Piedmont Natural Gas 10K/A 2004 Annual report (amended)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

Amendment No.1

(Mark One)

þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2004

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

For the Transition period from to

Commission file number1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

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

1915 Rexford Road, Charlotte, North Carolina		28211

(Address of principal executive offices)		(Zip Code)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:


Title of each class		Name of each exchange on which registered

Common Stock, no par value		New York Stock Exchange

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. Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yesþ Noo

State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of April 30, 2004.

Common Stock, no par value - $1,530,797,879

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


Class		Outstanding at January 7, 2005

Common Stock, no par value		76,624,547

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 4, 2005, are incorporated by reference into Part III.

Explanatory Note

We are filing this Amendment No.1 to our annual report on Form 10-K for the year ended October 31, 2004, as filed with the Securities and Exchange Commission on January 14, 2005. This amendment corrects three typographical errors. One typographical error in amounts is in Number of Retail Customers Billed on page 5 in Item 1 of Part I. Two typographical errors in amounts are on the Consolidated Balance Sheet on Page 30 in Item 8 of Part II. This amendment does not change any other previously reported financial statements and other financial disclosures.

PART I

Item 1. Business

Piedmont Natural Gas Company, Inc. (Piedmont), was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina.

Piedmont is an energy services company primarily engaged in the distribution of natural gas to 960,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 60,000 customers served by municipalities who are our wholesale customers. Our subsidiaries are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. We also sell residential and commercial gas appliances in Tennessee.

In the Carolinas, our service area is comprised of numerous cities, towns and communities, including Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, 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.

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of North Carolina Natural Gas Corporation (NCNG) from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million for estimated working capital. We paid an additional $.3 million for actual working capital in our second quarter ended April 30, 2004. NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing. We also purchased for $7.5 million in cash Progress’ equity interest in Eastern North Carolina Natural Gas Company (EasternNC), a regulated utility. EasternNC has a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. We are obligated to purchase additional authorized but unissued shares of such preferred stock for $14.4 million.

We have two reportable business segments, regulated utility and non-utility activities. Operations of our regulated utility segment are conducted by Piedmont, the parent company, and by EasternNC and are conducted within the United States of America. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. As of October 31, 2004, these operations were primarily conducted by Piedmont Intrastate Pipeline Company (Piedmont Intrastate), Piedmont Interstate Pipeline Company (Piedmont Interstate) and Piedmont Energy Company (Piedmont Energy). All of these companies are wholly owned subsidiaries of Piedmont Energy Partners, a holding company that is a wholly owned subsidiary

of the parent company.

Piedmont Intrastate owns 21.48% 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. Piedmont Interstate owns 40.0587% 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. Piedmont Energy owns 30% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

As of October 31, 2003, Piedmont Greenbrier Pipeline Company, LLC, owned 33% of the membership interests in Greenbrier Pipeline Company, LLC (Greenbrier). Greenbrier was formed to build a proposed interstate gas pipeline from West Virginia to North Carolina. On November 6, 2003, we sold our interest to the other member in the venture for our book value of $9.2 million.

Prior to January 20, 2004, Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners, owned 20.69% of the membership interests in US Propane, L.P., which owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. On January 20, we, along with the other members, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane for $130 million. Our share of the proceeds was $26.9 million. We recorded a gain on the sale of $4.7 million in our first quarter ended January 31, 2004. In connection with the sale, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units.

On November 12, 2004, our subsidiary, Piedmont Hardy Storage Company, LLC, and Columbia Hardy Corporation, a subsidiary of Columbia Gas Transmission Corporation (Columbia Gas), a subsidiary of NiSource Inc., announced an agreement to form Hardy Storage Company LLC (Hardy Storage), with each having a 50% equity interest in the project. Hardy Storage will seek approval from the FERC to construct, own and operate an underground natural gas storage facility located in Hardy and Hampshire Counties, West Virginia. Subject to obtaining all necessary approvals, construction is expected to begin in October 2005 with storage service commencing with initial injections in April 2007. Our portion of the project capital expenditures is estimated at $50 to $55 million. Columbia Gas will serve as operator of the facilities.

Operations by segment for the years ended October 31, 2004, 2003 and 2002, are presented below.


	Regulated		Non-Utility
In thousands	Utility		Activities			Total
2004
Revenues from external customers	$	1,529,739	$	—		$	1,529,739
Income before income taxes and minority interest		125,044		32,239			157,283
Income from equity method investments		—		27,381			27,381
Total assets		2,268,824		67,179			2,336,003
Long-lived assets (Utility Plant in Service and Other Physical Property, gross)		2,398,249		—			2,398,249
Deferred tax assets		18,705		—			18,705

2003
Revenues from external customers	$	1,220,822	$	—		$	1,220,822
Income before income taxes and minority interest		106,150		17,649			123,799
Income from equity method investments		—		17,972			17,972
Total assets		2,230,272		112,690			2,342,962
Long-lived assets (Utility Plant in Service and Other Physical Property, gross)		2,326,368		—			2,326,368
Deferred tax assets		12,587		(563	)		12,024

2002
Revenues from external customers	$	832,028	$	—		$	832,028
Income before income taxes and minority interest		83,525		18,486			102,011
Income from equity method investments		—		19,207			19,207
Total assets		1,404,438		95,302			1,499,740
Long-lived assets (Utility Plant in Service and Other Physical Property, gross)		1,692,352		—			1,692,352
Deferred tax assets		11,080		(821	)		10,259

Operating revenues shown in the consolidated statements of income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For the year ended October 31, 2004, 41% of our operating revenues were from residential customers, 23% from commercial customers, 13% from industrial and power generation customers, 20% from secondary market activity and 3% from various other sources. Operations of the non-utility activities segment are included in “Other Income (Expense)” in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.” For further information on equity method investments and business segments, see Notes 10 and 11 to the consolidated financial statements in Item 8 of this Form 10-K.

Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also subject to regulation by the NCUC as to the issuance of securities. The utility operations of EasternNC are subject to regulation by the NCUC. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of

hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, that are generally applicable to companies doing business in the United States of America.

We hold non-exclusive franchises for natural gas service in the communities we serve, with expiration dates from 2005 to 2054. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. Two franchises have expired as of October 31, 2004, and four will expire within the next fiscal year. We continue to operate in those areas with expired franchises with no significant impact on our business as we have operated normally within the provisions of the expired franchise. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed with no material adverse impact on us as most government entities do not want to prevent their citizens from having access to gas service or to interfere with our required system maintenance. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action.

The natural gas distribution business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. During the year ended October 31, 2004, the amount of natural gas in storage varied from 7.5 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 27 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $37 million to $138.7 million.

During the year ended October 31, 2004, which reflects a full year of the operations of NCNG and EasternNC compared with only one month in 2003, 102.5 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 62.5 million dekatherms in 2003. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 89.9 million dekatherms in 2004, compared with 86.3 million dekatherms in 2003. Weather, as measured by degree days, was 6% warmer than normal in 2004 and 3% colder than normal in 2003.

The following is a five-year comparison of operating statistics for the years ended October 31, 2000 through 2004:


	2004		2003		2002		2001		2000
Operating Revenues (in thousands)
Sales and Transportation:
Residential	$	624,487	$	524,933	$	358,027	$	525,650	$	343,476
Commercial		360,355		299,281		191,988		299,672		207,087
Industrial		179,302		112,986		102,127		128,831		183,685
For Power Generation		18,782		3,071		2,368		1,316		18,849
For Resale		38,074		1,948		374		371		249

Total		1,221,000		942,219		654,884		955,840		753,346
Secondary Market Sales		301,886		273,369		173,592		145,712		73,505
Miscellaneous		6,853		5,234		3,552		6,304		3,526

Total	$	1,529,739	$	1,220,822	$	832,028	$	1,107,856	$	830,377


	2004			2003			2002			2001			2000
Gas Volumes - Dekatherms (in thousands):
System Throughput:
Residential		54,412			52,603			40,047			47,869			40,520
Commercial		35,483			33,648			25,892			31,002			29,315
Industrial		83,957			60,054			58,414			54,285			61,144
For Power Generation		18,580			2,396			1,734			1,169			4,081
For Resale		8,912			623			41			29			20

Total		201,344			149,324			126,128			134,354			135,080


Secondary Market Sales		51,707			45,937			55,679			29,545			21,072


Number of Retail Customers Billed (12 month average):
Residential		771,037			657,965			620,642			601,682			577,314
Commercial		90,328			75,924			72,323			71,069			68,879
Industrial		3,194			2,626			2,583			2,764			2,696
For Power Generation		13			5			3			3			3
For Resale		15			4			3			3			3

Total		864,587			736,524			695,554			675,521			648,895


Average Per Residential Customer:
Gas Used – Dekatherms		70.57			79.95			64.53			79.56			70.19
Revenue	$	809.93		$	797.81		$	576.87		$	873.63		$	594.95
Revenue Per Dekatherm	$	11.48		$	9.98		$	8.94		$	10.98		$	8.48

Cost of Gas (in thousands):
Natural Gas Purchased	$	944,107		$	789,918		$	408,564		$	670,380		$	426,329
Transportation Gas Received (Not Delivered)		(217	)		200			(157	)		214			(868	)
Natural Gas Withdrawn From (Injected Into) Storage, net		(8,057	)		(38,137	)		9,693			115			(20,144	)
Other Storage		(3,059	)		(5,932	)		1,927			(983	)		(4,937	)
Capacity Demand Charges		125,178			89,514			89,103			80,622			94,095
Other Adjustments		(16,582	)		2,379			(12,896	)		19,530			17,571


Total	$	1,041,370		$	837,942		$	496,234		$	769,878		$	512,046


Supply Available for Distribution - Dekatherms (in thousands):
Natural Gas Purchased		163,257			143,716			136,206			121,465			126,228
Transportation Gas		91,795			52,895			48,179			44,285			31,896
Natural Gas Withdrawn From (Injected Into) Storage, net		902			(2,438	)		(1,416	)		1,598			(712	)
Other Storage		(127	)		(52	)		(45	)		50			(259	)
Company Use		(135	)		(147	)		(139	)		(167	)		(161	)


Total		255,692			193,974			182,785			167,231			156,992

As of October 31, 2004, we had contracts for the following pipeline firm transportation capacity in dekatherms of daily deliverability:


Williams-Transco (including certain upstream arrangements with Dominion and Texas Gas)			645,400
El Paso-Tennessee Pipeline			74,100
Duke-Texas Eastern			37,000
NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)			42,800
NiSource-Columbia Gulf			10,000

Total			809,300

In addition, we had the following contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets. This availability varies from five days to one year:


Piedmont Liquefied Natural Gas (LNG)			316,000
Pine Needle LNG			263,400
Williams-Transco Storage			86,100
NiSource-Columbia Gas Storage			96,400
El Paso-Tennessee Pipeline Storage			55,900

Total			817,800

We own or have under contract 29.9 million dekatherms of storage capacity, either in the

form of underground storage or LNG. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.

The gas delivered to meet our design day requirements for firm customers is purchased under firm contractual commitments. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the peak day, seasonal and annual needs of our customers by using a variety of firm transportation and storage capacity arrangements. The pipeline capacity contracts require the payment of fixed demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement firm contractual commitments with other supply arrangements to serve our interruptible market, or as an alternate supply for inventory withdrawals or injections. The source of the gas we distribute is primarily from the on-shore and off-shore Gulf Coast production region and is purchased primarily from major producers and marketers. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K.

During the year ended October 31, 2004, 8% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under regulations of the FERC, certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. Through October 31, 2004, only minimal bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms. The future level of bypass activity cannot be predicted.

The regulated utility faces competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products and the relative prices of those products. The most significant product competition occurs between natural gas and electricity for space heating, water heating and cooking. There are four major electric company competitors within our service areas. We continue to attract the majority of the new residential construction market, and we believe that the consumer’s preference is for natural gas based on such factors as reliability, comfort and convenience compared with electricity to meet their needs. In addition to its many advantages, natural gas has historically maintained a price advantage over electricity in our service areas; however, with the increasing customer demand for natural gas, flat to declining production levels and other public policy issues primarily associated with access to public lands for drilling, natural gas prices and price volatility have increased. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer.

In the industrial market, many of our customers are capable of burning a fuel other than

natural gas, fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between natural gas supply and demand has the greatest impact on the price of our product. With the imbalance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and policies of foreign and domestic governments.

During the year ended October 31, 2004, our largest customer contributed $14.1 million, or 1%, to total operating revenues.

We spend an immaterial amount for research and development costs, primarily limited to gas industry-sponsored research projects.

Compliance with federal, state and local environmental protection laws have had no material effect on construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 of this Form 10-K.

During our fourth quarter ended October 31, 2004, we established and committed to funding the Piedmont Natural Gas Foundation. The charitable foundation was funded with $7 million in cash in November 2005.

As of October 31, 2004, we had 2,120 employees, compared with 2,155 as of October 31, 2003.

Our filings on Form 10-K, Form 10-Q and Form 8-K are available at no cost on our web site atwww.piedmontng.com on the same day the report is filed with the Securities and Exchange Commission.

PART II

Item 8. Financial Statements and Supplementary Data

Consolidated financial statements and schedules required by this item are listed in Item 15 (a) 1 and (a) 2 in Part IV of this Form 10-K on page 71.

Consolidated Balance Sheets
October 31, 2004 and 2003

Assets


In thousands	2004		2003
Utility Plant:
Utility plant in service	$	2,395,494	$	2,323,513
Less accumulated depreciation		624,973		576,823

Utility plant in service, net		1,770,521		1,746,690
Construction work in progress		79,302		65,609

Total utility plant, net		1,849,823		1,812,299


Other Physical Property, at cost (net of accumulated depreciation of $1,782 in 2004 and $1,740 in 2003)		973		1,115


Current Assets:
Cash and cash equivalents		5,676		11,172
Restricted cash		12,732		6,749
Marketable securities, at market value		1,857		—
Receivables (less allowance for doubtful accounts of $1,086 in 2004 and $2,743 in 2003)		70,987		58,662
Unbilled utility revenues		25,711		34,630
Inventories:
Gas in storage		128,465		121,723
Materials, supplies and merchandise		4,727		4,774
Income taxes receivable		11,533		24,219
Amounts due from customers		34,716		15,245
Prepayments		38,709		31,085
Other		96		15,091

Total current assets		335,209		323,350


Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities		65,322		96,191
Goodwill		48,151		50,924
Unamortized debt expense		5,261		3,748
Other		31,138		24,485

Total investments, deferred charges and other assets		149,872		175,348


Total	$	2,335,877	$	2,312,112

See notes to consolidated financial statements.

Capitalization and Liabilities


In thousands	2004			2003
Capitalization:
Stockholders’ equity:
Cumulative preferred stock – no par value – 175 shares authorized	$	—		$	—
Common stock – no par value – 100,000 shares authorized; outstanding, 76,670 in 2004 and 67,309* in 2003		563,667			372,651
Retained earnings		291,397			259,476
Accumulated other comprehensive income		(166	)		(1,932	)

Total stockholders’ equity		854,898			630,195
Long-term debt		660,000			460,000

Total capitalization		1,514,898			1,090,195


Current Liabilities:
Current maturities of long-term debt and sinking fund requirements		—			2,000
Notes payable		109,500			109,500
Commercial paper		—			445,559
Accounts payable		99,599			90,901
Income taxes accrued		306			—
Customers’ deposits		18,018			16,408
Deferred income taxes		20,687			16,949
General taxes accrued		17,097			19,594
Amounts due to customers		19,081			20,627
Other		21,879			18,257

Total current liabilities		306,167			739,795


Deferred Credits and Other Liabilities:
Deferred income taxes		202,155			189,576
Unamortized federal investment tax credits		4,492			5,042
Asset retirement obligations		266,700			245,879
Other		41,465			41,625

Total deferred credits and other liabilities		514,812			482,122


Total	$	2,335,877		$	2,312,112

*Reflects a two-for-one stock split effective October 11, 2004. See Note 5.

See notes to consolidated financial statements.

Consolidated Statements of Income
For the Years Ended October 31, 2004, 2003 and 2002


In thousands except per share amounts	2004			2003			2002
Operating Revenues	$	1,529,739		$	1,220,822		$	832,028
Cost of Gas		1,041,370			837,942			496,234


Margin		488,369			382,880			335,794


Operating Expenses:
Operations and maintenance		200,282			152,107			133,427
Depreciation		82,276			63,164			57,593
General taxes		27,011			24,410			23,863
Income taxes		51,485			40,093			30,784


Total operating expenses		361,054			279,774			245,667


Operating Income		127,315			103,106			90,127


Other Income (Expense):
Income from equity method investments		27,381			17,972			19,207
Gain on sale of equity method investments		4,683			—			—
Allowance for equity funds used during construction		946			1,128			1,986
Non-operating income		2,285			2,560			1,238
Charitable contributions		(9,124	)		(692	)		(644	)
Non-operating expense		(324	)		(171	)		(83	)
Income taxes		(10,562	)		(8,524	)		(9,010	)


Total other income (expense), net of tax		15,285			12,273			12,694


Utility Interest Charges:
Interest on long-term debt		44,957			37,740			39,056
Allowance for borrowed funds used during construction		(1,669	)		(1,135	)		(1,438	)
Other		4,076			3,592			2,986


Total utility interest charges		47,364			40,197			40,604


Income before Minority Interest in Income of Consolidated Subsidiary		95,236			75,182			62,217

Less Minority Interest in Income of Consolidated Subsidiary		48			820			—


Net Income	$	95,188		$	74,362		$	62,217


Average Shares of Common Stock:
Basic *		74,359			66,782			65,527
Diluted *		74,797			67,007			65,873

Earnings Per Share of Common Stock:
Basic *	$	1.28		$	1.11		$	.95
Diluted *	$	1.27		$	1.11		$	.94

*Reflects a two-for-one stock split effective October 11, 2004. See Note 5.

See notes to consolidated financial statements.

This page is intentionally blank.

Consolidated Statements of Cash Flows
For the Years Ended October 31, 2004, 2003 and 2002


In thousands	2004			2003			2002
Cash Flows from Operating Activities:
Net income	$	95,188		$	74,362		$	62,217

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		87,336			66,782			60,311
Amortization of investment tax credits		(550	)		(550	)		(556	)
Allowance for doubtful accounts		(1,658	)		536			(171	)
Allowance for funds used during construction		(2,615	)		(2,263	)		(3,424	)
Undistributed earnings from equity method investments		(27,381	)		(17,972	)		(19,207	)
Gain on sale of equity method investments		(4,683	)		—			—
Changes in assets and liabilities:
Restricted cash		(5,983	)		1,936			1,221
Receivables		(7,598	)		(38,600	)		(9,961	)
Inventories		(6,695	)		(34,547	)		5,140
Amounts due from customers		(19,470	)		(8,708	)		(5,699	)
Other assets		17,529			(22,472	)		3,438
Accounts payable		5,950			10,597			9,487
Amounts due to customers		(1,547	)		11,285			(12,356	)
Deferred income taxes		21,337			46,865			14,105
Other liabilities		5,133			9,401			3,407


Total adjustments		59,105			22,290			45,735


Net cash provided by operating activities		154,293			96,652			107,952


Cash Flows from Investing Activities:
Utility construction expenditures		(141,761	)		(79,035	)		(80,416	)
Reimbursements from bond fund		41,497			3,762			—
Capital contributions to equity method investments		(113	)		(2,224	)		(4,491	)
Capital distributions from equity method investments		26,291			10,188			22,143
Purchase of gas distribution systems		—			2,153			(26,000	)
Proceeds from sale of equity method investments		36,096			—			—
Purchase of NCNG and EasternNC, net in 2003 of cash received of $7,185		(271	)		(450,168	)		—
Other		1,958			172			1,165


Net cash used in investing activities		(36,303	)		(515,152	)		(87,599	)


Cash Flows from Financing Activities:
Increase in notes payable		—			63,000			14,500
Increase (decrease) in commercial paper		(445,559	)		445,559			—
Proceeds from issuance of long-term debt, net of expenses		197,981			—			—
Retirement of long-term debt		(2,000	)		(47,000	)		(2,000	)
Proceeds from sale of common stock, net of expenses		173,828			—			—
Issuance of common stock through dividend reinvestment and employee stock plans		20,018			17,925			18,546
Repurchases of common stock		(4,487	)		—			—
Dividends paid		(63,267	)		(54,912	)		(51,909	)


Net cash provided by (used in) financing activities		(123,486	)		424,572			(20,863	)


Net Increase (Decrease) in Cash and Cash Equivalents		(5,496	)		6,072			(510	)
Cash and Cash Equivalents at Beginning of Year		11,172			5,100			5,610


Cash and Cash Equivalents at End of Year	$	5,676		$	11,172		$	5,100


Cash Paid During the Year for:
Interest	$	43,868		$	40,268		$	39,696
Income taxes	$	44,396		$	30,554		$	34,166


In thousands	2004			2003
Noncash Investing and Financing Activities Related to Acquisitions of NCNG and EasternNC:
Fair value/book value of assets (liabilities) acquired	$	(2,694	)	$	511,135
Cash paid		(271	)		(457,353	)
Adjustment of estimated working capital to actual		271			2,010

Liabilities assumed	$	(2,694	)	$	55,792

See notes to consolidated financial statements.

Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2004, 2003 and 2002


							Accumulated
							Other
	Common			Retained			Comprehensive
In thousands except per share amounts	Stock			Earnings			Income			Total
Balance, October 31, 2001	$	332,038		$	229,718		$	(1,377	)	$	560,379


Comprehensive Income:
Net income					62,217						62,217
Other comprehensive income:
Unrealized loss on equity method investments hedging activities, net of tax of ($1,699)								(2,571	)
Reclassification adjustment for gain on equity method investments hedging activities included in net income, net of tax of $620								965			(1,606	)

Total comprehensive income											60,611
Common Stock Issued		20,515									20,515
Dividends Declared ($.7925 per share)*					(51,909	)					(51,909	)


Balance, October 31, 2002		352,553			240,026			(2,983	)		589,596


Comprehensive Income:
Net income					74,362						74,362
Other comprehensive income:
Unrealized loss on equity method investments hedging activities, net of tax of ($869)								(1,326	)
Reclassification adjustment for gain on equity method investments hedging activities included in net income, net of tax of $1,553								2,377			1,051

Total comprehensive income											75,413
Common Stock Issued		20,098									20,098
Dividends Declared ($.8225 per share)*					(54,912	)					(54,912	)


Balance, October 31, 2003		372,651			259,476			(1,932	)		630,195


Comprehensive Income:
Net income					95,188						95,188
Other comprehensive income:
Unrealized gain on marketable securities, net of tax of $391								597
Unrealized gain on equity method investments hedging activities, net of tax of $292								381
Reclassification adjustment for gain on equity method investments hedging activities included in net income, net of tax of $512								788			1,766

Total comprehensive income											96,954
Common Stock Issued		195,503									195,503
Common Stock Repurchased		(4,487	)								(4,487	)
Dividends Declared ($.8525 per share)*					(63,267	)					(63,267	)


Balance, October 31, 2004	$	563,667		$	291,397		$	(166	)	$	854,898


In thousands	2004			2003			2002
Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of year	$	(1,932	)	$	(2,983	)	$	(1,377	)
Current year change		978			(1,326	)		(2,571	)
Current year reclassification to net income		788			2,377			965


Balance, end of year	$	(166	)	$	(1,932	)	$	(2,983	)

*Reflects a two-for-one stock split effective October 11, 2004. See Note 5.

See notes to consolidated financial statements.

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

A. Operations and Principles of Consolidation.

Piedmont Natural Gas Company, Inc. (Piedmont), is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. Our utility operations are regulated by three state regulatory commissions. For further information on regulatory matters, see Note 3 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and its 50% equity investment in Eastern North Carolina Natural Gas Company (EasternNC). Because we manage the day-to-day operations and accounting functions, we have consolidated EasternNC since our equity interest is considered to be a controlling interest. EasternNC is a regulated utility that is engaged in the distribution of natural gas to residential, commercial and industrial customers in eastern North Carolina. For further information on EasternNC, see Note 2 to the consolidated financial statements.

Investments in non-utility activities are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the consolidated statements of income. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the consolidated statements of income. Significant inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation” (Statement 71).

B. 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. Statement 71 provides 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 Statement 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from or refund to utility customers in future periods.

We monitor the regulatory and competitive environment in which we operate to determine that our regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of these regulatory assets no longer met the criteria for continued application of Statement 71, we would write off that portion which we could not recover, net of any regulatory liabilities which would be deemed no longer necessary. Our reviews have not resulted in any write offs of any regulatory assets or liabilities.

The amounts recorded as regulatory assets and liabilities in the consolidated balance

sheets as of October 31, 2004 and 2003, are summarized as follows.


In thousands	2004		2003
Regulatory Assets:
Unamortized debt expense	$	5,261	$	3,748
Amounts due from customers		34,716		15,245
Environmental costs *		4,658		5,442
Demand-side management costs *		5,089		5,711
Deferred operations and maintenance expenses *		5,579		2,913
Deferred integration costs of acquisition *		2,042		3,064
Deferred pension and other retirement benefits costs *		5,119		3,094
Other*		2,672		2,492

Total	$	65,136	$	41,709


Regulatory Liabilities:
Asset retirement obligations	$	266,700	$	245,879
Amounts due to customers		19,081		20,627
Deferred taxes		9,542		12,601
Environmental liability due customers *		2,314		3,471

Total	$	297,637	$	282,578

* Regulatory assets are included in “Other” in “Investments, Deferred Charges and Other Assets” and regulatory liabilities are included in “Other” in “Deferred Credits and Other Liabilities” in the consolidated balance sheets.

As of October 31, 2004, we had regulatory assets totaling $5 million on which we do not earn a return during the recovery period. For such regulatory assets, amortization periods range from three to 15 years and $.1 million will be fully amortized by 2005, $2.1 million by 2006, $.1 million by 2008, $.3 million by 2010 and $2.4 million by 2018.

C. Utility Plant and Depreciation.

Utility plant is stated at original cost, including direct labor and materials, allocable overhead charges and an allowance for borrowed and equity funds used during construction (AFUDC). For the years ended October 31, 2004, 2003 and 2002, AFUDC totaled $2.6 million, $2.3 million and $3.4 million, respectively. The portion of AFUDC attributable to equity funds is included in “Other Income (Expense)” and the portion attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the consolidated statements of income. The costs of property retired are removed from utility plant and charged to accumulated depreciation.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 72 years. The composite weighted-average depreciation rates were 3.51% for 2004, 3.64% for 2003 and 3.55% for 2002.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and propose new depreciation rates for approval. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. The approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. Therefore, we accrue estimated costs of removal of long-lived assets through depreciation expense. The cost of removal component of accumulated depreciation, that is, the “non-legal” asset retirement obligations, is recorded in a regulatory liability “Asset retirement obligations” in the consolidated balance sheets. SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143), requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that asset

retirement obligations exist for our underground mains and services; however, the fair value of the obligation cannot be determined because the end of the system life is indeterminable.

D. Receivables and Allowance for Doubtful Accounts.

Receivables consist of natural gas sales and transportation services, merchandise sales, service work and other miscellaneous receivables. We maintain an allowance for doubtful accounts based on the aging of these receivables and historical and projected charge-off activity. We adjust the allowance periodically. Our estimate of recoverability could differ from actual based on customer credit issues, the level of natural gas prices and general economic conditions. Merchandise receivables that will be collected beyond one year are recorded in “Other” in “Investments, Deferred Charges and Other Assets” in the consolidated balance sheets.

E. Goodwill, Equity Method Investments and Long-Lived Assets.

All of our goodwill is attributable to the regulated utility segment. We evaluate goodwill for impairment annually, or more frequently if impairment indicators arise, using a weighted average of the guideline company method of the market approach and the discounted cash flow method of the income approach on the premise of continued use, which assumes that a buyer and seller contemplate the continued use of the reporting unit at its present location as part of current and future operations. The guideline company method of the market approach is based on market multiples of companies that are representative of our peers in the natural gas distribution industry. The discounted cash flow method of the income approach consists of estimating annual future cash flows and individually discounting them back to the present value. These calculations are dependent on several subjective factors, including the timing of future cash flows, future growth rates and the discount rate. The calculations also define the reporting unit as the domestic natural gas distribution business. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. Through October 31, 2004, no impairment has been recognized.

Changes in goodwill for the years ended October 31, 2003 and 2004, are summarized as follows. For further information on acquisitions, see Note 2 to the consolidated financial statements.


In thousands
Balance as of October 31, 2002			$	7,109
Acquisition adjustment for North Carolina Gas Service (NCGS)				(2	)
Acquisition of North Carolina Natural Gas Corporation (NCNG)				42,150
Acquisition of EasternNC				1,139
Minority interest in EasternNC:
At acquisition				1,348
Income for the year				(820	)

Balance as of October 31, 2003				50,924
Purchase price allocation adjustments for NCNG:
Deferred income taxes from book and tax basis differences of the purchase price	(5,000	)
Unrecorded liabilities and true-up of working capital	2,275			(2,725	)

Minority interest income in EasternNC for the year				(48	)

Balance as of October 31, 2004			$	48,151

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. There were no events or circumstances during 2003 and 2004 that would have resulted in any impairment charges; however, we did write down our investment in propane

marketing activities by $1.4 million during 2002 due to an other than temporary decline in the value based on our calculation of estimated future cash flow projections. For further information on equity method investments, see Note 10 to the consolidated financial statements.

F. Unamortized Debt Expense.

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accounting fees, registration fees and rating agency fees, related to issuing long-term debt. We amortize debt expense over the life of the related debt on a straight-line basis. Our debt has varying lives ranging from 10 to 30 years.

G. Inventories.

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable as a base rate component under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

Materials and supplies and merchandise inventories are valued at the lower of average cost or market and are removed from such inventory at average cost.

H. Deferred Purchased Gas Adjustments.

Rate schedules for utility sales and transportation customers include purchased gas adjustment (PGA) provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the cost of gas. Under PGA provisions, charges to cost of gas are based on the gas cost amounts recoverable under approved rate schedules. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. We review gas costs and deferral activity periodically and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

I. Taxes.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax bases of assets and liabilities given the provisions of the enacted tax laws. Deferred taxes are primarily attributable to accelerated tax depreciation, equity method investments, compensation and employee benefits, environmental costs and the timing of the recording of revenues and cost of gas. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to the amount that is more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred pursuant to Statement 71, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders. We amortize deferred investment tax credits to income over the estimated useful lives of the property to which the credits relate.

General taxes consist primarily of property taxes, payroll taxes and franchise taxes. Also included to a lesser degree are gross receipts taxes, excise tax on natural gas used by us and a state regulatory fee. Such taxes are not included in revenues and expenses.

J. Revenue Recognition.

Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. A weather normalization adjustment (WNA) factor is included in rates charged to residential and commercial customers during the winter period November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact that unusually cold or warm weather has on customer billings during the winter season.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, changes in weather during the period and the impact of the WNA.

In January 2003, we performed an analysis of our revenue recognition practices and began recording revenues and cost of gas related to volumes delivered but not yet billed. Recording unbilled revenues changed the timing of revenue recognition from the cycle-billing method to the accrual method which is based on when the service is provided. The effect of the change was to increase net income $5.8 million and earnings per share by $.09 for the year ended October 31, 2003. Prior to 2003, we recognized revenues from meters read on a monthly cycle basis and deferred the cost of gas for volumes delivered but not yet billed.

Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on the contracted or market prices.

K. 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 years ended October 31, 2004, 2003 and 2002, is presented below.


In thousands except per share amounts	2004		2003		2002
Net Income	$	95,188	$	74,362	$	62,217


Average shares of Common Stock outstanding for basic earnings per share *		74,359		66,782		65,527
Contingently issuable shares under the Executive Long-Term Incentive Plan *		438		225		346

Average shares of dilutive stock		74,797		67,007		65,873


Earnings Per Share:
Basic *	$	1.28	$	1.11	$	.95
Diluted *	$	1.27	$	1.11	$	.94

* Reflects a two-for-one stock split effective October 11, 2004. See Note 5 to the consolidated financial statements.

L. Statement of Cash Flows.

For purposes of reporting cash flows, we consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents.

M. Use of Estimates.

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.

N. Reclassifications.

We have reclassified certain financial statement items for 2003 and 2002 to conform with the 2004 presentation.

2. Acquisitions

Effective September 30, 2002, we purchased for $26 million in cash substantially all of the natural gas distribution assets and certain of the liabilities of NCGS, a division of NUI Utilities, Inc. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina.

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of NCNG from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million for estimated working capital. We paid an additional $.3 million for actual working capital in our second quarter ended April 30, 2004. NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing.

We also purchased for $7.5 million in cash Progress’ equity interest in EasternNC. EasternNC is a regulated utility that has a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. We are obligated to purchase additional authorized but unissued shares of such preferred stock for $14.4 million.

We recorded the assets purchased at fair value, except for utility plant, franchises and consents and miscellaneous intangible property that were recorded at book value in accordance with Statement 71. We recorded estimated goodwill at closing of $42.2 million for NCNG and $1.1 million for EasternNC. We finalized the purchase price allocation during our third quarter ended July 31, 2004, resulting in a decrease of $2.7 million attributable to NCNG. This adjustment was primarily due to recording $5 million in deferred income taxes from book and tax basis differences of the purchase price, partially offset by unrecorded liabilities and the true up of estimated working capital to actual. The goodwill attributable to EasternNC was not adjusted. We believe that approximately $39 million of the goodwill will be deductible for tax purposes.

The following table summarizes the final purchase price allocation of assets acquired and liabilities assumed in the acquisitions.


In thousands	NCNG			EasternNC			Total
Utility plant, net	$	381,628		$	8,952		$	390,580
Equity method investments in non-utility activities		5,450			—			5,450
Current assets		57,745			7,723			65,468
Goodwill		39,426			1,139			40,565
Minority interest		—			1,348			1,348
Non-current assets		5,030			—			5,030

Total assets acquired		489,279			19,162			508,441
Current liabilities		(34,124	)		(11,646	)		(45,770	)
Non-current liabilities		(7,312	)		(16	)		(7,328	)

Net assets acquired	$	447,843		$	7,500		$	455,343

Our consolidated results of operations for 2003 include the operations of NCNG and EasternNC since September 30, 2003. The following information for the year ended October 31, 2003, is provided on an unaudited pro forma basis, assuming the acquisitions and the related permanent financing had occurred as of November 1, 2002:


In thousands, except per share amounts
Operating revenues	$	1,581,849
Income from continuing operations		76,808
Net income		76,808
Basic earnings per share	$	1.01	*

* Reflects a two-for-one stock split effective October 11, 2004. See Note 5 to the consolidated financial statements.

This unaudited pro forma information is not necessarily indicative of the results of operations had the acquisitions actually occurred at the beginning of our fiscal year 2003, nor is it indicative of future results.

3. Regulatory Matters

In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of the state. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. In accordance with an NCUC order in 2002, we no longer deposit refunds in the expansion fund for our pre-NCNG acquisition operations; however, we continue to deposit refunds attributable to NCNG operations in the expansion fund. As of October 31, 2004, the balance of $12.7 million in our expansion fund held by the state is included in “Restricted cash” with an offsetting liability included in “Amounts due to customers” in the consolidated balance sheets.

The PSCSC has approved a gas cost hedging plan that we implemented for the purpose of cost stabilization for customers. The plan is limited to 60% of our annual normalized sales

volumes for South Carolina and operates off of historical pricing indices that are tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan, except for certain personnel and administrative costs that are recovered in rates as operations and maintenance expenses, are deemed to be prudently incurred and are recovered in rates as a gas cost.

We have implemented a similar hedging plan in North Carolina. The plan is limited to 60% of the annual normalized sales volumes for North Carolina and operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange. Costs associated with the hedging plan are not pre-approved by the NCUC. Such costs are treated as gas costs subject to the annual gas cost prudence review based on information available at the time of the hedge, not at the time of the prudence review. Through October 31, 2004, we have recovered 100% of gas costs subject to prudence review.

Effective November 1, 2003, the NCUC issued an order approving an increase in NCNG’s regulatory margin of $29.4 million annually. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

Effective November 1, 2003, the TRA approved an increase in revenues of $10.3 million annually. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

In March 2003, we, along with two other natural gas companies in Tennessee, filed a petition with the TRA requesting a declaratory order that the gas cost portion of uncollectible accounts is recoverable through PGA procedures. The petition stated that to the extent that the gas cost portion of net write-offs for a fiscal year exceeds the gas cost portion of uncollectible accounts allowed in base rates, the unrecovered portion would be included in Actual Cost Adjustment (ACA) filings for future recovery from customers. Conversely, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings. On February 9, 2004, the TRA approved the petition by modifying the formula in the PGA rules to allow for the recovery of uncollected gas costs. These rules were implemented effective March 10.

In 1998, the North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of the state. In 2000, the NCUC issued an order awarding EasternNC an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting uneconomic feasibility of providing service. The order also granted $38.7 million in state bond funding for phase 1 of the project. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million to construct phases 2 through 7.

During fiscal 2004, we filed $42.4 million for reimbursement from the bond fund and received $41.5 million. As of October 31, 2004, there was $30.5 million remaining of the bond funds allocated to EasternNC. We establish a state bond receivable when we determine that construction costs are reimbursable by the state. As of October 31, 2004 and 2003, we had receivables of $3.5 million and $2.6 million, respectively, related to the bond fund recorded in “Receivables” in the consolidated balance sheets.

The NCUC has allowed EasternNC to defer its operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurs first, with a maximum deferral of $15 million. The deferred amounts accrue interest at a rate of 8.69% per annum. On December 1, 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. As of October 31, 2004 and 2003, deferred operations and maintenance expenses of $5.6 million and $2.9 million, respectively, including accrued interest, were deferred as a regulatory asset in the consolidated balance sheets.

On October 22, 2004, we filed a petition with the NCUC seeking deferred accounting treatment for certain pipeline integrity management costs to be incurred by us in compliance with the Pipeline Safety Improvement Act of 1992 and recently issued regulations of the United States Department of Transportation. On November 29, the NCUC approved deferral treatment of these costs applicable to all incremental expenditures beginning November 1, 2004.

4. Long-Term Debt

All of our long-term debt is unsecured. Long-term debt as of October 31, 2004 and 2003, is summarized as follows.


In thousands	2004		2003
Senior Notes:
10.06%, due 2004	$	—	$	2,000
9.44%, due 2006		35,000		35,000
8.51%, due 2017		35,000		35,000
Medium-Term Notes:
7.35%, due 2009		30,000		30,000
7.80%, due 2010		60,000		60,000
6.55%, due 2011		60,000		60,000
5.00%, due 2013		100,000		—
6.87%, due 2023		45,000		45,000
8.45%, due 2024		40,000		40,000
7.40%, due 2025		55,000		55,000
7.50%, due 2026		40,000		40,000
7.95%, due 2029		60,000		60,000
6.00%, due 2033		100,000		—

Total		660,000		462,000
Less current maturities		—		2,000

Total	$	660,000	$	460,000

Annual sinking fund requirements and maturities for the next five years ending October 31 and thereafter are summarized as follows.


In thousands
2005	$	—
2006		35,000
2007		—
2008		—
2009		30,000
Thereafter		595,000

Total	$	660,000

On December 19, 2003, we sold $100 million of 5% and $100 million of 6% medium-

term notes under a shelf registration statement filed with the Securities and Exchange Commission (SEC). The net proceeds were used to repay a portion of our outstanding commercial paper which had been issued to fund the acquisitions of NCNG and the equity interest in EasternNC. The 5% note due 2013 and the 6% note due 2033 are each to be redeemed in a single payment at maturity.

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, 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 October 31, 2004, net earnings available for restricted payments were $561.1 million. Retained earnings as of this date were $291.4 million; therefore, none of our retained earnings were restricted.

We are subject to default provisions related to our long-term debt. The default provisions of our senior notes are:

•	Failure to make principal, interest or sinking fund payments,

•	Interest coverage of 1.75 times,

•	Total debt cannot exceed 70% of total capitalization,

•	Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total company capitalization,

•	Failure to make payments on any capitalized lease obligation,

•	Bankruptcy, liquidation or insolvency, and

•	Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal.

	The default provisions of our medium-term notes are:

•	Failure to make principal, interest or sinking fund payments,

•	Failure after the receipt of a 90-day notice to observe or perform for any covenant or agreement in the notes or in the indenture under which the notes were issued, and

•	Bankruptcy, liquidation or insolvency.

Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of October 31, 2004, we are in compliance with all default provisions.

5. Capital Stock

Changes in Common Stock for the years ended October 31, 2002, 2003 and 2004, shares reflect the two-for-one stock split effective October 11, 2004, are summarized as follows.


In thousands	Shares			Amount
Balance, October 31, 2001		64,926		$	332,038
Issued to participants in the Employee Stock Purchase Plan (ESPP)		32			507
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		1,093			18,039
Issued to participants in the Executive Long-Term Incentive Plan (LTIP)		129			1,969

Balance, October 31, 2002		66,180			352,553
Issued to ESPP		33			550
Issued to DRIP		968			17,375
Issued to LTIP		128			2,173

Balance, October 31, 2003		67,309			372,651
Issued to ESPP		45			853
Issued to DRIP		940			19,164
Issued to LTIP		79			1,658
Sale of common stock, net of expenses		8,500			173,828
Shares repurchased		(203	)		(4,487	)

Balance, October 31, 2004		76,670		$	563,667

On January 23, 2004, we sold 8.5 million shares of Common Stock at a public offering price of $21.25 per share (4.3 million shares at $42.50 on a pre-split basis) under a shelf registration statement filed with the SEC. The net proceeds were used to repay a portion of our outstanding commercial paper which had been issued to fund the acquisitions of NCNG and the equity interest in EasternNC.

On June 4, 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorizes the repurchase of up to three million shares of currently outstanding shares of Common Stock. We utilize a broker to repurchase the shares on the open market and such shares are then cancelled and become authorized but unissued shares available for issuance under ESPP, DRIP and LTIP. We implemented the program on September 1, 2004.

On August 27, 2004, the Board of Directors declared a two-for-one stock split of Common Stock in the form of a 100% stock dividend to shareholders of record at the close of business on October 11, 2004. The additional shares were distributed on October 29. The stock split did not change the proportionate interest of a shareholder. References to the number of common shares and per common share amounts in the consolidated financial statements and notes have been restated to give retroactive effect to the stock split for all periods presented.

As of October 31, 2004, 4.8 million shares of Common Stock were reserved for issuance as follows.


In thousands
ESPP			220
DRIP			3,238
LTIP			1,299

Total			4,757

6. Financial Instruments and Related Fair Value

Various banks provide lines of credit totaling $200 million on a fee basis to finance current cash requirements. We have additional uncommitted lines of credit totaling $103 million

on a no fee and as needed, if available, basis. Short-term borrowings under the lines, with maturity dates of less than 90 days, include LIBOR cost-plus loans, transactional borrowings and overnight cost-plus loans based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. As of October 31, 2004, outstanding borrowings under the lines of credit are included in “Notes payable” in the consolidated balance sheets and consisted of $109.5 million in LIBOR cost-plus loans at a weighted average interest rate of 2.18%.

In addition to these bank lines of credit, we had a commercial paper program where we could issue up to $450 million in unsecured promissory notes that were backed by a $450 million credit agreement scheduled to expire June 22, 2004. This program was put in place to provide for the temporary financing of our acquisitions of NCNG and the equity interest in EasternNC. The notes issued under this program on September 29, 2003, were sold at a discount from face values at LIBOR cost-plus rates with maturities ranging from one to 30 days. On December 19, 2003, we sold $200 million of long-term debt in the form of 10- and 30-year medium-term notes. The net proceeds were used to repay a portion of our outstanding commercial paper. On January 23, 2004, we sold 8.5 million shares of Common Stock at a public offering price of $21.25 per share (4.3 million shares at $42.50 on a pre-split basis). The proceeds, net of underwriting discount, were used to repay a portion of our outstanding commercial paper. On January 22, 2004, we repaid the balance of the outstanding commercial paper from internally generated cash, and the program was terminated.

Our principal business activity is the distribution of natural gas. As of October 31, 2004, gas receivables were $61.6 million and other current receivables were $9.4 million, net of an allowance for doubtful accounts of $1.1 million. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected.

In connection with the sale in January 2004 of our propane interests, we received 37,244 common units of Energy Transfer Partners, LP. The market value of these units as of October 31, 2004, is reported in “Marketable securities” in the consolidated balance sheets as we may sell them at any time. For further information on this transaction, see Note 10 to the consolidated financial statements.

The carrying amounts in the consolidated balance sheets of cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values due to the short-term nature of these financial instruments. Based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings, the estimated fair value amounts of long-term debt as of October 31, 2004 and 2003, including current portion, were as follows.


	2004				2003
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	660,000	$	775,269	$	462,000	$	506,882

The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair value amounts. The fair value amounts do not reflect principal amounts that we will ultimately be required to pay.

We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service area where the customer is

located. We recover the cost of gas purchased for regulated operations through purchased gas cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

During the year ended October 31, 2004, we purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of October 31, 2004, we had no open forward positions. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing transportation and capacity in the secondary market and margin from secondary market sales of gas, are subject to an overall annual cap of $1.6 million for shareholder gains or losses. The net gains or losses on gas costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders, subject to the annual cap. The net overall annual performance results are collected from or refunded to customers, subject to the cap.

During the year ended October 31, 2004, we purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of October 31, 2004, we had forward positions for December 2004 through March 2005. The costs of these options are pre-approved by the PSCSC for recovery from customers subject to our following the provisions of the gas cost hedging plan. The hedging program uses a matrix of historic, inflation-adjusted gas prices over the past four years plus the current season, with a heavier weighting on current data, as the basis for determining the purchase of financial instruments. The hedging portfolio is diversified over a rolling 24 months with a short-term focus (one to 12 months) and a long-term focus (13 to 24 months). Hedges are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis.

During the year ended October 31, 2004, we purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of October 31, 2004, we had forward positions for December 2004 through March 2005. The gas cost hedging plan in North Carolina operates like the plan in South Carolina except that the costs of the plan are not pre-approved by the NCUC.

There is no income statement impact from the North Carolina and South Carolina hedging plans as all costs and related gain or loss amounts are passed through to customers under PGA procedures and are recorded in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. We mark the derivative instruments to market with corresponding entries to these accounts. As of October 31, 2004 and 2003, receivables from customers of $5.4 million and $6.3 million, respectively, for the costs of the North Carolina and South Carolina hedging plans and the related mark-to-market adjustments were included in “Amounts due to customers” or “Amounts due from customers.”

7. Leases and Unconditional Purchase Obligations

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

operating leases. For the years ended October 31, 2004, 2003 and 2002, operating lease payments were $5.7 million, $4.5 million and $4.5 million, respectively.

We are in the process of selling our corporate office building located in Charlotte, North Carolina. We have negotiated a preliminary ten-year lease with renewable options for space in a building that is currently under construction and anticipated to be ready for occupancy in late 2005. The lease payments for the ten-year term are estimated to range from $3 million to $3.4 million annually. These amounts have not been included in the table below pending the negotiation of the final lease and the completion of the building. We expect to lease back our current office building prior to occupancy of the new office space.

Future minimum lease obligations for leases in effect as of October 31, 2004, for the next five years ending October 31 and thereafter are as follows.


In thousands
2005	$	5,017
2006		3,923
2007		2,764
2008		1,729
2009		1,143
Thereafter		5,372

Total minimum lease obligations	$	19,948

In conducting our normal operations, we routinely enter into long-term commodity purchase commitments, as well as agreements that commit future cash flows to acquire services we need in our business. These commitments are for pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations with which to conduct our operations. The pipeline and storage capacity contract periods range from current to 2020. The gas supply contract periods are of shorter duration up to three years. The periods for the telecommunications and technology contracts providing maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, cell usage fees and contract labor and consulting fees range from current to 2009. Other purchase obligations consist of commitments for pipeline products, vehicles, contractors and merchandise due within one year.

The following table provides a summary of future unconditional purchase obligations as of October 31, 2004.


					Telecommunications
	Pipeline and				and Information
In thousands	Storage Capacity		Gas Supply		Technology		Other		Total
2005	$	119,905	$	22,825	$	14,174	$	17,196	$	174,100
2006		116,987		7,084		15,183		—		139,254
2007		110,480		—		15,487		—		125,967
2008		106,744		—		15,797		—		122,541
2009		106,515		—		16,113		—		122,628
Thereafter		495,675		—		—		—		495,675

Total	$	1,056,306	$	29,909	$	76,754	$	17,196	$	1,180,165

8. Employee Benefit Plans

We have a defined-benefit pension plan for the benefit of eligible full-time employees. An employee becomes eligible on the January 1 or July 1 following either the date on which he or she attains age 30 or attains age 21 and completes 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. We amend the plan from time to time in accordance with changes in tax law.

We provide certain postretirement health care and life insurance benefits to eligible full-time employees. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Those meeting this requirement or who retired prior to November 1, 1993, are in a “grandfathered” group for whom we pay the full cost of the retiree coverage and the retiree pays the full cost of dependent coverage. Employees not in the grandfathered group have 80% of the cost of retiree coverage paid by us, subject to certain annual contribution limits. The retiree pays 20% of the cost of his or her coverage plus the full cost of dependent coverage. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits.

In connection with the acquisition of NCNG discussed in Note 2 to the consolidated financial statements, we acquired pension and other postretirement benefit obligations (OPEB) related to former employees of NCNG. Cash of $34 million attributable to the accrued pension benefits as of September 30, 2003, for this group was transferred from Progress in February 2004 and is currently maintained and administered in a separate “frozen” plan. An additional $.2 million was transferred to this plan on November 19, 2004, as a result of updated employee information. The transferred active pension plan participants began accruing benefits under the Piedmont pension plan as of October 1, 2003. The OPEB obligation of $9.7 million as of September 30, 2003, for former employees of NCNG was recorded as a liability at closing. No assets attributable to this liability were transferred from Progress.

Effective August 1, 2004, we adopted Financial Accounting Standards Board Staff Position (FSP) No. 106-2 “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This FSP provides guidance on the accounting for the effects of the act for employers that sponsor postretirement health care plans that provide prescription drug benefits, and requires employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act. The adoption of the FSP reduced our expense for postretirement benefits for the year ended October 31, 2004, by an insignificant amount.

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2004 and 2003, and a statement of the funded status as recorded in the consolidated balance sheets as of October 31, 2004 and 2003, are presented below.


	2004			2003			2004			2003
In thousands	Pension Benefits						Other Benefits
Change in benefit obligation:
Obligation at beginning of year	$	199,732		$	149,693		$	43,680		$	25,632
Obligation of NCNG at date of acquisition		—			—			—			9,718
Service cost		9,698			6,060			1,338			808
Interest cost		12,084			10,114			2,547			2,128
Plan amendments		—			—			1,517			5,894
Actuarial (gain) loss		16,888			7,544			(8,194	)		1,844
Benefit payments		(12,087	)		(8,160	)		(2,014	)		(2,344	)
Recognized liabilities of the NCNG plan		—			34,481			—			—

Obligation at end of year	$	226,315		$	199,732		$	38,874		$	43,680


Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	163,831		$	125,056		$	12,439		$	11,311
Actual return on plan assets		15,668			11,765			527			379
Employer contributions		14,232			979			3,152			2,590
Administrative expenses		(400	)		(290	)		—			—
Recognized assets of the NCNG plan		—			34,481			—			—
Benefit payments		(12,087	)		(8,160	)		(2,073	)		(1,841	)

Fair value of plan assets at end of year	$	181,244		$	163,831		$	14,045		$	12,439


Funded status:
Funded status at end of year	$	(45,071	)	$	(35,901	)	$	(24,830	)	$	(31,241	)
Unrecognized transition obligation		—			—			7,912			8,791
Unrecognized prior-service cost		6,229			7,160			5,522			5,035
Unrecognized actuarial gain (loss)		38,694			20,853			(1,803	)		6,275

Accrued benefit liability	$	(148	)	$	(7,888	)	$	(13,199	)	$	(11,140	)

Net periodic benefit cost for the years ended October 31, 2004, 2003 and 2002, includes the following components.


	2004			2003			2002			2004			2003			2002
In thousands	Pension Benefits									Other Benefits
Service cost	$	9,698		$	6,060		$	5,456		$	1,338		$	808		$	542
Interest cost		12,084			10,114			9,729			2,547			2,128			1,696
Actual return on plan assets		(15,668	)		(11,765	)		3,979			(527	)		(379	)		(89	)
Deferred asset loss		(552	)		(1,610	)		(18,955	)		(395	)		(438	)		(824	)
Amortization of transition obligation		—			14			14			879			879			879
Amortization of prior-service cost		931			931			903			1,030			859			—
Amortization of actuarial (gain) loss		—			(840	)		(872	)		280			198			46

Net periodic benefit cost	$	6,493		$	2,904		$	254		$	5,152		$	4,055		$	2,250

In determining the market-related value of plan assets, we use the following methodology. Each year, the asset gain or loss is determined by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Each year’s asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of the balance sheet date is determined by adjusting the market

value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized. This method has been applied consistently in all years presented. The discount rate can vary from plan year to plan year. October 31 is the measurement date for the plans. The discount rate is determined by developing a hypothetical bond portfolio matching our projected benefit cost with our projected benefit obligations. As of October 31, 2004, the benchmark was 5.69%.

We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period of active employees. The method of amortization in all cases is straight-line.

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2004, 2003 and 2002, are presented below.


	2004			2003			2002			2004			2003			2002
	Pension Benefits									Other Benefits
Discount rate		5.75	%		6.25	%		7.00	%		5.75	%		6.25	%		7.00	%
Expected long-term rate of return on plan assets		8.50	%		8.50	%		9.50	%		8.50	%		8.50	%		9.50	%
Rate of compensation increase		3.97	%		3.97	%		3.97	%		3.97	%		3.97	%		3.97	%

The weighted-average asset allocations by asset category for the two pension plans as of October 31, 2004 and 2003, are presented below.


	2004			2003
Equity securities		62	%		68	%
Debt securities		38	%		32	%

Total		100	%		100	%

In our fourth quarter ended October 31, 2004, we began the process of migrating pension plan assets towards long-term target allocations by asset category of 60% for equity securities and 40% for debt securities. Our primary investment objective is to generate sufficient assets to meet plan liabilities. The plans’ assets will therefore be invested to maximize long-term returns consistent with the plans’ liabilities, cash flow requirements and risk tolerance. The plans’ liabilities are primarily defined in terms of participant salaries. Given the nature of these liabilities, and recognizing the long-term benefits of investing in stocks, we invest in a diversified portfolio which includes a significant exposure to stocks. Specific financial targets include:

	•	Achieve full funding over the longer term,

	•	Control fluctuation in pension expense from year to year,

	•	Achieve satisfactory performance relative to other similar pension plans, and

	•	Achieve positive returns in excess of inflation over short to intermediate time frames.

To develop the expected long-term rate of return on assets assumption, we considered historical returns and future expectations for returns for each asset class, as well as target asset allocation of the pension portfolio. This resulted in the selection of the 8.5% expected long-term

rate of return on plan assets assumption for 2004.

We expect to contribute $11 million to the pension plan and $3 million to the other postretirement benefits plan in 2005. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 became law. The act introduced a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare (Part D).

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid as follows.


	Pension		Other
In thousands	Benefits		Benefits
2005	$	7,696	$	2,919
2006		9,197		3,084
2007		10,676		2,822
2008		12,545		2,836
2009		14,591		2,984
2010-2014		101,701		16,673

The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation for the medical plans for all participants is 10.5% for 2004, declining gradually to 5% in 2012 and remaining at that level thereafter. In the past, information for participants aged less than 65 and those aged greater than 65 was maintained separately for calculating the heath care cost trend rate; however, actual experience and trend guidelines were indicating that post-age 65 medical trends were lower than pre-65 medical trends and prescription drug trends for both groups were at about the same level. Since post-age 65 participants have more prescription claims as a group, the trends are nearly equal. The change in trend rates did not have a material effect on the accumulated postretirement benefit obligation.

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.


In thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2004	$	143	$	(126	)

Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2004		1,376		(1,461	)

We maintain salary investment plans which are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). Employees who have completed six months of service are eligible to participate. Participants may defer a portion of their base salary to the plans and we match a portion of their contributions. All contributions vest immediately. For the years ended October 31, 2004, 2003 and 2002, our matching contributions totaled $2.9 million, $2.3 million and $2.2 million, respectively. There are several investment options available to enable participants to diversify their accounts. Participants may invest in Piedmont stock up to a maximum of 20% of their account.

9. Income Taxes

The components of income tax expense for the years ended October 31, 2004, 2003 and 2002, are as follows.


	2004						2003						2002
In thousands	Federal			State			Federal			State			Federal			State
Income taxes charged to operating income:
Current	$	22,343		$	8,862		$	(4,581	)	$	(959	)	$	15,482		$	4,410
Deferred		20,951			(121	)		38,252			7,931			10,711			737
Amortization of investment tax credits		(550	)		—			(550	)		—			(556	)		—

Total		42,744			8,741			33,121			6,972			25,637			5,147

Income taxes charged to other income (expense):
Current		11,293			2,236			7,685			1,561			5,424			952
Deferred		(2,582	)		(385	)		(623	)		(99	)		2,174			460

Total		8,711			1,851			7,062			1,462			7,598			1,412

Total income tax expense	$	51,455		$	10,592		$	40,183		$	8,434		$	33,235		$	6,559

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2004, 2003 and 2002, is as follows.


In thousands	2004			2003			2002
Federal taxes at 35%	$	55,032		$	43,043		$	35,704
State income taxes, net of federal benefit		6,885			5,482			4,263
Amortization of investment tax credits		(550	)		(550	)		(556	)
Other, net		680			642			383

Total income tax expense	$	62,047		$	48,617		$	39,794

As of October 31, 2004 and 2003, deferred income taxes consisted of the following temporary differences.


In thousands	2004			2003
Utility plant	$	197,392		$	171,896
Equity method investments		13,847			16,690
Revenues and cost of gas		22,597			23,432
Other, net		(10,994	)		(5,493	)

Net deferred income tax liabilities	$	222,842		$	206,525

As of October 31, 2004 and 2003, total deferred income tax liabilities were $241.5 million and $218.5 million and total net deferred income tax assets were $18.7 million and $12 million, respectively. Total net deferred income tax assets as of October 31, 2004 and 2003, are net of a valuation allowance of $1.2 million and $1 million, respectively, for net operating loss carryforwards that we believe are more likely than not to expire before we can use them. Piedmont and its wholly owned subsidiaries file a consolidated federal income tax return. EasternNC files a separate federal income tax return as we do not own the prerequisite 80% share of EasternNC to allow EasternNC to participate in our consolidated federal return. As of October 31, 2004, EasternNC had federal and state net operating loss carryforwards of $4.8 million that expire from 2017 through 2024.

During the year ended October 31, 2004, the Internal Revenue Service finalized its audit of our returns for the tax year ended October 31, 2001. The audit results, which did not have a material effect on our financial position or results of operations, have been reflected in the financial statements.

10. 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 recorded in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the consolidated statements of income.

As of October 31, 2004, the amount of our retained earnings that represents undistributed earnings of 50% or less owned equity method investments was $24.1 million.

Cardinal Pipeline Company, L.L.C.

We own 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, our portion of which is approximately 37%. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.

We have related party transactions with Cardinal as a transportation customer and we record in cost of gas the transportation costs charged by Cardinal. For the years ended October 31, 2004, 2003 and 2002, these gas costs were $4.7 million, $1.7 million and $1.5 million, respectively. As of October 31, 2004 and 2003, we owed Cardinal $.4 million.

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal as of and for the twelve months ended September 30, 2004, 2003 and 2002, is presented below.


In thousands	2004		2003		2002
Current assets	$	8,142	$	9,218	$	11,339
Non-current assets		91,049		93,333		95,256
Current liabilities		3,612		4,054		5,416
Non-current liabilities		39,360		41,280		43,200
Revenues		15,567		16,880		17,124
Gross profit		15,567		16,880		17,124
Income before income taxes		8,102		9,211		9,401

Pine Needle LNG Company, L.L.C.

We own 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc., SCANA Corporation and

Amerada Hess Corporation. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Pine Needle has firm service agreements for 100% of the storage capacity of the facility, our portion of which is approximately 64%. Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive income” in the consolidated balance sheets. Pine Needle’s long-term debt is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.

We have related party transactions with Pine Needle as a customer and we record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2004, 2003 and 2002, these gas costs were $12.3 million, $10.6 million and $10.9 million, respectively. As of October 31, 2004 and 2003, we owed Pine Needle $1 million.

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle as of and for the twelve months ended September 30, 2004, 2003 and 2002, is presented below.


In thousands	2004		2003		2002
Current assets	$	10,573	$	11,931	$	12,662
Non-current assets		94,745		97,425		98,309
Current liabilities		8,161		9,088		6,495
Non-current liabilities		45,933		50,759		55,856
Revenues		19,357		20,013		20,253
Gross profit		19,357		20,013		20,253
Income before income taxes		9,372		9,320		10,357

US Propane, L.P.

Prior to January 20, 2004, we owned 20.69% of the membership interests in US Propane, L.P. The other members were subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. On January 20, we, along with the other members, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane for $130 million. Our share of the proceeds was $26.9 million. We recorded a gain on the sale of our interest in Heritage Propane of $4.7 million. In connection with the sale, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units. The market value of these units as of October 31, 2004, is reported in “Marketable securities” in the consolidated balance sheets as we may sell the units at any time. Any unrealized gains and losses are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets.

SouthStar Energy Services LLC

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. The other member is AGL Resources, Inc. (AGLR). SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

On March 29, 2004, we executed an amended and restated limited liability company (LLC) agreement with AGLR. This new agreement eliminated the disproportionate sharing provision in the original LLC agreement and allocated earnings and losses beginning in January 2004 at 25% to us and 75% to AGLR. In addition, we agreed to a management services agreement which provided that AGLR would provide and administer certain accounting, treasury, internal audit, human resources and information technology functions on behalf of SouthStar. In connection with the elimination of the disproportionate sharing provision, we recorded in our first quarter ended January 31, 2004, an increase in pre-tax earnings of $2.5 million.

SouthStar utilizes financial contracts to hedge the variable cash flows associated with changes in the price of natural gas. These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. SouthStar does not enter into or hold derivatives for trading or speculative purposes. SouthStar also enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. Movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive income” in the consolidated balance sheets.

Prior to August 25, 2004, Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s fees for local delivery service. We guaranteed our 30% share of SouthStar’s obligation with a letter of credit with a bank in the amount of $18.1 million. On August 25, AGLC notified us that they no longer needed this guarantee and we cancelled the letter of credit.

We have related party transactions with SouthStar which purchases wholesale gas supplies from us. For the years ended October 31, 2004, 2003 and 2002, such operating revenues totaled $2.7 million, $.9 million and $10.7 million, respectively. As of October 31, 2004, SouthStar owed us $.6 million.

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar as of and for the twelve months ended September 30, 2004, 2003 and 2002, is presented below.


In thousands	2004		2003		2002
Current assets	$	157,655	$	168,302	$	134,113
Non-current assets		4,067		1,099		1,228
Current liabilities		50,045		48,568		61,990
Non-current liabilities		—		—		—
Revenues		790,288		727,871		606,191
Gross profit		122,811		99,618		124,315
Income before income taxes		72,056		55,805		54,308

Greenbrier Pipeline Company, LLC

As of October 31, 2003, we owned 33% of the membership interests in Greenbrier Pipeline Company, LLC (Greenbrier). The other member was a subsidiary of Dominion Resources, Inc. Greenbrier was formed to build a proposed interstate gas pipeline from West Virginia to North Carolina. On November 6, 2003, we sold our interest in Greenbrier to Dominion Resources for our book value of $9.2 million. Revenues and expenses of Greenbrier

for all periods presented were immaterial.

11. 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 and by EasternNC. 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 “Other Income (Expense)” 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 and the return on our investment in the ventures. All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Operations by segment for the years ended October 31, 2004, 2003 and 2002, are presented below.


	Regulated		Non-Utility
In thousands	Utility		Activities			Total
2004
Revenues from external customers	$	1,529,739	$	—		$	1,529,739
Margin		488,369		—			488,369
Operations and maintenance expenses		200,282		172			200,454
Depreciation		82,276		—			82,276
Operating income (loss)		178,800		(234	)		178,566
Income before income taxes and minority interest		125,044		32,239			157,283
Total assets		2,268,824		67,179			2,336,003
Income from equity method investments		—		27,381			27,381
Equity method investments in non-utility activities		—		65,322			65,322
Construction expenditures		141,837		—			141,837

2003
Revenues from external customers	$	1,220,822	$	—		$	1,220,822
Margin		382,880		—			382,880
Operations and maintenance expenses		152,107		73			152,180
Depreciation		63,164		—			63,164
Operating income (loss)		143,199		(132	)		143,067
Income before income taxes and minority interest		106,150		17,649			123,799
Total assets		2,230,272		112,690			2,342,962
Income from equity method investments		—		17,972			17,972
Equity method investments in non-utility activities		—		96,191			96,191
Construction expenditures		79,153		—			79,153


	Regulated		Non-Utility
In thousands	Utility		Activities			Total
2002
Revenues from external customers	$	832,028	$	—		$	832,028
Margin		335,794		—			335,794
Operations and maintenance expenses		133,427		348			133,775
Depreciation		57,593		—			57,593
Operating income (loss)		120,911		(465	)		120,446
Income before income taxes and minority interest		83,525		18,486			102,011
Total assets		1,404,438		95,302			1,499,740
Income from equity method investments		—		19,207			19,207
Equity method investments in non-utility activities		—		80,342			80,342
Construction expenditures		80,528		—			80,528

Reconciliations to the consolidated financial statements for the years ended and as of October 31, 2004, 2003 and 2002, are presented below.


In thousands	2004			2003			2002
Operating Income:
Segment operating income	$	178,566		$	143,067		$	120,446
Utility income taxes		(51,485	)		(40,093	)		(30,784	)
Non-utility activities		234			132			465

Operating income	$	127,315		$	103,106		$	90,127


Net Income:
Income before income taxes and minority interest for reportable segments	$	157,283		$	123,799		$	102,011
Income taxes		62,047			48,617			39,794
Less minority interest		48			820			—

Net income	$	95,188		$	74,362		$	62,217


Consolidated Assets:
Total assets for reportable segments	$	2,336,003		$	2,342,962		$	1,499,740
Eliminations/Adjustments		(126	)		(30,850	)		(48,114	)

Consolidated assets	$	2,335,877		$	2,312,112		$	1,451,626

12. Environmental Matters

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

In 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 an amount 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.

Three other MGP sites that we also have owned, leased or operated were not included in the settlement. 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 NCGS discussed in Note 2 to the consolidated financial statements.

As of October 31, 2004, our undiscounted environmental liability totaled $3 million, consisting of $2.7 million for the four MGP sites and $.3 million for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries. We increased the liability in 2004

by $.1 million to reflect the impact of inflation based on the consumer price index.

As of October 31, 2004, our regulatory assets for environmental costs totaled $4.7 million, net of recoveries from customers, in connection with the estimated liabilities for the MGP sites and underground storage tanks and for environmental costs incurred, primarily legal fees and engineering assessments. The portion of the regulatory assets representing actual costs incurred, including the settlement payment to the third party, is being amortized as recovered in rates from customers.

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

In connection with the acquisition in 2003 of NCNG discussed in Note 2 to the consolidated financial statements, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of 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 cost 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.

On October 30, 2003, in connection with the NCNG general rate case proceeding discussed in Note 3 to the consolidated financial statements, the NCUC ordered an environmental regulatory liability of $3.5 million be established for refund to customers over the three-year period beginning November 1, 2003. This liability resulted from a payment made to NCNG by its insurers prior to our acquisition.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Piedmont Natural Gas Company, Inc.:
Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (“Piedmont”) as of October 31, 2004 and 2003, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of Piedmont’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries as of October 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP
Charlotte, North Carolina
January 10, 2005

Management’s Responsibility For Financial Reporting

The management of Piedmont Natural Gas Company is responsible for the preparation and integrity of the accompanying consolidated financial statements and related notes. We prepared the statements in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and included amounts which are necessarily based on our best estimates and judgments made with due consideration to materiality. Financial information presented elsewhere in this report is consistent with that in the consolidated financial statements.

We have established and are responsible for maintaining a comprehensive system of internal accounting controls which we believe provides reasonable assurance that policies and procedures are complied with, assets are safeguarded and transactions are executed according to management’s authorization. We continually review this system for effectiveness and modify it in response to changing business conditions and operations and as a result of recommendations by internal and external auditors.

The Audit Committee of the Board of Directors, consisting solely of independent Directors, meets at least quarterly with Deloitte & Touche LLP, the internal auditors and representatives of management to discuss auditing and financial reporting matters. The Audit Committee reviews audit plans and results and accounting, financial reporting and internal control practices, procedures and results. Both Deloitte & Touche LLP and the internal auditors have full and free access to all levels of management.


/s/ Barry L. Guy
Barry L. Guy Vice President and Controller

Quarterly Financial Data (In thousands except per share amounts)


											Earnings (Loss)
								Net			Per Share of
	Operating				Operating			Income			Common Stock
	Revenues		Margin		Income (Loss)			(Loss)			Basic *			Diluted *
2004
January 31	$	618,785	$	196,480	$	77,349		$	74,622		$	1.09		$	1.09
April 30	$	482,398	$	145,855	$	45,904		$	41,259		$	.54		$	.54
July 31	$	214,750	$	69,728	$	1,465		$	(8,157	)	$	(.11	)	$	(.11	)
October 31	$	213,806	$	76,306	$	2,597		$	(12,536	)	$	(.16	)	$	(.16	)

2003
January 31	$	493,491	$	161,694	$	65,655		$	57,996		$	.87		$	.87
April 30	$	407,774	$	110,014	$	34,592		$	31,000		$	.47		$	.46
July 31	$	140,132	$	49,300	$	(1,870	)	$	(9,677	)	$	(.14	)	$	(.14	)
October 31	$	179,425	$	61,872	$	4,729		$	(4,957	)	$	(.07	)	$	(.07	)

* Reflects a two-for-one stock split effective October 11, 2004.

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

The information presented is not comparable due to the acquisitions of North Carolina Natural Gas Corporation (NCNG) and an equity interest in Eastern North Carolina Natural Gas Company (EastermNC) effective September 30, 2003.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No.1 to be signed on its behalf by the undersigned, thereunto duly authorized, on January 24, 2005.


		Piedmont Natural Gas Company, Inc.
		(Registrant)

		By:		/s/ Barry L. Guy

				Barry L. Guy Vice President and Controller (Principal Accounting Officer)

Schedule II

Piedmont Natural Gas Company, Inc. and Subsidiaries
Valuation and Qualifying Accounts
For the Years Ended October 31, 2004, 2003 and 2002


			Additions
	Balance at		Charged to		Charged to					Balance
	Beginning		Costs and		Other					at End
Description	of Period		Expenses		Accounts			Deductions (3)		of Period
			(in thousands)
Allowance for doubtful accounts:

2004	$	2,743	$	6,098	$	2		$	7,757	$	1,086
2003		810		6,425		1,375	(1)		5,867		2,743
2002		592		3,105		95	(2)		2,982		810

(1) Primarily related to acquisitions.

(2) Primarily related to an acquisition, partially offset by collections of previous deferrals of gas costs.

(3) Uncollectible accounts written off, net of recoveries.


Deferred tax valuation allowance:
2004	$	1,000	$	200	$	—	$	—	$	1,200
2003	$	—		1,000		—		—		1,000

EXHIBITS INDEX


23.1		Independent Auditors’ Consent.

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.

Piedmont Natural Gas (PNY) 10-K/A2004 FY Annual report (amended)