		73,239		72,492		73,280
Contingently issuable shares under incentive compensation plans		330		275		350		302

Average shares of dilutive stock		72,118		73,514		72,842		73,582


Earnings Per Share of Common Stock:
Basic	$	0.65	$	0.73	$	2.22	$	1.83
Diluted	$	0.65	$	0.73	$	2.20	$	1.83

4. Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in a rabbi trust established for our deferred compensation plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 6 to the consolidated financial statements 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 April 30, 2010 and October 31, 2009 is as follows.


	April 30, 2010				October 31, 2009
			Fair				Fair
In thousands	Cost		Value		Cost		Value

Money markets	$	275	$	275	$	169	$	169
Mutual funds		567		685		205		272

Total trading securities	$	842	$	960	$	374	$	441

5. Capital Stock

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

issuance of an additional 2.75 million shares of our common stock under the DRIP. On February 8, 2010, we filed a registration statement (Rescission Offer) which offered to rescind the purchase of the 568,000 shares sold under the DRIP between December 1, 2008 and November 16, 2009 and registered all previously unregistered shares issued under the DRIP during that period. The Rescission Offer expired on March 18, 2010. For the three months ended April 30, 2010, shares rescinded and resulting payments to shareholders were immaterial. While we are unable to predict the full consequences of these events, we do not expect any regulatory or other actions that would have a material adverse effect on us.

In January 2010, we began to purchase and retire 1.8 million shares of our common stock under the Common Stock Open Market Purchase Program. We used a broker to repurchase the shares on the open market, and such shares were cancelled and became authorized but unissued shares available for issuance. As of January 31, 2010, we had repurchased 1.4 million shares at an average price of $26.38 per share. Total consideration paid of $36.9 million to purchase the shares was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets. In February 2010, we repurchased an additional .4 million shares at an average price of $25.86 per share. Total consideration paid of $10.4 million to purchase these shares under the program was recorded as noted above.

6. Employee Benefit Plans

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended April 30, 2010 and 2009 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2010			2009			2010		2009			2010			2009
Service cost	$	2,100		$	1,487		$	10	$	6		$	334		$	360
Interest cost		2,850			2,750			61		81			476			579
Expected return on plan assets		(4,775	)		(4,138	)		—		—			(345	)		(426	)
Amortization of transition obligation		—			—			—		—			167			167
Amortization of prior service (credit) cost		(550	)		(549	)		5		5			—			—
Amortization of actuarial loss (gain)		550			—			2		(5	)		59			—

Total	$	175		$	(450	)	$	78	$	87		$	691		$	680

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2010 and 2009 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2010			2009			2010		2009			2010			2009
Service cost	$	4,200		$	2,974		$	19	$	13		$	669		$	720
Interest cost		5,700			5,501			121		164			953			1,159
Expected return on plan assets		(9,550	)		(8,276	)		—		—			(691	)		(853	)
Amortization of transition obligation		—			—			—		—			334			334
Amortization of prior service (credit) cost		(1,100	)		(1,099	)		10		10			—			—
Amortization of actuarial loss (gain)		1,100			—			5		(15	)		118			—

Total	$	350		$	(900	)	$	155	$	172		$	1,383		$	1,360

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		2,700

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 six months ended April 30, 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 April 30, 2010, we have a liability of $1.1 million for these plans.

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

7. Business Segments

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

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

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements in our Form 10-K for the year ended October 31, 2009.

Operations by segment for the three months and six months ended April 30, 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	$	472,846	$	455,432	$	—		$	—		$	472,846	$	455,432
Margin		168,678		169,953		—			—			168,678		169,953
Operations and maintenance expenses		57,503		53,352		111			37			57,614		53,389
Gain from sale of interest in equity method investment		—		—		—			—			—		—
Income from equity method investments		—		—		13,309			17,832			13,309		17,832
Operating income (loss) before income taxes		77,934		83,638		(118	)		(45	)		77,816		83,593
Income before income taxes		64,250		70,788		13,190			17,781			77,440		88,569

Six Months
Revenues from external customers	$	1,146,582	$	1,235,076	$	—		$	—		$	1,146,582	$	1,235,076
Margin		391,620		390,636		—			—			391,620		390,636
Operations and maintenance expenses		109,542		104,077		234			77			109,776		104,154
Gain from sale of interest in equity method investment		—		—		49,674			—			49,674		—
Income from equity method investments		—		—		25,142			27,621			25,142		27,621
Operating income (loss) before income taxes		215,897		220,717		(330	)		(177	)		215,567		220,540
Income before income taxes		190,849		194,680		74,488			27,429			265,337		222,109

Reconciliations to the consolidated statements of income for the three months and six months ended April 30, 2010 and 2009 are presented below.


	Three Months						Six Months
In thousands	2010			2009			2010			2009
Operating Income:
Segment operating income before income taxes	$	77,816		$	83,593		$	215,567		$	220,540
Utility income taxes		(25,709	)		(28,287	)		(75,871	)		(77,235	)
Non-utility activities before income taxes		118			45			330			177

Operating income	$	52,225		$	55,351		$	140,026		$	143,482


Net Income:
Income before income taxes for reportable segments	$	77,440		$	88,569		$	265,337		$	222,109
Income taxes		(30,615	)		(35,044	)		(104,763	)		(87,708	)

Net income	$	46,825		$	53,525		$	160,574		$	134,401

8. Equity Method Investments

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

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

On October 22, 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which 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 six months ended April 30, 2010 and 2009, these transportation costs and the amounts we owed Cardinal as of April 30, 2010 and October 31, 2009 are as follows.


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Transportation costs	$	1,001	$	1,001	$	2,035	$	2,035


	April 30,		October 31,
	2010		2009

Trade accounts payable	$	337	$	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 six months ended April 30, 2010 and 2009, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2010 and October 31, 2009 are as follows.


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Gas storage costs	$	3,104	$	2,926	$	6,313	$	5,950


	April 30,		October 31,
	2010		2009

Trade accounts payable	$	1,046	$	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 $.41 per diluted share. 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 six months ended April 30, 2010 and 2009, our operating revenues from these sales and the amounts SouthStar owed us as of April 30, 2010 and October 31, 2009 are as follows.


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Operating revenues	$	1,124	$	2,180	$	1,061	$	5,178


	April 30,		October 31,
	2010		2009

Trade accounts receivable	$	645	$	639

Summarized financial information provided to us by SouthStar for 100% of SouthStar for the three months and six months ended March 31, 2010 and 2009 is presented below.


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Revenues	$	392,800	$	343,520	$	625,166	$	629,430
Gross profit		95,943		84,143		155,895		132,307
Income before income taxes		74,807		63,189		114,168		93,045

Piedmont Hardy Storage Company, LLC, a wholly owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia that is regulated by the FERC. Initial service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals. Final service levels were placed into service on April 1, 2009 as scheduled.

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

On March 17, 2010, Hardy Storage paid $3.6 million on the interim notes to enable the completion of its conversion of the interim notes to long-term project financing. The new long-term notes are for $119.8 million due in 2023 at 5.88%. As a result of the conversion, our Guaranty of Principal and Residual Guaranty that were executed in connection with the interim financing terminated with no payments having been made. The long-term project financing is non-recourse to the members of Hardy Storage and their parent entities.

Prior to the long-term financing discussed above, we recorded a liability of $1.2 million for the fair value of the guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changed, the fair value of the guaranty was adjusted accordingly through a quarterly evaluation. Upon completion of permanent financing, the liability was reversed, and our investment account was adjusted accordingly to reflect the elimination of the guaranty.

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 six months ended April 30, 2010 and 2009, our gas storage costs and the amounts we owed Hardy Storage as of April 30, 2010 and October 31, 2009 are as follows.


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Gas storage costs	$	2,300	$	2,330	$	4,535	$	4,652


	April 30,		October 31,
	2010		2009

Trade accounts payable	$	808	$	781

9. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. Based on the value of our positions in these brokerage accounts and the associated margin requirements, we may be required to deposit cash into these brokerage accounts. The accounting guidance related to derivatives and hedging requires that we use a gross presentation for the fair value amounts for our derivative instruments and the fair

value of the right to reclaim cash collateral. We include amounts recognized for the right to reclaim cash collateral in our current assets and current liabilities. We had the right to reclaim cash collateral of $24.6 million and $35.4 million as of April 30, 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 six months ended April 30, 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 April 30, 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 April 30, 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	$	2,375	$	—	$	—	$	2,375
Debt and equity securities held as trading securities:
Money markets		275		—		—		275
Mutual funds		685		—		—		685

Total fair value assets	$	3,335	$	—	$	—	$	3,335

Liabilities:
Derivatives held for distribution operations	$	22,683	$	—	$	—	$	22,683

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 using 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 April 30, 2010	$	792,128	$	895,655
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 April 30, 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 April 30, 2010, we had long gas options providing total coverage of 34.5 million dekatherms, of which 12.6 million dekatherms are limited in upside protection. We have sold options for 9.7 million dekatherms that guarantee a minimum floor price for supply. The long and short options are for the period from June 2010 through May 2011.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of April 30, 2010 and October 31, 2009.

Fair Value of Derivative Instruments


	Fair Value			Fair Value
In thousands	April 30, 2010			October 31, 2009

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:

Asset Financial Instruments
Current Assets — Gas purchase derivative assets (June 2010-May 2011)	$	2,375
Current Assets — Gas purchase derivative assets (December 2009-November 2010)				$	2,559

Liability Financial Instruments
Current Liabilities — Gas purchase derivative liabilities (June 2010-May 2011)		22,683
Current Liabilities — Gas purchase derivative liabilities (December 2009-November 2010)					30,603


Total financial instruments, net	$	(20,308	)	$	(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 income for the three months and six months ended April 30, 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				Six Months Ended				Location of Loss
	April 30				April 30				Recognized through
In thousands	2010		2009		2010		2009		PGA Procedures

Gas purchase options	$	17,126	$	41,476	$	33,776	$	82,616	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 April 30, 2010, we have five International Swaps and Derivatives Association (ISDA) agreements for the purpose of securing put options as a part of our overall hedging program. The ISDA agreements specify a net liability of $55 million, $50 million, $30 million, $25 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 April 30, 2010.

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

10. Long-Term Debt Instruments

During the six months ended April 30, 2010, we paid $.4 million to noteholders of the 6.25% insured quarterly notes. These notes have a redemption right upon the death of the owner of the notes, within specified limitations.

11. Short-Term Debt Instruments

We have a syndicated five-year revolving credit facility that expires April 2011 with aggregate commitments totaling $450 million to meet working capital needs, 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 April 30, 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 April 30, 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 $35.5 million and $306 million, respectively, in LIBOR cost-plus loans. During the three months ended April 30, 2010, short-term borrowings ranged from $15 million to $287.5 million, and interest rates ranged from .48% to .53% (weighted average of .49%). During the six months ended April 30, 2010, short-term borrowings ranged from $15 million to $342.5 million, and interest rates ranged from .48% to .53% (weighted average of .49%). Our syndicated five-year revolving credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 45% at April 30, 2010.

We have corrected the presentation within the consolidated statements of cash flows for the six months ended April 30, 2009 to present borrowings and repayments under our syndicated five-year revolving credit facility on a gross basis. Such borrowings and repayments were formerly presented on a net basis. There was no effect on total cash flows from financing activities.

12. Employee Share-Based Plans

Under Board of Directors approved incentive compensation plans, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year

performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three months and six months ended April 30, 2010 and 2009, we recorded compensation expense, and as of April 30, 2010 and October 31, 2009, we have accrued amounts for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

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


	Three Months				Six Months
In thousands	2010		2009		2010		2009

Compensation expense	$	1,955	$	1,215	$	4,729	$	1,144


	April 30,		October 31,
	2010		2009

Liability	$	9,164	$	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.

13. Commitments and Contingent Liabilities

Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers, telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to fourteen years. The time periods for gas supply contracts range from one

to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

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

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases.

Legal

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

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.7 million in letters of credit that were issued and outstanding at April 30, 2010. Additional information concerning letters of credit is included in Note 11 to the consolidated financial statements in this Form 10-Q.

Environmental Matters

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

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid $5.3 million, charged to the estimated environmental liability, that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

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. 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). Subsequently, the TDEC requested an additional soil removal report, groundwater monitoring and its reporting, and limited soil investigation of an adjacent property and its reporting. Minor groundwater contamination was detected and soil contaminant levels of the adjacent property were found to be within state standards. Work is progressing to finalize the consent order for the site with the TDEC, and we anticipate completion in our fourth quarter of 2010. We have incurred $1.5 million through April 30, 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 are continuing to investigate and remediate the property where our Huntersville LNG facility is located. During the six months ended April 30, 2010, our estimate of the total cost to remediate the property increased from $1.6 million to $2.3 million, for which we increased our reserve by the additional $.7 million. We have incurred $1.6 million through April 30, 2010. 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 April 30, 2010, our undiscounted environmental liability for USTs for which we retain remediation responsibility is $.5 million.

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

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.

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

14. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware have been evaluated.

On May 1 and 2, 2010, powerful storms caused extensive flooding in our service territory in the Nashville, Tennessee area. As floodwaters have receded, our operations employees in the area have been working to perform leak detection surveys, disconnect service to homes and businesses that have been under water and reconnect service when repairs and replacements are complete and safety issues have been addressed. We proactively worked with the Office of Emergency Management, the TRA staff and the Attorney General’s office of Tennessee to provide communication updates to our customers. We have offered financial assistance to our Tennessee customers who have been affected by the flooding by not disconnecting service for non-payment, eliminating late fees and reconnection fees, and expanding payment arrangements. We are offering a 0% financing program for our qualifying customers who need to replace flood damaged natural gas appliances.

We do not anticipate that expenses related to this event will have a material impact on our financial position, results of operations or cash flows.

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

Forward-Looking Statements

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

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

	•		Residential, commercial, industrial and power generation growth and energy consumption in our service areas. The ability to grow our customer base, the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.

	•		Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies, and we expect this competitive environment to continue.

	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.

	•		The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and the cost and availability of labor and materials.

			Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.

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

	•		Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating, regulatory and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations. Since such risks may affect the availability and cost of natural gas, they also may affect the competitive position of natural gas relative to other energy sources.

	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, 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 repurchases under our Common Stock Open Market Purchase Program or new issuances.

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

Forward-looking statements are only as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Please reference our website at www.piedmontng.com

for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Executive Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

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

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

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 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 six months ended April 30, 2010, our earnings before taxes, including the gain from the sale of half of our ownership interest in SouthStar of $49.7 million, were $265.3 million. For the current six-month period, 72% 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 six months ended April 30, 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 28%, which consisted of 1% from regulated non-utility activities and 27% 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 six months ended April 30, 2010, 88% of our earnings before taxes came from our regulated utility segment, and earnings before taxes from our non-utility segment was 12%, which consisted of 2% from regulated non-utility activities and 10% from unregulated non-utility activities.

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

Our utility operations are regulated by the NCUC, the PSCSC and the TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also

regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the FERC that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the environment. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA.

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

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

With the 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 six months ended April 30, 2010, the margin decoupling mechanism in North Carolina reduced margin by $18.2 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. We will continue to seek power generation project opportunities to provide long-term transportation service in our market area.

While we are seeing the impacts of the economic recession in our market area with a decline in customer growth in our new construction market and continued customer conservation practices, we have seen some rebound in the industrial markets as compared with the prior year period. As discussed above, we are positioning ourselves to capitalize on new opportunities as the economy improves, 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% — 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 8 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 net income of $46.8 million for the three months ended April 30, 2010 as compared to $53.5 million for the same period in 2009. The following table sets forth a comparison of the components of our consolidated statements of income for the three months ended April 30, 2010 as compared with the three months ended April 30, 2009.

Income Statement Components


	Three Months Ended April 30
In thousands, except per share amounts	2010		2009		Variance			Percent Change
Operating Revenues	$	472,846	$	455,432	$	17,414			3.8	%
Cost of Gas		304,168		285,479		18,689			6.5	%

Margin		168,678		169,953		(1,275	)		(0.8	)%

Operations and Maintenance		57,503		53,352		4,151			7.8	%
Depreciation		24,483		24,306		177			0.7	%
General Taxes		8,758		8,657		101			1.2	%
Income Taxes		25,709		28,287		(2,578	)		(9.1	)%

Total Operating Expenses		116,453		114,602		1,851			1.6	%

Operating Income		52,225		55,351		(3,126	)		(5.6	)%
Other Income (Expense), net of tax		7,611		10,086		(2,475	)		(24.5	)%
Utility Interest Charges		13,011		11,912		1,099			9.2	%

Net Income	$	46,825	$	53,525	$	(6,700	)		(12.5	)%


Average Shares of Common Stock:
Basic		71,788		73,239		(1,451	)		(2.0	)%
Diluted		72,118		73,514		(1,396	)		(1.9	)%


Earnings Per Share of Common Stock:
Basic	$	0.65	$	0.73	$	(0.08	)		(11.0	)%
Diluted	$	0.65	$	0.73	$	(0.08	)		(11.0	)%

We reported net income of $160.6 million for the six months ended April 30, 2010 as compared to $134.4 million for the same period in 2009. The following table sets forth a comparison of the components of our consolidated statements of income for the six months ended April 30, 2010 as compared with the six months ended April 30, 2009.

Income Statement Components


	Six Months Ended April 30
In thousands, except per share amounts	2010		2009		Variance			Percent Change
Operating Revenues	$	1,146,582	$	1,235,076	$	(88,494	)		(7.2	)%
Cost of Gas		754,962		844,440		(89,478	)		(10.6	)%

Margin		391,620		390,636		984			0.3	%

Operations and Maintenance		109,542		104,077		5,465			5.3	%
Depreciation		48,838		48,448		390			0.8	%
General Taxes		17,343		17,394		(51	)		(0.3	)%
Income Taxes		75,871		77,235		(1,364	)		(1.8	)%

Total Operating Expenses		251,594		247,154		4,440			1.8	%

Operating Income		140,026		143,482		(3,456	)		(2.4	)%
Other Income (Expense), net of tax		44,863		15,844		29,019			183.2	%
Utility Interest Charges		24,315		24,925		(610	)		(2.4	)%

Net Income	$	160,574	$	134,401	$	26,173			19.5	%


Average Shares of Common Stock:
Basic		72,492		73,280		(788	)		(1.1	)%
Diluted		72,842		73,582		(740	)		(1.0	)%


Earnings Per Share of Common Stock:
Basic	$	2.22	$	1.83	$	0.39			21.3	%
Diluted	$	2.20	$	1.83	$	0.37			20.2	%

Key statistics are shown in the table below for the three months ended April 30, 2010 and 2009.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended
	April 30
	2010			2009			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		38,249			34,870			3,379			9.7	%
Transportation Volumes		28,438			22,583			5,855			25.9	%

Throughput		66,687			57,453			9,234			16.1	%

Secondary Market Volumes		9,817			9,576			241			2.5	%

Customers Billed (at period end)		972,440			964,623			7,817			0.8	%
Gross Customer Additions		2,362			2,337			25			1.1	%

Degree Days
Actual		1,319			1,204			115			9.6	%
Normal		1,207			1,212			(5	)		(0.4	)%
Percent colder (warmer) than normal		9.3	%		(0.7	)%		n/a			n/a

Number of Employees (at period end)		1,806			1,829			(23	)		(1.3	)%

Key statistics are shown in the table below for the six months ended April 30, 2010 and 2009.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Six Months Ended
	April 30
	2010			2009			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		93,616			87,246			6,370			7.3	%
Transportation Volumes		57,793			46,738			11,055			23.7	%

Throughput		151,409			133,984			17,425			13.0	%

Secondary Market Volumes		20,341			22,968			(2,627	)		(11.4	)%

Customers Billed (at period end)		972,440			964,623			7,817			0.8	%
Gross Customer Additions		5,428			6,250			(822	)		(13.2	)%

Degree Days
Actual		3,369			3,148			221			7.0	%
Normal		3,065			3,068			(3	)		(0.1	)%
Percent colder than normal		9.9	%		2.6	%		n/a			n/a

Number of Employees (at period end)		1,806			1,829			(23	)		(1.3	)%

Operating Revenues

Operating revenues increased $17.4 million for the three months ended April 30, 2010 compared with the same period in 2009 primarily due to the following increases:

	•		$25.4 million of gas costs, primarily from increased volume deliveries to sales customers.

	•		$3.7 million from revenues in secondary market transactions due to increased activity. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

	•		$1.7 million from increased volumes delivered to transportation customers other than power generation.

These increases were partially offset by the following decreases:

	•		$7.1 million from decreased revenues under the WNA in South Carolina and Tennessee.

	•		$5.8 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 $88.5 million for the six months ended April 30, 2010 compared with the same period in 2009 primarily due to the following decreases:

	•		$38.4 million primarily from gas costs passed through to sales customers.

	•		$29.3 million from revenues in secondary market transactions due to decreased activity and gas costs.

	•		$14.4 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 $3 million from increased volumes delivered to transportation customers other than power generation.

Cost of Gas

Cost of gas increased $18.7 million for the three months ended April 30, 2010 compared with the same period in 2009 primarily due to the following increases:

	•		$21.3 million of commodity gas costs from increased volume deliveries to sales customers.

	•		$3.9 million from commodity gas costs in secondary market transactions due to increased activity.

These increases were partially offset by a decrease of $14.1 million of commodity gas costs from lower gas costs passed through to sales customers.

Cost of gas decreased $89.5 million for the six months ended April 30, 2010 compared with the same period in 2009 primarily due to the following decreases:

	•		$110.6 million primarily from lower gas costs passed through to sales customers.

	•		$28.5 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

These decreases were partially offset by an increase of $42.2 million of commodity gas costs from increased volume deliveries to sales customers.

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

Margin

Margin decreased $1.3 million for the three months ended April 30, 2010 compared with the same period in 2009, primarily due to net adjustments to gas costs, accounts payable, and lost and unaccounted for gas.

Margin increased $1 million for the six months ended April 30, 2010 compared with the same period in 2009 primarily due the following increases:

	•		$1.4 million from increased volumes to our industrial customers.

	•		$.7 million from residential customer growth.

These increases were partially offset by a decrease of $.9 million from secondary market transactions.

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 six months ended April 30, 2010, and transportation and storage costs, which accounted for 5%.

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 $4.2 million for the three months ended April 30, 2010 compared with the same period in 2009 due to increases in payroll expense primarily from increases in long-term incentive plan accruals priced at a higher current stock price, merit wage increases for non-officer employees, and employee benefits expense increases due primarily to an increase in pension expense from a lower discount rate used to determine periodic benefit cost.

Operations and maintenance expenses increased $5.5 million for the six months ended April 30, 2010 compared with the same period in 2009 due to $5.2 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.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and other miscellaneous expenses.

The primary changes to Other Income (Expense) for the three months and six months ended April 30, 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 six 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 $.41 per diluted earnings per share, for the six months ended April 30, 2010.

Income from equity method investments decreased $4.5 million for the three months ended April 30, 2010 as compared with the same period in 2009 due to a $4.7 million decrease in earnings from SouthStar primarily due to the current quarter recording of earnings at the new 15% ownership interest as discussed in our Form 10-K for the year ended October 31, 2009, partially offset by increased average customer usage due to colder weather, higher operating margins in the Ohio and Florida markets and favorable changes in the lower of cost or

market storage inventory adjustment, partially offset by losses on weather derivatives and changes in the retail pricing mix chosen by SouthStar customers.

Income from equity method investments decreased $2.5 million for the six months ended April 30, 2010 as compared with the same period in 2009 due to a $2.3 million decrease in earnings from SouthStar primarily due to the current quarter recording of earnings at the new 15% ownership interest, partially offset by increased average customer usage due to colder weather and favorable changes in the lower of cost or market storage inventory adjustment.

Utility Interest Charges

Utility interest charges increased $1.1 million for the three months ended April 30, 2010 compared with the same period in 2009 primarily due to the following:

	•		$2.4 million decrease in interest income due to lower amounts due from customers.

	•		$.6 million decrease in interest expense on long-term debt primarily due to lower amounts outstanding.

	•		$.4 million decrease in interest expense on short-term debt primarily due to an average interest rate for the current period being approximately 25 basis points lower than the prior year period combined with lower levels of borrowing in the current period.

Utility interest charges decreased $.6 million for the six months ended April 30, 2010 compared with the same period in 2009 primarily due to the following:

	•		$2.1 million decrease in interest income due to lower amounts due from customers.

	•		$1.4 million decrease in interest expense on short-term debt primarily due to an average interest rate for the current period being approximately 60 basis points lower than the prior year period combined with lower levels of borrowing in the current period.

	•		$1.1 million decrease in interest expense on long-term debt primarily due to lower amounts outstanding.

Financial Condition and Liquidity

To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. 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 future syndicated five-year revolving 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 $360.6 million and $317.3 million for the six months ended April 30, 2010 and 2009, respectively. Net cash provided by operating activities reflects a $26.2 million increase in net income for 2010 compared with 2009, which includes an after-tax gain of $30.2 million on the sale of half of our interest in SouthStar as discussed in “Results of Operations” above.

The effect of changes in working capital on net cash provided by operating activities is described below:

	•		Trade accounts receivable and unbilled utility revenues increased $54.6 million in the current period primarily due to higher volumes delivered in 2010 as compared with 2009. Volumes sold to residential and commercial customers increased 6.1 million dekatherms primarily due to weather that was 7% colder, partially offset by lower gas costs in 2010 as compared with 2009. Total throughput increased 17.4 million dekatherms as compared with the same prior period.

	•		Net amounts due from customers decreased $147.6 million primarily due to the collection of deferred gas costs related to hedging activities through rates.

	•		Gas in storage decreased $23.8 million in the current period primarily due to withdrawals from gas in storage and a decrease in the average cost of gas in storage.

	•		Prepaid gas costs decreased $29.3 million in the current period primarily due to gas becoming available for sale during the period. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the winter heating season.

•

Trade accounts payable increased $8.3 million in the current period primarily due to gas purchases to meet customer demand during the winter months.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated credits to customers of $9.2 million and $.8 million in the six months ended April 30, 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 $18.2 million and $3.8 million in the six months ended April 30, 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 $12.2 million and $52.7 million for the six months ended April 30, 2010 and 2009, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the six months ended April 30, 2010 were $70 million as compared to $52.4 million in the same prior period primarily due to the acquisition of land and the construction of buildings.

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 April 30, 2010, we have forecasted capital expenditures of $224 million for fiscal 2010, including $60 million for pipeline infrastructure to serve gas-fired power generation projects in North Carolina. Even though we are seeing a slower pace of core residential and commercial customer growth in our service territory due to the downturn in the housing market and other economic factors, significant utility construction expenditures are expected to continue to meet long-term growth and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

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 $88 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 $217 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 8 to the consolidated financial statements in this Form 10-Q.

Cash Flows from Financing Activities. Net cash used in financing activities was $349 million and $251 million for the six months ended April 30, 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 April 30, 2010, our current assets were $318.1 million and our current liabilities were $329.9 million primarily due to seasonal requirements as discussed above.

As of April 30, 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 $35.5 million as of April 30, 2010 primarily due to lower commodity gas costs and lower interest payments for short-term debt. During the six months ended April 30, 2010, short-term borrowings ranged from $15 million to $342.5 million, and interest rates ranged from .48% to .53% (weighted average of .49%).

As of April 30, 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 April 30, 2010, unused lines of credit available under our syndicated five-year revolving credit facility, including the issuance of the letters of credit, totaled $411.8 million.

In July 2010, we will begin the process of replacing our existing credit facility. During the renewal process, we will evaluate 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 late fiscal year 2011 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 six months ended April 30, 2010, we issued $9.8 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 six months ended April 30, 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 April 30, 2010, our retained earnings were not restricted. On June 4, 2010, the Board of Directors declared a quarterly dividend on common stock of $.28 per share, payable July 15, 2010 to shareholders of record at the close of business on June 24, 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 April 30, 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 April 30, 2010 and 2009, and October 31, 2009, are summarized in the table below.


	April 30					October 31					April 30
In thousands	2010		Percentage			2009		Percentage			2009		Percentage
Short-term debt	$	35,500		2	%	$	306,000		15	%	$	205,500		10	%
Current portion of long-term debt		60,000		3	%		60,000		3	%		30,000		1	%
Long-term debt		732,128		40	%		732,512		36	%		793,471		40	%

Total debt		827,628		45	%		1,098,512		54	%		1,028,971		51	%
Common stockholders’ equity		1,013,521		55	%		927,948		46	%		969,852		49	%

Total capitalization (including short-term debt)	$	1,841,149		100	%	$	2,026,460		100	%	$	1,998,823		100	%

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

As of April 30, 2010, all of our long-term debt was unsecured. Our long-term debt is rated “A” by S&P and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of April 30, 2010, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended April 30, 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.

As of October 31, 2009, Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, had entered into a guaranty in the normal course of business pertaining to our investment in Hardy Storage. The guaranty involved some levels of performance and credit risk that were not included on our consolidated balance sheets.

We recorded an estimated liability of $1.2 million as of October 31, 2009. The possibility of having to perform on the guaranty was largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. In March 2010, Hardy Storage obtained long-term non-recourse project financing, and we were released from any liability under the guaranty, and accordingly, we reversed the liability for the guaranty. For further information on this guaranty, see Note 8 to the consolidated financial statements in this Form 10-Q.

Critical Accounting Policies and Estimates

We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates presented in our Form 10-K for the year ended October 31, 2009, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Management has discussed these critical accounting estimates with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates since October 31, 2009.

Recent Accounting Pronouncements

Accounting Pronouncements

operations or cash flows. We will adopt the guidance during the first quarter of our fiscal year ending October 31, 2011.

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 April 30, 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 April 30, 2010, we had $35.5 million of short-term debt outstanding under our syndicated revolving credit facility at an interest rate of .53%. 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 $.3 million during the three months ended April 30, 2010 and $1 million during the six months ended April 30, 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 second 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 six months ended April 30, 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 April 30, 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									4,912,174
02/01/10 - 02/28/10		402,100		$	25.86		402,100		4,510,074
03/01/10 - 03/31/10		—		$	—		—		4,510,074
04/01/10 - 04/30/10		190	(2)	$	26.73		—		4,510,074

Total		402,290		$	25.86		402,100


(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 the Rescission Offer, 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 April 30, 2010, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 5. Other Information

Submission of Matters to a Vote of Security Holders

We held our Annual Meeting of Shareholders on February 26, 2010. Because of the date of the Annual Meeting, we were not required to file a report on Form 8-K under Item 5.07. We are providing the information required by this item on Form 8-K under this Item 5 of this Form 10-Q.

At the Annual Meeting, shareholders voted on the election of four directors, the ratification of the selection of our independent registered public accounting firm and the approval of an amendment to our Employee Stock Purchase Plan increasing the number of shares authorized for issuance under the plan. The record date for determining the shareholders entitled to receive notice of and to vote at the meeting was December 28, 2009. We solicited proxies for the meeting according to section 14(a) of the Securities and Exchange Act of 1934. There was no solicitation in opposition to management’s solicitations.

Shareholders elected all of the nominees for director as listed in the proxy statement by the following votes:


	Shares		Shares		Broker
	Voted		Voted		Non-
	FOR		WITHHELD		Votes
For terms expiring in 2013:
Jerry W. Amos		36,878,555		707,040		23,447,003
Frankie T. Jones, Sr.		36,973,421		612,174		23,447,003
Vicki McElreath		36,983,580		602,015		23,447,003
Thomas E. Skains		36,394,073		1,191,522		23,447,003

The current terms of continuing directors Malcolm E. Everett III, Frank B. Holding, Jr., Minor M. Shaw and Muriel W. Sheubrooks will expire at our annual meeting in 2011. The current terms of continuing directors E. James Burton, John W. Harris, Aubrey B. Harwell, Jr., and David E. Shi will expire at our annual meeting in 2012.

Shareholders ratified the selection by the Board of Directors of the firm Deloitte & Touche LLP as our independent public accounting firm for the fiscal year ending October 31, 2010, by the following vote:


Shares	Shares	Shares	Broker
Voted	Voted	Voted	Non-
FOR	AGAINST	ABSTAINING	Votes
59,435,161	1,421,030	176,407	—

Shareholders approved an amendment to increase the number of shares authorized for issuance under our Employee Stock Purchase Plan by the following vote:


Shares	Shares	Shares	Broker
Voted	Voted	Voted	Non-
FOR	AGAINST	ABSTAINING	Votes
35,443,069	1,230,933	911,593	23,447,003

Item 6. Exhibits


		Compensatory Contracts:

10.1		Resolution of Board of Directors, February 26, 2010, establishing compensation for non-management directors.

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

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

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

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

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 June 9, 2010	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)


Date June 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 April 30, 2010

Exhibits

Compensatory Contracts:

	10.1		Resolution of Board of Directors, February 26, 2010, establishing compensation for non-management directors

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

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

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

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