UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.D.C. 20549
FORMForm 10-K
(Mark One)
(Mark One)
þ
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedOctober 31, 2005
Or
  For the fiscal year ended October 31, 2006
Or
o
 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from          to          
For the Transition period fromto
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.)
   
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
4720 Piedmont Row Drive,
Charlotte, North Carolina		28210

(Address of principal executive offices)		 28210
(Zip Code)
Registrant’s telephone number, including area code (704) 364-3120
Registrant’s telephone number, including area code
(704) 364-3120
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
   
Title of each classEach Class
 
Name of each exchangeEach Exchange on which registeredWhich Registered
 
Common Stock, no par value New York Stock Exchange
 
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securitiessecurities Act.  Yesþ     Noo
 If this report is an annual or transition report, indicate
Indicate by check mark if the registrant is not required to file reports pursuant to Sectionsection 13 or 15(d) of the Securities Exchange Act of 1934.Act.  Yeso     Noþ
 
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 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K.þo
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Act). YesAct. (Check one):
Large accelerated filer þ     NoAccelerated filer o     Non-accelerated filer o
 
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act).  Yeso     Noþ
 
State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2005.2006.
Common Stock, no par value — $1,744,011,535$1,825,389,696
 
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 10, 20068, 2007
 
Common Stock, no par value 76,612,68574,606,758
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 3, 2006,7, 2007, are incorporated by reference into Part III.
 

 

Piedmont Natural Gas Company, Inc.
2005
2006FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
       
    Page
Part I.      
       
Item 1. Business  1 
Item 1A.Risk Factors5
Item 1B.Unresolved Staff Comments8
Item 2. Properties  68 
Item 3. Legal Proceedings  79 
Item 4. Submission of Matters to a Vote of Security Holders  79 
       
Part II.      
       
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities  89 
Item 6. Selected Financial Data  911 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations  911 
Item 7A. Quantitative and Qualitative DisclosureDisclosures about Market Risk  2830 
Item 8. Financial Statements and Supplementary Data  2931 
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  6769 
Item 9A. Controls and Procedures  6769 
Item 9B. Other Information  7172 
       
Part III.      
       
Item 10. Directors and Executive Officers of the Registrant  72 
Item 11. Executive Compensation  72 
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters  72 
Item 13. Certain Relationships and Related Transactions  73 
Item 14. Principal AccountantAccounting Fees and Services  73 
       
Part IV.      
       
Item 15. Exhibits, and Financial Statement Schedules  7473 
 
  Signatures  8077 

 

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 990,0001,016,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 61,00062,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.
 
In the Carolinas, our service area is comprised of numerous cities, towns and communities, includingcommunities. We maintain service offices in Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to Greenville, Monroe, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.
 
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 in cash for estimated working capital. We paid an additional $.3 million in cash for actual working capital in our second quarter ended April 30, 2004. At the time of the acquisition, 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.
 
On September 30, 2003, we also purchased for $7.5 million in cash Progress’ equity interest in Eastern North Carolina Natural Gas Company (EasternNC). At that time, EasternNC was a regulated utility with 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. Effective at the close of business on October 25, 2005, we purchased for $1 the remaining 50% interest in common stock of EasternNC from Albemarle Pamlico Economic Development Corporation. EasternNC was merged into Piedmont immediately following the closing.
 
We have two reportable business segments, regulated utility and non-utility activities. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. Operations of both segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 1011 and Note 11,12, respectively, to the consolidated financial statements.

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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, 2005, 39%2006, 44% of our operating revenues were from residential customers, 24%26% from commercial customers, 13%11% from industrial and power generation customers, 21%18% from secondary market activity and 3%1% from various other sources. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments.”
 
Our utility operations are subject to regulationregulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates,


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service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the availability of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution and transmission 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, which 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 20052006 to 2055. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. TwoEight franchise agreements have expired as of October 31, 2005,2006, and ninefour will expire during the 20062007 fiscal year. We continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed or service continued 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 thisForm 10-K. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. During the year ended October 31, 2005,2006, the amount of natural gas in storage varied from 10.113.6 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 25.425.7 million dekatherms, and the

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aggregate commodity cost of this gas in storage varied from $58.6$104.6 million to $151.5$204.8 million.
 
During the year ended October 31, 2005, 106.72006, 106.6 million dekatherms of gas were sold to or transported for large industrial and power-generationpower generation customers, compared with 102.5106.7 million dekatherms in 2004.2005. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 83.6 million dekatherms in 2006, compared with 89 million dekatherms in 2005, compared with 89.9 million dekatherms2005. Weather in 2004. Weather,2006, as measured by degree days, was 5% warmer than normal in 2005 and 6% warmer than normal and in 2004.2005 was 5% warmer than normal.
 
The following is a five-year comparison of operating statistics for the years ended October 31, 20012002 through 2005.2006. The information presented is not comparable for all periods due to the acquisitions of NCNG and an equity interest in EasternNC effective September 30, 2003.2003, and the remaining 50% interest of EasternNC effective October 25, 2005.
                    
                     2006 2005 2004 2003 2002 
 2005 2004 2003 2002 2001 
Operating Revenues (in thousands):                     
Sales and Transportation:                     
Residential $686,304 $624,487 $524,933 $358,027 $525,650  $841,051  $686,304  $624,487  $524,933  $358,027 
Commercial 421,499 360,355 299,281 191,988 299,672   498,956   421,499   360,355   299,281   191,988 
Industrial 215,505 179,302 112,986 102,127 128,831   205,384   215,505   179,302   112,986   102,127 
For Power Generation 16,248 18,782 3,071 2,368 1,316   22,963   16,248   18,782   3,071   2,368 
For Resale 40,122 38,074 1,948 374 371   11,342   40,122   38,074   1,948   374 
                      
Total 1,379,678 1,221,000 942,219 654,884 955,840   1,579,696   1,379,678   1,221,000   942,219   654,884 
Secondary Market Sales 373,353 301,886 273,369 173,592 145,712   337,278   373,353   301,886   273,369   173,592 
Miscellaneous 8,060 6,853 5,234 3,552 6,304   7,654   8,060   6,853   5,234   3,552 
                      
Total $1,761,091 $1,529,739 $1,220,822 $832,028 $1,107,856  $1,924,628  $1,761,091  $1,529,739  $1,220,822  $832,028 
                      
 
Gas Volumes — Dekatherms (in thousands): 
System Throughput: 
Residential 52,966 54,412 52,603 40,047 47,869 
Commercial 36,000 35,483 33,648 25,892 31,002 
Industrial 81,102 83,957 60,054 58,414 54,285 
For Power Generation 25,591 18,580 2,396 1,734 1,169 
For Resale 8,779 8,912 623 41 29 
           
Total 204,438 201,344 149,324 126,128 134,354 
           
 
Secondary Market Sales 47,057 51,707 45,937 55,679 29,545 
           
 
Number of Retail Customers Billed (12-month average): 
Residential 792,061 771,037 657,965 620,642 601,682 
Commercial 91,645 90,328 75,924 72,323 71,069 
Industrial 3,146 3,194 2,626 2,583 2,764 
For Power Generation 16 13 5 3 3 
For Resale 15 15 4 3 3 
           
Total 886,883 864,587 736,524 695,554 675,521 
           
 
Average Per Residential Customer: 
Gas Used — Dekatherms 66.87 70.57 79.95 64.53 79.56 
Revenue $866.48 $809.93 $797.81 $576.87 $873.63 
Revenue Per Dekatherm $12.96 $11.48 $9.98 $8.94 $10.98 
 
Cost of Gas (in thousands): 
Natural Gas Commodity Costs $1,226,999 $943,890 $790,118 $408,407 $670,594 
Capacity Demand Charges 117,287 125,178 89,514 89,103 80,622 
Natural Gas Withdrawn From (Injected Into) Storage, net  (35,151)  (11,116)  (44,069) 11,620  (868)

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2

 

                     
  2006  2005  2004  2003  2002 
 
Gas Volumes — Dekatherms (in thousands):                    
System Throughput:                    
Residential  49,119   52,966   54,412   52,603   40,047 
Commercial  34,476   36,000   35,483   33,648   25,892 
Industrial  80,490   81,102   83,957   60,054   58,414 
For Power Generation  26,099   25,591   18,580   2,396   1,734 
For Resale  8,472   8,779   8,912   623   41 
                     
Total  198,656   204,438   201,344   149,324   126,128 
                    ��
Secondary Market Sales  40,994   47,057   51,707   45,937   55,679 
                     
Number of Retail Customers Billed(12-month average):
                    
Residential  815,579   792,061   771,037   657,965   620,642 
Commercial  92,692   91,645   90,328   75,924   72,323 
Industrial  3,008   3,146   3,194   2,626   2,583 
For Power Generation  12   16   13   5   3 
For Resale  19   15   15   4   3 
                     
Total  911,310   886,883   864,587   736,524   695,554 
                     
Average Per Residential Customer:                    
Gas Used — Dekatherms  60.23   66.87   70.57   79.95   64.53 
Revenue $1,031.23  $866.48  $809.93  $797.81  $576.87 
Revenue Per Dekatherm $17.12  $12.96  $11.48  $9.98  $8.94 
           
Cost of Gas (in thousands):                    
Natural Gas Commodity Costs $1,229,326  $1,226,999  $943,890  $790,118  $408,407 
Capacity Demand Charges  99,333   117,287   125,178   89,514   89,103 
Natural Gas Withdrawn From (Injected Into) Storage, net  15,709   (35,151)  (11,116)  (44,069)  11,620 
Regulatory Charges (Credits), net  56,781   (47,183)  (16,582)  2,379   (12,896)
                     
Total $1,401,149  $1,261,952  $1,041,370  $837,942  $496,234 
                     
Supply Available for Distribution (dekatherms in thousands):                    
Natural Gas Purchased  140,999   155,614   163,257   143,716   136,206 
Transportation Gas  101,414   97,959   91,795   52,895   48,179 
Natural Gas Withdrawn From (Injected Into) Storage, net  (197)  856   775   (2,490)  (1,461)
Company Use  (127)  (133)  (135)  (147)  (139)
                     
Total  242,089   254,296   255,692   193,974   182,785 
                     
                     
  2005  2004  2003  2002  2001 
Regulatory Charges (Credits), net  (47,183)  (16,582)  2,379   (12,896)  19,530 
                
Total $1,261,952  $1,041,370  $837,942  $496,234  $769,878 
                
                     
Supply Available for Distribution (dekatherms in thousands):        
Natural Gas Purchased  155,614   163,257   143,716   136,206   121,465 
Transportation Gas  97,959   91,795   52,895   48,179   44,285 
Natural Gas Withdrawn From (Injected Into) Storage, net  856   775   (2,490)  (1,461)  1,648 
Company Use  (133)  (135)  (147)  (139)  (167)
                
Total  254,296   255,692   193,974   182,785   167,231 
                
 As of October 31, 2005, 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 Eastern37,000
Duke-East Tennessee (through arrangements with Transco)25,000
NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)42,800
NiSource-Columbia Gulf10,000
Total834,300
     As of October 31, 2005, we had the following assets or 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)278,000
Pine Needle LNG263,400
Williams-Transco Storage86,100
NiSource-Columbia Gas Storage96,400
El Paso-Tennessee Pipeline Storage55,900
Duke Energy (delivered peaking service)76,000
Total855,800
     We own or have under contract 29.5 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement or replace regular pipeline supplies.
We purchase natural gas under firm contractual commitments to meet ourdesign-day requirements for firm sales customers. 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 firm customers by using a variety of firm transportation and storage capacity arrangements. The

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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.
 
As of October 31, 2006, 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 Pipeline74,100
Duke-Texas Eastern37,000
Duke-East Tennessee (through arrangements with Transco)25,000
NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)42,800
NiSource-Columbia Gulf10,000
Total834,300
As of October 31, 2006, we had the following assets or 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 deliverability varies from five days to one year:
Piedmont Liquefied Natural Gas (LNG)278,000
Pine Needle LNG263,400
Williams-Transco Storage86,100
NiSource-Columbia Gas Storage96,400
El Paso-Tennessee Pipeline Storage55,900
Duke Energy (delivered peaking service)76,000
Total855,800
As of October 31, 2006, we own or have under contract 29.5 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement or replace regular pipeline supplies.
The source of the gas we distribute is primarily the Gulf Coast production region, and is purchased primarily from major producers and marketers. The natural gas production,

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processing and pipeline infrastructure in the Gulf of Mexico was significantly affected by hurricanes in August and September 2005, with supplies being shut-in at various levels for extended periods due to lack of power, damage to facilities and lack of gas flow. As part of our long-term plan to diversify our reliance away from the Gulf Coast region, we have contracted with a proposedan underground storage facility that is under construction in West Virginia and withhave a proposed extension of a natural gasfirm transportation contract pending for additional pipeline capacity that accesses gas supplies from Canada and the Rocky Mountains. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of thisForm 10-K and Note 3 to the consolidated financial statements.
 
During the year ended October 31, 2005, 8%2006, approximately 5% 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 FERC regulations, 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. ThroughDuring the fiscal year ended October 31, 2005, only minimal2006, no bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms.was experienced. The future level of bypass activity cannot be predicted.


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The regulated utility competes in the residential and commercial customer markets with other energy products. The most significant competition between natural gas and electricity is for space heating, water heating and cooking. There are four major electric companies within our service areas. We continue to attract the majority of the new residential construction market on or near our distribution mains, and we believe that the consumer’s preference for natural gas includesis influenced by such factors as reliability, comfort, convenience and convenience.environmental factors. Natural gas has historically maintained a price advantage over electricity in our service areas; however, with a tighter national supply and demand balance, wholesale natural gas prices and price volatility have increased over recent years. Increases in the price of natural gas can negatively impact our competitive position by decreasing or eliminating the price benefits of natural gas to the consumer.
 
As indicated above, many of our customers can utilize a fuel other than natural gas, and our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market prices of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers. With higher wholesale gas prices, we anticipate that there may be more fuel switching by large industrial customers in the near term.
 
During the year ended October 31, 2005,2006, our largest customer contributed $14.2$15.8 million, or less than 1%, to total operating revenues.

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Our costs for research and development are not material and are 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 thisForm 10-K.
 
As of October 31, 2005,2006, our fiscal year end, we had 2,1242,051 employees, compared with 2,1202,124 as of October 31, 2004.2005.
 
Our reports onForm 10-K,Form 10-Q andForm 8-K, and amendments to these reports, are available at no cost on our web sitewebsite atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.
Item 1A.  Risk Factors
A decrease in the availability of adequate upstream, interstate pipeline transportation capacity and natural gas supply could reduce our earnings.  We purchase all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to that supply or interstate pipeline capacity due to unforeseen events, including but not limited to, hurricanes, freeze off of natural gas wells, terrorist attacks or other acts of war could reduce our normal interstate supply of gas, which could reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling platforms, processing and gathering systems, off-shore pipelines and interstate pipelines cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.
Changes in federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacityand/or gas supply and thereby reduce our earnings.  Congress has enacted laws that give the FERC the power to regulate the interstate transportation of natural gas and the terms and conditions of service. Additionally, Congress has enacted laws that deregulate the price of natural gas sold at the wellhead. Any Congressional legislation or agency regulation that would alter the current statutory and regulatory structure in a way to significantly raise costs that could not be recovered in rates from our customers or reduce the availability of supply or capacity would negatively impact our earnings.


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Further increases in the wholesale price of natural gas could reduce our earnings.  In recent years, natural gas prices have increased dramatically due to growing demand and limitations on North American gas production. The cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy. Significant price increases could also cause new home developers and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills and bad debt expenses may increase and reduce our earnings.
Weather conditions may cause our earnings to vary from year to year.  Our earnings can vary from year to year, depending in part on weather conditions. Currently, we have in place regulatory mechanisms that account for this and normalize our margin for weather, providing for an adjustment up or down to take into account colder-than-normal or warmer-than-normal weather. We estimate that approximately 50% to 60% of our annual gas sales are to temperature-sensitive customers. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell and deliver in any year. If our rates and tariffs were modified to eliminate weather protection, then we would be exposed to significant risk associated with weather and our earnings could vary as a result.
Governmental actions at the state level could result in lower earnings.  Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. If a state regulatory commission were to prohibit us from setting rates that timely recover our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers (including cost of gas) or other tariff provisions, then our earnings could be impacted. Additionally, the state agencies foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there were changes in regulatory philosophies that altered our ability to compete for these customers, then we could lose customers, or incur significant unrecoverable expenses to retain them. Both scenarios would impact our earnings.
Operational interruptions to our gas distribution activities caused by accidents, strikes or acts of terrorism could adversely impact earnings.  Inherent in our gas distribution activities are a variety of hazards and operation risks, such as leaks, ruptures and mechanical problems that, if severe enough or led to operational interruptions, could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Additionally, the fact that we have a workforce that is partially represented by the union exposes us to the risk of a strike. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.
Increases in our debt ratios could adversely affect our ability to service our debt obligations and our ability to access capital on favorable terms.  An increase in our leverage could adversely affect us by:
• increasing the cost of future debt financing;
• making it more difficult for us to satisfy our existing financial obligations;
• limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes;
• increasing our vulnerability to adverse economic and industry conditions;


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• requiring us to dedicate a substantial portion of our cash flows from operations to payments on our debt, which would reduce funds available for operations, future business opportunities or other purposes; and
• limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete.
We do not generate sufficient cash flows to meet all our cash needs.  Historically, we have made large capital expenditures in order to finance the expansion and upgrading of our distribution system. We have also purchased and will continue to purchase natural gas to store in inventory. Moreover, we have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our revenues and profits. We have funded a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new securities into the market. Our dependency on external sources of financing creates the risks that our profits could decrease as a result of high capital costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.  The terms of our senior indebtedness, including our credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us.
We are exposed to credit risk of counterparties with whom we do business.  Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments or fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligation could adversely affect our financial position, results of operations or cash flows.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.  Our costs of providing non-contributory defined benefit pension plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions made to the plans. Without sustained growth in the pension investments over time to increase the value of our plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing cash flows and could negatively affect results of operations.
We are subject to numerous environmental laws and regulations that may require significant expenditures or increase operating costs.  We are subject to numerous federal and state environmental laws and regulations affecting many aspects of our present and future operations. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and approvals. Compliance with these laws and regulations can require significant expenditures forclean-up costs and damages arising out of contaminated properties. Failure to comply may result in fines, penalties and injunctive measures affecting operating assets.
An overall economic downturn could negatively impact our earnings.  A lower level of economic activity in our markets could result in a decline in energy consumption which could adversely affect our revenues or restrict our future growth. Additionally, a significant slow down in the housing market in our service area could restrict our future growth and negatively impact our earnings.


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Our inability to attract and retain professional and technical employees could impact our earnings.  Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract and retain a technically skilled workforce. Without such a skilled workforce, our ability to provide quality service to our customers and meet our regulatory requirements will be challenged and this could negatively impact our earnings.
Item 1B.  Unresolved Staff Comments
None.
Item 2.  Properties
 
All property shown in the consolidated balance sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, production plant, storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with 93%94% of the total invested in distribution and transmission plant to serve our customers. We have approximately 3,0003,100 miles of lateral pipelines up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,70023,300 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on private property. All of these properties are located within our service areas in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in progress” which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion.
 
None of our property is encumbered and all property is in use.
 
We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and district and regional offices in the locations shown below. Lease payments for these various offices totaled $1.9$3.8 million for the year ended October 31, 2005.2006.
     
North Carolina
 
South Carolina
 
Tennessee
 
BurlingtonAndersonNashville
CaryGaffney
CharlotteGreenville
Elizabeth CitySpartanburg
Fayetteville    
Burlington
Charlotte
Elizabeth City
Fayetteville
Goldsboro
Greensboro
Hickory
High Point
Indian Trail
New Bern
Reidsville
Rockingham		 Anderson
Gaffney
Greenville
Spartanburg		 Nashville

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Greensboro
Hickory
High Point
Indian Trail
New Bern
Reidsville
Rockingham    
Salisbury
Spruce Pine
Tarboro
Wilmington
Winston-Salem    
 We sold our corporate headquarters building in 2005 and entered into a ten-year lease on new office space beginning November 1, 2005. The lease payments for the ten-year term range from $3 million to $3.4 million annually.
     All propertyProperty shown in the consolidated balance sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of


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residential and commercial water heaters leased to natural gas customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.
Item 3.  Legal Proceedings
 
From time to time, we conduct business with natural gas marketers who act as agents for various industrial customers of ours or who purchase natural gas directly for their own account. We previously had such an arrangement with National Gas Distributors LLC (NGD), which filed a voluntary bankruptcy petition on January 20, 2006. The bankruptcy trustee for this petition claimed that certain amounts paid by NGD to us for gas supply constitute preference payments, and sought their return. We have disputed these claims and vigorously defended our position on the matter. In October 2006, we agreed to settle with the NGD bankruptcy trustee in order to avoid protracted litigation and the expense thereof. The settlement has been submitted to the bankruptcy court for approval. During the fourth quarter, we recorded our estimated liability under the settlement, which does not have a material adverse impact on our financial position, results of operations or cash flows.
Otherwise, we have only routine litigation in the normal course of business and do not expect the outcomes to have any material impact on our financial position or results of operations.business.
Item 4.  Submission of Matters to a Vote of Security Holders
 
No matters were submitted to a vote of security holders during our fourth quarter ended October 31, 2005.2006.

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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
(a) Our Common Stockcommon stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 20052006 and 2004.
           
      2005 High Low       2004 High Low
Quarter ended:     Quarter ended:    
      January 31 $24.35  $22.01         January 31 $21.98   $19.71  
      April 30 24.44 21.76       April 30 21.53 19.90
      July 31 24.99 22.84       July 31 21.59 19.16
      October 31 25.80 22.33       October 31 23.03 20.45
2005.
 
         
2006
 High  Low 
 
Quarter ended:        
January 31 $24.94  $21.26 
April 30  25.23   23.21 
July 31  26.17   23.31 
October 31  27.27   24.72 
         
2005
 High  Low 
 
Quarter ended:        
January 31 $24.35  $22.01 
April 30  24.44   21.76 
July 31  24.99   22.84 
October 31  25.80   22.33 
(b) As of January 10, 2006,8, 2007, our Common Stockcommon stock was owned by 16,60616,191 shareholders of record.


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(c) The following table provides information with respect to quarterly dividends paid on Common Stockcommon stock for the years ended October 31, 20052006 and 2004.2005. We expect that comparable cash dividends will continue to be paid in the future.
       
  Dividends Paid   Dividends Paid
      2005 Per Share       2004 Per Share
Quarter ended:   Quarter ended:  
      January 31 21.50¢       January 31 20.75¢
      April 30 23.00¢       April 30 21.50¢
      July 31 23.00¢       July 31 21.50¢
      October 31 23.00¢       October 31 21.50¢
Dividends Paid
2006
per Share
Quarter ended:
January 3123.00¢
April 3024.00¢
July 3124.00¢
October 3124.00¢
 
Dividends Paid
2005
per Share
Quarter ended:
January 3121.50¢
April 3023.00¢
July 3123.00¢
October 3123.00¢
The amount of cash dividends that may be paid on Common Stockcommon stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2005,2006, net earnings available for restricted payments were greater than retained earnings; therefore, none of our retained earnings were not restricted.

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The following table provides information with respect to repurchases of our Common Stockcommon stock under the Common Stock Open Market Purchase Program during the fourth quarter ended October 31, 2005.2006.
                 
          Total Number of Maximum Number
  Total Number     Shares Purchased of Shares that May
  of Shares Average Price as Part of Publicly Yet be Purchased
Period Purchased Paid Per Share Announced Program Under the Program *
               1,896,100 
  8/1/05 –   8/31/05  110,000  $24.10   110,000   1,786,100 
  9/1/05 –   9/30/05  25,000  $24.78   25,000   1,761,100 
10/1/05 – 10/31/05  69,000  $24.34   69,000   1,692,100 
                 
Total  204,000       204,000     
 
                 
        Total Number of
  Maximum Number
 
  Total Number
     Shares Purchased
  of Shares that May
 
  of Shares
  Average Price
  as Part of Publicly
  Yet be Purchased
 
Period
 Purchased  Paid per Share  Announced Program  Under the Program* 
 
               6,649,474 
 8/1/06 - 8/31/06  37,400  $25.81   37,400   6,612,074 
 9/1/06 - 9/30/06  —  $—   —   6,612,074 
10/1/06 - 10/31/06  —  $—   —   6,612,074 
Total  37,400  $25.81   37,400     
*The Common Stock Open Market Purchase Program was announced on June 4, 2004, to repurchasepurchase up to three million shares of Common Stock.common stock for reissuance under our dividend reinvestment, stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect thetwo-for-one stock split in 2004. The Board also approved the purchase of up to four million additional shares of common stock and amended the program to provide for purchases to maintain ourdebt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares.


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Item 6.  Selected Financial Data
 On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the stock split in 2004. The Board also approved the repurchase of up to four million additional shares of currently outstanding shares of Common Stock and amended the program to provide for repurchases to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares.
Item 6. Selected Financial Data
The following table provides selected financial data for the years ended October 31, 20012002 through 2005.2006. The information presented is not comparable for all periods due to the acquisitions of North Carolina Natural Gas Corporation (NCNG) and an equity interest in Eastern North Carolina Natural Gas Company (EasternNC) effective September 30, 2003, and the remaining 50% interest of EasternNC effective October 25, 2005, as discussed in Note 2 to the consolidated financial statements.
                                        
In thousands except per share amounts 2005 2004* 2003* 2002* 2001* 
 2006 2005 2004 2003 2002 
 In thousands except per share amounts 
 
Operating Revenues $1,761,091 $1,529,739 $1,220,822 $832,028 $1,107,856  $1,924,628  $1,761,091  $1,529,739  $1,220,822  $832,028 
Margin (Operating Revenues less Cost of Gas) $499,139 $488,369 $382,880 $335,794 $337,978  $523,479  $499,139  $488,369  $382,880  $335,794 
Net Income $101,270 $95,188 $74,362 $62,217 $65,485  $97,189  $101,270  $95,188  $74,362  $62,217 
Earnings per Share of Common Stock:                     
Basic $1.32 $1.28 $1.11 $.95 $1.02  $1.28  $1.32  $1.28  $1.11  $0.95 
Diluted $1.32 $1.27 $1.11 $.94 $1.01  $1.28  $1.32  $1.27  $1.11  $0.94 
Cash Dividends Per Share of Common Stock $.905 $.8525 $.8225 $.7925 $.76 
Cash Dividends per Share of Common Stock $0.950  $0.905  $0.8525  $0.8225  $0.7925 
Total Assets $2,602,490 $2,392,164 $2,339,283 $1,478,014 $1,407,521  $2,733,939  $2,602,490  $2,392,164  $2,339,283  $1,478,014 
Long-Term Debt (less current maturities) $625,000 $660,000 $460,000 $462,000 $509,000  $825,000  $625,000  $660,000  $460,000  $462,000 
 
Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
This report as well as other documents we file with the Securities and Exchange Commission (SEC) may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations and information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to:
*• Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our effectiveness in achieving the allowed rates of return and initiate rate proceedings or operating changes as needed. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated.
 Total assets for• Residential, commercial and industrial growth in our service areas. The ability to grow our customer base and the years 2001 through 2004 have been restated. See Note 13pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.
• Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies, and we expect this competitive environment to continue. We must be able to adapt to the consolidatedchanging environments and the competition.
• The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts at lowerper-unit margins.


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• Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.
• The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project.
• Capital market conditions. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets could affect access to and cost of capital.
• Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial statements.risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.
• Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.
• Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.
• Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.
• Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.
• Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses and we assume such risks as an equity investor.
Item 7. Management’s Discussion
Other factors may be described elsewhere in this report. All of these factors are difficult to predict and Analysismany of FinancialConditionthem are beyond our control. For these reasons, you should not rely on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “will,” “assume,” “can,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and Resultsvariations of Operationssuch words and similar expressions are intended to identify forward-looking statements.
 The following discussion gives effect
Forward-looking statements are only as of the date they are made and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Please reference our website atwww.piedmontng.com for current information. Our reports onForm 10-K,Form 10-Q andForm 8-K and amendments to these reports are available at no cost on our website as soon as reasonably practicable after the report is filed with or furnished to the restatement of the consolidated balance sheet and the consolidated statements of cash flows discussed in Note 13 to the consolidated financial statements.SEC.


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Overview
Overview
Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in portions of North

9

Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments.segments — the regulated utility segment and the non-utility activities segment.
 
The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the twelve months ended October 31, 2006, 82% of our earnings before taxes came from our regulated utility segment.
 
The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.
 
Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are generated during the winter season. During warm winters or unevenly cold winters, heating customers may significantly reduce their consumption of natural gas. AlthoughIn South Carolina and Tennesee, we have weather normalization adjustment (WNA) mechanisms that are designed to protect a portion of our revenues againstwarmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact ofcolder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, through a general rate case proceeding duringin 2005, the North Carolina Utilities Commission (NCUC) ordered the establishment of a Customer Utilization Tracker (CUT) and the elimination ofhas eliminated the WNA effective November 1, 2005. The North Carolina OfficeCUT provides for the recovery of the Attorney General has filed a noticeour approved margin per customer independent of appeal in this rate proceeding challenging the lawfulnessboth weather and other consumption patterns of the NCUC’s authorizationresidential and approval of the CUT.commercial customers. For further information, see Note 3 to the consolidated financial statements.
 
Over the past few years, there have been significant increases in the wholesale cost of natural gas. The relationship between supply and demand has the greatest impact on wholesale gas prices. TheIncreased wholesale prices for natural gas production, processing and pipeline infrastructureare being driven by increased demand that is exceeding the growth in the Gulf of Mexico was significantly affected by hurricanes in August and September 2005. After the hurricanes, this production was shut-in at various levels for extended periods due to lack of power, damage to facilities and lack ofaccessible supply. Continued high gas flow. Some of the production remains closed or is operating at reduced capacity. As a result of this disruption in supply and other supply and demand factors, wholesale gas prices are expected to remain high and significantly increase customers’ bills during the 2005-2006 heating season. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers; however, price increases could shift our customers’ preference away from natural gas toward other energy sources, particularly in the industrial market. Price increasesHigh gas prices could also affect the consumption levels of ouras customers or make it more difficult for themreact to pay theirhigh bills. We expect that the wholesale price of natural gas will remain high relative to historic levels and volatile until natural gas supply and demand are in better balance.
 On August 8, 2005, President Bush signed into law
The majority of our natural gas supplies come from the Energy Policy Act of 2005, the first major energy legislation passed by Congress in 13 years.Gulf Coast region. We believe this legislationthat diversification of our supply portfolio is the first step towards addressingin our nation’s energy issues, but it falls short.customers’ best interest. We believe the legislation does not adequately stimulate domestic natural gas supply development and

10

have a firm transportation contract pending with Midwestern Gas Transmission Company for additional measures are necessary topipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies in areas such asvia the Outer Continental Shelf,Chicago hub, primarily to serve our Tennessee markets. Due to regulatory delays impacting the Rocky Mountains and Alaska.commencement of construction for the winter of2006-2007, Midwestern has only been able to provide a portion of the original contracted capacity. It is too early to identifyanticipated that the impact of this legislation on us.entire capacity will be available during the2007-2008 winter. We have also executed an agreement with Hardy Storage Company LLC for market-area storage capacity in West Virginia with an anticipated in-service date in April 2007.
 Although we have been operating in a relatively low-interest-rate environment for both short- and long-term debt financing during the past few years, the federal funds rate has steadily increased and is the highest it has been in over four years. We anticipate that interest rates will continue to rise, which could result in an increase in rates on our borrowings.
Part of our strategic plan is to manage our gas distribution business through sound rate and regulatory initiatives, control of our operating costs, and implementation of new technologies.technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, both forincluding improvements for current customers and the pursuit of customer growth opportunities in our service areas. We strive for quality customer service by investing in systems, processes and people. We will continue to work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.


13

Our strategic plan includes a focus on maintaining adebt-to-capitalization ratio within a range of 45 to 50%. We will continue to stress the importance of maintaining a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.
As part of an ongoing, larger effort aimed at streamlining business processes, capturing operational and organizational efficiencies and improving customer service, we restructured our management group in 2006. We continually monitor our levelexpect the restructuring to generate savings of short-term borrowings and secure short-term bank lines that meet our short-term operating needs.$7 to $7.5 million annually beginning in fiscal 2007. For further information, see Note 14 to the consolidated financial statements.
Results of Operations
Net income increased $6.1decreased $4.1 million in 20052006 compared with 20042005 primarily due to the following changes which decreased net income:
• $12.4 million increase in operations and maintenance expenses, primarily due to restructuring charges and customer service initiatives.
• $8.1 million increase in utility interest charges.
• $4.5 million increase in depreciation expense.
• $3.3 million increase in general taxes.
• $1.7 million decrease from the non-recurring 2005 gain on the sale of corporate office land.
• $1.6 million increase related to the non-recurring 2005 income tax expensetrue-up of the effective federal income tax rate following the sale of our propane interests.
• $1.5 million decrease from the non-recurring 2005 gain on the sale of marketable securities.
These changes were partially offset by the following changes which increased net income:
 • $10.824.3 million increase in margin (operating revenues less cost of gas).
 
 •$2.3 million increase in earnings from equity method investments.
• $1.4 million decrease in charitable contributions.
• $.6 million decrease from the 2005 inclusion of minority interest in income of consolidated subsidiary.
The net income increase of $6.1 million in 2005 compared with 2004 was primarily due to the following changes which increased net income:
• $10.8 increase in margin.
• $3.1 million decrease in utility interest charges.
 
 • $1.5 million gain on the sale of marketable securities.
 
 • $7.4 million decrease in charitable contributions.
 
 • $1.6 million decrease in income tax expense due totrue-up of the effective federal income tax rate following the sale of our propane interests.
These changes were partially offset by the following changes which decreased net income:
 • $6.7 million increase in operations and maintenance expenses.
 
 • $4.7 million decrease from the non-recurring gain in 2004 on the sale of our equity method investment in propane.
 
 • $2.9 million increase in depreciation expense.
 
 • $2.8 million increase in general taxes.
              Operating results for 2004 reflect the full effect of the acquisitions of NCNG and an equity interest in EasternNC on September 30, 2003. The net income increase of $20.8 million in 2004 compared with 2003 was primarily due to the following changes which increased net income:
•$105.5 million increase in margin.
•$9.4 million increase in income from equity method investments.
•$4.7 million gain on the sale of our equity method investment in propane.

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              These changes were partially offset by the following changes which decreased net income:
•$48.2 million increase in operations and maintenance expenses.
•$19.1 million increase in depreciation expense.
•$8.4 million increase in charitable contributions.
•$7.2 million increase in interest on long-term debt.
•$2.6 million increase in general taxes.
Compared with the prior year, weather in our service area, as measured by degree days, was 2% warmer in 2006 and 2005 and 9% warmer in 2004 and 21% colder in 2003.2004. Volumes of gas delivered to customers were 198.7 million dekatherms in 2006, compared with 204.4 million dekatherms in 2005 compared withand 201.3 million dekatherms in 2004 and 149.3 million dekatherms in 2003.2004. In addition to volumes delivered to customers, secondary market sales volumes were 41 million dekatherms in 2006, compared with 47.1 million dekatherms in 2005 compared withand 51.7 million dekatherms in 2004 and 45.9 million dekatherms in 2003.2004.
 
Operating revenues in 20052006 increased $231.4$163.5 million compared with 20042005 primarily due to the following increases:
 • $133.4197.8 million from increased commodity gas costs passed through to customers.
 
 •$30.4 million from the CUT mechanism put in place as of November 1, 2005, as compared with the North Carolina WNA surcharge in 2005 of $4.7 million. As discussed in “Financial Condition and Liquidity” below, the CUT mechanism was in place throughout 2006, to offset the impact of conservation and weather that is warmer or colder than normal on residential and commercial customer billings and margin. The CUT replaced the WNA in North Carolina in 2006.
These increases were partially offset by the following decreases:
 • $71.536.1 million from secondary market activity. Secondary market transactions consist of off-system sales and capacity release arrangements.
 
 • $11.132.6 million from changes in the composition of delivery mix,services, including the impacts of sales revenues versus transportation revenues and sales and transportation services to power generation customers.
Operating revenues in 2005 increased $231.4 million compared with 2004 primarily due to the following increases:
• $133.4 million from increased commodity gas costs passed through to customers.
• $71.5 million from secondary market activity.
• $11.1 million from changes in the composition of delivery services, including the impacts of sales revenues versus transportation revenues and sales and transportation services to power generation customers.
 
 • $6.3 million from the WNA due to charges of $8.4 million in 2005 compared with charges of $2.1 million in 2004. As discussed in “Financial Condition and Liquidity” below, we had, through October 31, 2005, a WNA in all three states designed to offset the impact of unusually cold or warm weather on residential and commercial customer billings and margin.
              Operating revenues in 2004 increased $308.9 million compared with 2003 primarily due to the following increases:
•$259.9 million from the increase in volumes of 59.6 million dekatherms and facility charges from NCNG customers, including the impact of WNA credits of $1.6 million.
•$28.5 million from secondary market activity.
•$32.2 million from increased commodity gas costs.
•$13.3 million from the WNA due to charges of $3.7 million in 2004 compared with credits of $9.6 million in 2003, excluding the impact of the WNA for NCNG.
•$8.4 million from increased customer rates and charges, including changes in rate design, in Tennessee, effective November 1, 2003.
              Excluding NCNG, volumes decreased 7.8 million dekatherms in 2004 primarily due to 9% warmer weather. This decrease resulted in a decrease in operating revenues of $46.8 million.
In general rate proceedings, state regulatory commissions authorize us to recover a margin, which is the applicable billing rate less cost of gas, on each unit of gas delivered. The commissions also authorize us to recover margin losses resulting from negotiating lower rates to industrial customers when necessary to remain competitive. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.

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Cost of gas in 2006 increased $139.2 million compared with 2005 primarily due to $197.8 million from increased commodity gas costs, partially offset by the following decreases:
• $37.6 million from lower secondary market activity.
• $28.6 million from lower volumes and changes in the composition of delivery services.
Cost of gas in 2005 increased $220.6 million compared with 2004 primarily due to the following increases:
 • $133.4 million from increased commodity gas costs.
 
 • $68.5 million from increased secondary market activity.
 
 • $13.1 million from increased volumes and changes in the composition of delivery mix.services.


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              Cost of gasMargin increased $24.3 million in 2004 increased $203.4 million2006 compared with 20032005 primarily due to growth in the following increases:
•$166.3 million from the increase in volumes from NCNG customers.
•$30.3 million from increased secondary market activity.
•$32.2 million from increased commodity gas costs.
residential and commercial customer base, plus base rate increases of $22.8 million. This net increase was negatively impacted by decreased consumption because of conservation in the residential and commercial classes in South Carolina and Tennessee.
 Excluding NCNG, volumes decreased 7.8 million dekatherms in 2004 which resulted in a decrease in cost of gas of $32.8 million.
Margin increased $10.8 million in 2005 compared with 2004 primarily due to growth in the residential and commercial customer base, partially offset by decreased consumption because of warmer weather, equipment efficiencies and conservation. The margin increase of $105.5
Operations and maintenance expenses increased $12.4 million in 20042006 compared with 2003 was2005 primarily due to the increase in volumes and facility charges from NCNG customers and growthfollowing increases:
• $7.4 million in payroll primarily due to $7.9 million in one-time costs associated with the management restructuring program, increases in long-term incentive plan accruals and costs associated with providing improved customer service, partially offset by decreases in accruals for short-term incentive plans.
• $6 million in outside services primarily due to our enhanced customer service initiative.
• $1.8 million in rents and leases due to leasing of corporate office space, partially offset by a reduction of 2006 expenses related to copier leases.
• $2 million in other corporate expense primarily due to $.5 million of conservation programs approved by the NCUC as a part of a rate case settlement and $.75 million in conservation programs under the CUT settlement, and amortization of deferred operations and maintenance expenses of EasternNC. For further information, see Note 3 to the consolidated financial statements.
These increases were partially offset by the residential and commercial customer base.following decreases:
 
• $2.2 million in postretirement health care and life insurance costs.
• $1.3 million in the provision for uncollectibles.
• $.8 million from reduced telecommunications costs.
• $.8 million from reduced risk insurance premium costs.
Operations and maintenance expenses increased $6.7 million in 2005 compared with 2004 primarily due to the following increases:
 • $5.5 million in employee benefits expense primarily due to pension and postretirement health care and life insurance costs.
 
 • $3.8 million in payroll costs primarily due to increases in vacation benefits, merit and bargaining unit contract increases and long-term incentive plan accruals.
 
 • $1.2 million in utilities expenses primarily due to increased telecommunication costs.
 
 • $1.1 million in rents and leases primarily due to buyout of lease contracts on printers and copiers and other maintenance costs.
 
 • $.6 million in transportation expenses primarily due to an increase in fuel costs.
These increases were partially offset by the following decreases:
 • $2.3 million due to the accrual in the prior year of the projected benefit obligation for a retirement plan for certain current and former members of the Board of Directors.
 
 • $2 million in outside consultant fees primarily for a continuous business process improvement program and an integrated mapping project.
 
 • $1.4 million in other corporate expenses primarily due to accruals for severance agreements and sales tax expense in 2004 that did not recur in 2005 and lower bank fees.
              Operations and maintenance expenses increased $48.2 million in 2004 compared with 2003 primarily due to the following increases:
$22.8 million in payroll costs primarily due to merit increases, the addition of NCNG employees for a full year and accruals of short-term incentive plans.

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•$5.9 million in other corporate expenses primarily due to amortization of NCNG integration costs and the deferral in 2003 to a regulatory asset of EasternNC’s operations and maintenance costs that were expensed prior to September 30, 2003. See Note 3 to the consolidated financial statements.
•$4.3 million in employee benefits expense primarily due to pension and postretirement health care and life insurance costs.
•$4 million in outside labor primarily due to NCNG operations and increased costs of outsourced mainframe utilization.
•$2.4 million in transportation primarily due to NCNG operations.
•$2.3 million due to accrual of the projected benefit obligation for the Board of Directors’ retirement plan.
•$1.6 million in utilities primarily due to NCNG operations.
•$1.2 million in materials primarily due to NCNG operations.
•$1.2 million in outside consulting fees primarily for a continuous business process improvement program, the pipeline integrity management program and an integrated mapping project.
Depreciation expense increased from $63.2$82.3 million to $85.2$89.7 million over the three-year period 20032004 to 20052006 primarily due to increases in plant in service, including a full year of depreciation expenseservice.
General taxes increased $3.3 million in 2005 and 20042006 compared with only one month in 2003 on plant acquired from NCNG.2005 primarily due to the following changes:
 
• $2.2 million increase in property taxes.
• $.6 million increase in other gross receipts taxes.
• $.5 million increase in payroll taxes.
General taxes increased $2.8 million in 2005 compared with 2004 primarily due to the following changes:
 • $1.8 million increase in property taxes as the expense in 2004 reflected the impact of a favorable court ruling that reduced assessed property values and the estimated tax accruals for prior periods.
 
 • $.3 million increase in other property taxes.
 
 • $.4 million increase in payroll taxes.
              General taxesIncome from equity method investments increased $2.6$2.3 million in 20042006, compared with 20032005 primarily due to the following changes:
•$1.7 million increase in payroll taxes primarily due to NCNG operations.
•$1.5 million increase in property taxes primarily due to NCNG operations.
•$.3 million decrease in Tennessee gross receipts taxes.
increases in earnings from SouthStar of $.9 million, Pine Needle of $.3 million and Hardy Storage of $1 million.
 
Income from equity method investments increased $.3 million in 2005 compared with 2004.
              Income from equity method investments increased $9.4 million in 2004 compared with 2003 primarily due to an increase of $8.9 millionincreases in earnings from SouthStar including a one-time benefit of $2.5$2.3 million, frompartially offset by the resolutionabsence of certain disproportionate sharing issues between$2.2 million in propane earnings due to the memberssale of SouthStar.our propane interests.
 
The gain on sale of equity method investments of $4.7 million in 2004 resulted from the sale of our propane interests effective January 20, 2004. See Note 1011 to the consolidated financial statements.

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The gain on sale of marketable securities of $1.5 million in 2005 resulted from the sale in February 2005 of common units of Energy Transfer Partners, L.P., which we received in connection with the sale of our propane interests in 2004.
 
The equity portion of the allowance for funds used during construction (AFUDC) was zero in 2006 and 2005 and $.9 million in 2004 and $1.1 million in 2003.2004. AFUDC is allocated between equity and debt based on actual amounts computed and the ratio of construction work in progress to average short-term borrowings.
 
Non-operating income is comprised of non-regulated merchandising and service work, the non-equity-method portion of the activities of our subsidiaries,subsidiary operations, interest income and other miscellaneous income. Non-operating income in 2005 includesincluded a pre-tax gain on the sale of the corporate office land of $1.7 million. Changes in all other non-operating income were not significant.
Charitable contributions decreased $1.4 million in 2006 compared with 2005 primarily due to the $1 million contribution made to the Piedmont Natural Gas Foundation in 2005. Charitable contributions decreased $7.4 million in 2005 compared with 2004 primarily due to the initial commitment in October 2004 of $7 million to the newly established charitable foundation. We contributed an additional $1 million to the foundation in 2005. Charitable contributions
Utility interest charges increased $8.4$8.1 million in 20042006 compared with 20032005 primarily due to the $7 million gift to the foundation.following changes:
 
• $6.5 million increase in interest on short-term debt due to higher balances outstanding at interest rates that were approximately two percentage points higher in 2006 than in 2005. See further discussion in “Financial Condition and Liquidity” below.
• $3.7 million increase in interest on long-term debt due to the issuance on June 20, 2006 of $200 million of insured quarterly notes due June 1, 2036.
• $2.1 decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2006.
• $.8 million decrease due to an increase in AFUDC allocated to debt.


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• $.5 million increase in interest expense on regulatory treatment of certain components of deferred income taxes.
Utility interest charges decreased $3.1 million in 2005 compared with 2004 primarily due to the following changes:
 • $3.5 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2005.
 
 • $1 million decrease in interest on short-term debt from commercial paper used to temporarily finance the NCNG and EasternNC acquisitions.
 
 • $1.5 million decrease due to an increase in AFUDC allocated to debt.
 
 • $1.7 million increase in interest on short-term debt due to higher balances outstanding at higher interest rates, largely due to purchases of gas at higher prices.
 
 • $1.2 million increase in interest on long-term debt due to higher balances outstanding, including amounts due to the permanent financing of the NCNG and EasternNC acquisitions.
Our Business
 Utility interest charges increased $7.2 million in 2004 compared with 2003 primarily due to the following changes:
•$7.2 million increase in interest on long-term debt due to higher balances outstanding, including amounts due to the permanent financing of the NCNG and EasternNC acquisitions.
•$.8 million increase for interest in connection with the Internal Revenue Service audit of our federal income tax return for 2001.
•$1.3 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2004 compared with significantly higher net payables in 2003.

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Our BusinessPiedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 990,0001,016,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 61,00062,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.
 
In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.
 
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 the second quarter ended April 30, 2004. At the time of the acquisition, 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.
 
On September 30, 2003, we also purchased for $7.5 million in cash Progress’ equity interest in EasternNC. At that time, EasternNC was a regulated utility with a certificate of public convenience and necessity from the NCUC 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. Effective at the close of business on October 25, 2005, we purchased for $1 the remaining 50% interest in common stock of EasternNC from Albemarle Pamlico Economic Development Corporation. EasternNC was merged into Piedmont immediately following the closing. For further information on this transaction, see Note 2 to the consolidated financial statements.
 
We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us. We also regularly evaluate opportunities for obtaining natural gas supplies from different production regions and supply sources to maximize our natural gas portfolio flexibility and reliability. For further information, see “Gas Supply and Regulatory Proceedings” below and Note 3 and Note 6 to the consolidated financial statements.
 
We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 1112 to the consolidated financial statements.


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Our utility operations are regulated by the NCUC,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 regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the availability of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that

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affect the construction, operation, maintenance, integrity and safety of natural gas distribution and transmission 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, which are generally applicable to companies doing business in the United States of America.
 
In the Carolinas, our service area is comprised of numerous cities, towns and communities includingcommunities. We maintain service offices in Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to Greenville, Monroe, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.
 
Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially offset the impact of unusually cold or warm weather on bills rendered during the months of November through March for weather-sensitive customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the WNA. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin per customer independent of both weather and other consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. For further information on the CUT, see Note 3 to the consolidated financial statements.
We invest in joint ventures to complement or supplement income from our regulated utility operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate the project with a major factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding existing joint ventures are based on many factors, including performance results and continued alignment with our business strategies.
Financial Condition and LiquidityWe believe we have access to adequate resources to
To meet our needs for working capital construction expenditures, anticipated debt redemptions and dividend payments. Theseliquidity requirements, we rely on certain resources, include netincluding cash flowflows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank lines of credit.borrowings. We believe that these sources will continue to allow us to meet our needs for working capital, construction expenditures, anticipated debt redemptions and dividend payments.
Cash Flows from Operating Activities.  The natural gas distribution business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations resulting from such factors as weather, natural gas purchases and prices, gas inventory storage activity, collections from customers naturaland deferred gas purchases and gas inventory storage activity.cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first


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and second quarters, we generally haveexperience overall positive cash flows from the sale of flowing gas and gas in storage and the collection of accountsamounts billed to customers. We use this cash to reduce short-term debt to zerocustomers during much of the second and third quarters. We realize most of our annual earnings in the winter period, which is the first five months of our fiscal year.peak heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, paying down short-term debt and decreases in receipts from customers.
 Net
During the peak heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The value of the gas can vary significantly from period to period due to volatility in the price of natural gas, which is a function of market fluctuations in the price of natural gas, along with our changing requirements for storage volumes. Our natural gas costs and amounts due to/from customers represent the difference between natural gas costs that we have paid to suppliers and amounts that we have collected from customers. These natural gas costs can cause cash provided by operating activities was $183.4 millionflows to vary significantly from period to period along with variations in 2005, $183.7 million in 2004 and $103.8 million in 2003. the timing of collections of gas costs under our gas cost recovery mechanisms.
Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower total marginrevenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their consumption. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.
 
Net cash provided by operating activities was $103.8 million in 2006, $183.4 million in 2005 and $183.7 million in 2004. Net cash provided by operating activities reflects a $4.1 million decrease in net income for 2006, compared with 2005, as well as changes in working capital as described below:
• Trade accounts receivable and unbilled utility revenues decreased $19.5 million primarily due to a decrease in volumes sold to customers of 5.5 million dekatherms as compared with the prior year due to the current winter period being 6% warmer than normal and 2% warmer than the similar prior period.
• Amounts due to/from customers increased $54.5 million related to the deferral of gas costs yet to be billed and collected from customers.
• Gas in storage decreased $13.7 million primarily due to decreases in average gas costs and the amount of inventory storage dekatherms in 2006 as compared with 2005.
• Prepaid gas costs decreased $6.6 million primarily due to a decrease in average gas costs. Under asset management agreements, prepaid gas costs during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until November 1, the beginning of the winter period.
• Trade accounts payable decreased $102.5 million this year primarily due to a decrease in the cost of the natural gas commodity.
Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have had a WNA mechanism in place in all three statesSouth Carolina and Tennessee that partially offsets the impact of unusually cold or warm weather on bills rendered in

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November through March for weather-sensitive customers. The WNA in South Carolina and Tennessee generated charges to customers of $8.4$4.1 million in 2006, $3.7 million in 2005 and $2.1$4 million in 2004 and credits to customers of $9.6 million in 2003.2004. In North Carolina and Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or refund to all customers in the class. Effective November 1, 2005, we have a CUT mechanism in North Carolina that provides for any over- or under-collection of approved margin per customer that operates independently of weather or other usage and consumption patterns of residential and commercial customers. The CUT mechanism provided margin of $30.4 million as compared to North Carolina WNA formula calculates the actual weather variance from normal, using 30 yearsthat generated charges to customers of history, which results$4.7 million in an increase2005 and refunds to customers of $1.9 million in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The2004. Our gas cost portion of our costs isare recoverable through purchased gas adjustment (PGA)PGA procedures and isare not affected by the WNA.WNA or the CUT.


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The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is minimalnot significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary.
 In anticipation of higher gas prices for the 2005-2006 winter heating season, we have worked with our regulators to design mechanisms to assist residential customers who experience difficulty in paying their winter bills by expanding the availability of alternative billing arrangements.
We have held educational forumscommission approval in each ofNorth Carolina, South Carolina and Tennessee that places additional credit requirements on the retail natural gas marketers that schedule gas into our jurisdictions, and have communicated via radio and newspaper, to educate customers on winter gas prices and available payment plans and to encourage conservation efforts. In addition, we have established a web site, NaturalGasAnswers.com, to help customers learn how to reduce the cost of heating their homes. We have also asked our representatives in Congress to approve additional funds for Low Income Home Energy Assistance Program funds, and have encouraged our customers to do so also.system.
 
The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, such as price volatility, the availability of natural gas in relation to other energy forms, general economic conditions, weather, energy conservation and the ability to convert from natural gas to other energy sources. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.
 
In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With a tighter balance 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 the policies of foreign and domestic governments.governments and organizations. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers. With significantly higher wholesale gas costs due in part to the recent hurricanes, we anticipate that there may be more fuel switching by large industrial customers in the near term.
Cash Flows from Investing Activities.  Net cash used in investing activities was $167.6 million in 2006, $159 million in 2005 and $65.7 million in 2004 and $522.3 million in 2003. The net2004. Net cash used in investing activities was primarily for utility construction expenditures, and in 2003, the purchases of NCNG and EasternNC.expenditures. Gross utility construction expenditures were $204.1 million in 2006, a 7% increase over the $191.4 million ($157.9in 2005, primarily due to expenditures for the automated meter reading project as well as additions to transmission and distribution mains and transmission plant. Reimbursements from the bond fund decreased $13.9 million netfrom 2005 as construction of

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AFUDC, contributions gas infrastructure in aid of construction and bond reimbursements for EasternNC’s expenditures). As expenditures are made in EasternNC’s service territory, reimbursement requests are made to the State ofeastern North Carolina under orders issued by the NCUC granting EasternNC a total of $188.3 million of bond funds. Such funds are available to pay for the uneconomic portion of the construction of the natural gas distribution infrastructure in the eastern part of the state.has now been completed. For further information about the bond fund, see Note 3 to the consolidated financial statements.
 
We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. Net utility construction expenditures in 2005 were $157.9 million, compared with $103.2 million in 2004 and $80.3 million in 2003. Gross utility construction expenditures totaling $181.2$144.8 million, primarily to serve customer growth, are budgeted for 2006;2007; however, we are not contractually obligated to expend capital until the work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.
 
During 2006, we contributed $23.7 million to Hardy Storage Company LLC, a joint venture investee of one of our non-utility subsidiaries, for construction of a FERC regulated interstate storage facility. On June 29, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility to fund the project. Upon securing this financing, we received $30 million as reimbursement for construction costs we had funded through capital contributions, including the $23.7 million mentioned above. We anticipate contributing $26.6 million to Hardy Storage when the interim notes and revolving equity bridge facility are converted to a mortgage-style note after the project goes in service in April 2007.
During 2006, the restrictions on cash totaling $13.2 million were removed in connection with implementing the NCUC order in the general rate proceeding discussed in Note 4 to the consolidated financial


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statements. As ordered by the NCUC, such cash had been held in an expansion fund to extend natural gas service to unserved areas of the state.
On May 12, 2005, we sold our corporate office building located in Charlotte, North Carolina for $6.7 million in cash, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land as a pre-tax gain of $1.7 million in “Other Income (Expense)” in the consolidated statement of income and a loss of $1.8 million on the disposition of the building as a charge to “Accumulated depreciation” in the consolidated balance sheet, based on the sales price allocation from an independent third party. Under the terms of the purchase and sale agreement, we leased back the building from the new owner until our new office space was ready for occupancy. We relocated to our new office space in November 2005 under a negotiated a ten-year lease with renewable options in a building that we relocated to in November 2005.renewal options. The lease payments for the ten-year term range from $3 million to $3.4 million annually.
 
We received $2.4 million in cash in 2005 from the sale of marketable securities which we received in connection with the sale of our propane interests in 2004.
 
We received $36.1 million in cash in 2004 from the sale of equity method investments, $26.9 million from our investment in US Propane, L.P., and $9.2 million from our investment in Greenbrier Pipeline Company, LLC.
 
In 2003, we acquired 100% of the common stock of NCNG and a 50% equity interest in EasternNC from Progress. In 2005, we acquired the remaining 50% equity interest in EasternNC. These acquisitions were a part of our focus on growing our core utility business. For further information regarding the acquisitions, see Note 1.E and Note 2 to the consolidated financial statements.
Cash Flows from Financing Activities.  Net cash provided by (used in) financing activities was $65.6 million in 2006, $(22.9) million in 2005 and $(123.5) million in 2004 and $424.6 million in 2003.2004. Funds wereare primarily provided from bank borrowings and in 2004 and 2003, the issuance of Common Stockcommon stock through dividend reinvestment and employee stock plans.plans, net of purchases under the common stock repurchase program. Financing activities in 2004 and 2003 also reflect the temporary and permanent financing of the acquisitions of NCNG and EasternNC. When required, we sell Common Stockcommon stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. As of October 31, 2005,2006, our current assets were $504.9$476 million and our current liabilities were $528.6$400.4 million, primarily due to seasonal requirements as discussed above.

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 Under
As of October 31, 2006, we had committed bank lines of credit totaling $250under our new senior credit facility effective April 24, 2006, of $350 million with the ability to expand up to $600 million, for which we pay a maximuman annual fee of $.3 million, outstanding$35,000 plus six basis points for any unused amount up to $350 million. Outstanding short-term borrowings duringincreased from $158.5 million as of October 31, 2005, to $170 million as of October 31, 2006, primarily due to higher gas costs and a slower recovery of customer receivables from an increased number of customers on our equal payment plan, partially offset by the issuance of new long-term debt discussed below. During the twelve months ended October 31, 2006, short-term borrowings ranged from zero to $229.5$378.5 million, and when borrowing, interest rates ranged from 2.11%4.07% to 4.34%5.67% (weighted average of 5.03%).
As of October 31, 2005,2006, we had additional uncommittedletters of credit under the old lines of credit totaling $113of $1.2 million on a no feeissued and as needed, if available, basis. As of January 17,outstanding. On November 1, 2006, we have increased the amount of uncommitted lines to $225 million.
     As of October 31, 2005,under our new credit facility, we had a line of credit foravailable letters of credit of $1.5$5 million of which $1.2$1.4 million werewas issued and outstanding. TheseThe letters of credit are used to guarantee claims from self-insurance under our general liability policies.
 
As of October 31, 2006, unused lines of credit available under our new senior credit facility totaled $180 million. As of November 1, 2006, including the issuance of the letters of credit, unused lines of credit available totaled $178.6 million.
The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high, we may incur more short-term debt to pay for


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natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.
 
During 2005,2006, we issued $23.5$18.4 million of Common Stockcommon stock through dividend reinvestment and stock purchase plans. On April 7, 2006, we entered into an accelerated share repurchase (ASR) program and repurchased and retired 1 million shares of common stock for $23.9 million. On June 6, 2006, we settled the transaction and paid an additional $.4 million. Under the ASR and the Common Stock Open Market Purchase Program discussed in Note 5 to the consolidated financial statements, during 20052006 we paid $26.1$50.2 million for 1.12.1 million shares of Common Stockcommon stock that are available for reissuance to these plans. During 2005, 1.1 million shares were repurchased for $26.1 million.
 
On November 7, 2006, we entered into another ASR where we purchased and retired 1 million shares of our common stock from an investment bank at the closing price of $26.48 per share. Total consideration paid to purchase the shares was $26.6 million, including $118,800 in commission and fees.
Through the ASR program, we will repurchase and subsequently retire approximately four million shares of common stock for a period not to exceed December 31, 2010, including the 1 million shares repurchased in April 2006 and the 1 million shares as repurchased in November 2006. These repurchases are in addition to shares that are repurchased on a normal basis through the open market program.
We increased our Common Stockcommon stock dividend on an annualized basis by $.05 per share in 2006, $.06 per share in 2005 and $.03 per share in 2004 and 2003.2004. Dividends of $72.1 million, $69.4 million and $63.3 million for 2006, 2005 and $54.9 million for 2005, 2004, and 2003, respectively, were paid on Common Stock.common stock. The amount of cash dividends that may be paid on Common Stockcommon stock is restricted by provisions contained in certain note agreements under which long-term debt was issued; however, as of October 31, 2005, none of2006, our retained earnings were not restricted. For further information, see Note 4 to the consolidated financial statements.
 In July
On June 20, 2006, we expectsold $200 million of long-term debt available to makeus under a shelf registration filed with the scheduled paymentSEC. The remaining balance of unused long-term financing available under this shelf registration statement is $109.4 million. This new issuance of long-term debt was used to pay off $188 million of short-term debt on June 20 and to pay off a portion of the sinking fund of $35 million on the 9.44% senior notes. We expect to issue long-term debt in 2006 depending upon our needs for long-term financing and current market conditions.Senior Notes due July 30.
 
As of October 31, 2005,2006, our capitalization including current maturities of long-term debt, consisted of 43%48% in long-term debt and 57%52% in common equity. Our long-term targeted capitalization ratio is45-50% in long-term debt and50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings.
 
As of October 31, 2005,2006, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:
 • Ratio of total debt to total capitalization, including balance sheet leverage,
 
 • Ratio of net cash flows to capital expenditures,
 
 • Funds from operations interest coverage,
 
 • Ratio of funds from operations to average total debt,
• Pension liabilities and funding status, and
• Pre-tax interest coverage.

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Pre-tax interest coverage.
Qualitative factors include, among other things:
 • Stability of regulation in the jurisdictions in which we operate,
 
 •Consistency of our earnings over time,
• Risks and controls inherent in the distribution of natural gas,
 
 • Predictability of cash flows,
 
 •BusinessQuality of business strategy and management,
 
 • Corporate governance guidelines and practices,
 
 • Industry position, and
 
 • Contingencies.
We are subject to default provisions related to our long-term debt and short-term bank lines of credit.borrowings. 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 a90-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.
              FailureThere are cross-default provisions in all of our debt agreements, and thus 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, 2005,2006, we are in compliance with all default provisions.

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As of October 31, 2005,2006, our estimated future contractual obligations were as follows.
Payments Due by Period
                     
  Payments Due by Period 
  Less than
  1-3
  4-5
  After
    
  1 Year  Years  Years  5 Years  Total 
  In thousands 
 
Long-term debt(1) $—  $90,000  $60,000  $675,000  $825,000 
Interest on long-term debt(1)  43,146   128,920   68,230   406,261   646,557 
Pipeline and storage capacity(2)  124,454   402,142   261,636   452,888   1,241,120 
Gas supply(3)  29,539   1,148   —   —   30,687 
Telecommunications and information technology(4)  20,337   74,264   25,801   —   120,402 
Qualified and nonqualified pension plan funding(5)  17,100   46,900   —   —   64,000 
Postretirement benefits plan funding(5)  3,000   6,900   —   —   9,900 
Operating leases(6)  6,316   14,010   7,660   13,641   41,627 
Letter of credit  1,400   4,200   2,800   —   8,400 
Other purchase obligations(7)  28,406   —   —   —   28,406 
                     
Total $273,698  $768,484  $426,127  $1,547,790  $3,016,099 
                     
                     
  Less than  1-3  4-5  After    
In thousands 1 Year  Years  Years  5 Years  Total 
                     
Long-term debt (1) $35,000  $30,000  $120,000  $475,000  $660,000 
Interest on long-term debt (1)  45,927   129,968   77,989   438,601   692,485 
Pipeline and storage capacity (2)  121,169   345,968   223,470   350,952   1,041,559 
Gas supply (3)  13,351   484   —   —   13,835 
Telecommunications and information technology (4)  14,447   47,545   17,361   —   79,353 
Defined-benefit pension plan funding (5)  15,300   45,700   —   —   61,000 
Postretirement benefits plan funding (5)  2,600   6,300   —   —   8,900 
Operating leases (6)  7,143   15,792   8,846   17,652   49,433 
Other purchase obligations (7)  19,811   —   —   —   19,811 
                
Total $274,748  $621,757  $447,666  $1,282,205  $2,626,376 
                
 
(1)See Note 4 to the consolidated financial statements.
 
(2)100% recoverable through purchased gas adjustment (PGA) procedures.
 
(3)Reservation fees that are 100% recoverable through PGA procedures.
 
(4)Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees and contract labor and consulting fees.
 
(5)Estimated funding beyond three years is not available. See Note 8 to the consolidated financial statements.
 
(6)See Note 7 to the consolidated financial statements.
 
(7)Consists primarily of pipeline products, vehicles, contractors and merchandise.
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than operating leases that are reflected in the table above and discussed in Note 7 to the consolidated financial statements.
Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves levels of performance and credit risk that are not included on our consolidated balance sheets. The possibility of having to perform on the guaranty is largely dependent upon the future operations of the joint venture, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 11 to the consolidated financial statements.
Critical Accounting Policies and Estimates
We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.


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Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, goodwill and pension and postretirement benefits to be our critical accounting estimates. Management has discussed the selection and development of the critical accounting policies and estimates presented below with the Audit Committee of the Board of Directors.
Regulatory Accounting.  Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For Thefor the Effects of Certain Types of Regulation” (Statement 71), and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues inon the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from

22

the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded. Regulatory assets as of October 31, 2006 and 2005, and 2004, totaled $85.8$143.5 million and $59.3$85.8 million, respectively. Regulatory liabilities as of October 31, 2006 and 2005, and 2004, totaled $333.3$337 million and $320.2$333.3 million, respectively. The detail of these regulatory assets and liabilities is presented in Note 1.B to the consolidated financial statements.
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 procedures. Through October 31, 2005, a WNA factor, based on the margin or base rate component of the billing rate, iswas included in rates charged to residential and commercial customers during the winter period of November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact that unusually coldofwarmer-than-normal or warmcolder-than-normal weather has on customer billings during the winter season. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin per customer independent of both weather and other consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over- collection or recover any under-collection. Without the WNA or CUT, our operating revenues in 20052006 would have been lower by $8.4$34.6 million.
 
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. Meters are read throughout the month based on an approximate30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. 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.WNA or CUT mechanisms, as applicable. Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on contract or market prices.
Goodwill.  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


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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.

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Our annual goodwill impairment assessment was performed on October 31, 2006, and we determined that there was no impairment to the carrying value of our goodwill. In addition, there were no impairment indicators during 2006.
Using a discounted cash flow model to estimate fair value is subjective and requires significant judgment in applying a discount rate, growth assumptions and continued cash flows. An increase or decrease of 100 basis points in the weighted average cost of capital would have the following effects.
                
In thousands 100 Basis Point Increase 100 Basis Point Decrease  100 Basis Point Increase 100 Basis Point Decrease
 
Change in fair value of the regulated utility segment $(198,000)  $294,000  $(155,000) $220,000 
The 100 basis point increase or decrease in the weighted average cost of capital would not have required the recording of an impairment charge.
Pension and Postretirement Benefits.  We have a defined-benefit pension plan for the benefit of eligible full-time employees. We also provide certain postretirement health care and life insurance benefits to eligible full-time employees. Our reported costs of providing these benefits, as described in Note 8 to the consolidated financial statements, are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.
 
Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.
 
The discount rate in 2005 washas been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s AA or better-rated non-callable bonds. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plans changed from 6.25%6% in 20032005 to 5.78% in 2006. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 5.75% in 2004 and 6%2005 to 5.67% in 2005.2006. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 6.25% in 2003 to 5.75% in 2004 and 5.89% in 2005.2005 to 5.74% in 2006. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we changed our health care cost trend rate from 10% in 2003 to 10.5% in 2004 and 9.75% in 2005 to 9% in 2006, declining gradually to 5% in 2012.
 
In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 60% equity securities and 40% fixed income securities. The expected long-term rate of return ofon plan assets was 8.5% in 2003, 2004, 2005 and 2005,2006, and will be maintained at 8.5% in 2006.2007. Based on a fairly stagnant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.97% in 20032004 and 2004, but2005, and increased to 4.05% in 20052006 due to a change in the demographics of the participants.

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The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plans, assuming that the other components of the calculation are constant.
                        
     Impact on
 
In thousands Change in Impact on 2005 Impact on Projected 
 Change in
 Impact on 2006
 Projected
 
Actuarial Assumption Assumption Pension Cost Benefit Obligation  Assumption Pension Cost Benefit Obligation 
 Increase (Decrease) 
 Increase (Decrease)  In thousands 
 
Discount rate  (.25%) $518 $6,253   (.25)% $558  $6,546 
Rate of return on plan assets  (.25%) 488 N/A   (.25)%  503   N/A 
Rate of increase in compensation  .25% 868 3,951   .25%  841   4,332 
 
The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.
                        
   Impact on      Impact on
 
 Impact on Accumulated    Impact on 2006
 Accumulated
 
In thousands Change in 2005 Postretirement Postretirement 
 Change in
 Postretirement
 Postretirement
 
Actuarial Assumption Assumption Benefit Cost Benefit Obligation  Assumption Benefit Cost Benefit Obligation 
 Increase (Decrease) 
 Increase (Decrease)  In thousands 
 
Health care cost trend rate  .25% $26 $256   .25% $51  $318 
Rate of return on plan assets  (.25%) 67 N/A   (.25)%  37   N/A 
Discount rate  (.25%) 72 711   (.25)%  161   719 
 
We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Gas Supply and Regulatory Proceedings
We continue to pursue the diversification of our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have a firm transportation contract pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. TheDue to regulatory delays impacting commencement of construction, we have only contracted for 40,000 of the total 120,000 dekatherms per day of capacity for the winter of2006-2007 with the difference being covered by short-term firm winter arrangements. It is anticipated in-service date is November 2006.that the entire capacity will be available during the2007-2008 winter. We have also executed an agreement with Hardy Storage Company LLC for market-area storage capacity in West Virginia with an anticipated in-service date in April 2007. We have a 50% equity interest in this project which is more fully discussed in Note 1011 to the consolidated financial statements.
 
Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smallerper-unit wholesale margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. In North Carolina and South Carolina, a sharing mechanism is in effect where 75% of any margin earned is refundedpassed through to customers. Secondary market transactions in Tennessee are included in the performance incentive plan discussed in Note 3 to the consolidated financial statements.
 Rate
Regulatory proceedings in NorthSouth Carolina andunder the South Carolina Rate Stabilization Act were completed during 20052006 that will impact 20062007 earnings. Proceedings in both states adopted new approaches to ratemaking design. For further information about these regulatory proceedings and other regulatory information, see Note 3 to the consolidated financial statements.

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Equity Method Investments
For information about our equity method investments, see Note 1011 to the consolidated financial statements.
Environmental Matters
We have developed an environmental self-assessment plan to assess our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 1213 to the consolidated financial statements.
Accounting Pronouncements
In December 2004,March 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We will adopt Statement 123R on November 1, 2005, and amend our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R will not have a material effect on our financial position or results of operations.
     In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” FIN 47 requires that a liability be recognized for the fair value of a conditional asset retirement obligation (ARO) when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly,As of October 31, 2006, we will adoptadopted FIN 47 no later thanand recorded an asset retirement cost of $7 million as part of “Utility Plant,” a liability for the conditional asset retirement obligation of $19.1 million and a regulatory asset of $12.1 million. We received regulatory approval to establish a regulatory asset for the accumulated accretion expense and accumulated depreciation. Consequently, the adoption of FIN 47 did not have an impact on our fourth fiscal quarterresults of operations or cash flows. Additionally, had FIN 47 been applied to the prior year presented with this report, the conditional ARO would have been $17.1 million and $18.1 million at November 1, 2004 and October 31, 2005, respectively. In accordance with FIN 47, such amounts are not reflected in the balance sheet as of October 31, 2005.
In June 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. This interpretation is effective the beginning of the first annual period commencing after December 15, 2006. We are currently assessing the impact FIN 4748 may have on our consolidated balance sheet;financial statements; however, we believe the adoption of FIN 4748 will not have a material impact on our financial position, results of operations or cash flows.
Forward-Looking StatementsDocuments
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not expand the use of fair value in any new circumstances. Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under Statement 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. Accordingly, we file withwill adopt Statement 157 no later than our first fiscal quarter in 2008. We believe the Securities and Exchange Commission (SEC) may contain forward-looking statements. In addition,adoption of Statement 157 will not have a material effect on our senior management and other authorized spokespersons may make forward-looking statements in printfinancial position, results of operations or orally to analysts, investors, the media and others. Forward-looking statements concern, among others, plans, objectives, proposed capital expenditures and future events or performance. These statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include:
Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our effectiveness in achieving the allowed rates of return and initiate rate proceedings or operating changes as needed. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated.
cash flows.

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•Residential, commercial and industrial growth in our service areas. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.
•Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies and we expect this highly competitive environment to continue.
•The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts at lower per-unit margins.
•Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.
•The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our internally generated cash flows are not adequate to finance the full cost of this construction. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations.
•Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.
•Impact of the Energy Policy Act of 2005. Key components of the bill include provisions that encourage fuel diversity in the generation of electricity, provide incentives promoting energy efficiency and innovative technology, allow an inventory of energy reserves in the Outer Continental Shelf and support Liquified Natural Gas (LNG) imports and improved leasing and permitting processes in the development of existing supply fields. The effect of this legislation on our future operations is unknown.
•Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.
•Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.
•Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

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•Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.
•Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses and we assume such risks as an equity investor.
     AllIn September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158). Statement 158 requires an employer to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in the financial statements by recognizing in its statement of these factors are difficultfinancial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status rather than only disclosing the funded status in the footnotes to predict and many are beyond our control. Accordingly, while we believe the assumptions underlying our forward-looking statementsfinancial statements. Statement 158 requires employers to recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Those changes will be reasonable, there can be no assurance that these statements will approximate actual experience orreported in accumulated other comprehensive income (OCI) in the stockholders’ equity section of the balance sheet. Statement 158 also requires that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “seek,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal” or similar words or future or conditional verbs suchcompany measure a plan’s assets and its obligations that determine its funded status as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.
     Factors relating to regulation and management also may be described or incorporated by reference in future filings with the SEC. Some of the factors that may cause actual resultsend of the employer’s fiscal year.
Statement 158 provides different effective dates for the recognition and related disclosure provisions and for the required change to differ have been described above. Others may be described elsewhere in this report. There may also be other factors besides those described above that could cause actual conditions, events or resultsa fiscal year-end measurement date. The requirement to differ from those inrecognize the forward-looking statements.
     Forward-looking statements reflect our current expectations onlyfunded status of a benefit plan and the related disclosure requirements initially will apply as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date they are made.of the employer’s fiscal year end statement of financial position will be effective for fiscal years ending after December 15, 2008, and will not be applied retrospectively. Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. The measurement date portion of Statement 158 does not apply to us because our pension plan measurement date is already the same as our fiscal year end date. We assume no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. Please reference our web site at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no costbelieve the adoption of Statement 158 will not have a material effect on our web sitefinancial position, results of operations or cash flows.
If Statement 158 had been adopted for the current year ended October 31, 2006, the effect on the consolidated balance sheets would have been a non-cash charge of $42.3 million as soon as reasonably practicable aftera regulatory asset of $25.6 million and deferred income taxes of $16.7 million with a reduction of $14.6 million to prepaid pension and an increase in accrued postretirement benefits of $27.7 million. The actual charge at October 31, 2007, could be substantially different depending on the report is fileddiscount rate, asset returns and plan population at that time. Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any regulatory asset or liability that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. We intend to meet with or furnishedour regulators in fiscal year 2007 to discuss the SEC.
Item 7A. Quantitativeregulatory accounting and Qualitative Disclosures about Market Riskrate treatment of Statement 158.
 
Item 7A.  Quantitative and Qualitative Disclosures about Market Risk
We hold all financial instruments discussed below for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Our exposure to interest rate changes relates primarily to short-term debt. We are exposed to interest rate changes to long-term debt when we are in the market to issue long-term debt. As of October 31, 2005,2006, all of our long-term debt was issued at fixed rates. Exposure to gas cost variations relates to the wholesale supply, demand and price of natural gas.
Interest Rate Risk
 
We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period depending upon many factors, including our investments in capital projects. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.
 
As of October 31, 2005,2006, we had $158.5$170 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 4.28%5.57%. The carrying amount of our short-term debt approximates fair value. During 2005, suchA change of 100 basis points in the underlying average interest rate for our short-term debt outstanding ranged from zero to $229.5would have caused a change in interest expense of approximately $1.8 million with interest rates from 2.11% to 4.34%.during 2006.

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     Information asAs of October 31, 2005,2006, information about our long-term debt that, for holders of our long-term debt, is sensitive to changes in interest rates is presented below.
                                              
 Expected Maturity Date Fair Value as                Fair Value as
 
 There- of October 31,  Expected Maturity Date of October 31,
 
In millions 2006 2007 2008 2009 2010 after Total 2005 
 2007 2008 2009 2010 2011 Thereafter Total 2006 
 In millions 
 
Fixed Rate Long-term Debt $35 $— $— $30 $60 $535 $660 $753  $—  $—  $30  $60  $60  $675  $825  $914 
Average Interest Rate  9.44% — —  7.35%  7.80%  6.77%  7.03%   —   —   7.35%  7.80%  6.55%  6.64%  6.74%    
Commodity Price Risk
 
In the normal course of business, we utilize exchange-traded contracts of various duration for the forward sale and purchase of a portion of our natural gas requirements. We also manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. Due to cost-based rate regulation in our utility operations, we have limited financial exposure to changes in commodity prices as substantiallyhistorically we have recovered all changes in purchased gas costs and the costs of hedging our gas supplies are passed on to customers through PGA mechanisms.
Materials Riskprocedures.
 Our supply of plastic pipe was affected by the August and September 2005 hurricanes in the Gulf Coast region as the pipe is a petroleum product. One of our suppliers evoked force majeure and placed all of its customers on an allocation program. Our allocation was increased in November and December 2005 and is expected to be at a normal level by early 2006. We have avoided any stock outages by relocating inventory within our service areas and by receiving additional allotments from vendors.
Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of thisForm 10-K.
Item 8. Financial Statements and Supplementary Data
 
Item 8.  Financial Statements and Supplementary Data
Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of thisForm 10-K on page 74.73.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.
 
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (“Piedmont”) as of October 31, 20052006 and 2004,2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2005.2006. These financial statements are the responsibility of Piedmont’s management. Our responsibility is to express an opinion on the financial statements 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, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 20052006 and 2004,2005, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 20052006 in conformity with accounting principles generally accepted in the United States of America.
 As discussed in Note 13, the accompanying 2004 and 2003 financial statements have been restated.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Piedmont’s internal control over financial reporting as of October 31, 2005,2006, based on the criteria established inInternal Control—Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated January 17, 200612, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of Piedmont’s internal control over financial reporting and an unqualified opinion on the effectiveness of Piedmont’s internal control over financial reporting.
/s/  Deloitte & Touche LLP
Charlotte, North Carolina
January 17, 200612, 2007

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Piedmont Natural Gas Company, Inc.
 
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Consolidated Balance Sheets
October 31, 20052006 and 20042005
Assets
         
  2006  2005 
  In thousands 
 
ASSETS
Utility Plant:        
Utility plant in service $2,714,606  $2,532,263 
Less accumulated depreciation  733,682   672,502 
         
Utility plant in service, net  1,980,924   1,859,761 
Construction work in progress  94,386   79,314 
         
Total utility plant, net  2,075,310   1,939,075 
         
Other Physical Property, at cost (net of accumulated depreciation of $2,040 in 2006 and $1,888 in 2005)  1,154   731 
         
Current Assets:        
Cash and cash equivalents  8,886   7,065 
Restricted cash  —   13,108 
Trade accounts receivable (less allowance for doubtful accounts of $1,239 in 2006 and $1,188 in 2005)  90,493   107,535 
Income taxes receivable  30,849   21,570 
Other receivables  160   12,102 
Unbilled utility revenues  45,938   48,414 
Inventories:        
Gas in storage  138,183   151,865 
Materials, supplies and merchandise  6,221   5,331 
Gas purchase options, at fair value  3,147   22,843 
Amounts due from customers  89,635   52,161 
Prepayments  62,356   62,821 
Other  96   96 
         
Total current assets  475,964   504,911 
         
Investments, Deferred Charges and Other Assets:        
Equity method investments in non-utility activities  75,330   71,520 
Goodwill  47,383   47,383 
Unamortized debt expense  11,306   4,822 
Regulatory cost of removal asset  12,086   — 
Other  35,406   34,048 
         
Total investments, deferred charges and other assets  181,511   157,773 
         
Total $2,733,939  $2,602,490 
         
 
CAPITALIZATION AND LIABILITIES
Capitalization:        
Stockholders’ equity:        
Cumulative preferred stock — no par value — 175 shares authorized $—  $— 
Common stock — no par value — shares authorized: 200,000 in 2006 and 100,000 in 2005; shares outstanding: 75,464 in 2006 and 76,698 in 2005  532,764   562,880 
Paid-in capital
  56   — 
Retained earnings  348,765   323,565 
Accumulated other comprehensive income (loss)  1,340   (2,253)
         
Total stockholders’ equity  882,925   884,192 
Long-term debt  825,000   625,000 
         
Total capitalization  1,707,925   1,509,192 
         
Current Liabilities:        
Current maturities of long-term debt  —   35,000 
Notes payable  170,000   158,500 
Trade accounts payable  80,304   182,847 
Other accounts payable  50,935   45,325 
Income taxes accrued  1,184   6,201 
Accrued interest  21,273   16,491 
Customers’ deposits  22,308   20,162 
Deferred income taxes  25,085   23,128 
General taxes accrued  18,522   16,450 
Amounts due to customers  123   17,124 
Other  10,655   7,336 
         
Total current liabilities  400,389   528,564 
         
Deferred Credits and Other Liabilities:        
Deferred income taxes  235,411   213,050 
Unamortized federal investment tax credits  3,417   3,951 
Cost of removal obligations  330,104   288,989 
Other  56,693   58,744 
         
Total deferred credits and other liabilities  625,625   564,734 
         
Total $2,733,939  $2,602,490 
         
         
In thousands 2005  2004 
      (As Restated - 
      See Note 13) 
         
Utility Plant:        
Utility plant in service $2,532,263  $2,395,588 
Less accumulated depreciation  672,502   624,973 
       
Utility plant in service, net  1,859,761   1,770,615 
Construction work in progress  79,314   79,302 
       
Total utility plant, net  1,939,075   1,849,917 
       
         
Other Physical Property, at cost (net of accumulated depreciation of $1,888 in 2005 and $1,782 in 2004)  731   973 
       
         
Current Assets:        
Cash and cash equivalents  7,065   5,676 
Restricted cash  13,108   12,732 
Marketable securities, at market value  —   1,857 
Trade accounts receivable (less allowance for doubtful accounts of $1,188 in 2005 and $1,086 in 2004)  107,535   86,486 
Income taxes receivable  21,570   28,282 
Other receivables  12,102   4,223 
Unbilled utility revenues  48,414   25,711 
Inventories:        
Gas in storage  151,865   128,465 
Materials, supplies and merchandise  5,331   4,727 
Gas purchase options, at fair value  22,843   13,182 
Amounts due from customers  52,161   28,832 
Prepayments  62,821   50,473 
Other  96   96 
       
Total current assets  504,911   390,742 
       
         
Investments, Deferred Charges and Other Assets:        
Equity method investments in non-utility activities  71,520   65,322 
Goodwill  47,383   48,151 
Unamortized debt expense  4,822   5,261 
Other  34,048   31,798 
       
Total investments, deferred charges and other assets  157,773   150,532 
       
         
Total $2,602,490  $2,392,164 
       
See notes to consolidated financial statements.

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CapitalizationPiedmont Natural Gas Company, Inc.
Consolidated Statements of Income
For the Years Ended October 31, 2006, 2005 and Liabilities2004
         
In thousands 2005  2004 
      (As Restated - 
      See Note 13) 
         
Capitalization:        
Stockholders’ equity:        
Cumulative preferred stock — no par value — 175 shares authorized $—  $— 
Common stock — no par value — 100,000 shares authorized; outstanding, 76,698 shares in 2005 and 76,670 shares in 2004  562,880   563,667 
Retained earnings  323,565   291,397 
Accumulated other comprehensive income (loss)  (2,253)  (166)
       
Total stockholders’ equity  884,192   854,898 
Long-term debt  625,000   660,000 
       
Total capitalization  1,509,192   1,514,898 
       
         
Current Liabilities:        
Current maturities of long-term debt  35,000   — 
Notes payable  158,500   109,500 
Trade accounts payable  182,847   83,895 
Other accounts payable  45,325   47,712 
Income taxes accrued  6,201   5,259 
Customers’ deposits  20,162   18,018 
Deferred income taxes  23,128   6,416 
General taxes accrued  16,450   17,097 
Amounts due to customers  17,124   26,379 
Other  23,827   21,879 
       
Total current liabilities  528,564   336,155 
       
         
Deferred Credits and Other Liabilities:        
Deferred income taxes  213,050   212,925 
Unamortized federal investment tax credits  3,951   4,492 
Regulatory cost of removal obligations  288,989   266,700 
Other  58,744   56,994 
       
Total deferred credits and other liabilities  564,734   541,111 
       
         
Total $2,602,490  $2,392,164 
       
             
  2006  2005  2004 
  In thousands except per share amounts 
 
Operating Revenues $1,924,628  $1,761,091  $1,529,739 
Cost of Gas  1,401,149   1,261,952   1,041,370 
             
Margin  523,479   499,139   488,369 
             
Operating Expenses:            
Operations and maintenance  219,353   206,983   200,282 
Depreciation  89,696   85,169   82,276 
General taxes  33,138   29,807   27,011 
Income taxes  50,543   51,880   51,485 
             
Total operating expenses  392,730   373,839   361,054 
             
Operating Income  130,749   125,300   127,315 
             
Other Income (Expense):            
Income from equity method investments  29,917   27,664   27,381 
Gain on sale of equity method investments  —   —   4,683 
Gain on sale of marketable securities  —   1,525   — 
Allowance for equity funds used during construction  —   —   946 
Non-operating income  1,147   3,830   2,285 
Charitable contributions  (321)  (1,717)  (9,124)
Non-operating expense  (106)  (28)  (324)
Income taxes  (11,887)  (10,446)  (10,562)
             
Total other income (expense), net of tax  18,750   20,828   15,285 
             
Utility Interest Charges:            
Interest on long-term debt  49,915   46,173   44,957 
Allowance for borrowed funds used during construction  (3,893)  (3,137)  (1,669)
Other  6,288   1,220   4,076 
             
Total utility interest charges  52,310   44,256   47,364 
             
Income before Minority Interest in Income of Consolidated Subsidiary  97,189   101,872   95,236 
Less Minority Interest in Income of Consolidated Subsidiary  —   602   48 
             
Net Income $97,189  $101,270  $95,188 
             
Average Shares of Common Stock:            
Basic  75,863   76,680   74,359 
Diluted  76,156   76,992   74,797 
Earnings Per Share of Common Stock:            
Basic $1.28  $1.32  $1.28 
Diluted $1.28  $1.32  $1.27 
See notes to consolidated financial statements.

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Piedmont Natural Gas Company, Inc.
Consolidated Statements of IncomeCash Flows
For the Years Ended October 31, 2006, 2005 2004 and 20032004
             
In thousands except per share amounts 2005  2004  2003 
             
Operating Revenues $1,761,091  $1,529,739  $1,220,822 
Cost of Gas  1,261,952   1,041,370   837,942 
          
             
Margin  499,139   488,369   382,880 
          
             
Operating Expenses:            
Operations and maintenance  206,983   200,282   152,107 
Depreciation  85,169   82,276   63,164 
General taxes  29,807   27,011   24,410 
Income taxes  51,880   51,485   40,093 
          
             
Total operating expenses  373,839   361,054   279,774 
          
             
Operating Income  125,300   127,315   103,106 
          
             
Other Income (Expense):            
Income from equity method investments  27,664   27,381   17,972 
Gain on sale of equity method investments  —   4,683   — 
Gain on sale of marketable securities  1,525   —   — 
Allowance for equity funds used during construction  —   946   1,128 
Non-operating income  3,830   2,285   2,560 
Charitable contributions  (1,717)  (9,124)  (692)
Non-operating expense  (28)  (324)  (171)
Income taxes  (10,446)  (10,562)  (8,524)
          
             
Total other income (expense), net of tax  20,828   15,285   12,273 
          
             
Utility Interest Charges:            
Interest on long-term debt  46,173   44,957   37,740 
Allowance for borrowed funds used during construction  (3,137)  (1,669)  (1,135)
Other  1,220   4,076   3,592 
          
             
Total utility interest charges  44,256   47,364   40,197 
          
             
Income before Minority Interest in Income of Consolidated Subsidiary  101,872   95,236   75,182 
             
Less Minority Interest in Income of Consolidated Subsidiary  602   48   820 
          
             
Net Income $101,270  $95,188  $74,362 
          
             
Average Shares of Common Stock:            
Basic  76,680   74,359   66,782 
Diluted  76,992   74,797   67,007 
             
Earnings Per Share of Common Stock:            
Basic $1.32  $1.28  $1.11 
Diluted $1.32  $1.27  $1.11 
             
  2006  2005  2004 
  In thousands 
 
Cash Flows from Operating Activities:            
Net income $97,189  $101,270  $95,188 
             
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation and amortization  94,111   91,677   87,336 
Amortization of investment tax credits  (534)  (541)  (550)
Allowance for doubtful accounts  51   102   (1,658)
Allowance for funds used during construction  (3,893)  (3,137)  (2,615)
Gain on sale of corporate office land  —   (1,659)  — 
Earnings from equity method investments  (29,917)  (27,664)  (27,381)
Distributions of earnings from equity method investments  28,442   23,649   26,078 
Gain on sale of equity method investments  —   —   (4,683)
Gain on sale of marketable securities  —   (1,525)  — 
Deferred income taxes  22,021   18,278   17,835 
Changes in assets and liabilities:            
Receivables  19,395   (43,214)  (6,683)
Inventories  12,791   (24,004)  (6,695)
Amounts due from customers  (37,474)  (23,329)  (13,750)
Other assets  7,581   (20,164)  (18,221)
Accounts payable  (94,095)  94,530   8,941 
Amounts due to customers  (17,001)  (9,255)  5,163 
Other liabilities  5,146   8,362   25,434 
             
Total adjustments  6,624   82,106   88,551 
             
Net cash provided by operating activities  103,813   183,376   183,739 
             
Cash Flows from Investing Activities:            
Utility construction expenditures  (204,116)  (191,407)  (139,146)
Reimbursements from bond fund  15,955   29,841   41,497 
Contributions to equity method investments  (23,696)  (6,162)  (113)
Distributions of capital from equity method investments  28,968   695   213 
Proceeds from sale of corporate office building and land  —   6,660   — 
Proceeds from sale of marketable securities  —   2,394   — 
Proceeds from sale of equity method investments  —   —   36,096 
Purchase of NCNG and EasternNC (working capital adjustment)  —   —   (271)
Decrease (increase) in restricted cash  13,108   (376)  (5,983)
Other  2,227   (683)  1,958 
             
Net cash used in investing activities  (167,554)  (159,038)  (65,749)
             
Cash Flows from Financing Activities:            
Increase in notes payable, net of expenses of $405 in 2006  11,095   49,000   — 
Decrease in commercial paper  —   —   (445,559)
Proceeds from issuance of long-term debt, net of expenses  193,360   —   197,981 
Retirement of long-term debt  (35,000)  —   (2,000)
Proceeds from sale of common stock, net of expenses  —   —   173,828 
Issuance of common stock through dividend reinvestment and employee stock plans  18,377   23,536   20,018 
Repurchases of common stock  (50,163)  (26,119)  (4,487)
Dividends paid  (72,107)  (69,366)  (63,267)
             
Net cash provided by (used in) financing activities  65,562   (22,949)  (123,486)
             
Net Increase (Decrease) in Cash and Cash Equivalents  1,821   1,389   (5,496)
Cash and Cash Equivalents at Beginning of Year  7,065   5,676   11,172 
             
Cash and Cash Equivalents at End of Year $8,886  $7,065  $5,676 
             
Cash Paid During the Year for:            
Interest $54,669  $48,888  $43,868 
Income taxes  56,615   35,888   44,396 
       
Noncash Investing and Financing Activities:            
Accrued construction expenditures $2,837  $2,036  $2,615 
Guaranty  1,820   —   — 
See notes to consolidated financial statements.

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Piedmont Natural Gas Company, Inc.
 
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35

Consolidated Statements of Cash FlowsStockholders’ Equity
For the Years Ended October 31, 2006, 2005 2004 and 20032004
             
In thousands 2005  2004  2003 
      (As Restated - See Note 13) 
 
Cash Flows from Operating Activities:            
Net income $101,270  $95,188  $74,362 
          
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation and amortization  91,677   87,336   66,782 
Amortization of investment tax credits  (541)  (550)  (550)
Allowance for doubtful accounts  102   (1,658)  536 
Allowance for funds used during construction  (3,137)  (2,615)  (2,263)
Gain on sale of corporate office land  (1,659)  —   — 
Earnings from equity method investments  (27,664)  (27,381)  (17,972)
Distributions of earnings from equity method investments  23,649   26,078   9,946 
Gain on sale of equity method investments  —   (4,683)  — 
Gain on sale of marketable securities  (1,525)  —  — 
Deferred income taxes  18,278   17,835   46,865 
Changes in assets and liabilities:            
Receivables  (43,214)  (6,683)  (37,570)
Inventories  (24,004)  (6,695)  (34,547)
Amounts due from customers  (23,329)  (13,750)  (8,905)
Other assets  (20,164)  (18,221)  (24,087)
Accounts payable  94,530   8,941   10,591 
Amounts due to customers  (9,255)  5,163   11,177 
Other liabilities  8,362   25,434   9,425 
          
             
Total adjustments  82,106   88,551   29,428 
          
             
Net cash provided by operating activities  183,376   183,739   103,790 
          
             
Cash Flows from Investing Activities:            
Utility construction expenditures  (191,407)  (139,146)  (78,163)
Reimbursements from bond fund  29,841   41,497   3,762 
Contributions to equity method investments  (6,162)  (113)  (2,224)
Distributions of capital from equity method investments  695   213   242 
Proceeds from sale of corporate office building and land  6,660   —   — 
Proceeds from sale of marketable securities  2,394   —   — 
Proceeds from sale of equity method investments  —   36,096   — 
Purchase of gas distribution system  —   —   2,153 
Purchase of NCNG and EasternNC, net in 2003 of cash received of $7,185  —   (271)  (450,168)
Decrease (increase) in restricted cash  (376)  (5,983)  1,936 
Other  (683)  1,958   172 
          
             
Net cash used in investing activities  (159,038)  (65,749)  (522,290)
          
             
Cash Flows from Financing Activities:            
Increase in notes payable  49,000   —   63,000 
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)
Proceeds from sale of common stock, net of expenses  —   173,828   — 
Issuance of common stock through dividend reinvestment and employee stock plans  23,536   20,018   17,925 
Repurchases of common stock  (26,119)  (4,487)  — 
Dividends paid  (69,366)  (63,267)  (54,912)
          
             
Net cash provided by (used in) financing activities  (22,949)  (123,486)  424,572 
          
             
Net Increase (Decrease) in Cash and Cash Equivalents  1,389   (5,496)  6,072 
Cash and Cash Equivalents at Beginning of Year  5,676   11,172   5,100 
          
             
Cash and Cash Equivalents at End of Year $7,065  $5,676  $11,172 
          
             
Cash Paid During the Year for:            
Interest $48,888  $43,868  $40,268 
Income taxes  35,888   44,396   30,554 

36

                         
           Accumulated
       
           Other
       
  Common
  Paid-in
  Retained
  Comprehensive
       
  Stock  Capital  Earnings  Income (Loss)  Total    
  In thousands except per share amounts 
 
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 from hedging activities of equity method investments, net of tax of $292              381         
Reclassification adjustment of realized loss from hedging activities of equity method investments 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     
                         
Comprehensive Income:                        
Net income          101,270       101,270     
Other comprehensive income:                        
Reclassification adjustment of realized gain on marketable securities included in net income, net of tax of ($391)              (597)        
Unrealized gain from hedging activities of equity method investments, net of tax of $287              436         
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($1,280)              (1,926)  (2,087)    
                         
Total comprehensive income                  99,183     
Common Stock Issued  25,332               25,332     
Common Stock Repurchased  (26,119)              (26,119)    
Tax Benefit from Dividends Paid on ESOP Shares          264       264     
Dividends Declared ($.905 per share)          (69,366)      (69,366)    
                         
Balance, October 31, 2005  562,880   —   323,565   (2,253)  884,192     
                         
Comprehensive Income:                        
Net income          97,189       97,189     
Other comprehensive income:                        
Minimum pension liability, net of tax of ($51)              (78)        
Unrealized gain from hedging activities of equity method investments, net of tax of $3,013              4,644         
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($665)              (973)  3,593     
                         
Total comprehensive income                  100,782     
Common Stock Issued  20,047               20,047     
Common Stock Repurchased  (50,163)              (50,163)    
Share-Based Compensation Expense      56           56     
Tax Benefit from Dividends Paid on ESOP Shares          118       118     
Dividends Declared ($.95 per share)          (72,107)      (72,107)    
                         
Balance, October 31, 2006 $532,764  $56  $348,765  $1,340  $882,925     
                         

             
In thousands 2005  2004  2003 
      (As Restated - See Note 13) 
Noncash Investing and Financing Activities:            
Accrued construction expenditures $2,036  $2,615  $872 
 
Acquisitions of NCNG and EasternNC:            
Fair 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.

37

Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2005, 2004 and 2003
                 
          Accumulated    
          Other    
  Common  Retained  Comprehensive    
In thousands except per share amounts Stock  Earnings  Income (Loss)  Total 
                 
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 from hedging activities of equity method investments, net of tax of ($869)          (1,326)    
Reclassification adjustment of realized loss from hedging activities of equity method investments 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 from hedging activities of equity method investments, net of tax of $292          381     
Reclassification adjustment of realized loss from hedging activities of equity method investments 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 
                
                 
Comprehensive Income:                
Net income      101,270       101,270 
Other comprehensive income:                
Reclassification adjustment of realized gain on marketable securities included in net income, net of tax of ($391)          (597)    
Unrealized gain from hedging activities of equity method investments, net of tax of $287          436     
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($1,280)          (1,926)  (2,087)
                
Total comprehensive income              99,183 
Common Stock Issued  25,332           25,332 
Common Stock Repurchased  (26,119)          (26,119)
Tax benefit from dividends paid on ESOP shares      264       264 
Dividends Declared ($.905 per share)      (69,366)      (69,366)
             
                 
Balance, October 31, 2005 $562,880  $323,565  $(2,253) $884,192 
             

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The components of accumulated other comprehensive income (loss) as of October 31, 20042006 and 2005, are as follows.
                
In thousands 2004 2005 
  2006 2005 
 In thousands 
Minimum pension liability $(78) $— 
Unrealized gain (loss) from hedging activities of equity method investments $(763) $(2,253)  1,418   (2,253)
Unrealized gain on marketable securities 597 — 
          
Accumulated other comprehensive income (loss) $(166) $(2,253) $1,340  $(2,253)
          
See notes to consolidated financial statements.statements

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36

 

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation.
 
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 and intrastate natural gas transportation. 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, through October 25, 2005, its 50% equity interest in Eastern North Carolina Natural Gas Company (EasternNC). On October 25, 2005, we purchased the remaining 50% interest in EasternNC and merged it into Piedmont. See Note 2 to the consolidated financial statements for further information on acquisitions.
 
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 method investments are recorded in “Income from equity method investments” in the consolidated statements of income. For further information on equity method investments, see Note 1011 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” 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 and costs from 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, in order to provide for recovery from or refund to utility customers in future periods.
 We monitor
Our regulatory assets are recoverable through either rate riders or base rates specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the regulatory and competitive environmentperiod the rates are in which we operate to determine thateffect. As such, all of our regulatory assets continueare subject to be probable of recovery. If we were to determinereview by the respective state regulatory commission during any future rate proceedings. In the event that all or a portion of these regulatory assets no longer met the criteria for continued applicationprovisions of Statement 71 were no longer applicable, we would write offrecognize a write-off of net regulatory assets (regulatory assets less regulatory liabilities) that portion whichwould result in a change to net income. However, although the natural gas distribution industry is becoming increasingly competitive, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we could not recover, net of anybelieve that the accounting prescribed under Statement 71 remains appropriate. It is also our opinion that all regulatory liabilities which would be deemed no longer necessary. Our reviewsassets are recoverable in future rate proceedings, and therefore we have not resulted in any write offs ofrecorded any regulatory assets that are recoverable but are not yet included in base rates or liabilities.contemplated in a future rate recovery proceeding.

40
37

 

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 20052006 and 2004,2005, are as follows.
                
In thousands 2005 2004 
 2006 2005 
 In thousands 
 
Regulatory Assets:         
Unamortized debt expense $4,822 $5,261  $11,306  $4,822 
Amounts due from customers 52,161 28,832   89,635   52,161 
Environmental costs * 4,085 4,658 
Demand-side management costs * 4,387 5,089 
Deferred operations and maintenance expenses * 9,219 5,579 
Deferred integration costs of acquisition * 1,021 2,042 
Deferred pension and other retirement benefits costs * 6,480 5,119 
Other * 3,671 2,672 
Environmental costs*  3,812   4,085 
Demand-side management costs*  3,554   4,387 
Deferred operations and maintenance expenses*  9,234   9,219 
Deferred integration costs of acquisition*  681   1,021 
Deferred pension and other retirement benefits costs*  8,748   6,480 
Regulatory cost of removal asset  12,086   — 
Other*  4,412   3,671 
          
Total $85,846 $59,252  $143,468  $85,846 
     
      
Regulatory Liabilities:         
Regulatory cost of removal obligations $288,989 $266,700  $310,989  $288,989 
Amounts due to customers 17,124 26,379   123   17,124 
Deferred income taxes 25,992 24,840   25,134   25,992 
Environmental liability due customers * 1,157 2,314 
Environmental liability due customers*  772   1,157 
          
Total $333,262 $320,233  $337,018  $333,262 
          
 
*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, 2005,2006, we had regulatory assets totaling $3.7$4.4 million on which we do not earn a return during the recovery period. The original amortization periods for these assets range from three3 to 15 years and, accordingly, $2.5$3.3 million will be fully amortized by 2008, $.2 million will be fully amortized by 2010 and the remaining $1$.9 million will be fully amortized 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, 2006, 2005 2004 and 2003,2004, AFUDC totaled $3.9 million, $3.1 million $2.6 million and $2.3$2.6 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 54 to 6588 years. The composite weighted-average depreciation rates were 3.46% for 2006, 3.46% for 2005 and 3.51% for 2004 and 3.64% for 2003.2004.
 
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


38

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

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. Accordingly,Through depreciation expense, we accrue estimated non-legal costs of removal on any depreciable asset that includes cost of long-lived assets throughremoval in its depreciation expense.rates. The related costcosts of removal accrual is reflected in “Regulatory cost“Cost of removal obligations” in the consolidated balance sheets. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

41

On November 1, 2002, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (AROs) (Statement 143),. Statement 143 addresses financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires that we recordthe recognition of the fair value of a liability at fair value for an asset retirement obligation whenARO in the legal obligation to retireperiod in which the asset has beenliability is incurred if a reasonable estimate of fair value can be made. We have determined that we have asset retirement obligationsAROs exist for our underground mains and services; however,services.
In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. We collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal costs are non-legal obligations as defined by Statement 143. Because these estimated removal costs meet the requirements of Statement 71, we have accounted for these non-legal asset removal obligations as a regulatory liability. We have reclassified the estimated non-legal asset removal obligations from “Accumulated depreciation” to “Cost of removal obligations” in “Deferred Credits and Other Liabilities” in our consolidated balance sheets.
In our fourth quarter of 2006, we applied FIN 47 requiring recognition of a liability for the fair value of a conditional asset retirement obligation when incurred if the obligations cannotliability can be determined because the end of the system life is indeterminable.reasonably estimated. We have recorded a liability on our distribution and transmission mains and services. For further discussion of asset retirement obligations, see Note 1.N to the consolidated financial statements.
D. Trade Accounts Receivable
The cost of removal obligations recorded in our consolidated balance sheets as of October 31, 2006 and Allowance for Doubtful Accounts.2005, are shown below.
 
         
  2006  2005 
  In thousands 
 
Regulatory non-legal asset removal obligations $310,989  $288,989 
Conditional asset retirement obligations  19,115   — 
         
Total cost of removal obligations $330,104  $288,989 
         
  D.  Trade Accounts Receivable and Allowance for Doubtful Accounts.
Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. Effective November 1, 2005 as approved in the November 3 order, the NCUC has allowed the recovery of all uncollected gas costs in North Carolina through the gas cost deferral account. As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Merchandise receivables due beyond one year are included in “Other” in “Investments, Deferred Charges and Other Assets” in the consolidated balance sheets.


39

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

A reconciliation of changes in the allowance for doubtful accounts for the years ended October 31, 2006, 2005 2004 and 2003,2004, is as follows.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Balance at beginning of year $1,086 $2,743 $810  $1,188  $1,086  $2,743 
Additions charged to uncollectibles expense 6,224 6,098 6,427   4,706   6,224   6,098 
Additions from acquisitions — — 1,385 
Accounts written off, net of recoveries  (6,122)  (7,755)  (5,879)  (4,655)  (6,122)  (7,755)
              
Balance at end of year $1,188 $1,086 $2,743  $1,239  $1,188  $1,086 
              
E. Goodwill, Equity Method Investments and Long-Lived Assets.
 
  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 on October 31, or more frequently if impairment indicators surfacearise during the year. We did not recomputerecomputed the fair value of goodwill in 2005 since our last fair value determination exceeded the carrying amount by a substantial margin. The assets2006, and liabilities that comprise the reporting unit have not changed significantly. Based on an analysis of events that have occurred and circumstances that have changed since the most recent fair value determination, we believe the likelihood that the current carrying amounts would be less than the fair valuethere is remote.no impairment.
 
In our 20042006 appraisal, we used 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. This method 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. No impairment has been recognized during the years ended October 31, 2005, 2004 and 2003.

42

     Changes in goodwill for the years ended October 31,2006, 2005 and 2004, are as follows. For further information on acquisitions, see Note 2 to the consolidated financial statements.
         
In thousands        
 
Balance, 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, October 31, 2004      48,151 
Minority interest income in EasternNC for the year      (602)
Acquisition of remaining 50% interest in EasternNC      (166)
        
Balance, October 31, 2005     $47,383 
        
2004.
 
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 the years ended October 31, 2006, 2005 2004 and 2003,2004, that resulted in any impairment charges. For further information on equity method investments, see Note 1011 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, registration fees and rating agency fees, related to issuing long-term debt. We amortize debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt which has 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 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, supplies and merchandise inventories are valued at the lower of average cost or market and are removed from such inventory at average cost.


40

H. Deferred Purchased
Piedmont Natural Gas Adjustments.Company, Inc.
 
Notes to Consolidated Financial Statements — (Continued)

  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.

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  I.  Taxes.

I. Taxes.
Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. Deferred taxes are primarily attributable to utility plant, equity method investments and revenues and cost of gas. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are 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 and payroll taxes. These taxes are not included in revenues.
J.  Revenue Recognition.
Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional 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 coldwarmer-than-normal or warmcolder-than-normal weather has on customer billings during the winter season. Effective November 1, 2005, in North Carolina, through a general rate case proceeding, a Customer Utilization Tracker (CUT) eliminated the WNA that had previously been used. The CUT provides for the recovery of our approved margin per customer independent of both weather and other consumption patterns of residential and commercial customers.
 
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.WNA or CUT mechanisms, as applicable.
 
Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on contract or market prices.


41

K. Earnings Per Share.
Piedmont Natural Gas Company, Inc.
 
Notes to Consolidated Financial Statements — (Continued)

  K.  Earnings Per Share.

We compute basic earnings per share using the weighted average number of shares of Common Stockcommon stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2006, 2005 2004 and 2003,2004, is presented below.
             
In thousands except per share amounts 2005  2004  2003 
             
Net Income $101,270  $95,188  $74,362 
          
             
Average shares of Common Stock outstanding for basic earnings per share  76,680   74,359   66,782 
Contingently issuable shares under the Executive Long-Term Incentive Plan  312   438   225 
          
Average shares of dilutive stock  76,992   74,797   67,007 
          
             
Earnings Per Share:            
Basic $1.32  $1.28  $1.11 
Diluted $1.32  $1.27  $1.11 

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  2006  2005  2004 
  (In thousands except per share amounts) 
 
Net Income $97,189  $101,270  $95,188 
             
Average shares of common stock outstanding for basic earnings per share  75,863   76,680   74,359 
Contingently issuable shares under the Executive Long-Term Incentive Plan  293   312   438 
             
Average shares of dilutive stock  76,156   76,992   74,797 
             
Earnings Per Share:            
Basic $1.28  $1.32  $1.28 
Diluted $1.28  $1.32  $1.27 

L. Statements of Cash Flows.
 
  L.  Statements 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 as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.
N.  Recently Issued Accounting Standards.
In December 2004,March 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We will adopt Statement 123R on November 1, 2005, and amend our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R will not have a material effect on our financial position or results of operations.
     In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” FIN 47 requires that a liability be recognized for the fair value of a conditional asset retirement obligationAROs when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly,As of October 31, 2006, we will adoptadopted FIN 47 no later thanand recorded an asset retirement cost of $7 million as part of “Utility Plant,” a liability for the conditional asset retirement obligation of $19.1 million and a regulatory asset of $12.1 million. We received regulatory approval to establish a regulatory asset for the accumulated accretion expense and accumulated depreciation. Consequently, the adoption of FIN 47 did not have an impact on our fourth fiscal quarterresults of operations or cash flows. Additionally, had FIN 47 been applied to the prior year presented with this report, the conditional ARO would have been $17.1 million and $18.1 million at November 1, 2004 and October 31, 2005, respectively. In accordance with FIN 47, such amounts are not reflected in the balance sheet as of October 31, 2005.
In June 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an


42

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. This interpretation is effective the beginning of the first annual period commencing after December 15, 2006. We are currently assessing the impact FIN 4748 may have on our consolidated balance sheet;financial statements; however, we believe the adoption of FIN 4748 will not have a material impact on our financial position, results of operations or cash flows.
2. Acquisitions
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not expand the use of fair value in any new circumstances. Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under Statement 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. Accordingly, we will adopt Statement 157 no later than our first fiscal quarter in 2008. We believe the adoption of Statement 157 will not have a material effect on our financial position, results of operations or cash flows.
 
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158). Statement 158 requires an employer to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in the financial statements by recognizing in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status rather than only disclosing the funded status in the footnotes to the financial statements. Statement 158 requires employers to recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Those changes will be reported in accumulated other comprehensive income (OCI) in the stockholders’ equity section of the balance sheet. Statement 158 also requires that the company measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year.
Statement 158 provides different effective dates for the recognition and related disclosure provisions and for the required change to a fiscal year-end measurement date. The requirement to recognize the funded status of a benefit plan and the related disclosure requirements initially will apply as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year end statement of financial position will be effective for fiscal years ending after December 15, 2008, and will not be applied retrospectively. Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. The measurement date portion of Statement 158 does not apply to us because our pension plan measurement date is already the same as our fiscal year end date. We believe the adoption of Statement 158 will not have a material effect on our financial position, results of operations or cash flows.
If Statement 158 had been adopted for the current year ended October 31, 2006, the effect on the consolidated balance sheets would have been a non-cash charge of $42.3 million as a regulatory asset of $25.6 million and deferred income taxes of $16.7 million with a reduction of $14.6 million to prepaid pension and an increase in accrued postretirement benefits of $27.7 million. The actual charge at October 31, 2007, could be substantially different depending on the discount rate, asset returns and plan population at that time. Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any regulatory asset or liability that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. We


43

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

intend to meet with our regulators in fiscal year 2007 to discuss the regulatory accounting and rate treatment of Statement 158.
2.  Acquisitions
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. At the time of the acquisition, 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. At that time, EasternNC was a regulated utility with 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.

45

 
We recorded the assets purchased on September 30, 2003, 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 in goodwill 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 thetrue-up of estimated working capital to actual. The goodwill attributable to EasternNC as of September 30, 2003, was not adjusted. We believe that approximately $31.4 million of the goodwill will be deductible for tax purposes.
 
On October 25, 2005, we purchased the remaining 50% interest in EasternNC for $1. EasternNC was merged into Piedmont immediately following the closing. The primary reason for the purchase of the remaining 50% interest was to integrate the rate structure of EasternNC into Piedmont’s rate structure.
3.  Regulatory Matters
Our utility operations are subject to regulationregulated 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 regulationregulated by the NCUC as to the issuance of securities.
 
In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of North Carolina. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. In accordance with a 2002 NCUC order, we no longer deposit supplier refunds in the expansion fund for our pre-NCNG acquisition operations; however, we continuecontinued to deposit supplier refunds attributable to NCNG operations in the expansion fund.fund until an order was issued in the general rate case proceeding in 2005 discussed below. As of October 31, 2005, the balance of $13.1 million in our expansion fund held by the North Carolina State Treasurer iswas included in the consolidated balance sheet in “Restricted cash,” with an offsetting liability included in “Amounts due to customers.” In accordance with the order in the general rate case proceeding in 2005 discussed below, the expansion funds held byrestrictions on this cash were removed. We received $13.2 million in January 2006 from the North Carolina State Treasurer will be returnedthat was offset against “Amounts due to us in early 2006.customers.”
 
The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan is limitedtargets 30% to 60% of annual normalized sales volumes for South Carolina and operates


44

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

using 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 are deemed to be prudently incurred and are recovered in rates as a gas cost. Any benefits recognized are deemed to be reductions in gas cost and are refunded to South Carolina customers in rates.
 
We have a similar hedging plan in North Carolina. Recovery of costs associated with the hedging plan is not pre-approved by the NCUC and the costs are treated as gas costs subject to the annual gas cost prudence review. Any benefits or gain recognition are deemed to be reductions in gas costs and are refunded to North Carolina customers in rates. Through October 31, 2005,2006, we have recovered 100% of the costs incurred under the North Carolina plan that have been reviewedwhich is still under review for prudence.

46

 
In Tennessee, costs and benefits associated with hedging activities are recovered through the Actual Cost Adjustment (ACA) mechanism. The costs and benefits of financial instruments and all other gas costs incurred are components of the Tennessee Incentive Plan (TIP) mechanism approved by the TRA. The TIP mechanism replaced annual prudence reviews by benchmarking gas costs and secondary market activity performance against amounts determined by published market indices. In July 2005, in the order approving our 2004 TIP filing, the TRA established a separate docket to address issues raised by the Tennessee Consumer Advocate Staff and the TRA Staff related to the breadth of secondary market activities covered by the TIP, the method for selecting the independent consultant to review performance under the TIP, and the procedures utilized with respect to request for proposals. The TRA set a procedural schedule that included a hearing date of May 15, 2006. A series of settlement discussions followed leading to a September 2006 proposal that represented a reasonable balance between the respective roles of regulatory oversight and the alignment of ratepayer and shareholder interests inherent in the TIP to which the Tennessee Consumer Advocate Division and the TRA Staff have preliminarily agreed. Final approval of the settlement will be sought from the TRA and would maintain our annual incentive cap of gains and losses of $1.6 million which has been a key element of the TIP since its inception.
 
Due to the seasonal nature of our business and weather conditions during the winter period, we contract with customers in the secondary market to sell supply and capacity assets when available. In North Carolina and South Carolina, we operate under benefit-sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions (capacity release and off-system sales) whereby 75% of the benefit is refunded to jurisdictional customers in rates and 25% of the benefit is retained by us. In Tennessee, we operate under the TIP whereby gas purchase benchmarking benefits or losses are combined with secondary market transaction benefits or losses and shared by customers and us under a pre-approved formula. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million.
 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 be recovered 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 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. In February 2004, the TRA approved the petition by modifying the formula in the PGA rules to allow for the recovery of uncollected gas cost on an experimental basis for one year, effective March 10, 2004. On April 4, 2005, the authorityTRA extended the experimental period for one more year. On June 26, 2006, a motion was made to permanently approve the procedure. After receiving further comments, the TRA approved this motion on August 7, 2006. In conjunction with the approval, the TRA established a rulemaking to implement the formula.
 
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


45

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

of North Carolina. 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. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. As of
During the fiscal year ended October 31, 2005,2006, we were reimbursed $16 million in construction costs by the state, the remaining balance of the bond funds allocated to EasternNCfund as of October 31, 2005. There was $16 million.

47

     We establish a stateno remaining bond receivable when we determine that construction costs are reimbursable by the state.as of October 31, 2006. As of October 31, 2005, and 2004, we had receivables of $12 million and $3.5 million, respectively, related to the bond fund included in “Other receivables” in the consolidated balance sheets. In accordance with NCUC orders, we must also contribute funding to the project that is not subject to bond reimbursement. During the twelve months ended October 31, 2005, we made capital expenditures totaling $9.5 million for which we did not seek reimbursement from the bond fund.
 
The NCUC hashad allowed EasternNC to defer its operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occursoccurred first, with a maximum deferral of $15 million. The deferred amounts accrueaccrued 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, 2005 and 2004, deferred operations and maintenance expenses of $9.2 million and $5.6 million, respectively, including accrued interest, were deferred as a regulatory asset in the consolidated balance sheets. As a part of the general rate case proceeding discussed below, deferral will ceaseceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005, will be$7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Amortization of amounts totaling $1.3 million that were deferred between July 1 and October 31, 2005, will be addressed in theour next North Carolina general rate case.
 
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 regulations of the United States Department of Transportation. The NCUC approved deferral treatment of these costs applicable to all incremental expenditures beginning November 1, 2004. As a part of the general rate case discussed below, the balance of $.4 million in the deferred account as of June 30, 2005, will beis being amortized over three years beginning November 1, 2005, and subsequent expenditures will continue to be deferred. Any unamortized balance at the end of the three years will be addressed in a future rate case.
 
On February 16, 2005, the Natural Gas Rate Stabilization Act of 2005 became effective in South Carolina. The law provides electing natural gas utilities, including Piedmont, with a mechanism for the regular, periodic and more frequent (annual) adjustment of rates which is intended to: (1) encourage investment by natural gas utilities, (2) enhance economic development efforts, (3) reduce the cost of rate adjustment proceedings and (4) result in smaller but more frequent rate changes for customers. If the utility elects to operate under the Act, the annual filing will provide that the utility’s rate of return on equity will remain within a 50-basis points band above or below the current allowed rate of return on equity. On April 26, 2005, we filed an election with the PSCSC to adopt this new mechanism.
 
On June 15, 2005, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2005, along with revenue deficiency calculations and proposed changes in our tariff rates. In the filing, we requested an increase in annual margin of $3.2 million. On October 21, 2005, the PSCSC issued an order approving an increase in annual margin of $2.6 million, effective November 1, 2005.
 
On June 15, 2006, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2006, along with revenue deficiency calculations and proposed changes in our tariff rates. In the filing, we requested an increase in annual margin of $10.4 million. On September 1, 2006, we, the Office of Regulatory Staff (ORS) and the South Carolina Energy Users Committee (SCEUC) filed a settlement agreement with the PSCSC addressing our proposed rate changes under the Natural Gas Rate Stabilization Act. On September 27, 2006, the PSCSC approved the settlement which will result in a $6.5 million increase in revenue based on 11.2% return on equity effective November 1, 2006.


46

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

On August 30, 2006, the PSCSC approved a settlement agreement between us, the ORS and the SCEUC accepting our purchased gas adjustment and finding our gas purchasing policies prudent. As part of this approved settlement effective November 1, 2006, we can recover uncollectible gas costs through the PGA mechanism in South Carolina.
On April 1, 2005, we filed a general rate case application with the NCUC requesting a consolidation of the respective rate bases, revenues and expenses of Piedmont, NCNG and EasternNC. In addition to a unified and uniform rate structure for all customers served by us in North Carolina, the application requested a general restructuring and increase in rates and charges for customers to produce an overall annual increase in margin of $36.7 million, a

48

consolidationand/or amortization of certain deferred accounts, changes to cost allocations and rate design including an innovative “conservation tariff”tariff mechanism that decouples margin recovery from residential and commercial customer consumption, changes and unification of existing service regulations and tariffs, common depreciation rates for plant and recovery of uncollectible gas costs through the gas cost deferred account.
 On August 31, 2005, a stipulation was filed in this proceeding resolving all issues and providing a margin increase of $20.2 million.
On November 3, 2005, the NCUC issued an order approving, theamong other things, an annual increase in margin increaseof $20.2 million and authorizing new rates effective November 1, 2005. The Stipulationorder provided for the elimination of the WNAweather normalization adjustment (WNA) mechanism in North Carolina and the establishment of a Customer Utilization Tracker (CUT). that decouples margin recovery from residential and commercial customer consumption. The CUT is a tracker which is experimental and can be effective for no more than three years, subject to review and approval in a future general rate case proceeding. The CUT provides for the recovery of our approved margin per customer independent of weather or other usage and consumption patterns of residential and commercial customers. The CUT will tracktracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. During the life of the CUT, the NCUC ordered us to contribute $500,000 per year toward conservation programs to assist residential and commercial customers. The conservation programs are subject to review and approval by the NCUC. On March 17, 2006, we made our first rate adjustment filing to collect, beginning April 1, $11.8 million attributable to the period ended January 31, 2006. On October 16, 2006, we made our second rate adjustment filing to collect, beginning November 1, 2006, $26.4 million attributable to the period ended August 31, 2006. Both of these rate adjustment filings have been approved by the NCUC.
Effective November 1, 2005 as approved in the November 3 order, the NCUC has allowed the recovery of all uncollected gas costs through the gas cost deferral account. As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense.
On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal in thisthe general rate case proceeding challenging the lawfulness of the NCUC’s authorization and approval of the CUT. We believeOn April 6, the Attorney General filed a Notice of Appeal and Exceptions to the NCUC’s March 28, 2006, order approving the first adjustment filing under the CUT. On July 18, the Company and the Office of the Attorney General filed a settlement with the NCUC. As a result, the Attorney General withdrew both appeals. In the settlement, we agreed to share, in each of the three years the CUT is lawful, justeffective, the first $3 million of CUT dollars that are non-weather related. Annually, the first $3 million of non-weather related CUT amounts will be allocated 25% to customer rate reduction, 25% to energy conservation program funding and reasonable50% to us. Accordingly, we recognized a $1.5 million liability with this settlement in our third quarter that was composed of an annual $750,000 to conservation programs (in addition to the $500,000 annual contribution in the rate case order) and reflects good public policy,an annual $750,000 to the reduction of customer rates during the same period. The NCUC approved the settlement on September 14, 2006.
The financial condition of the natural gas marketers and we intendpipelines that supply and deliver natural gas to vigorously defendour distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the NCUC’s action authorizingfinancial condition of the marketers and approvingpipelines is not significant based on our receipt of the Stipulation


47

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

products and services prior to payment and the CUT. availability of other marketers of natural gas to meet our firm supply needs if necessary.
We are unablecurrently have commission approval in all three states that place additional credit requirements on the retail natural gas marketers that schedule gas into our system.
We filed a petition with the NCUC and the PSCSC on September 20, 2006, and with the TRA on September 29, 2006, for authorization to predictplace certain ARO costs in deferred accounts so that the outcome of an appeal being granted or the potential impactcurrent regulatory treatment for these costs will not be altered due to our rates, charges or terms and conditionsadoption of service shouldFIN 47. We requested that an order on these issues be made effective as of October 31, 2006. On October 16, 2006, the TRA approved the petition. On October 27, 2006, the NCUC order be reversed or remanded.
4. Long-Term Debtapproved the petition. On November 2, 2006, the PSCSC approved the petition.
 
4.  Long-Term Debt
All of our long-term debt is unsecured. Long-term debt as of October 31, 20052006 and 2004,2005, is as follows.
         
In thousands 2005  2004 
 
Senior Notes:        
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   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   100,000 
       
Total  660,000   660,000 
Less current maturities  35,000   — 
       
Total $625,000  $660,000 
       

49

         
  2006  2005 
  In thousands 
 
Senior Notes:        
9.44%, due 2006 $—  $35,000 
8.51%, due 2017  35,000   35,000 
Insured Quarterly Notes:        
6.25%, due 2036  200,000   — 
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   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   100,000 
         
Total  825,000   660,000 
Less current maturities  —   35,000 
         
Total $825,000  $625,000 
         

 
Current maturities for the next five years ending October 31 and thereafter are as follows.
        
In thousands 
 In thousands 
2006 $35,000 
2007 —  $— 
2008 —   — 
2009 30,000   30,000 
2010 60,000   60,000 
2011  60,000 
Thereafter 535,000   675,000 
      
Total $660,000  $825,000 
      


48

Piedmont Natural Gas Company, Inc.
 
Notes to Consolidated Financial Statements — (Continued)

We have a shelf registration statement that can be used for either debt or equity securities filed with the Securities and Exchange Commission for $690 million. In December 2003,Commission. On June 20, 2006, we sold $200 million of medium-term6.25% insured quarterly notes and in January 2004, we sold $180.6 million of Common Stock under this shelf registration statement. The unsecured and unsubordinated insured quarterly notes are due on June 1, 2036. We have the option to redeem all or part of the notes before the stated maturity at any time on or after June 1, 2011, at 100% of their principal amount plus any accrued and unpaid interest to the date of redemption. We are obligated to redeem the notes in whole upon the occurrence of certain corporate transactions or failure to pay the premium under the insurance agreement. These quarterly notes were used to pay off $188 million of short-term debt on June 20 and to pay off a portion of the sinking fund of $35 million on the 9.44% Senior Notes due July 30. The remaining balance of unused long-term financing available under this shelf registration statement is $309.4$109.4 million.
 
The amount of cash dividends that may be paid on Common Stockcommon 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, 2005,2006, we could make restricted payments totaling $576.6$558.4 million. Retained earnings as of this date were $323.6$348.8 million; therefore, none of our retained earnings were not restricted.
 
We are subject to default provisions related to our long-term debt. 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, 2005,2006, we are in compliance with all default provisions.
5.  Capital Stock and Accelerated Share Repurchase
Changes in Common Stockcommon stock for the years ended October 31, 2003, 2004, 2005 and 2005,2006, are as follows.
                
In thousands Shares Amount 
 Shares Amount 
Balance, October 31, 2002 66,180 $352,553 
 In thousands 
Balance, October 31, 2003  67,309  $372,651 
Issued to participants in the Employee Stock Purchase Plan (ESPP) 33 550   45   853 
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 968 17,375   940   19,164 
Issued to participants in the Executive Long-Term Incentive Plan (LTIP) 128 2,173   79   1,658 
     
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   8,500   173,828 
Shares repurchased  (203)  (4,487)
Shares repurchased under Common Stock Open Market Repurchase Plan  (203)  (4,487)
          
Balance, October 31, 2004 76,670 563,667   76,670   563,667 
Issued to ESPP 43 904   43   904 
Issued to DRIP 1,013 22,632   1,013   22,632 
Issued to LTIP 77 1,796   77   1,796 
Shares repurchased  (1,105)  (26,119)
Shares repurchased under Common Stock Open Market Repurchase Plan  (1,105)  (26,119)
          
Balance, October 31, 2005 76,698 $562,880   76,698   562,880 
Issued to ESPP  36   882 
Issued to DRIP  735   17,496 
Issued to LTIP  75   1,669 
Shares repurchased under Common Stock Open Market Repurchase Plan  (1,080)  (25,871)
Shares repurchased under Accelerated Share Repurchase Plan (ASR)  (1,000)  (24,292)
          
Balance, October 31, 2006  75,464  $532,764 
     

50
49

 

 Under the LTIP, the Board of Directors has awarded units
Piedmont Natural Gas Company, Inc.
Notes to eligible officers and other participants. Depending upon the levels of performance targets achieved by Piedmont during multi-year performance periods, distribution of those awards may be made in the form of shares of Common Stock and cash withheld for payment of applicable taxes on the compensation. The LTIP requires that a minimum threshold performance be achieved in order for any award to be distributed. For the years ended October 31, 2005, 2004 and 2003, we recorded compensation expense for the LTIP of $4 million, $3.1 million and $3.9 million, respectively.Consolidated Financial Statements — (Continued)

In June 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.common stock. We implemented the program in September 2004. 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 the ESPP, DRIP and LTIP.
 
On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the stock split in 2004. The Board also approved the repurchase of up to four million additional shares of currently outstanding shares of Common Stockcommon stock and amended the program to provide for repurchases to maintain ourdebt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares.
 
On April 7, 2006, we entered into an accelerated share repurchase program whereby we purchased and retired 1 million shares of our common stock from an investment bank at the closing price that day of $23.87 per share. Total consideration paid to purchase the shares of $23.9 million, including $30,000 in commissions and other fees, was recorded in “Stockholders’ equity” as a reduction in “Common stock.”
As part of the accelerated share repurchase, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 50 trading days. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 1 million shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price was higher than the April 7, 2006, closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price for the shares purchased was lower than the April 7, 2006, closing price. At settlement on June 6, we paid cash of $.4 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction in “Common stock.” The $.4 million was the difference between the investment bank’s weighted average purchase price of $24.26 and the April 7, 2006, closing price of $23.87 per share multiplied by 1 million shares.
As of October 31, 2005, 3.62006, 2.8 million shares of Common Stockcommon stock were reserved for issuance as follows.
     
In thousands In thousands 
 
ESPP  177141 
DRIP  2,2251,489 
LTIP  1,2221,148 
    
Total  3,6242,778 
    
6. Financial Instruments and Related Fair Value
 As of October 31, 2005,
6.  Financial Instruments and Related Fair Value
On April 24, 2006, we hadreplaced our expiring $250 million364-day committed bank lines of credit totaling $250with a new senior five-year credit facility that includes renewal options. This new credit facility provides a committed line of credit of $350 million with the ability to expand up to $600 million, for which we pay a maximuman annual fee of $.3 million, and additional uncommitted lines$35,000 plus six basis points for any unused amount up to $350 million. This new credit facility also provides a line of credit totaling $113 million on a no fee and as needed, if available, basis.for letters of credit of $5 million. The fee for the committed lines iscredit facility bears interest based on the portion of the credit facility that is unused. As of January 17, 2006, we have increased the amount of uncommitted lines30-day LIBOR rate plus from .15% to $225 million.
     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.35%, based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. our credit ratings.
As of October 31, 20052006 and 2004,2005, outstanding borrowings under the lines are included in “Notes payable” in the consolidated balance sheets, and consisted of $158.5$170 million and $109.5$158.5 million, respectively, in LIBOR cost-plus loans at a weighted average interest rate of 4.28%5.57% and 2.18%4.28%, respectively. Our credit facility’s


50

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and actual was 53% at October 31, 2006. As of October 31, 2005,2006, the unused committed lines of credit totaled $91.5$180 million.
 
As of October 31, 2005,2006, we had a line of credit for$1.2 million in letters of credit of $1.5 million, of which $1.2 million were issued and outstanding. These letters of credit are used to guarantee self-insured claims from self-insurance under our general liability policies.

51

 
Our principal business activity is the distribution of natural gas. As of October 31, 2005,2006, our trade accounts receivable consisted of gas receivables of $103.1$85.7 million and merchandise and jobbing receivables of $4.4$4.8 million, net of an allowance for doubtful accounts of $1.2 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, was included in “Marketable securities” in the consolidated balance sheet. In February 2005, we sold all of the common units with proceeds of $2.4 million, resulting in a pre-tax gain of $1.5 million. For further information on this transaction, see Note 1011 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, 20052006 and 2004,2005, including current portion, were as follows.
                 
  2005  2004 
In thousands Carrying Amount  Fair Value  Carrying Amount  Fair Value 
 
Long-term debt $660,000  $753,267  $660,000  $775,269 
                 
  2006  2005 
  Carrying
  Fair
  Carrying
  Fair
 
  Amount  Value  Amount  Value 
  In thousands 
 
Long-term debt $825,000  $913,739  $660,000  $753,267 
 
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. Our risk management policies allow us to use financial instruments for limited trading purposes and to hedge risks. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.
 
We have purchased and sold financial options for natural gas in all three states for our gas purchase portfolios. The gains or losses on financial derivatives utilized in the regulated utility segment ultimately will be included in our rates to customers. Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due customers in accordance with Statement 71. Accordingly, there is no earnings impact on the regulated utility segment as a result of the use of these financial derivatives. As of October 31, 20052006 and 2004,2005, the total fair value of gas purchase options included in the consolidated balance sheets was $3.1 million and $22.8 million, and $13.2 million, respectively.

52

7.  Leases, and Unconditional Purchase Obligations and Legal Obligations
 
We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. For the years ended October 31, 2006, 2005 2004 and 2003,2004, operating lease payments were $6.9$7.2 million, $5.7


51

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

$6.9 million and $4.5$5.7 million, respectively. During 2005, we sold our corporate office building and entered into a ten-year lease on new office space beginning November 1, 2005.
 
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
        
In thousands 
 In thousands 
2006 $7,143 
2007 6,046  $6,316 
2008 5,146   5,317 
2009 4,600   4,721 
2010 3,883   3,972 
2011  3,839 
Thereafter 22,615   17,462 
      
Total $49,433  $41,627 
      
 
We routinely enter into long-term commodity purchase commitments and agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to 15nineteen years. The time periods for gas supply contracts range from one to three years. The time 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 feesphone and contract labor and consultingpager usage fees range from one to fourfive years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.
 
As of October 31, 2005,2006, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
                                        
 Telecommunications          Telecommunications
     
 Pipeline and and Information      Pipeline and
   and Information
     
In thousands Storage Capacity Gas Supply Technology Other Total 
 Storage Capacity Gas Supply Technology Other Total 
2006 $121,169 $13,351 $14,447 $19,811 $168,778 
 In thousands 
2007 117,335 191 15,126 — 132,652  $124,454  $29,539  $20,337  $28,406  $202,736 
2008 116,351 180 15,837 — 132,368   133,649   848   24,242   —   158,739 
2009 112,282 113 16,582 — 128,977   134,914   285   24,751   —   159,950 
2010 112,282 — 17,361 — 129,643   133,579   15   25,271   —   158,865 
2011  133,722   —   25,801   —   159,523 
Thereafter 462,140 — — — 462,140   580,802   —   —   —   580,802 
                      
Total $1,041,559 $13,835 $79,353 $19,811 $1,154,558  $1,241,120  $30,687  $120,402  $28,406  $1,420,615 
                      
8. Employee Benefit Plans
 
From time to time, we conduct business with natural gas marketers who act as agents for various industrial customers of ours or who purchase natural gas directly for their own account. We previously had such an arrangement with National Gas Distributors LLC (NGD), which filed a voluntary bankruptcy petition on January 20, 2006. The bankruptcy trustee for this petition claimed that certain amounts paid by NGD to us for gas supply constitute preference payments, and sought their return. We have disputed these claims and vigorously defended our position on the matter. In October 2006, we agreed to settle with the NGD bankruptcy trustee in order to avoid protracted litigation and the expense thereof. The settlement has been submitted to the bankruptcy court for approval. During the fourth quarter, we recorded our estimated liability under the settlement, which does not have a material adverse impact on our financial position, results of operations or cash flows.


52

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

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 the12-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

53

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 provide certain postretirement health care and life insurance benefits (OPEB) to eligible full-time employees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. 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. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s 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. Retirees not in the grandfathered group pay 20% of the cost of their coverage plus the full cost of dependent coverage.
 
In connection with the acquisition of NCNG, we acquired certain pension and OPEB obligations of former employees of NCNG. In February 2004, Progress transferred $34 million attributable to the accrued pension benefits for this group as of September 30, 2003, to the trust fund for this separate “frozen” plan. Progress transferred an additional $.2 million 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.
     In January 2005, we determined that We intend to merge the accumulated benefit obligation of the“frozen” qualified NCNG pension plan exceededwith the fair valuePiedmont pension plan as of plan assets. We recognized an additional minimum pension liability of $4.5 million with a corresponding entry to accumulated other comprehensive income of $2.7 million, net of deferred income taxes. As of OctoberDecember 31, 2005, the plan assets exceeded the accumulated benefit obligation and this plan is disclosed on a consolidated basis with our other pension plan.2006.
 
As a result of the Medicare Prescription Drug Improvement and Modernization Act of 2003, we amended our postretirement benefit plan on August 1, 2005, to eliminate prescription drug coverage beginning January 1, 2006, for retirees who are Medicare eligible. This prescription drug benefit will bewas replaced by a defined dollar benefit intended to pay the premiums for Medicare Part D.
 
In connection with the acquisition of NCNG, we acquired certain pension liabilities related to a supplemental executive retirement plan (SERP) for 10 former retirees or directors of NCNG. The nonqualified SERP provides for a defined benefit payment to the former employee, director or their surviving spouse. There are no assets related to the plan, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year.
In addition, there is a nonqualified retirement plan for non-employee directors which provides retirement benefits to directors of the Company who were elected on or prior to August 20, 2003. Both of these nonqualified plans are presented below.
We also have a SERP covering all officers at the vice president level and above. It provides supplemental retirement income for officers whose benefits under the Company’s qualified retirement plan are limited by tax code provisions. The level of insurance benefit and target retirement income benefits intended to be provided under the SERP depend upon the position of the officer. The SERP is funded by life insurance policies covering each officer, and the policy is owned exclusively by each officer. Premiums on these policies paid and expensed by us, as grossed up for taxes to the individual officer, totaled $.7 million in 2006, $1 million in 2005 and $86,000 in 2004.


53

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 20052006 and 2004,2005, and a statement of the funded status as recorded in the consolidated balance sheets as of October 31, 20052006 and 2004,2005, are presented below.
                                        
 2005 2004 2005 2004  Qualified Pension Nonqualified Pension Other Benefits 
In thousands Pension Benefits Other Benefits 
 2006 2005 2006 2005 2006 2005 
 In thousands 
Change in benefit obligation:                         
Obligation at beginning of year $226,315 $199,732 $38,874 $43,680  $236,608  $226,315  $4,484  $4,698  $30,732  $38,874 
Service cost 11,278 9,698 1,391 1,338   10,972   11,278   66   61   1,134   1,391 
Interest cost 12,816 12,084 2,151 2,547   13,436   12,816   239   255   1,747   2,151 
Plan amendments — —  (5,934) 1,517   —   —   —   —   —   (5,934)
Actuarial (gain) loss  (1,792) 16,888  (3,260)  (8,194)  (190)  (1,792)  84   (9)  3,816   (3,260)
Benefit payments  (12,009)  (12,087)  (2,490)  (2,014)  (24,497)  (12,009)  (531)  (521)  (3,177)  (2,490)
                      
Obligation at end of year $236,608 $226,315 $30,732 $38,874  $236,329  $236,608  $4,342  $4,484  $34,252  $30,732 
                      
Change in fair value of plan assets:                        
Fair value at beginning of year $199,159  $181,244  $—  $—  $15,275  $14,045 
Actual return on plan assets  22,681   13,121   —   —   1,740   964 
Employer contributions  15,100   17,300   531   521   2,962   2,721 
Administrative expenses  (517)  (497)  —   —   —   — 
Benefit payments  (24,497)  (12,009)  (531)  (521)  (3,177)  (2,455)
             
Fair value at end of year $211,926  $199,159  $—  $—  $16,800  $15,275 
             
Funded status:                        
Funded status at end of year $(24,403) $(37,449) $(4,342) $(4,484) $(17,452) $(15,459)
Unrecognized transition obligation  —   —   —   —   4,669   5,336 
Unrecognized prior-service cost  4,395   5,327   —   —   —   — 
Unrecognized actuarial (gain) loss  34,615   40,462   220   136   (1,553)  (4,996)
             
Accrued benefit asset (liability) $14,607  $8,340  $(4,122) $(4,348) $(14,336) $(15,119)
             
Amounts recognized in the consolidated balance sheets consist of:                        
Prepaid benefit cost $14,607  $8,340  $—  $—  $—  $— 
Accrued benefit liability  —   —   (4,342)  (4,484)  (14,336)  (15,119)
Intangible asset  —   —   —   —   —   — 
Accumulated other comprehensive income  —   —   220   136   —   — 
             
Net amount recognized at year end $14,607  $8,340  $(4,122) $(4,348) $(14,336) $(15,119)
             
Other comprehensive income attributable to change in additional minimum pension liability recognition $—  $(4,526) $84  $(9) $—  $— 


54

 

                 
  2005  2004  2005  2004 
In thousands Pension Benefits  Other Benefits 
 
Change in fair value of plan assets:                
Fair value at beginning of year $181,244  $163,831  $14,045  $12,439 
Actual return on plan assets  13,121   15,668   964   527 
Employer contributions  17,300   14,232   2,721   3,152 
Administrative expenses  (497)  (400)  —   — 
Benefit payments  (12,009)  (12,087)  (2,455)  (2,073)
             
Fair value at end of year $199,159  $181,244  $15,275  $14,045 
             
 
Funded status:                
Funded status at end of year $(37,449) $(45,071) $(15,459) $(24,830)
Unrecognized transition obligation  —   —   5,336   7,912 
Unrecognized prior-service cost  5,327   6,229   —   5,522 
Unrecognized actuarial gain (loss)  40,462   38,694   (4,996)  (1,803)
             
Accrued benefit asset (liability) $8,340  $(148) $(15,119) $(13,199)
             
Piedmont Natural Gas Company, Inc.
 The NCNG pension plan was underfunded as of October 31, 2004, as the accumulated benefit obligation exceeded the fair value of plan assets. The status of this plan as of October 31, 2005 and 2004, is presented below.
         
In thousands 2005  2004 
 
Projected benefit obligation $35,981  $36,858 
Accumulated benefit obligation  35,981   36,858 
Fair value of plan assets  37,741   33,005 
Minimum pension liability  —   4,526 
Notes to Consolidated Financial Statements — (Continued)

Net periodic benefit cost for the years ended October 31, 2006, 2005 2004 and 2003,2004, includes the following components.
                                                            
 2005 2004 2003 2005 2004 2003  Qualified Pension Nonqualified Pension Other Benefits 
In thousands Pension Benefits Other Benefits 
 2006 2005 2004 2006 2005 2004 2006 2005 2004 
 In thousands 
Service cost $11,278 $9,698 $6,060 $1,391 $1,338 $808  $10,972  $11,278  $9,698  $66  $61  $53  $1,134  $1,391  $1,338 
Interest cost 12,816 12,084 10,114 2,151 2,547 2,128   13,436   12,816   12,084   239   255   282   1,747   2,151   2,547 
Expected return on plan assets  (16,593)  (16,220)  (13,375)  (1,030)  (922)  (817)  (17,112)  (16,593)  (16,220)  —   —   —   (1,151)  (1,030)  (922)
Amortization of transition obligation — — 14 879 879 879   —   — �� —   —   —   —   667   879   879 
Amortization of prior-service cost 933 931 931 1,285 1,030 859 
Amortization of prior service cost  933   933   931   —   —   —   —   1,285   1,030 
Amortization of actuarial (gain) loss 378 —  (840) — 280 198   604   378   —   —   —   —   (218)  —   280 
                                
Total $8,812 $6,493 $2,904 $4,676 $5,152 $4,055  $8,833  $8,812  $6,493  $305  $316  $335  $2,179  $4,676  $5,152 
                                
 
In determining the market-related value of plan assets, we use the following methodology. The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end 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 in the consolidated financial statements. The discount rate can vary from plan year to plan year. October 31 is the measurement date for the plans.

55

 
The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. As of October 31, 2005,2006, the benchmark was 6.03%5.78% for the Piedmont pension plan 5.84% forand the NCNG pension plan, 5.65% for the NCNG SERP, 5.69% for the directors’ SERP and 5.89%5.74% for OPEB.
 
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 for 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, 2005, 20042006 and 2003,2005, are presented below.
                                                
 2005 2004 2003 2005 2004 2003 Qualified Pension Nonqualified Pension Other Benefits 
 Pension Benefits Other Benefits 2006 2005 2006 2005 2006 2005 
 
Discount rate  6.00%  5.75%  6.25%  5.89%  5.75%  6.25%  5.78%  6.00%  5.67%  5.75%  5.74%  5.89%
Rate of compensation increase  4.05%  3.97%  3.97%  4.05%  3.97%  3.97%  4.01%  4.05%  N/A   N/A   4.01%  4.05%


55

Piedmont Natural Gas Company, Inc.
 
Notes to Consolidated Financial Statements — (Continued)

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2006, 2005 2004 and 2003,2004, are presented below.
                                                   
 2005 2004 2003 2005 2004 2003 Qualified Pension Nonqualified Pension Other Benefits 
 Pension Benefits Other Benefits 2006 2005 2004 2006 2005 2004 2006 2005 2004 
 
Discount rate  6.00%  5.75%  6.25%  5.89%  5.75%  6.25%  6.00%  5.75%  6.25%  5.75%  5.75%  6.25%  5.89%  5.75%  6.25%
Expected long-term rate of return on plan assets  8.50%  8.50%  8.50%  8.50%  8.50%  8.50%  8.50%  8.50%  8.50%  N/A   N/A   N/A   8.50%  8.50%  8.50%
Rate of compensation increase  4.05%  3.97%  3.97% N/A N/A N/A   4.05%  3.97%  3.97%  N/A   N/A   N/A   N/A   N/A   N/A 
 
The weighted-average asset allocations by asset category for the two pension plans and the OPEB plan as of October 31, 20052006 and 2004,2005, are presented below.
                            
 2005 2004 2005 2004 Pension Benefits Other Benefits 
 Pension Benefits Other Benefits 2006 2005 2006 2005 
 
Equity securities  63%  62%  45%  47%  68%  63%  48%  45%
Debt securities  37%  38%  55%  53%  32%  37%  52%  55%
                  
Total  100%  100%  100%  100%  100%  100%  100%  100%
                  
 
We have long-term target allocations for the pension and OPEB plans 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 equity securities, we invest in a diversified portfolio which includes a significant exposure to equity securities.
Specific financial targets include:
 • Achieve full funding over the longer term,
 
 • Control fluctuation in pension expense from year to year,

56

 • 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 and OPEB portfolios. We believeintend to use 8.5% as the expected long-term rate of return on the pension and OPEB plans should remain at 8.50% for 2006.2007.
We estimate that we will contribute $15.3$16.5 million to the qualified pension plans, $.6 million to the nonqualified pension plans and $2.6$3 million to the OPEB plan in 2007.
The Pension Protection Act of 2006 (PPA) was signed into law by the President of the United States on August 17, 2006. While the PPA will have some effect on specific plan provisions in our retirement programs, the primary effect will be to change the minimum funding requirements for plan years beginning in 2008. The PPA has directed the United States Department of the Treasury to develop a new yield curve to discount pension obligations for determining the funded status of a plan when calculating funding requirements. Until regulations are issued by the Department of the Treasury, we are unable to determine the effect on our consolidated financial statements.
Because we believe that our plans are well funded, we expect the PPA to reduce our contributions to the pension plan that would otherwise have been required to be made beginning in 2008, deferring them to a later year. However, the amount of futureyear-by-year contributions is not expected to be materially different from our current projections.


56

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
                    
 Pension Other  Qualified
 Nonqualified
 Other
 
In thousands Benefits Benefits 
  Pension Pension Benefits 
2006 $13,231 $2,154 
 In thousands 
2007 12,877 2,251  $14,774  $495  $2,785 
2008 14,393 2,177   11,239   459   2,705 
2009 17,347 2,209   12,184   443   2,711 
2010 15,701 2,304   15,003   443   2,768 
2011-2015 95,211 ��13,145 
2011  14,415   417   2,762 
2012 - 2016  76,294   1,836   14,661 
The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 20052006 and 2004,2005, are presented below.
                
 2005 2004 2006 2005 
 
Health care cost trend rate assumed for next year  9.75%  10.50%  9.00%  9.75%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)  5.00%  5.00%  5.00%  5.00%
Year that the rate reaches the ultimate trend rate 2012 2012   2012   2012 
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 OPEB 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, 2005  $    103   $     (111)
         
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2005  1,024   (1,037)

57

         
  1% Increase  1% Decrease 
  In thousands 
 
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2006 $85  $(106)
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2006  1,277   (1,272)

 
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). The salary investment plans are subject to the provisions of the Employee Retirement Income Security Act. Full-time employees who have completed six months30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary to the plans and we match a portion of their contributions. AllEmployee contributions vest immediately.immediately and company contributions vest after six months of service. For the years ended October 31, 2006, 2005 2004 and 2003,2004, our matching contributions totaled $3.3 million, $3.2 million $2.9 million and $2.3$2.9 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.
 
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into our salary investment plans. Former ESOP participants may remain invested in Piedmont common stock in their salary investment plan or may sell the common stock at any time and


57

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the consolidated statement of stockholders’ equity as an increase in retained earnings.
9. Income Taxes
9.  Employee Share-Based Plans
Under the LTIP, the Board of Directors has awarded units to eligible officers and other participants. Depending upon the levels of performance targets achieved by Piedmont during multi-year performance periods, distribution of those awards may be made in the form of shares of common stock and cash withheld for payment of applicable taxes on the compensation. The LTIP requires that a minimum threshold performance be achieved in order for any award to be distributed. For the years ended October 31, 2006, 2005 and 2004, we recorded compensation expense for the LTIP of $5.4 million, $4 million and $3.1 million, respectively. Shares of common stock to be issued under the LTIP are contingently issuable shares and are included in our calculation of fully diluted earnings per share.
 
We have four awards under the LTIP with three-year performance periods ending October 31, 2006, October 31, 2007, October 31, 2008 and October 31, 2009. Fifty percent of the units awarded will be based on achievement of a target annual compounded increase in basic earnings per share (EPS). For this 50% portion, an EPS performance of 80% of target will result in an 80% payout, an EPS performance of 100% of target will result in a 100% payout and an EPS performance of 120% of target will result in a maximum 120% payout, and EPS performance levels between these levels will be subject to mathematical interpolation. EPS performance below 80% of target will result in no payout of this portion. The other 50% of the units awarded will be based on the achievement of a target total annual shareholder return in comparison to the A. G. Edwards Large Natural Gas Distribution Index industry peer group (Peer Group) total shareholder return (increase in the registrant’s common stock price plus dividends paid over the specified period of time). The total shareholder return performance measure will be the registrant’s percentile ranking in relationship to the Peer Group. For this 50% portion, a ranking below the 25th percentile will result in no payout, a ranking between the 25th and 39th percentile will result in an 80% payout, a ranking between the 40th and 49th percentile will result in a 90% payout, a ranking between the 50th and 74th percentile will result in a 100% payout, a ranking between the 75th and 89th percentile will result in a 110% payout, and a ranking at or above the 90th percentile will result in a maximum 120% payout.
We have one additional award with a five-year performance period that ended October 31, 2006, for a group of retired employees with 75% of the units awarded being based on achievement of a target cumulative increase in net income and 25% of the units awarded based on achievement of a target total annual shareholder return in comparison to the Peer Group discussed above and in the same percentile rankings. The payout under this award will occur over a three-year period.
As of October 31, 2006 and 2005, we have accrued $11.4 million and $9.3 million for these awards. The accrual is based on the fair market value of our stock at the end each quarter. The liability is re-measured to market value at the settlement date.
On September 1, 2006, the Board of Directors approved a grant under our Incentive Compensation Plan (ICP) to our President and Chief Executive Officer of 65,000 restricted shares of our common stock with a value at the date of grant of $1.7 million, based on the average closing price of our stock during the period July 1-30, 2006. The restricted shares shall vest and be payable on the following schedule only if he is an employee on the vesting date for each tranche:
• 20% on September 1, 2009,
• 30% on September 1, 2010, and
• 50% on September 1, 2011.


58

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

During the vesting period, any dividends paid on these shares will be accrued and converted into additional shares at the closing price on the date of the dividend payment. The additional shares will vest according to the vesting schedule above. As of October 31, 2006, we have recorded $.06 million as compensation expense. We are recording compensation under the ICP on the straight-line method.
On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for the issuance as an equity transaction. On November 1, 2005, we amended our plan to lower the discount from 10% to 5%. The purchase price on the purchase date is 95% of the average closing price as recorded on the New York Stock Exchange for the last month of the payroll contribution period.
As discussed in Note 5, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares available for issuance under our employee plans, including the ESPP, LTIP and ICP.
10.  Income Taxes
The components of income tax expense for the years ended October 31, 2006, 2005 2004 and 2003,2004, are as follows.
                                                
 2005 2004 2003  2006 2005 2004 
In thousands Federal State Federal State Federal State 
 Federal State Federal State Federal State 
 In thousands 
 
Charged to operating income:                         
Current $19,073 $3,880 $18,414 $9,298 $(4,581) $(959) $27,470  $4,977  $19,073  $3,880  $18,414  $9,298 
Deferred 24,006 5,462 24,880  (557) 38,252 7,931   14,775   3,855   24,006   5,462   24,880   (557)
Amortization of investment tax credits  (541) —  (550) —  (550) —   (534)  —   (541)  —   (550)  — 
                          
Total 42,538 9,342 42,744 8,741 33,121 6,972   41,711   8,832   42,538   9,342   42,744   8,741 
             
              
Charged to other income (expense):                         
Current 15,588 2,966 11,293 2,236 7,685 1,561   9,052   1,427   15,588   2,966   11,293   2,236 
Deferred  (6,407)  (1,701)  (2,582)  (385)  (623)  (99)  1,107   301   (6,407)  (1,701)  (2,582)  (385)
                          
Total 9,181 1,265 8,711 1,851 7,062 1,462   10,159   1,728   9,181   1,265   8,711   1,851 
                          
Total $51,719 $10,607 $51,455 $10,592 $40,183 $8,434  $51,870  $10,560  $51,719  $10,607  $51,455  $10,592 
                          
 
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2006, 2005 2004 and 2003,2004, is as follows.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Federal taxes at 35% $57,258 $55,032 $43,043  $55,867  $57,258  $55,032 
State income taxes, net of federal benefit 6,894 6,885 5,482   6,864   6,894   6,885 
Amortization of investment tax credits  (541)  (550)  (550)  (534)  (541)  (550)
Sale of propane interests  (1,624) — —   —   (1,624)  — 
Other, net 339 680 642   233   339   680 
              
Total $62,326 $62,047 $48,617  $62,430  $62,326  $62,047 
              

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59

 

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

As of October 31, 20052006 and 2004,2005, deferred income taxes consisted of the following temporary differences.
                
In thousands 2005 2004 
 2006 2005 
 In thousands 
 
Utility plant $208,947 $198,110  $226,866  $208,947 
Equity method investments 12,114 22,148   15,419   12,114 
Revenues and cost of gas 25,273 10,946   25,356   25,273 
Other, net  (10,156)  (11,863)  (7,145)  (10,156)
          
Net deferred income tax liabilities $236,178 $219,341  $260,496  $236,178 
          
 
As of October 31, 20052006 and 2004,2005, total deferred income tax liabilities were $261.6$281.8 million and $239.4$261.6 million and total net deferred income tax assets were $25.4$21.3 million and $20.1$25.4 million, respectively. Total net deferred income tax assets as of October 31, 20052006 and 2004,2005, were net of a valuation allowance of $.5 million and $1.2$.6 million, respectively, for net operating loss carryforwards that we believed were more likely than not to expire before we could use them. Piedmont and its wholly owned subsidiaries file a consolidated federal income tax return. Prior to October 25, 2005, EasternNC filed a separate federal income tax return as we did not own the prerequisite 80% share of EasternNC to allow EasternNC to participate in our consolidated federal return. With Piedmont’s acquisition of the remaining 50% interest in EasternNC, EasternNC became a member of Piedmont’s consolidated group on October 25, 2005, and was immediately merged into Piedmont. As of the acquisition date, EasternNC had federal and state net operating loss carryforwards of $7.5 million that expire from 2017 through 2025. Piedmont may use the EasternNC federal loss carryforwards to offset taxable income, subject to an annual limitation of $.3 million.
 
A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2006, 2005 2004 and 2003,2004, is as follows.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Balance at beginning of year $1,200 $1,000 $—  $583  $1,245  $1,073 
Charged (credited) to income tax expense  (700) 200 1,000   (15)  (662)  172 
              
Balance at end of year $500 $1,200 $1,000  $568  $583  $1,245 
              
 
During the yearyears ended October 31, 2004 and October 31, 2006, the Internal Revenue Service finalized its audit of our returns for the tax yearyears ended October 31, 2001.2001 and 2002, respectively. The audit results, which did not have a material effect on our financial position or results of operations, have been reflected in the consolidated financial statements. The Internal Revenue Service is auditing our tax returnreturns for the tax yearyears ended October 31, 2002.2003 through October 31, 2005. We believe the results of the audit will not have a material effect on our financial position or results of operations.
10.
11.  Equity Method Investments
The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the consolidated statements of income.
 
As of October 31, 2005, the amount of our retained earnings2006, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments was $6.2 million.in our retained earnings.

59
60

 

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

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, of which Piedmont subscribes to approximately 37%38%. 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 as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For each of the years ended October 31, 2006, 2005 2004 and 2003,2004, these gas costs were $4.7 million, $4.7 million and $1.7 million, respectively.million. As of October 31, 20052006 and 2004,2005, we owed Cardinal $.1 million and $.4 million.million, respectively.
 
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 20052006 and 2004,2005, and for the twelve months ended September 30, 2006, 2005 2004 and 2003,2004, is presented below.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Current assets $7,270 $8,142    $8,717  $7,270     
Non-current assets 88,250 91,049     85,933   88,250     
Current liabilities 3,238 3,612     4,458   3,294     
Non-current liabilities 37,496 39,360     35,520   37,440     
Revenues 15,525 15,567 $16,880   15,524   15,525  $15,567 
Gross profit 15,525 15,567 16,880   15,524   15,525   15,567 
Income before income taxes 8,368 8,102 9,211   8,785   8,368   8,102 
Pine Needle LNG Company, L.L.C.
 
We own 40% 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, of which Piedmont subscribes to approximately 64%.
 
Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. MovementsOur share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive income (loss)” 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 as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2006, 2005 2004 and 2003,2004, these gas costs were $12.7 million, $12.4 million $12.3 million and $10.6$12.3 million, respectively. As of October 31, 20052006 and 2004,2005, we owed Pine Needle $1.1 million and $1 million, respectively.million.

60
61

 

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 20052006 and 2004,2005, and for the twelve months ended September 30, 2006, 2005 2004 and 2003,2004, is presented below.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Current assets $8,653 $10,573    $10,823  $8,653     
Non-current assets 92,255 94,745     88,879   92,255     
Current liabilities 6,752 8,161     8,208   6,752     
Non-current liabilities 40,251 45,933     34,835   40,251     
Revenues 19,870 19,357 $20,013   19,231   19,870  $19,357 
Gross profit 19,870 19,357 20,013   19,231   19,870   19,357 
Income before income taxes 9,480 9,372 9,320   10,047   9,480   9,372 
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. In January 2004, we, along with the other members, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane for $130 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, was included in “Marketable securities” in the consolidated balance sheet. On February 1, 2005, we sold 18,622 of the units and on February 2, 2005, we sold the remaining 18,622 units for total cash proceeds of $2.4 million. We recorded a pre-tax gain of $1.5 million in the consolidated statement of income for the year ended October 31, 2005.
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). Under the terms of an amendedthe Amended and restated limited liability company operating agreement with AGLRRestated Limited Liability Company Agreement (Restated Agreement) effective January 1, 2004, earnings and losses are allocated 25% to us and 75% to AGLR.the other member, Georgia Natural Gas Company (GNGC), a subsidiary of AGL Resources, Inc. SouthStar primarily 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.
 
Contained in the SouthStar utilizes financial contractsRestated Agreement mentioned above between us and GNGC, there are provisions providing for the disposition of ownership interests between members, including a provision granting three options to hedgeGNGC to purchase our ownership interest in SouthStar. By November 1, 2007, with the variable cash flows associatedoption effective on January 1, 2008 (2008 option), GNGC has the option to purchase one-third of our 30% interest in SouthStar. With the same notice in the following years, GNGC has the option to purchase 50% of our interest to be effective on January 1, 2009 (2009 option), and 100% of our interest to be effective on January 1, 2010. The purchase price would be based on the market value of SouthStar as defined in the Restated Agreement.
If GNGC exercises either the 2008 option or the 2009 option, we, at our discretion, may cause GNGC to purchase our entire ownership interest.


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Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

For further information on this provision, please see the Restated Agreement that was filed with the Securities and Exchange Commission (SEC) as Exhibit 10.1 in ourForm 10-Q for the quarter ended April 30, 2004.
SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price changes on the timing of its earnings, wholesale price volatility can cause variations in the timing of the recognition of earnings.
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 eventOur share of warmer-than-normal weather in the winter months. Movementsmovements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive income (loss)” in the consolidated balance sheets.

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We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the years ended October 31, 2006, 2005 2004 and 2003,2004, these operating revenues were $21.6 million, $10.3 million $2.7 million and $.9$2.7 million, respectively. As of October 31, 20052006 and 2004,2005, SouthStar owed us $.9$.8 million and $.6$.9 million, respectively.
 
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 20052006 and 2004,2005, and for the twelve months ended September 30, 2006, 2005 2004 and 2003,2004, is presented below.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Current assets $218,562 $157,656    $195,893  $208,537     
Non-current assets 5,472 4,066     11,136   15,497     
Current liabilities 109,111 50,045     69,438   109,111     
Non-current liabilities  870   —     
Revenues 861,091 790,288 $727,871   1,053,770   861,091  $790,288 
Gross profit 148,885 122,811 99,618   155,416   148,885   122,811 
Income before income taxes 91,200 72,056 55,805   88,765   91,200   72,056 
Hardy Storage Company LLC
 We own
Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly-owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage)., a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, (Columbia Gas), a subsidiary of NiSource Inc. Hardy Storage intends to construct, own and operateis constructing an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia.Virginia, that it intends to own and operate. The storage facility will have the capacity to store approximately 12 billion cubic feet of natural gas and deliver up to 176,000 dekatherms per day by November 2009. Construction is expected to beginbe in early 2006 with storage service commencing with initial injections in April 2007. On June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for up to a total of $173.1 million for funding during the construction period. Once in service and after the satisfaction of certain conditions in the note purchase agreement, the two members of Hardy Storage will pay off 30% of the construction financing with their equity contributions and the remaining 70% debt will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. The other member of Hardy Storage will contribute assets and cash as part of its share of the 30% owner contributions, and we will contribute cash as our share.
The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. The guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly owned subsidiary of Piedmont and a sister company of Piedmont Hardy. Our share of the guaranty is capped at $111.5 million. Depending upon


63

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

the facility’s performance over the first three years after the in-service date, there could be additional construction requiring debt of up to $10 million, of which PEP will guarantee 50%.
Securing PEP’s guaranty is a pledge of intercompany notes issued by Piedmont held by non-utility subsidiaries of PEP. Should Hardy Storage be unable to perform its payment obligation under the construction financing, PEP will call on Piedmont for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interests in Hardy Storage.
As we are in the formation stage of the joint venture, we are recording a liability at fair value for this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changes, the fair value of the guaranty is fully subscribedadjusted accordingly through a quarterly evaluation.
As of October 31, 2006, $65.1 million was outstanding under long-term contracts. Total project capital expenditures are estimated at $135 to $145the construction financing, and we have recorded a guaranty liability of $1.8 million.
 
On November 1, 2005, the FERC issued an order granting a certificate of public convenience and necessity to Hardy Storage authorizing it to construct and operate the proposed project. In December 2005, two intervenors filed for rehearing with the FERC contesting the inclusion of income tax allowances in Hardy Storage’s rates. This issue was settled subsequently with the intervenors with no material effect on the project.
On October 26, 2006, Hardy Storage filed an application with the FERC for an amendment to its certificate of public convenience and necessity for approval of a settlement that establishes revised initial rates based on updated cost estimates. This application also requested expedited treatment for an order to be issued no later than February 28, 2007. The estimated cost of the project as refiled with the FERC is $164 million, an increase of $43 million from the original application of $121 million, due to higher costs for skilled labor, material and equipment for the project. The project sponsors will continue to pursue the developmentconstruction of the project with the goal of meeting the targetan anticipated in-service date of April 2007.
11. Business Segments
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2006 and 2005, and for the twelve months ended October 31, 2006 and 2005, is presented below.
 
             
  2006  2005  2004 
  In thousands 
 
Current assets $12,807  $8,107   n/a 
Non-current assets  88,194   9,914     
Current liabilities  39,873   2,644     
Non-current liabilities  2,922   2,756     
Revenues  *  *     
Gross profit  *  *     
Income before income taxes  2,023   123     
*Hardy Storage is not “in service” during the periods presented. The income above is related to AFUDC associated with the financing and construction activities of the storage facilities, and is recorded in accordance with regulatory guidelines.
12.  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, through October 25, 2005, by EasternNC. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures.


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Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

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

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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. 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, 2006, 2005 2004 and 2003,2004, and as of October 31, 20052006 and 2004,2005, are presented below.
                        
 Regulated Non-Utility    Regulated
 Non-Utility
   
In thousands Utility Activities Total 
 Utility Activities Total 
 In thousands 
2006            
Revenues from external customers $1,924,628  $—  $1,924,628 
Margin  523,479   —   523,479 
Operations and maintenance expenses  219,353   503   219,856 
Depreciation  89,696   4   89,700 
Income from equity method investments  —   29,917   29,917 
Interest expense  52,310   50   52,360 
Operating income (loss) before income taxes  181,292   (623)  180,669 
Income before income taxes and minority interest  130,730   28,889   159,619 
Total assets  2,600,411   75,877   2,676,288 
Equity method investments in non-utility activities  —   75,330   75,330 
Construction expenditures  196,730   551   197,281 
    
2005             
Revenues from external customers $1,761,091 $— $1,761,091  $1,761,091  $—  $1,761,091 
Margin 499,139 — 499,139   499,139   —   499,139 
Operations and maintenance expenses 206,983 214 207,197   206,983   214   207,197 
Depreciation 85,169 — 85,169   85,169   —   85,169 
Income from equity method investments — 27,664 27,664   —   27,664   27,664 
Interest expense 44,256 52 44,308   44,256   52   44,308 
Operating income (loss) before income taxes 177,180  (403) 176,777   177,180   (403)  176,777 
Income before income taxes and minority interest 135,758 28,440 164,198   135,758   28,440   164,198 
Total assets 2,527,993 71,520 2,599,513   2,527,993   71,520   2,599,513 
Equity method investments in non-utility activities — 71,520 71,520   —   71,520   71,520 
Construction expenditures 157,883 — 157,883   157,883   —   157,883 
    
2004             
Revenues from external customers $1,529,739 $— $1,529,739  $1,529,739  $—  $1,529,739 
Margin 488,369 — 488,369   488,369   —   488,369 
Operations and maintenance expenses 200,282 172 200,454   200,282   172   200,454 
Depreciation 82,276 — 82,276   82,276   —   82,276 
Income from equity method investments — 27,381 27,381   —   27,381   27,381 
Interest expense 47,364 48 47,412   47,364   48   47,412 
Operating income (loss) before income taxes 178,800  (234) 178,566   178,800   (234)  178,566 
Income before income taxes and minority interest 125,044 32,239 157,283   125,044   32,239   157,283 
Total assets 2,325,110 67,179 2,392,289 
Equity method investments in non-utility activities — 65,322 65,322 
Construction expenditures 103,187 — 103,187   103,187   —   103,187 
 
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 
Income from equity method investments — 17,972 17,972 
Interest expense 40,197 58 40,255 
Operating income (loss) before income taxes 143,199  (132) 143,067 
Income before income taxes and minority interest 106,150 17,649 123,799 
Construction expenditures 80,315 — 80,315 

63
65

 

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

Reconciliations to the consolidated financial statements for the years ended October 31, 2006, 2005 2004 and 2003,2004, and as of October 31, 20052006 and 2004,2005, are as follows.
                        
In thousands 2005 2004 2003 
 2006 2005 2004 
 In thousands 
 
Operating Income:             
Segment operating income before income taxes $176,777 $178,566 $143,067  $180,669  $176,777  $178,566 
Utility income taxes  (51,880)  (51,485)  (40,093)  (50,543)  (51,880)  (51,485)
Non-utility activities before income taxes 403 234 132   623   403   234 
              
Total $125,300 $127,315 $103,106  $130,749  $125,300  $127,315 
              
 
Net Income:             
Income before income taxes and minority interest for reportable segments $164,198 $157,283 $123,799  $159,619  $164,198  $157,283 
Income taxes  (62,326)  (62,047)  (48,617)  (62,430)  (62,326)  (62,047)
Less minority interest  (602)  (48)  (820)  —   (602)  (48)
              
Total $101,270 $95,188 $74,362  $97,189  $101,270  $95,188 
              
 
Consolidated Assets:             
Total assets for reportable segments $2,599,513 $2,392,289  $2,676,288  $2,599,513     
Eliminations/Adjustments 2,977  (125)   57,651   2,977     
          
Total $2,602,490 $2,392,164  $2,733,939  $2,602,490     
          
12. Environmental Matters
 
13.  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 actual environmental costs incurred and for estimated environmental liabilities recorded.
 
Several years ago, 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, charged to the estimated environmental liability, that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. 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 North Carolina Gas Services, a division of NUI Utilities, Inc.
 
As of October 31, 2005,2006, our undiscounted environmental liability totaled $3.2$3.3 million, and consisted of $2.8$2.9 million for the four MGP sites and $.4 million for underground storage tanks not yet remediated. We increased the liability in 20052006 by $.2$.1 million and in 20042005 by $.1$.2 million to reflect the impact of inflation based on the consumer price index.
 
As of October 31, 2005,2006, our regulatory assets for unamortized environmental costs totaled $4.1$3.8 million. 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, cash flows or results of operations.


66

 
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

In connection with the acquisition in 2003 of NCNG, several MGP sites owned by NCNG were transferred to a wholly owned

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subsidiary of Progress prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing andclean-up at these sites, including both the cost of such testing andclean-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 2003 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. As a part of the 2005 NCUC general rate case proceeding also discussed in Note 3 to the consolidated financial statements, the NCUC ordered a new three-year amortization period for the unamortized balance as of June 30, 2005, beginning November 1, 2005.
 
On July 26, 2005, we were notified by the North Carolina Department of Environment and Natural Resources that we were named as a potentially responsible party for alleged environmental problems associated with an underground storage tank site. We owned this site for less than two years several years ago in connection with a non-utility venture. There have been at least four owners of the site. We contractually transferred anyclean-up costs to the new owner of the site when we sold this venture. Our current estimate of the cost to remediate the site is approximately $120,000.$124,800. It is unclear how many of the former owners may ultimately be held liable for this site; however, based on the uncertainty of the ultimate liability, we established a non-regulated environmental liability for $30,000,$31,200, one-fourth of the estimated cost.
13. Restatement
14.  Restructuring
On April 13, 2006, we announced plans to restructure our management group at an estimated one-time cost of Statements$7 to $8 million. The restructuring plans were a part of Cash Flowsan ongoing, larger effort aimed at streamlining business processes, capturing operational and Balance Sheetorganizational efficiencies and improving customer service. The restructuring began with an offer of early retirement for 23 employees in our management group, and eventually included the further consolidation and reorganization of management positions and functions that was completed in July 2006.
 Subsequent
Since April, we have recognized a liability and expense of $7.9 million, which was included in operations and maintenance expense for the cost of the restructuring program. This liability included early retirement for 22 employees of the management group and severance for 17 additional employees through further consolidation. Due to the issuanceshort discount period, the liability for the program was recorded at its gross value.
A reconciliation of activity to the liability is as follows:
     
  In thousands 
 
Costs incurred and expensed $7,982 
Costs paid  (6,748)
Adjustment to accruals  (79)
     
Ending liability, October 31, 2006 $1,155 
     
15.  Subsequent Events
On November 7, 2006, we entered into an accelerated share repurchase program whereby we purchased and retired 1 million shares of our 2004 financial statements, management identified errorscommon stock from an investment bank at the closing price that day of $26.48 per share. Total consideration paid to purchase the shares of $26.6 million, including $118,800 in the consolidated statements of cash flows for the years ended October 31, 2004commissions and 2003, relating to distributions of earnings received from equity method investees, changesother fees, was recorded in restricted cash and the amounts reported“Stockholders’ equity” as construction expenditures. Management also identified errorsa reduction in the consolidated balance sheet as of October 31, 2004, relating principally to the inappropriate netting of customer credit balances in accounts receivable and prepaid group insurance assets in accounts payable. Additionally, management determined that we should have separately reported gas purchase options at fair value which previously had been included within amounts due to customers and amounts due from customers, and also identified other classification errors affecting balances reported for current and deferred income tax assets and liabilities.“Common stock.” As
     As a result, the accompanying 2004 and 2003 consolidated financial statements have been restated from the amounts previously reported to correct the presentation of these items. The restatement did not affect previously reported operating income, net income, earnings per share or stockholders’ equity.

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67

 

 A summary
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)

part of the significant effectsaccelerated share repurchase, we simultaneously entered into a forward sale contract with the investment bank that is expected to mature in approximately 50 trading days. Under the terms of the restatementforward sale contract, the investment bank is as follows:required to purchase, in the open market, 1 million shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, are required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price is higher than the November 7, 2006, closing price. The investment bank is required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price for the shares purchased is lower than the November 7, 2006, closing price.
         
In thousands As Previously    
As of October 31, 2004 Reported  As Restated 
Total current assets $335,209  $390,742 
Total current liabilities  306,167   336,155 
Deferred income taxes (non-current)  202,155   212,925 
Other deferred liabilities  41,465   56,994 
                 
  2004  2003 
  As      As    
In thousands Previously      Previously    
For the Years Ended October 31 Reported  As Restated  Reported  As Restated 
Cash flows from operating activities:                
Distributions of earnings from equity method investments $—  $26,078  $—  $9,946 
Decrease (increase) in restricted cash  (5,983)  —   1,936   — 
Net cash provided by operating activities  154,293   183,739   96,652   103,790 
                 
Cash flows from investing activities:                
Distributions of capital from equity method investments  26,291   213   10,188   242 
Decrease (increase) in restricted cash  —   (5,983)  —   1,936 
Net cash used in investing activities  (36,303)  (65,749)  (515,152)  (522,290)
* * * * *

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Selected Quarterly Financial Data (In thousands except per share amounts)
                         
                  Earnings (Loss)
              Net  Per Share of
  Operating      Operating  Income  Common Stock
  Revenues  Margin  Income  (Loss)  Basic  Diluted 
 
                         
Fiscal Year 2005                        
January 31 $680,556  $202,620  $78,919  $71,277  $.93  $.93 
April 30  508,035   140,657   40,914   39,632   .52   .52 
July 31  232,912   76,616   2,984   (4,666)  (.06)  (.06)
October 31  339,588   79,246   2,483   (4,973)  (.06)  (.06)
                         
Fiscal Year 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)
 
                         
              Earnings (Loss)
 
           Net
  per Share of
 
  Operating
     Operating
  Income
  Common Stock 
  Revenues  Margin  Income (Loss)  (Loss)  Basic  Diluted 
 
Fiscal Year 2006                        
January 31 $921,347  $209,372  $81,161  $71,997  $0.94  $0.94 
April 30  483,198   154,010   44,200   43,742   0.57   0.57 
July 31  237,874   72,982   (1,026)  (12,389)  (0.16)  (0.16)
October 31  282,209   87,115   6,414   (6,161)  (0.08)  (0.08)
             
Fiscal Year 2005                        
January 31 $680,556  $202,620  $78,919  $71,277  $0.93  $0.93 
April 30  508,035   140,657   40,914   39,632   0.52   0.52 
July 31  232,912   76,616   2,984   (4,666)  (0.06)  (0.06)
October 31  339,588   79,246   2,483   (4,973)  (0.06)  (0.06)
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.


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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
 None.
Item 9A.�� Controls and Procedures
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
 
Management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures. Such disclosure controls and procedures are designed to ensure that all information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on our evaluation process, the Chief Executive Officer and the Chief Financial Officer have concluded that ourwe have effective disclosure controls and procedures are effective as of October 31, 2005.2006. Management’s report on internal control over financial reporting and the attestation report of our independent registered public accounting firm are on Page 6870 and Page 69,71, respectively. There were no changes in our internal control over financial reporting during the fourth quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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69

 

Management’s Report on Internal Control Over Financial Reporting
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
January 17, 200612, 2007
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined inRules 13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Business Conduct and Ethics adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.
Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.
We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control-IntegratedControl — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based upon such evaluation, our management concluded that as of October 31, 2006, our internal control over financial reporting was effective as of October 31, 2005.effective.
Management’s assessment of the effectiveness of our internal control over financial reporting as of October 31, 2005,2006, has been audited by Deloitte and Touche LLP, an independent registered public accounting firm. Their attestation report is on Page 69.71.
 
Piedmont Natural Gas Company, Inc.
 
 /s/  Thomas E. Skains
Thomas E. Skains 
Chairman, President and Chief Executive Officer 
/s/ David J. Dzuricky  
David J. Dzuricky 
Senior Vice President and Chief Financial Officer 
/s/ Barry L. Guy  
Barry L. Guy 
Vice President and Controller 
Thomas E. Skains
Chairman, President and Chief Executive Officer
/s/  David J. Dzuricky
David J. Dzuricky
Senior Vice President and Chief Financial Officer
/s/  Jose M. Simon
Jose M. Simon
Vice President and Controller

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Piedmont Natural Gas Company Inc. and subsidiaries (“Piedmont”) maintained effective internal control over financial reporting as of October 31, 2005,2006, based on criteria established inInternal Control—Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Piedmont’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of Piedmont’s internal control over financial reporting based on our audit.
 
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management’s assessment that Piedmont maintained effective internal control over financial reporting as of October 31, 2005,2006, is fairly stated, in all material respects, based on the criteria established inInternal Control—Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Piedmont maintained, in all material respects, effective internal control over financial reporting

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as of October 31, 2005,2006, based on the criteria established inInternal Control—Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Piedmont as of and for the year ended October 31, 2005,2006, and our report dated January 17, 200612, 2007 expressed an unqualified opinion on those financial statements.
/s/  Deloitte & Touche LLP
Charlotte, North Carolina
January 17, 200612, 2007

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Item 9B. Other Information
     None.


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Item 9B.Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
 
Item 10.Directors and Executive Officers of the Registrant
Information concerning our executive officers and directors is set forth in the sections entitled “Election“Information Regarding the Board of Directors” and “Executive Officers” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which sections are incorporated in this annual report onForm 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
 
Information concerning our Audit Committee and our Audit Committee financial expertexperts is set forth in the section entitled “Committees of the Board” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
 
We have adopted a Code of Business Conduct and Ethics that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics was filed as Exhibit 14.1 to our annual report onForm 10-K for the year ended October 31, 2003, and is available on our website atwww.piedmontng.com. If we amend the Code of Business Conduct and Ethics or grant a waiver, including an implicit waiver, from the Code of Business Conduct and Ethics, we intend towill disclose the informationamendment or waiver on our website within four business days of such amendment or waiver.
Item 11. Executive Compensation
Item 11.Executive Compensation
Information for this item is set forth in the sections entitled “Executive Compensation and Other Information” andInformation,” “Directors’ Compensation Policy”Policy,” “Compensation Committee Interlocks and Insider Participation,” “Compensation Committee Report on Executive Compensation” and “Comparisons of Cumulative Total Shareholder Returns” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which sections are incorporated in this annual report onForm 10-K by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information for this item is set forth in the sectionssection entitled “Security Ownership of Management”Management and “Security Ownership of Certain Beneficial Owners” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which sections aresection is incorporated in this annual report onForm 10-K by reference.
 
We know of no arrangement, or pledge, which may result in a change in control. Information describing any material changes to the procedures for recommending nominees to the Board is set forth in the section entitled “Questions and Answers About the Annual Meeting

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and Voting”“Commonly Asked Questions” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
 
Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Long-Term Incentive Plan Awards”Awards — Awards in Last Fiscal Year” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.


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Item 13. Certain Relationships and Related Transactions
Item 13.Certain Relationships and Related Transactions
Information for this item is set forth in the section entitled “Certain Relationships and Related Transactions” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
Item 14. Principal Accounting Fees and Services
Item 14.Principal Accounting Fees and Services
Information for this item is set forth in the section entitled “Selection“Fees For Services” in “Proposal B — Ratification of Deloitte & Touche As Independent Registered Public Accounting Firm”Firm For Fiscal Year 2007” in our Proxy Statement for the 20062007 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.

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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)Item 15.1.Exhibits, Financial StatementsStatement Schedules
(a) 1.Financial Statements
 
The following consolidated financial statements for the year ended October 31, 2005,2006, are included in Item 8 of this report as follows:
   
  Page
 
Consolidated Balance Sheets — October 31, 20052006 and 2004 (Restated)2005 3233
Consolidated Statements of Income — Years Ended October 31, 2006, 2005 2004 and 20032004 34
Consolidated Statements of Cash Flows — Years Ended October 31, 2006, 2005 2004 (Restated) and 2003 (Restated)2004 3635
Consolidated Statements of Stockholders’ Equity — Years Ended October 31, 2006, 2005 2004 and 20032004 3836
Notes to Consolidated Financial Statements 4037
(a)2.Supplemental Consolidated Financial Statement Schedules
 
(a) 2.Supplemental Consolidated Financial Statement Schedules
None
 
Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(a)3.Exhibits
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
The exhibits numbered 10.1 through 10.18 are management contracts or compensatory plans or arrangements.
3.1Articles of Incorporation as of March 7, 1997, filed in the Department of State of the State of North Carolina (Exhibit 4.6, Form S-3 Registration Statement No. 333-111806).
(a) 3.Exhibits
     
    Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
    The exhibits numbered 10.1 through 10.26 are management contracts or compensatory plans or arrangements.
 3.1 Articles of Incorporation of the Company as of March 3, 2006, filed in the Department of State of the State of North Carolina (Exhibit 4.1,Form S-8 Registration StatementNo. 333-132738).
 3.2 Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed ‘‘Piedmont Natural Gas Company, Inc.” (Exhibits 3.2 and 3.1, Registration Statement onForm 8-B, dated March 2, 1994).
 3.3 By-Laws, dated February 27, 2004 (Exhibit 3.1,Form 10-Q for the quarter ended April 30, 2004).
 4.1 Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.30,Form 10-K for the fiscal year ended October 31, 1992).
 4.2 Indenture, dated as of April 1, 1993, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.1,Form S-3 Registration Statement No.33-59369).
 4.3 Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7,Form 10-K for the fiscal year ended October 31, 1993).


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 4.4 Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8,Form 10-K for the fiscal year ended October 31, 1993).
 4.5 First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (Exhibit 4.2,Form S-3 Registration StatementNo. 33-59369).
 4.6 Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9,Form 10-K for the fiscal year ended October 31, 1994).
 4.7 Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit 4.10,Form 10-K for the fiscal year ended October 31, 1995).
 4.8 Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit 4.11,Form 10-K for the fiscal year ended October 31, 1996).
 4.9 Rights Agreement, dated as of February 27, 1998, between Piedmont and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1,Form 8-K dated February 27, 1998).
 4.10 Agreement of Substitution and Amendment of Common Shares Rights Agreement, dated as of December 18, 2003, between Piedmont and American Stock Transfer and Trust Company, Inc. (Exhibit 4.10,Form S-3 Registration StatementNo. 333-111806).
 4.11 Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4,Form S-3 Registration StatementNo. 333-26161).
 4.12 Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration Statement Nos.33-59369 and333-26161).
 4.13 Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration Statement Nos.33-59369 and333-26161).
 4.14 Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration StatementNo. 333-26161).
 4.15 Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4,Form S-3 Registration Statement No.333-62222).
 4.16 Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration StatementNo. 333-62222).
 4.17 Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.3,Form S-3 Registration StatementNo. 333-106268).
 4.18 Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1,Form 8-K, dated December 23, 2003).
 4.19 Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2,Form 8-K, dated December 23, 2003).
 4.20 Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (Exhibit 4.1,Form 8-K dated June 20, 2006).
 4.21 Form of 6.25% Insured Quarterly Note Series 2006, Due 2036 (Exhibit 4.2 (as included in Exhibit 4.1),Form 8-K dated June 20, 2006).
    Compensatory Contracts:
 10.1 Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit 10.54,Form 10-K for the fiscal year ended October 31, 1999).
 10.2 Resolution of Board of Directors, September 2, 2005, establishing compensation for non-management directors (Exhibit 10.1,Form 8-K dated September 9, 2005).
 10.3 Executive Long-Term Incentive Plan, dated February 27, 2004 (Exhibit 10.2,Form 10-Q for quarter ended April 30, 2004).
 10.4 Establishment of Measures for Long-Term Incentive Plan #10 (filed inForm 8-K dated October 20, 2006, as Item 1.01).
 10.5 Form of Award Agreement under Executive Long-Term Incentive Plan.
 10.6 Employment Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37,Form 10-K for the fiscal year ended October 31, 1999).

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3.2Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed “Piedmont Natural Gas Company, Inc.” (Exhibits 3.2 and 3.1, Registration Statement on Form 8-B, dated March 2, 1994).
3.3By-Laws, dated February 27, 2004 (Exhibit 3.1, Form 10-Q for the quarter ended April 30, 2004).
4.1Note Agreement, dated as of July 30, 1991, between Piedmont and The Prudential Insurance Company of America (Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 1991).
4.2Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).
4.3Indenture, dated as of April 1, 1993, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).
4.4Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7, Form 10-K for the fiscal year ended October 31, 1993).
4.5Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
4.6First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (Exhibit 4.2, Form S-3 Registration Statement No. 33-59369).
4.7Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.8Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
4.9Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
4.10Rights Agreement, dated as of February 27, 1998, between Piedmont and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1, Form 8-K dated February 27, 1998).
     
 10.7 Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40,Form 10-K for the fiscal year ended October 31, 1999).
 10.8 Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23,Form 10-K for the fiscal year ended October 31, 2002).
 10.9 Employment Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2006).
 10.10 Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.2,Form 10-Q for the quarter ended April 30, 2006).
 10.11 Severance Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.41,Form 10-K for the fiscal year ended October 31, 1999).
 10.12 Severance Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.44,Form 10-K for the fiscal year ended October 31, 1999).
 10.13 Severance Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.28,Form 10-K for the fiscal year ended October 31, 2002).
 10.14 Severance Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.3,Form 10-Q for the quarter ended April 30, 2006).
 10.15 Severance Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.4,Form 10-Q for the quarter ended April 30, 2006).
 10.16 Severance Agreement with June B. Moore, dated May 1, 2006 (Exhibit 10.5,Form 10-Q for the quarter ended April 30, 2006).
 10.17 Severance Agreement with Jane R. Lewis-Raymond, dated May 1, 2006 (Exhibit 10.6,Form 10-Q for the quarter ended April 30, 2006).
 10.18 Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (Exhibit 10.1,Form 8-K dated December 10, 2004).
 10.19 Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (with supplemental retirement benefit) (Exhibit 10.14,Form 10-K for the fiscal year ended October 31, 2004).
 10.20 Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (without supplemental retirement benefit) (Exhibit 10.15,Form 10-K for the fiscal year ended October 31, 2004).
 10.21 Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (effective November 1, 2003) (Exhibit 10.16,Form 10-K for the fiscal year ended October 31, 2004).
 10.22 Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP).
 10.23 Establishment of Measures for 2007 Short-Term Incentive Plan (filed inForm 8-K dated October 20, 2006, as Item 1.01).
 10.24 Jerry W. Amos Engagement Letter dated January 3, 2005 (Exhibit 10.1,Form 8-K filed January 6, 2005) (Exhibit 10.18,Form 10-K for the fiscal year ended October 31, 2004).
 10.25 Piedmont Natural Gas Company, Inc. Incentive Compensation Plan (Exhibit 10.1,Form 8-K dated March 3, 2006).
 10.26 Restricted Stock Award Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated September 1, 2006.
    Other Contracts:
 10.27 Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2004).
 10.28 First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company.

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 10.29 Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company.
 10.30 Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company.
 10.31 Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (Exhibit 10.1,Form 8-K dated November 16, 2004).
 10.32 Construction, Operation and Maintenance Agreement by and Between Columbia Gas Transmission Corporation and Hardy Storage Company, LLC, dated November 12, 2004 (Exhibit 10.2,Form 8-K dated November 16, 2004).
 10.33 Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3,Form 8-K dated November 16, 2004).
 10.34 Guaranty of Principal dated as of June 29, 2006, by Piedmont Energy Partners, Inc. in favor of U.S. Bank National Association, as agent (Exhibit 10.1,Form 8-K dated July 5, 2006).
 10.35 Residual Guaranty dated as of June 29, 2006, by Piedmont Energy Partners, Inc. in favor of U.S. Bank National Association, as agent (Exhibit 10.2,Form 8-K dated July 5, 2006).
 12  Computation of Ratio of Earnings to Fixed Charges.
 21  List of Subsidiaries.
 23.1 Consent of Independent Registered Public Accounting Firm.
 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.
4.11Agreement of Substitution and Amendment of Common Shares Rights Agreement, dated as of December 18, 2003, between Piedmont and American Stock Transfer and Trust Company, Inc. (Exhibit 4.10, Form S-3 Registration Statement No. 333-111806).
4.12Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).
4.13Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
4.14Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
4.15Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement No. 333-26161).
4.16Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4, Form S-3 Registration Statement No. 333-62222).
4.17Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement No. 333-62222).
4.18Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.3, Form S-3 Registration Statement No. 333-106268).
4.19Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1, Form 8-K, dated December 23, 2003).
4.20Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2, Form 8-K, dated December 23, 2003).
Compensatory Contracts:
10.1Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).

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10.2Executive Long-Term Incentive Plan, dated February 27, 2004 (Exhibit 10.2, Form 10-Q for quarter ended April 30, 2004).
10.3Employment Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1999).
10.4Employment Agreement with Ray B. Killough, dated December 1, 1999 (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1999).
10.5Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999).
10.6Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 2002).
10.7Employment Agreement with Kim R. Cocklin, dated February 3, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2003).
10.8Severance Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1999).
10.9Severance Agreement with Ray B. Killough, dated December 1, 1999 (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1999).
10.10Severance Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.44, Form 10-K for the fiscal year ended October 31, 1999).
10.11Severance Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2002).
10.12Severance Agreement with Kim R. Cocklin, dated February 3, 2003 (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2003).
10.13Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (Exhibit 10.1, Form 8-K dated December 10, 2004).
10.14Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (with supplemental retirement benefit) (Exhibit 10.14, Form 10-K for the fiscal year ended October 31, 2004).

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10.15Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (without supplemental retirement benefit) (Exhibit 10.15, Form 10-K for the fiscal year ended October 31, 2004).
10.16Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (effective November 1, 2003) (Exhibit 10.16, Form 10-K for the fiscal year ended October 31, 2004).
10.17Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (Exhibit 10.17, Form 10-K for the fiscal year ended October 31, 2004).
10.18Jerry W. Amos Engagement Letter dated January 3, 2005 (Exhibit 10.1, Form 8-K filed January 6, 2005) (Exhibit 10.18, Form 10-K for the fiscal year ended October 31, 2004).
Other Contracts:
10.19Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004).
10.20Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (Exhibit 10.1, Form 8-K dated November 16, 2004).
10.21Construction, Operation and Maintenance Agreement by and Between Columbia Gas Transmission Corporation and Hardy Storage Company, LLC, dated November 12, 2004 (Exhibit 10.2, Form 8-K dated November 16, 2004).
10.22Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3, Form 8-K dated November 16, 2004).
12     Computation of Ratio of Earnings to Fixed Charges.
21     List of Subsidiaries.
23.1  Consent of Independent Registered Public Accounting Firm.
31.1  Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.

78

31.2Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
32.1Certification 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.
32.2Certification 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.

79

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Piedmont Natural Gas Company, Inc.
            (Registrant)
 Piedmont Natural Gas Company, Inc.
                    (Registrant)
By: /s/  Thomas E. Skains
Thomas E. Skains
Chairman of the Board, President
Thomas E. Skains
Chairman of the Board, President
and Chief Executive OfficerDate: January 17, 2006
 
Date: January 12, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
   
Signature
 
Title
Date
 
/s/  Thomas E. Skains

Thomas E. Skains		 Chairman of the Board, President and Chief Executive Officer
(Principal Executive Officer)		January 12, 2007
   
Thomas E. SkainsChief Executive Officer
(Principal Executive Officer)
  
Date: January 17, 2006
/s/  David J. Dzuricky

David J. Dzuricky		 Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)		January 12, 2007
   
David J. Dzuricky
/s/  Jose M. Simon

Jose M. Simon		 Chief Financial OfficerVice President and Controller
(Principal Accounting Officer)		January 12, 2007


77

  (Principal Financial Officer)
Signature
Title
Date
/s/  Jerry W. Amos

Jerry W. Amos		DirectorJanuary 12, 2007
   
Date: January 17, 2006
/s/  E. James Burton

E. James Burton		 DirectorJanuary 12, 2007
   
/s/  Barry L. GuyD. Hayes Clement

D. Hayes Clement		 Vice President and ControllerDirectorJanuary 12, 2007
   
Barry L. Guy
/s/  Malcolm E. Everett III

Malcolm E. Everett III		 (Principal Accounting Officer)DirectorJanuary 12, 2007
   
Date:
/s/  John W. Harris

John W. Harris		DirectorJanuary 17, 200612, 2007
  
/s/  Aubrey B. Harwell, Jr.

Aubrey B. Harwell, Jr.		DirectorJanuary 12, 2007
/s/  Muriel W. Sheubrooks

Muriel W. Sheubrooks		DirectorJanuary 12, 2007
/s/  Frank B. Holding, Jr.

Frank B. Holding, Jr.		DirectorJanuary 12, 2007
/s/  Minor M. Shaw

Minor M. Shaw		DirectorJanuary 12, 2007
/s/  David E. Shi

David E. Shi		DirectorJanuary 12, 2007
/s/  Vicki McElreath

Vicki McElreath		DirectorJanuary 12, 2007

80
78

 

SignatureTitle
/s/ Jerry W. AmosDirector
Jerry W. Amos
/s/ D. Hayes ClementDirector
D. Hayes Clement
/s/ Malcolm E. Everett IIIDirector
Malcolm E. Everett III
/s/ John W. HarrisDirector
John W. Harris
/s/ Aubrey B. Harwell, Jr.Director
Aubrey B. Harwell, Jr.
/s/ Muriel W. HelmsDirector
Muriel W. Helms
/s/ Frank B. Holding, Jr.Director
Frank B. Holding, Jr.
/s/ Minor M. ShawDirector
Minor M. Shaw
/s/ David E. ShiDirector
David E. Shi

81

Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 20052006
Exhibits
12Computation of Ratio of Earnings to Fixed Charges.
21List of Subsidiaries
23.1Consent of Independent Registered Public Accounting Firm.
31.1Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
31.2Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
32.1Certification 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.
32.2Certification 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.
Exhibits
     
 10.5 Form of Award Agreement under Executive Long-Term Incentive Plan
 10.22 Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP)
 10.26 Restricted Stock Award Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated September 1, 2006
 10.28 First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company
 10.29 Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company
 10.30 Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company
 12  Computation of Ratio of Earnings to Fixed Charges
 21  List of Subsidiaries
 23.1 Consent of Independent Registered Public Accounting Firm
 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