UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FormFORM 10-K

(Mark One)

x
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2011

or

¨For the fiscal year ended October 31, 2008
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 from             to             

Commission file number1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina 56-0556998
North Carolina56-0556998

(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

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

Title of each class

 

Name of each exchange on which registered

Title of Each Class
Name of Each Exchange on Which 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 Securities Act.    Yes  þx    No  o¨

Indicate by check mark if the registrant is not required to file reports pursuant to section 13 or 15 (d) of the Act.    Yes  o¨    No  þx

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.    Yes  þx    No  o¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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.    ¨o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):

Large accelerated filerxAccelerated filer¨
Large acceleratedNon-accelerated filerþAccelerated filer oNon-accelerated¨  filer o(Do not check if a smaller reporting company)Smaller reporting companyo¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act).    Yes  o¨    No  þx

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2008.

2011.

Common Stock, no par value — $1,911,028,686

- $2,259,483,861

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

Class

 
Class

Outstanding at December 16, 2008

2011

Common Stock, no par value

 73,260,67272,338,303

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 6, 2009,8, 2012 are incorporated by reference into Part III.


Piedmont Natural Gas Company, Inc.
2008

2011 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

       Page
 

    

Item 1.

  

   1  

  

   57  

  

   815  

  

   815  

  

   916  

  

   916  

Part II.

    

Item 5.

  
Part II.

   917  

  

   1219  

  

   1220  

  

   3449  

  

   3552  

  

   79119  

  

   79119  

  

   82122  

Part III.

    

Item 10.

  
Part III.

   82122  

  

   82122  

  

   82123  

  

   82123  

  

   82123  

Part IV.

    

Item 15.

  
Part IV.

   83124  
  

   87131  
EX-10.32
EX-10.33
EX-12
EX-21
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2


PART I

Item 1. Business

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 whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 62,00051,800 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.

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

We have two reportable business segments, regulated utility and non-utility activities. OperationsThe regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated segment include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. For the year ended October 31, 2011, 87% of our earnings before taxes came from our regulated utility segment. The non-utility activities segment are comprisedconsists of our equity method investments in joint ventures.venture, energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. For the year ended October 31, 2011, 13% of our earnings before taxes came from our non-utility segment, which consists of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. Operations of both segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 1012 and Note 11,14, respectively, to the consolidated financial statements.

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 prudently incurred purchased gas costs from suppliers are passed onthrough 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, 2008, 39%2011, 46% of our operating revenues were from residential customers, 24%27% from commercial customers, 12%10% from large volume customers, including industrial, power generation and resale customers, and 25%17% from secondary market activities. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatoryutility gas supply management program with regulatory-approvedregulator-approved sharing mechanisms between our utility customers and our shareholders. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.”

Our utility operations are regulated 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 areThe NCUC also regulated by the NCUCregulates us as to the issuance of long-term debt and equity 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 purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the design, construction, operation, maintenance, integrity, safety and security 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.environment. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit 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 many of the communities we serve, with expiration dates from 2008December 2011 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. TwelveTwenty-one franchise agreements have expired as of


1


October 31, 2008, and eleven will expire during the 2009 fiscal year.2011. We continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Two franchise agreements will expire during the 2012 fiscal year. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed or that service will be continued in the ordinary course of business under our state-granted franchise rights without the specific franchise agreements with each city or municipality, 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.
us.

The natural gas distribution business is seasonal in nature as variations in weather conditions and our regulated utility rate designs 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.10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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 monthsheating season (principally November through March) when customer demand is higher. During the year ended October 31, 2008,2011, the amount of natural gas in storage varied from 13.214.6 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 2526.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $100.4$75.9 million to $190.3$133.2 million.

During the year ended October 31, 2008, 121.62011, 181.2 million dekatherms of gas were sold to or transported for large volume customers compared with 122.3154.3 million dekatherms in 2007.2010. Of these volumes sold to or transported for large volume customers, we transported 83.5 million dekatherms this year to power generation facilities as compared with 63 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed demand contracts. Deliveries to temperature-sensitive residential

and commercial customers, whose consumption varies with the weather, totaled 88.798.5 million dekatherms in 2008,2011, compared with 83.798.3 million dekatherms in 2007.2010. Weather, as measured by degree days, was 5% warmer10% colder than normal in 20082011 and 12% warmer6% colder than normal in 2007.

2010.

The following is a five-year comparison of operating statistics for the years ended October 31, 20042007 through 2008.

                     
  2008  2007  2006  2005  2004 
 
Operating Revenues (in thousands):                    
Sales and Transportation:                    
Residential $813,032  $743,637  $841,051  $686,304  $624,487 
Commercial  503,317   418,426   498,956   421,499   360,355 
Industrial  209,341   190,204   205,384   215,505   179,302 
For Power Generation  25,266   29,135   22,963   16,248   18,782 
For Resale  12,326   13,907   11,342   40,122   38,074 
                     
Total  1,563,282   1,395,309   1,579,696   1,379,678   1,221,000 
Secondary Market Sales  515,968   308,904   337,278   373,353   301,886 
Miscellaneous  9,858   7,079   7,654   8,060   6,853 
                     
Total $2,089,108  $1,711,292  $1,924,628  $1,761,091  $1,529,739 
                     
Gas Volumes — Dekatherms (in thousands):                    
System Throughput:                    
Residential  51,909   50,072   49,119   52,966   54,412 
Commercial  36,766   33,647   34,476   36,000   35,483 
Industrial  81,780   79,266   80,490   81,102   83,957 
For Power Generation  30,875   34,096   26,099   25,591   18,580 
For Resale  8,921   8,923   8,472   8,779   8,912 
                     
Total  210,251   206,004   198,656   204,438   201,344 
                     
Secondary Market Sales  53,442   42,049   40,994   47,057   51,707 
                     


2

2011.


   2011   2010   2009   2008   2007 

Operating Revenues (in thousands):

          

Sales and Transportation:

          

Residential

  $658,892   $743,346   $787,994   $813,032   $743,637 

Commercial

   379,846    428,085    462,160    503,317    418,426 

Industrial

   104,774    116,122    126,855    209,341    190,204 

For Power Generation

   28,969    21,708    19,609    25,266    29,135 

For Resale

   9,692    11,061    11,746    12,326    13,907 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   1,182,173    1,320,322    1,408,364    1,563,282    1,395,309 

Secondary Market Sales

   244,824    224,973    221,300    515,968    308,904 

Miscellaneous

   6,908    7,000    8,452    9,858    7,079 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $1,433,905   $1,552,295   $1,638,116   $2,089,108   $1,711,292 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gas Volumes - Dekatherms (in thousands):

          

System Throughput:

          

Residential

   57,778    58,327    55,298    51,909    50,072 

Commercial

   40,749    39,994    38,526    36,766    33,647 

Industrial

   90,842    82,805    74,363    81,780    79,266 

For Power Generation

   83,522    63,024    39,639    30,875    34,096 

For Resale

   6,870    8,465    9,048    8,921    8,923 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   279,761    252,615    216,874    210,251    206,004 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Secondary Market Sales

   48,835    46,823    46,057    53,442    42,049 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Number of Customers Billed (12-month average):

          

Residential

   871,401    864,205    855,670    852,586    835,636 

Commercial

   94,485    94,287    94,404    94,045    93,472 

Industrial

   2,265    2,273    2,358    2,937    2,959 

For Power Generation

   22    20    20    20    15 

For Resale

   15    16    17    17    15 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   968,188    960,801    952,469    949,605    932,097 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

   2011  2010  2009  2008  2007 

Average Per Residential Customer:

      

Gas Used - Dekatherms

   66.30   67.49   64.63   60.88   59.92 

Revenue

  $756.13  $860.15  $920.91  $953.61  $889.90 

Revenue Per Dekatherm

  $11.40  $12.74  $14.25  $15.66  $14.85 

Cost of Gas (in thousands):

      

Natural Gas Commodity Costs

  $666,930  $753,529  $727,744  $1,454,073  $1,055,600 

Capacity Demand Charges

   136,139   127,137   128,081   127,640   116,977 

Natural Gas Withdrawn From (Injected Into) Storage, net

   11,362   5,293   126,480   (78,283  (12,815

Regulatory Charges (Credits), net

   45,835   113,744   94,237   32,705   27,365 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total

  $860,266  $999,703  $1,076,542  $1,536,135  $1,187,127 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Supply Available for Distribution (dekatherms in thousands):

      

Natural Gas Purchased

   155,550   157,021   149,696   159,857   143,598 

Transportation Gas

   175,005   147,038   115,519   108,332   108,355 

Natural Gas Withdrawn From (Injected Into) Storage, net

   196   (1,309  1,010   (2,980  (1,640

Company Use

   (309  (282  (283  (135  (141
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total

   330,442   302,468   265,942   265,074   250,172 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

                     
  2008  2007  2006  2005  2004 
 
Number of Retail Customers Billed(12-month average):
                    
Residential  852,586   835,636   815,579   792,061   771,037 
Commercial  94,045   93,472   92,692   91,645   90,328 
Industrial  2,937   2,959   3,008   3,146   3,194 
For Power Generation  20   15   12   16   13 
For Resale  17   15   19   15   15 
                     
Total  949,605   932,097   911,310   886,883   864,587 
                     
                     
Average Per Residential Customer:                    
Gas Used — Dekatherms  60.88   59.92   60.23   66.87   70.57 
Revenue $953.61  $889.90  $1,031.23  $866.48  $809.93 
Revenue Per Dekatherm $15.66  $14.85  $17.12  $12.96  $11.48 
                     
Cost of Gas (in thousands):                    
Natural Gas Commodity Costs $1,454,073  $1,055,600  $1,229,326  $1,226,999  $943,890 
Capacity Demand Charges  127,640   116,977   99,333   117,287   125,178 
Natural Gas Withdrawn From (Injected Into) Storage, net  (78,283)  (12,815)  15,709   (35,151)  (11,116)
Regulatory Charges (Credits), net  32,705   27,365   56,781   (47,183)  (16,582)
                     
Total $1,536,135  $1,187,127  $1,401,149  $1,261,952  $1,041,370 
                     
                     
Supply Available for Distribution (dekatherms in thousands):                    
Natural Gas Purchased  159,857   143,598   140,999   155,614   163,257 
Transportation Gas  108,332   108,355   101,414   97,959   91,795 
Natural Gas Withdrawn From (Injected Into) Storage, net  (2,980)  (1,640)  (197)  856   775 
Company Use  (135)  (141)  (127)  (133)  (135)
                     
Total  265,074   250,172   242,089   254,296   255,692 
                     
We purchase natural gas under firm contracts 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 contracts. The pipeline capacity contracts require the payment of fixed demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement these firm contracts with other supply arrangements to serve our interruptible market.

3


As of October 31, 2008,2011, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.

Williams-Transco

   632,200 

El Paso-Tennessee Pipeline

   74,100 

Spectra-Texas Eastern (through arrangements with East Tennessee and Transco)

   38,00036,700 

NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)

   42,800 

NiSource-Columbia Gulf

   10,000 

ONEOK-Midwestern (through arrangements with Tennessee, Columbia Gulf, East Tennessee and Transco)

   120,000 

Total

   915,800 
Total  

917,100

 

As of October 31, 2008,2011, 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 with deliverability varying from 5 days to one year.

Piedmont Liquefied Natural Gas (LNG)

   278,000268,000 

Pine Needle LNG (through arrangements with Transco)

   263,400 

Williams-Transco Storage

   86,100 

NiSource-Columbia Gas Storage

   96,400 

Hardy Storage (through arrangements with Columbia Gas and Transco)

   58,70068,800 

Dominion Storage (through arrangements with Transco)

   13,200 

El Paso-Tennessee Pipeline Storage

   55,900 

Total

   851,800 
Total  

851,700

 

As of October 31, 2008,2011, we own or have under contract 35.336.1 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 from the Gulf Coast production region and is purchased primarily from major and independent producers and marketers. Natural gas demand is continuing to grow in our service area. As part of our long-term plan toarea, particularly from power generation customers. To diversify our reliance away from the Gulf Coast region, we are now receivingreceive firm, long-term market area storage service from Hardy Storage Company, LLC a storage facility(Hardy Storage) located in West Virginia, Columbia Gas Storage located in West Virginia, Ohio and Pennsylvania, and Dominion Storage located in West Virginia, Pennsylvania and New York that may be filled with Appalachian sourced supply. We also have firm, long-term transportation service from Midwestern Gas Transmission Company that provides access to gas supplies from Canadian and Rocky Mountain supply basins via the Chicago hub.

As part of our planhub that can supply city gate demand or be used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.

We completed two pipeline expansion projects in fiscal year 2011 and one in December 2011 to provide safe, reliablelong-term gas distributiontransportation service to power generation customers in our growing customer base and manage our seasonal demand, we intendmarket area. We have two pipeline expansion projects under construction to design, construct, own and operate a LNG peak storage facilityprovide natural gas delivery service to power generation facilities currently under construction in Robeson County, North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the capacity to store approximately 1.25 billion cubic feetenvironmental benefits of replacing a coal-fired power plant with a new natural gas-fired power plant, the construction of the natural gas pipelines for use during times of peak demand. The LNG facilitythese projects will be aalso add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for economic growth and development. See the following discussion of our regulated utility segmentforecasted capital investment related to the construction of the natural gas pipelines and is plannedcompressor stations to beserve these new power generation facilities in service for the2012-2013 winter heating season. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings”“Cash Flows from Investing Activities” in Item 7 of thisForm 10-K in Management’s Discussion and Note 2Analysis of Financial Condition and Results of Operations.

We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes and slower new home construction. However, we took advantage of the consolidated financial statements.

growth opportunities that existed in those markets and continue to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal year 2011, we added 10,522 new customers, including 6,843 residential new home construction customers, 1,406 commercial and industrial customers and 2,273 conversion customers, as well as two new power generation customers mentioned above. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.

During the year ended October 31, 2008,2011, 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, availability and the price of alternate fuels. Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2008,2011, no bypass activity was experienced.occurred. The future level of bypass activity cannot be predicted.


4


As noted above, many of our industrial customers are capable of burning a fuel other than natural gas, with fuel oil being the most prevalent energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

The regulated utility also competes with other energy products, such as electricity and propane, in the residential and small commercial customer markets. The most significant product competition is with electricity 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 is influenced by such factors as price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. 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 in recent years. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. However, theThe direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and lowers the carbon footprint of those premises.
As noted above, many ofpremises in our industrial 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 worldwide supply and demand and the policies of foreign and domestic governments and organizations. Our revenues could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.
area.

During the year ended October 31, 2008,2011, our largest revenue generating customer contributed $104.3$49.5 million, or 5%3%, toof total operating revenues, which resulted in less than 1% torevenues. Our largest margin generating customer contributed $15.6 million, or 3% of total margin.

Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.

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

10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As of October 31, 2008,2011, our fiscal year end, we had 1,8331,782 employees compared with 1,8761,788 as of October 31, 2007.

2010.

Our reports onForm 10-K,Form 10-Q andForm 8-K, and any amendments to these reports, are available at no cost on our website atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.

Commission (SEC).

Item 1A. Risk Factors

Item 1A.

Risk Factors
Further increasesAn overall economic downturn or slow recovery could negatively impact our earnings.

Weakening or slow recovery of economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial assumptions. Inflationary pressure could increase the costs of goods, services and labor, and an increase in interest rates could increase our interest expense and make it more difficult or expensive for us to access the capital markets. Earnings and liquidity would be negatively affected, reducing our ability to grow the business.

Increases in the wholesale price of natural gas could reduce our earnings and working capital.  In recent years,

The supply and demand balance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas, and restrictions or regulations on shale gas production could cause natural gas prices have increased dramatically due to growing demand and limitations on access to domestic gas reserves.increase. The prudently incurred 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 alsoenergy as well as cause new home developers, builders and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, 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,high, our working capital costs could increase due to higher carrying higher costcosts of gas storage inventories, and customers may have trouble paying the resulting higher bills andleading to bad debt expenses, which may increase and reduce our earnings.

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


5


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, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist attacks or other acts of war, could reduce our normal interstate supply of gas which couldand thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.

Our business is subject to competition that could negatively affect our results of operations.

The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.

In residential, commercial and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher gas costs, could cause these customers to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.

Higher gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our earnings.

Our business activities are concentrated in three states.

Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers, and could adversely affect our earnings.

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.

The FERC has regulatory authority over some of our operations, including sales of natural gas in the wholesale market and the purchase and sale of interstate pipeline and storage capacity. Additionally, Congressthe Commodities Futures Trading Commission under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has enacted laws that deregulateregulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of naturalour gas sold at the wellhead.supply. Any Congressionalfederal legislation or agency regulation that would alter these or other similar statutory and regulatory structures in a way tohas the effect of significantly raiseraising costs that could not be recovered in rates from our customers that would reduceor reducing the availability of supply or capacity, the liquidity of the natural gas supply market or that would reduce our competitiveness wouldcould negatively impact our earnings. Furthermore, Congress has for some time been considering various forms

Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.

The federal or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, legislation. Thereincluding greenhouse gas emissions such as carbon dioxide. Such laws or regulations could impose operational requirements, impose additional charges to fund energy efficiency activities, provide a cost advantage to alternative energy sources other than natural gas, impose costs or restrictions on end users of natural gas, or result in other costs or requirements. As a result, there is a possibility that, when and if enacted the final form ofor adopted, such legislation or regulation could impact our costs and put upward pressure on wholesalethe cost of natural gas prices. Higher cost levels couldrelative to other energy sources, increase our costs and impact the competitive position of natural gas and the ability to serve new customers, negatively affectaffecting our growth opportunities, cash flows and 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 normalize our margin for weather during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. We estimate that 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.

GovernmentalRegulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our 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. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. If a state regulatory commission were to prohibit us from setting rates that allow for the timely recoverrecovery of our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers (including margin decoupling and cost of gas) or other tariff provisions, then our earnings could be negatively impacted. In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various appropriate entities. Regulatory authorities also review whether our gas costs are prudent and can adjust the amount of our gas costs that we pass through to our customers. Additionally, theour state regulators 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 results of operations, financial condition and cash flows. Additionally, ourOur debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or 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 normalize our margin for weather during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. Mild winter temperatures can cause a decrease in the amount of gas we sell and deliver in any year and the margin we collect from these customers. If our rates and tariffs were modified to eliminate weather protection, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather, and our earnings could vary as a result.

Our gas supply risk management programs are subject to state regulatory approval or annual review in gas cost proceedings.

We manage our gas supply costs through short-term and long-term procurement and storage contracts. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments of various durations for the forward purchase or sale of our natural gas requirements, subject to regulatory approval or review. As a component of our gas costs, these expenses are subject to regulatory approval, and we may be exposed to additional liability if the anticipated recovery of these costs of gas supply procurement or risk management activities is excluded by our regulators in gas cost flow throughrecovery proceedings.


6


Operational interruptions to our gas distribution and transmission activities caused by accidents, strikes,work stoppage, severe weather conditions, including destructive weather patterns such as a major hurricane,hurricanes, tornadoes and floods, pandemic or acts of terrorism could adversely impact earnings.

Inherent in our gas distribution and transmission activities are a variety of hazards and operational risks, such as third party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. Pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If theythe foregoing events are severe enough or if they lead to operational interruptions, they 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, we have aOur regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would negatively affect our earnings. With part of our workforce that is partially represented by the union that exposes usunions, we are exposed to the risk of a strike.work stoppage. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.

TheWe may not be able to complete necessary or desirable pipeline integrity or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business.

In order to serve new customers or existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to access capital obtain required approval from local, state and/or significant increasesfederal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, which would negatively impact our earnings. In addition, the counterparties to our power generation construction and service agreements may elect to terminate the agreements, which would negatively affect future earnings and cash flow.

A downgrade in theour credit ratings could negatively affect our cost of capital could adversely affect our business.and ability to access capital.

Our ability to obtain adequate and cost effective financing depends on our credit ratings as well as the liquidity of financial markets.ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our cost of borrowing and/or access to sources of liquidity and capital. Additionally, suchSuch a downgrade could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement would increase. An increase in borrowing costs without the recognition ofability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.

The inability to access capital or significant increases in the cost of capital could adversely affect our business.

Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets could adversely affect our ability to access short-term and long-term capital. Our access to funds under short-term credit facilities is dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the European credit market could cause the interest rate we pay on our short-term credit facility, which is based on the London Interbank Offered Rate, to increase, could result in higher interest rates on future financings, and could impact the liquidity of the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. Longer disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to capital needed for our business.

The inability to access adequate capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our cost of borrowing.

Changes in federal and state fiscal and monetary policy could significantly increase our costs or decrease our cash flows.

Changes in federal and state fiscal and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers. This series of events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flow. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.

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 transmission and distribution system.systems. We have also purchased and will continue to purchase natural gas for storage. Moreover, weWe have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We have fundedfund 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 in the market.debt and equity securities. Our dependency on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing 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. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could include deferringcause deferral of major capital expenditures, changingchanges in our gas supply procurement and risk management programsprogram, the reduction or reducing or eliminatingelimination of the dividend payment or other discretionary uses of cash.

cash, and could negatively affect our future growth and earnings.

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 revolving credit facilities,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.

us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.

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


7


counterparties to remit payments orto fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.

Poor investment performanceThe cost of providing pension plan holdingsbenefits is subject to changes in pension fund values and other factors impacting pension plan costsand could unfavorably impact our liquidity and results of operations.

Our costs of providing for thea non-contributory defined benefit pension plan 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 plan, changes in these actuarial assumptions, future government regulation and our required or voluntary contributions made to the plan. AChanges in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, may significantly differ from or alter the values and actuarial assumptions used to calculate our future pension expense. A decline in the value of these investments could increase the expense of our pension plan, and we could be required to fund our plan 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 Additionally, the discovery of presently unknown environmental conditions could negatively impactgive rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our earnings.  The weakeningbusiness, results of economic activityoperations or financial condition.

We are subject to new and existing pipeline safety and system integrity laws and regulations that may require significant expenditures or significantly increase operating costs.

We are subject to existing and may be subject to new pipeline safety and system integrity laws and regulations affecting various aspects of our present and future operations. These laws and regulations generally require us to enhance pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our marketscustomers. Furthermore, because the language in some of these laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures. All of the above could result in a declinematerial adverse effect on our business, results of operations or financial condition.

We may invest in customer additionscompanies that have risks that are inherent in their businesses, and energy consumptionthese risks may negatively affect our earnings from those companies.

We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by the regulated utility segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance. All the foregoing could adversely affect our revenuesearnings from or restrictreturn of our investment in these businesses. We could make future growth. It may become more difficult for customersinvestments in similarly unregulated businesses that have the similar potential to pay their gas bills, leading to slow collections and higher-than-normal levelsadversely affect our earnings from or return of accounts receivable. Thisour investment in those businesses. All these adverse impacts could increasenegatively affect our financing requirements and non-gas cost bad debt expense. Earnings would be affected by these higher costs.

results of operations or financial condition.

Our inability to attract and retain professional and technical employees could adversely impact our earningsearnings..  

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. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. 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

Changes in accounting standards may adversely impact our financial condition and results of operations.

The SEC is considering whether issuers in the United States should be required to prepare financial statements in accordance with International Financial Reporting Standards (IFRS) instead of the current generally accepted accounting principles (GAAP) in the United States. IFRS is a comprehensive set of accounting standards promulgated by the International Accounting Standards Board (IASB), which are currently in effect for most other countries in the world. Unlike U.S. GAAP, IFRS does not currently provide an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may adversely impact our reported financial condition and results of operations should adoption of IFRS be required. Also, the U.S. Financial Accounting Standards Board is considering various changes to U.S. GAAP, some of which may be significant, as part of a joint effort with the IASB to converge accounting standards over the next several years. If approved, adoption of these changes may adversely impact our reported financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2.Properties

Item 2. Properties

All property included 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 94% of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,6002,700 linear miles of transmission 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 27,90022,000 linear miles (three-inch equivalent) of distribution mains.mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located on or undernear public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on privatesuch property. All of these properties are located 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.


8

use except for “Plant held for future use” as classified in our consolidated balance sheets. The amount classified as plant held for future use relates to expenditures associated with a potential LNG peak storage facility in the eastern part of North Carolina that has been delayed given the slowing of our growth due to current economic conditions. Another project under construction will help serve the near term system pressure requirements in a cost effective manner in that part of North Carolina. The timing and design scope of the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.


We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and district and regional officesour resource centers in the locations shown below. Lease payments for these various offices totaled $4.2$4 million for the year ended October 31, 2008.
2011.

North Carolina

  South Carolina  Tennessee
North Carolina
South Carolina
Tennessee

Burlington
Cary
Charlotte
Elizabeth City
Fayetteville
Goldsboro
Greensboro
Hickory
High Point
Indian Trail
New Bern
Reidsville
Rockingham
Salisbury
Spruce Pine
Tarboro
Wilmington
Winston-Salem

  Anderson
Gaffney
Greenville
Spartanburg
  Nashville

Cary

Gaffney

Charlotte

Greenville

Elizabeth City

Spartanburg

Fayetteville

Goldsboro

Greensboro

Hickory

High Point

Indian Trail

New Bern

Reidsville

Rockingham

Salisbury

Spruce Pine

Tarboro

Wilmington

Winston-Salem

Property included 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 residential and commercialnatural gas water heaters leased to natural gascommercial 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

Item 3. Legal Proceedings

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

Item 4.Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote

Item 4. (Removed and Reserved)

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of security holders during our fourth quarter ended October 31, 2008.

PART IIEquity Securities
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
(a) 

Market Information

Our common 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, 20082011 and 2007.

         
2008
 High  Low 
 
Quarter ended:        
January 31 $27.98  $24.01 
April 30  27.68   24.05 
July 31  27.95   25.00 
October 31  35.29   20.52 
         
2007
 High  Low 
 
Quarter ended:        
January 31 $28.44  $25.78 
April 30  27.50   24.33 
July 31  27.50   22.00 
October 31  27.50   23.09 


9

2010.


2011

  High   Low   

2010

  High   Low 

Quarter ended:

      

Quarter ended:

    

January 31

  $30.10   $27.57   

January 31

  $27.84   $22.51 

April 30

   32.00    27.88   

April 30

   28.52    23.87 

July 31

   31.98    28.80   

July 31

   27.97    24.50 

October 31

   33.60    25.86   

October 31

   29.85    26.15 

Holders

(b) As of December 16, 2008,2011, our common stock was owned by 14,99313,916 shareholders of record.
(c)  Holders of record exclude the individual and institutional security owners whose shares are held in the street name or in the name of an investment company.

Dividends

The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 20082011 and 2007.2010. We expect that comparable cash dividends will continue to be paid in the future.

Dividends Paid
2008
Per Share
Quarter ended:
January 3125¢
April 3026¢
July 3126¢
October 3126¢
Dividends Paid
2007
Per Share
Quarter ended:
January 3124¢
April 3025¢
July 3125¢
October 3125¢

2011

  Dividends Paid
Per Share
  

2010

  Dividends Paid
Per Share
 

Quarter ended:

   

Quarter ended:

  

January 31

   28¢  

January 31

   27¢ 

April 30

   29¢  

April 30

   28¢ 

July 31

   29¢  

July 31

   28¢ 

October 31

   29¢  

October 31

   28¢ 

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2008,2011, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Share Repurchases

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the fourth quarterthree months ended October 31, 2008.

                 
        Total Number of
  Maximum Number
 
  Total Number
     Shares Purchased
  of Shares that May
 
  of Shares
  Average Price
  as Part of Publicly
  Yet be Purchased
 
Period
 Purchased  Paid per Share  Announced Program  Under the Program * 
 
Beginning of the period              3,230,074 
 8/1/08 —  8/31/08  66,000  $28.05   66,000   3,164,074 
 9/1/08 —  9/30/08  64,000  $29.33   64,000   3,100,074 
10/1/08 —  10/31/08  90,000  $30.23   90,000   3,010,074 
Total  220,000  $29.32   220,000     
2011.

Period

  Total Number
of Shares
Purchased
  Average Price
Paid Per Share
   Total Number of
Shares Purchased
as Part of Publicly
Announced  Program
   Maximum Number
of Shares that May
Yet be Purchased
Under the Program (1)
 

Beginning of the period

        3,710,074 

8/1/11 - 8/31/11

   —    $—      —      3,710,074 

9/1/11 - 9/30/11

   19,345(2)  $31.28    —      3,710,074 

10/1/11 - 10/31/11

   1,753(2)  $33.29    —      3,710,074 

Total

   21,098  $31.45    —     

*(1)The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares arewere referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.
(2)The total number of shares purchased is shares withheld by us to satisfy tax withholding obligations related to the vesting of shares of restricted stock and have an expiration dateshares awarded under a retention award under incentive compensation plans, which are outside of December 31, 2010.the Common Stock Open Market Purchase Program.


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Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares our cumulative total shareholder return from October 31, 20032006 through October 31, 20082011 (a five-year period), with our utility peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500), and with our utility peer group.. Large natural gas distribution companies that are representative of our peers in the natural gas distribution industry are included in our LDC Peer Group index.

The Laclede Group, Inc. and South Jersey Industries, Inc. were added to our peer group because they are publicly traded companies with a focus on natural gas distribution in multi-state territories and have similar annual revenues and market capitalization as compared with us. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our cumulative shareholder return as we use for market benchmarking for our executive compensation plans. It was recommended by a benefits consultant that we expand our peer group.

Our total return of $100 invested as of October 31, 2011 was $147. With the addition of The Laclede Group, Inc. and South Jersey Industries, Inc., our peer group return was $148. Without them, the peer group return would have been $142.

The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2003,2006 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

Comparisons of Five-Year Cumulative Total Returns
Value of $100 Invested as of October 31, 2003

Comparisons of Five-Year Cumulative Total Returns

Value of $100 Invested as of October 31, 2006

LDC Peer Group — Group—The following companies are included: AGL Resources Inc., Atmos Energy Corporation, New Jersey Resources Corporation, NICOR Inc., NiSource Inc., Northwest Natural Gas Company, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc.


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Item 6. Selected Financial Data

Item 6.Selected Financial Data
The following table provides selected financial data for the years ended October 31, 20042007 through 2008. The information presented for net income2011.

In thousands except per share amounts

  2011   2010   2009   2008   2007 

Operating Revenues

  $1,433,905   $1,552,295   $1,638,116   $2,089,108   $1,711,292 

Margin (operating revenues less cost of gas)

  $573,639   $552,592   $561,574   $552,973   $524,165 

Net Income

  $113,568   $141,954   $122,824   $110,007   $104,387 

Earnings per Share of Common Stock:

          

Basic

  $1.58   $1.96   $1.68   $1.50   $1.41 

Diluted

  $1.57   $1.96   $1.67   $1.49   $1.40 

Cash Dividends per Share of Common Stock

  $1.15   $1.11   $1.07   $1.03   $0.99 

Total Assets *

  $3,242,541   $3,053,275   $3,118,819   $3,138,401   $2,823,106 

Long-Term Debt (less current maturities)

  $675,000   $671,922   $732,512   $794,261   $824,887 

*Total assets for the years 2007 and 2008 have been adjusted to reflect the gross presentation rather than a net presentation in accordance with the adoption of new accounting guidance related to offsetting of amounts related to certain contracts with the same counterparty.

Item 7. Management’s Discussion and earnings per share for 2004 is not comparable due to the acquisitionAnalysis of the remaining 50% equity interest in Eastern North Carolina Natural Gas Company (EasternNC) effective October 25, 2005. The initial acquisitionFinancial Condition and Results of 50% of EasternNC was effective September 30, 2003 with the acquisition of North Carolina Natural Gas Corporation.

                     
  2008  2007  2006  2005  2004 
  In thousands except per share amounts 
 
Operating Revenues $2,089,108  $1,711,292  $1,924,628  $1,761,091  $1,529,739 
Margin (operating revenues less cost of gas) $552,973  $524,165  $523,479  $499,139  $488,369 
Net Income $110,007  $104,387  $97,189  $101,270  $95,188 
Earnings per Share of Common Stock:                    
Basic $1.50  $1.41  $1.28  $1.32  $1.28 
Diluted $1.49  $1.40  $1.28  $1.32  $1.27 
Cash Dividends per Share of Common Stock $1.030  $0.990  $0.950  $0.905  $0.8525 
Total Assets $3,093,580  $2,820,318  $2,733,939  $2,602,490  $2,392,164 
Long-Term Debt (less current maturities) $794,261  $824,887  $825,000  $625,000  $660,000 
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 andfrom 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:

to the following, as well as those discussed in Item 1A. Risk Factors:

 

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

 

Customer growth and consumption.Residential, commercial, industrial and industrialpower generation growth and energy consumption in our service areas.areas may change. The ability to retain and grow our customer base, and the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and by 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 changing environments and the competition.
• The potential loss of large-volume Large-volume industrial customers may switch to alternate fuels or to bypass our system or the shift by such customers to special competitive contracts or to tariff rates that are at lowerper-unit margins than that customer’s existing rate.


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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.
 

Competition in the energy industry. We face competition in the energy industry, such as from electric companies, energy marketing and trading companies, fuel oil and propane dealers, renewable energy companies and coal companies, and we expect this competitive environment to continue.

 

The capital-intensive nature of our business. In order to maintain growth, we must add toinvest in our natural gas transmission and distribution system each year. The cost of this constructionand the ability to complete these capital projects may be affected by the ability to obtain and the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, cost and timing of project development-related contracts and approvals, project development project delays, federal and changes in project costs.state tax policies, and the cost and availability of labor and materials. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.

 

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

 

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

 

Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, tornadoes and floods, can impact our customers, our suppliers and the pipelines that deliver gas to our distribution system.system and our distribution and transmission assets. Weather conditions directly influence the supply, of, demand, fordistribution and the cost of natural gas.

 

Changes in environmental, safety and system integrity regulationscosts of compliance with laws and the cost of compliance.regulations. We are subject to extensive federal, state and local laws and regulations. Environmental, safety, system integrity, tax and other laws and regulations, including those related to carbon regulation, may change. Compliance with such laws and regulations may result in increasedcould increase capital or operating costs.costs, affect our reported earnings or cash flows, increase our liabilities or change the way our business is conducted.

 

Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

 

Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities, and could affect our reported earnings or increase our liabilities.

 

Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and thosethese risks may negatively affect our earnings from those companies.

Changes in outstanding shares. The number of outstanding shares may fluctuate due to new issuances or repurchases under our Common Stock Open Market Purchase Program.

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

Forward-looking statements are onlybased on information available to us 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 atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.


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Executive Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 62,00051,800 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.

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

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

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated utility include operating 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 monthsyear ended October 31, 2008, 85%2011, 87% 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, and regulated interstate natural gas storage and intrastate natural gas transportation. For the year ended October 31, 2011, 13% of our earnings before taxes came from our non-utility segment, which consisted of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. For further information on equity method investments and business segments, see Note 1112 and Note 14, respectively, to the consolidated financial statements. For information about our equity method investments, see Note 10 to the consolidated financial statements.

Our utility operations are regulated 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 areThe NCUC also regulated by the NCUCregulates us as to the issuance of long-term debt and equity 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 purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security 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.environment. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation.

In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on a year around basis independent of consumption patterns. The margin decoupling mechanism will resultresults in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase inincreases revenues when weather is warmer than normal and a decrease indecreases revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is


14


not affected by the margin decoupling mechanism or the WNA. For further information, see Note 2 to the consolidated financial statements.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the naturechanging energy economy. We have been pursuing alternatives to the traditional utility rate design that provide for the collection of margin revenue based on volumetric throughput with new rate designs and incentives that allow utilities to encourage energy efficiency and conservation. By decoupling the link between energy consumption and margin revenues, our interests are aligned with our customers’ interests on conservation and energy efficiency. In North Carolina, we have decoupled residential and commercial rates. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. For the twelve months ended October 31, 2011, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 70% of our businessutility margins, including margin decoupling in North Carolina, facilities charges to our customers and explore alternativesfixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and

Tennessee; and volumetric or periodic renegotiation of 12% of our core business of traditional regulated utility service. Non-traditional ratemaking initiativesmargins. For the twelve months ended October 31, 2011, the margin decoupling mechanism in North Carolina reduced margin by $7 million, and market-based pricing of productsthe WNA in South Carolina and services provide additional opportunitiesTennessee reduced margin by $4.9 million.

On September 2, 2011, we filed a general rate application with the TRA for an increase in rates and challenges for us.

charges to all customers that would be effective March 1, 2012. We also regularly evaluate opportunitiesrequested a modification of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for obtaining natural gas from different supply regionsplant and changes to diversify our natural gas portfolio. In January 2008, we began receiving 120,000 dekatherms per day of firm, long-term transportationthe existing service from Midwestern Gas Transmission Company (Midwestern) that provides access to Canadianregulations and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. In April 2007, we began receiving firm, long-term market-area storage service from Hardy Storage Company (Hardy Storage) in West Virginia that will provide 58,700 dekatherms per day of withdrawal service for the winter of2008-2009. We have a 50% equity interest in this project.tariffs. For further information, see “Gas Supply and Regulatory Proceedings” below and Note 2 Note 5 and Note 10 to the consolidated financial statements.
As part of

We have refined our planstrategic objectives to provide safe, reliable gas distribution service to our growing customer basea customer-centered approach and manage our seasonal demand,what we intend to design, construct, own and operate a liquefied natural gas (LNG) peak storage facility in Robeson County, North Carolina withbelieve is the capacity to store approximately 1.25 billion cubic feetinherent benefit of natural gas forcompared to other types of energy. Our overall corporate focus is to expand our core natural gas and complementary energy-related businesses to enhance shareholder value. This focus includes traditional growth in the core residential, commercial and industrial markets, growth in the power generation market, supply diversity and complementary energy-related investments and natural gas end use during timestechnology. We want our customers to choose us because of peak demand. The LNG facility will be a partthe value of natural gas and the quality of our regulated utility segment and is plannedservice to bethem. We strive to achieve excellence in service for the2012-2013 winter heating season.

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers and in our business operations with every customer contact we make. We pursue business practices to promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and fostering increased awareness and use of natural gas. We support our employees with improved processes and technology to better serve our customers and to add value for our shareholders while continuing to build on our healthy, high performance culture in order to recruit, retain and motivate our workforce.

To support these objectives, we are reorganizing our field customer services, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service and increase customer loyalty and satisfaction while improving operational efficiencies. We have also implemented new centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

The safety of our system, the public and our employees is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing programs to inspect our system for corrosion and leaks. Given an increased interest in pipeline safety and integrity in the growing Southeastwake of several serious pipeline incidents in the United States, we anticipate federal legislative and regulatory enactments that will add further requirements to our pipeline safety and integrity programs. We met an August 2011 deadline to evaluate any risks to our distribution pipeline system (such as corrosion and leak detection) and created an action plan to address those risks. We have transmission pipeline integrity programs where we execute standard procedures and programs for pipeline safety that include leak detection surveys, periodic valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection, in-line inspection devices, hydrostatic and compressed air pressure testings of new facilities and other evaluation methods. It is likely that these programs will increase in scope as a result of anticipated legislation and regulation. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

The safeguarding of our information technology infrastructure is important to our business. There is risk associated with the unauthorized access of digital data with the intent to misappropriate information, corrupt data or cause operational disruptions. To protect confidential customer, vendor, financial and employee information, we believe we have appropriate levels of security measures in place to secure our information systems from cybersecurity attacks or breaches. We also have a comprehensive identity theft protection program to protect customer information, as well as a cybersecurity insurance policy.

We continue our efforts to promote the benefits of natural gas. Promotion efforts are led by educating consumers on the benefits of natural gas compared to other energy sources as well as advocating the benefits of natural gas to prospective customers in our communities. We continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security. We also promote and market the cost and environmental benefits of natural gas to power generation customers in our market area. PartPrice moderation and stability of natural gas continues, which has made natural gas more economical than many other fuels.

We completed two pipeline expansion projects in fiscal year 2011 and one in December 2011 to provide long-term gas transportation service to power generation customers in our market area. We have two pipeline expansion projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the environmental benefits of replacing a coal-fired power plant with a new natural gas-fired power plant, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for economic growth and development. See the following discussion of our forecasted capital investment related to the construction of the natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes, and slower new home construction. We took advantage of the growth opportunities that existed in those markets and continue to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal 2011, our gross customers additions were 4% lower than 2010; however, our month-end customers billed as well as the twelve-month average customers billed during fiscal year 2011 increased 1% over the respective prior year. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations in use, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.

Our financial strength and flexibility is critical to manage our gas distribution business throughsuccess as a company. We will continue our stewardship to maintain our financial strength, which translates to continued access to capital markets. We continue to evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. In June 2011, we replaced $196.8 million of notes with a 6.25% stated interest rate with $200 million of notes with a weighted interest rate of 4%. In July 2011, we filed a shelf registration statement that will allow for future issuances of debt or equity. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue to control of our operating costs, implementation ofimplement new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers and the pursuit of profitable customer growth opportunities in our service areas. We strive for quality customer service by investing in technology, processes and people. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

We seek to maintain a long-term debt-to-capitalization ratio within a range of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.
While we have seen the impact of the economic recession of 2008 in our market area, we remain one of the fastest growing natural gas utilities in the nation for new customer additions. We added 20,506 new customers to our distribution system in 2008, a gross new customer addition growth rate of 2%. Although we saw a decline in customer growth in our new construction residential market during 2008, we experienced a slight increase in residential customer conversions over 2007. The decline in our customer growth rate did not have a significant effect on our financial results for 2008. As one of the initial investors in the Council for Responsible Energy, we are leading the effort to promote natural gas and inform consumers about the environmental benefits of using natural gas directly in their homes and businesses for the most efficient use of natural gas. In advance of the winter heating season, we work to educate consumers of assistance that is available to those who qualify for the national Low Income Home Energy Assistance Program funds and other similar local programs.
With the recent slowdown in the national economy, including tighter credit markets, increased unemployment and mortgage defaults and significant decreases in investment assets, the financial resources of many domestic households have been adversely affected. A further weakening of the economy in our service areas could result in a greater decline in customer additions and energy consumption which could adversely affect our revenues or restrict our future growth.
Under current economic conditions, it may become more difficult for customers to pay their gas bills, leading to slower collections and higher-than-normal levels of accounts receivable and ultimately increasing the non-gas bad debt expense. With a slower turnover of accounts receivable, our level of borrowings could increase in order to meet our working capital needs.


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We remain focused on implementing and improving our underlying business processes while at the same time monitoring economic and other ongoing developments in order to ensure that our operations and business plan stay in step with these developments.
We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects with a major factor being a projected raterates of return greater thancommensurate with the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.
During 2008, margin increased $28.8 million from residentialstrategies

Several new laws were enacted in 2010 for health care reform and commercial customer growth as well as periodthe regulation of U.S. financial markets. We continue to period net adjustments related tofollow the progress of new regulations that are being issued and will be issued by various regulatory and gas cost accounting reviews. We wereagencies. While we are not able to realizeassess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material impact on our financial position, results of operations or cash flows.

Also, the Tax Relief, Unemployment Insurance Reauthorization and maintenance expense decreasesJob Creation Act of $3.7 million primarily due2010, enacted in December 2010, extended the 50% “bonus depreciation” that expired December 31, 2009 and temporarily increased “bonus depreciation” for federal income tax purposes to lower pension expense accruals due100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. The Internal Revenue Service has issued regulations that are intended to provide guidance in interpreting the restructuringlaw. Based on current capital projections and timelines, we are anticipating a benefit through 2014 of $130 - 170 million. We anticipate that the bonus depreciation allowance will have a material favorable impact on our defined benefit pension program.

cash flows in the near term by reducing cash needed to pay federal income taxes.

Results of Operations

The following tables present our financial highlights for the years ended October 31, 2008, 20072011, 2010 and 2006.

2009.

Income Statement Components

                     
           Percent Change 
           2008 vs.
  2007 vs.
 
  2008  2007  2006  2007  2006 
  (In thousands, except per share amounts) 
 
Operating Revenues $2,089,108  $1,711,292  $1,924,628   22.1%  (11.1)%
Cost of Gas  1,536,135   1,187,127   1,401,149   29.4%  (15.3)%
                     
Margin  552,973   524,165   523,479   5.5%  0.1%
                     
Operations and Maintenance  210,757   214,442   219,353   (1.7)%  (2.2)%
Depreciation  93,121   88,654   89,696   5.0%  (1.2)%
General Taxes  33,170   32,407   33,138   2.4%  (2.2)%
Income Taxes  62,814   51,315   50,543   22.4%  1.5%
                     
Total Operating Expenses  399,862   386,818   392,730   3.4%  (1.5)%
                     
Operating Income  153,111   137,347   130,749   11.5%  5.0%
Other Income (Expense), net of tax  16,169   24,312   18,750   (33.5)%  29.7%
Utility Interest Charges  59,273   57,272   52,310   3.5%  9.5%
                     
Net Income $110,007  $104,387  $97,189   5.4%  7.4%
                     
Average Shares of Common Stock:                    
Basic  73,334   74,250   75,863   (1.2)%  (2.1)%
Diluted  73,612   74,472   76,156   (1.2)%  (2.2)%
Earnings per Share of Common Stock:                    
Basic $1.50  $1.41  $1.28   6.4%  10.2%
Diluted $1.49  $1.40  $1.28   6.4%  9.4%


16


               Percent Change 

In thousands except per share amounts

  2011   2010   2009   2011 vs.
2010
  2010 vs.
2009
 

Operating Revenues

  $1,433,905   $1,552,295   $1,638,116    (7.6)%   (5.2)% 

Cost of Gas

   860,266    999,703    1,076,542    (13.9)%   (7.1)% 
  

 

 

   

 

 

   

 

 

    

Margin

   573,639    552,592    561,574    3.8  (1.6)% 
  

 

 

   

 

 

   

 

 

    

Operations and Maintenance

   225,351    219,829    208,105    2.5  5.6

Depreciation

   102,829    98,494    97,425    4.4  1.1

General Taxes

   38,380    33,909    34,590    13.2  (2.0)% 

Utility Income Taxes

   64,068    62,082    70,079    3.2  (11.4)% 
  

 

 

   

 

 

   

 

 

    

Total Operating Expenses

   430,628    414,314    410,199    3.9  1.0
  

 

 

   

 

 

   

 

 

    

Operating Income

   143,011    138,278    151,375    3.4  (8.7)% 

Other Income (Expense), net of tax

   14,549    47,387    18,124    (69.3)%   161.5

Utility Interest Charges

   43,992    43,711    46,675    0.6  (6.4)% 
  

 

 

   

 

 

   

 

 

    

Net Income

  $113,568   $141,954   $122,824    (20.0)%   15.6
  

 

 

   

 

 

   

 

 

    

Average Shares of Common Stock:

         

Basic

   72,056    72,275    73,171    (0.3)%   (1.2)% 

Diluted

   72,266    72,525    73,461    (0.4)%   (1.3)% 

Earnings per Share of Common Stock:

         

Basic

  $1.58   $1.96   $1.68    (19.4)%   16.7

Diluted

  $1.57   $1.96   $1.67    (19.9)%   17.4

Gas Deliveries, Customers, Weather Statistics and Number of Employees
                     
           Percent Change 
           2008 vs.
  2007 vs.
 
Deliveries in Dekatherms (in thousands)
 2008  2007  2006  2007  2006 
 
Sales Volumes  110,801   105,606   105,728   4.9%  (0.1)%
Transportation Volumes  99,450   100,398   92,928   (0.9)%  8.0%
                     
Throughput  210,251   206,004   198,656   2.1%  3.7%
                     
Secondary Market Volumes  53,442   42,049   40,994   27.1%  2.6%
Customers Billed (at period end)  935,724   922,961   903,368   1.4%  2.2%
Gross Customer Additions  20,506   30,437   34,445   (32.6)%  (11.6)%
Degree Days                    
Actual  3,195   2,977   3,192   7.3%  (6.7)%
Normal  3,358   3,388   3,386   (0.9)%  0.1%
Percent warmer than normal  (4.9)%  (12.1)%  (5.7)%  n/a   n/a 
Number of Employees (at period end)  1,833   1,876   2,051   (2.3)%  (8.5)%

            Percent Change 
    2011  2010  2009  2011 vs.
2010
  2010 vs.
2009
 

Deliveries in Dekatherms (in thousands):

      

Sales Volumes

   104,740   105,583   110,379   (0.8)%   (4.3)% 

Transportation Volumes

   175,021   147,032   106,495   19.0  38.1
  

 

 

  

 

 

  

 

 

   

Throughput

   279,761   252,615   216,874   10.8  16.5
  

 

 

  

 

 

  

 

 

   

Secondary Market Volumes

   48,835   46,823   46,057   4.3  1.7

Customers Billed (at period end)

   958,307   946,785   937,962   1.2  0.9

Gross Customer Additions

   10,522   10,975   12,608   (4.1)%   (13.0)% 

Degree Days

      

Actual

   3,662   3,535   3,413   3.6  3.6

Normal

   3,318   3,321   3,324   (0.1)%   (0.1)% 

Percent colder than normal

   10.4  6.4  2.7  n/a    n/a  

Number of Employees (at period end)

   1,782   1,788   1,821   (0.3)%   (1.8)% 

Net Income

Net income decreased $28.4 million in 2011 compared with 2010 primarily due to the following changes which decreased net income:

$49.7 million decrease due to gain on sale of interest in equity method investment in the prior year.

$5.5 million increase in operations and maintenance expenses.

$4.8 million decrease in income from equity method investments.

$4.5 million increase in general taxes.

$4.3 million increase in depreciation.

$.6 million increase in non-operating expense.

$.5 million increase in charitable contributions.

These changes were partially offset by the following changes, which increased net income:

$21 million increase in margin (operating revenues less cost of gas).

$19.6 million decrease in income taxes.

$1.1 million increase in non-operating income.

Net income increased $5.6$19.1 million in 20082010 compared with 20072009 primarily due to the following changes which increased net income:

$49.7 million gain on sale of interest in equity method investment.

$3 million decrease in utility interest charges.

• $28.8 million increase in margin (operating revenues less cost of gas).
• $3.7 million decrease in operations and maintenance expenses, primarily due to lower pension expense accruals due to the restructuring of our defined benefit pension program.

$.9 million decrease in non-operating expense.

$.7 million decrease in general taxes.

$.6 million decrease in charitable contributions.

$.6 million increase in non-operating income.

These changes were partially offset by the following changes, which decreased net income:

$11.7 million increase in operations and maintenance expenses.

• $9.4 million decrease in earnings from equity method investments.
• $7.9

$10 million increase in income taxes.

• $4.5 million increase in depreciation.
• $2.3 million decrease in net other income (expense) items.
• $2 million increase in utility interest charges.
• $.8 million increase in general taxes.
Net income increased $7.2taxes.

$9 million decrease in 2007margin.

$4.6 million decrease in income from equity method investments.

$1.1 million increase in depreciation.

Operating Revenues

Operating revenues in 2011 decreased $118.4 million compared with 20062010 primarily due to the following changes which increased net income:

decreases:

• $7.2 million increase in earnings from equity method investments.
• $1.1 million increase in non-operating income.
• $.7 million increase in margin.
• $4.9 million decrease in operations and maintenance expenses, primarily due to organizational restructuring and process improvement initiatives.
• $1 million decrease in depreciation.
• $.7 million decrease in general taxes.
These changes were partially offset by the following changes which decreased net income:
• $5 million increase in utility interest charges.
• $3.2 million increase in income taxes.


17$150.8 million of lower gas costs passed through to sales customers.


Operating Revenues
Operating revenues in 2008 increased $377.8$1.1 million compared with 2007 primarily due to the following increases:
• $207.1 million from revenues in secondary market transactions due to increased activity and higher gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.
• $143.7 million primarily from increased commodity and demand costs passed through to sales customers.
• $29.3 million of commodity gas costs from higher volume deliveries to sales customers.
These increases were partially offset by a $7.3 million decrease from decreased revenues under the margin decoupling mechanism. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism, previously defined as the Customer Utilization Tracker (CUT) mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to conservation and weather.

Operating revenues in 2007 decreased $213.3 million compared with 2006 primarily due to the following decreases:
• $212.9 million from lower commodity gas costs passed through to customers.
• $28.4 million lower revenues from secondary market transactions.

These decreases were partially offset by the following increases:

• $26.4 million related to non-commodity components in rates.
• $5.2 million from increased volumes delivered to transportation customers.
• $2.3 million from revenues under the WNA in South Carolina and Tennessee.
• $2.3 million from revenues under the CUT in North Carolina.
Cost

$19.8 million from higher revenues in secondary market transactions due to increased activity and gas costs. Secondary market transactions consist of Gas

Costoff-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

$5.8 million from an increase in 2008volumes delivered to transportation customers.

$3.9 million from increased $349revenues under the WNA in South Carolina and Tennessee.

Operating revenues in 2010 decreased $85.8 million compared with 20072009 primarily due to the following increases:

decreases:

• $207.7

$65.4 million from commodity gas costs in secondary market transactions due to increased activity and higher gas costs.

• $111.9 million from increased commodity and demand costs passed through to sales customers.
• $29.3 million of commodity gas costs from higher volume deliveries to sales customers.
Cost of gas in 2007 decreased $214 million compared with 2006costs primarily due to decreases of $212.9 million from lower commoditytotal gas costs passed through to sales customers.

$11.9 million from decreased revenues under the margin decoupling mechanism.

Under PGA procedures

$7.6 million from decreased revenues under the WNA in South Carolina and Tennessee.

These decreases were partially offset by the following increases:

$3.7 million from revenues in secondary market transactions due to increased activity.

$1.2 million increase from volumes delivered to transportation customers.

Cost of Gas

Cost of gas in 2011 decreased $139.4 million compared with 2010 primarily due to the following decreases:

$83.2 million of decreased costs due to approved gas cost mechanisms, primarily commodity gas cost true ups.

$80.5 million of decreased commodity gas costs primarily due to lower gas costs passed through to sales customers.

These decreases were partially offset by the following increases:

$16.5 million of increased commodity gas costs in secondary marketing transactions due to increased activity and higher average gas costs.

$9 million of increased demand charges primarily due to timing of asset manager agreement terms.

Cost of gas in 2010 decreased $76.8 million compared with 2009 primarily due to $131.1 million from lower priced gas costs passed through to sales customers, partially offset by the following increases:

$31.7 million of commodity gas costs from increased volume deliveries to sales customers.

$4.8 million from commodity gas costs in secondary market transactions due to increased activity.

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

Margin

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impactpassthrough of volatilechanges in wholesale commodity prices,gas costs, which accountsaccounted for 66%47% of


18


revenues for the twelve months ended October 31, 2008,2011, and transportation and storage costs, which accountaccounted for 6%9%.

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

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include the WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the Tennessee Incentive Plan (TIP) in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the collectionrecovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Margin increased $28.8$21 million in 20082011 compared with 20072010 primarily due to the following increases:

• $12.8

$7.8 million from period to period net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews.

• $11.3 million from growth in our residential and commercial customer base.
• $5.4 million from the regulatory ruling that discontinued the capitalizing and amortizing of storage demand charges effective November 1, 2007.
These increases were partially offset by a $.9 million decrease from lower salesin volumes in ourand services to industrial and power generation market.customers.

$5.1 million from residential and commercial customers primarily due to growth in those markets.

Margin increased $.7

$4.8 million in 2007net gas cost adjustments.

$3.3 million from increased secondary market activity and margins.

Margin decreased $9 million in 2010 compared with 20062009 primarily due to the following increases:decreases:

$6.6 million from net adjustments to gas costs, accounts payable and lost and unaccounted for gas.

$1.1 million from decreased volatility in secondary market transactions.

• $3.9 million from a new power generation customer.
• $4 million net increase, which includes a net increase of 20,800 residential and commercial customers billed (twelve-month average) and an increase of $5.6 million in base rates in South Carolina, partially offset by a decrease in consumption related to warmer-than-normal weather and conservation.

These increases were

$1 million from our residential and commercial markets primarily due to a $3 million negative impact of warmer weather in the non-weather normalized months of April and October, partially offset by the following decreases:customer growth.

• $4.6 million, which includes $5.4 million from the regulatory ruling that discontinued the capitalizing and amortizing of storage demand charges, partially offset by $.8 million from 2006 activity.
• $1.9 million from adjustments related to compensating meter indices.
• $1.2 million from adjustments related to the North Carolina 2006 gas cost accounting review.

Operations and Maintenance Expenses

Operations and maintenance expenses decreased $3.7increased $5.5 million in 20082011 compared with 20072010 primarily due to the following decreases:

increases:

• $9.1 million in employee benefits expense due to reductions in pension expense resulting from changes in plan design and lower group insurance expense from claims experience, and fewer employees.
• $1 million in office supplies due to customer billing outsourcing which resulted in reduced postage and billing supply

$2.5 million in vehicle and transportation expenses.

• $.6 million in transportation costs primarily due to fewer vehicles being used as a result of our automated meter reading initiative and other fleet management efforts.


19


These decreases were partially offset by$2.3 million in other miscellaneous expenses primarily due to a recovery disallowance of some prior years’ franchise fees in one of our jurisdictions and higher bank fees from increased activity and unused amounts of the following increases:revolving syndicated credit facility.

$1.5 million in materials.

• $3.6 million in payroll expense primarily due to an increase in long-term incentive plan accruals in 2008 because of a higher share price and performance levels, partially offset by the impact of fewer employees.
• $2.3 million in contract labor primarily due to contract billing services, telecom and financial, gas accounting and compliance systems.
• $.5 million in utilities primarily due to increased charges for measurement systems.
• $.5 million in advertising.

Operations and maintenance expenses decreased $4.9increased $11.7 million in 20072010 compared with 20062009 primarily due to the following decreases:increases:

$4.2 million in payroll expense primarily from increases in long-term incentive plan accruals priced as a higher current stock price and merit wage increases for non-officer employees.

$3.3 million in employee benefits expense due primarily to increases in pension expense from a lower discount rate used to determine periodic benefit cost and group insurance expense from higher claims.

• $11 million in payroll primarily related to the management restructuring program in 2006, including impacts on short-term and long-term incentive plan accruals. For further information, see Note 12 to the consolidated financial statements.
• $.6 million in transportation costs primarily due to fewer vehicles being used as a result of our automated meter reading initiative and continuous business process improvements.

$2.4 million in contract labor for contract billing services, telecom and activity related to a new corporate rebranding campaign.

These decreases were partially offset by the following increases:

$.9 million in advertising and sales promotion related to a new corporate rebranding campaign.

• $3.2 million in outside services primarily due to increased telephony services and our gas accounting, financial close and record retention projects.
• $2 million in employee benefits primarily due to pension and postretirement health care costs and health initiative programs and adjustments in group insurance expense.
• $1.3 million in regulatory expense primarily due to consulting related to gas cost accounting reviews.

Depreciation

Depreciation expense increased from $89.7$97.4 million to $93.1$102.8 million over the three-year period 20062009 to 20082011 primarily due to increases in plant in service.

General Taxes

General taxes increased $.8$4.5 million in 20082011 compared with 20072010 primarily due to the following changes:increases:

$2.5 million from the accrual and payment of a liability for sales tax on certain customer accounts that were not exempt from sales tax.

$1.8 million in property taxes related to a larger property base and property value reassessments by taxing authorities.

• $.6 million increase in property taxes related to a refund for South Carolina taxes in the prior year.
• $.4 million increase in gross receipts taxes in Tennessee.
• $.2 million decrease in payroll taxes primarily related to organizational restructuring and process improvement initiatives that began in 2007, partially offset by an increase in the social security wage limit.

General taxes decreased $.7 millionby an insignificant amount in 20072010 compared with 2006 primarily due to the following changes:

• $1.2 million decrease in property taxes related to lower assessments in South Carolina and Tennessee as well as refunds from South Carolina for prior years.
• $.5 million decrease in payroll taxes.
• $.9 million increase in gross receipts taxes in Tennessee.
2009.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, charitable contributions, non-operating expense and income taxes related to these items. Non-operating income


20


includes non-regulated merchandising and service work, home service warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of other miscellaneous expenses.

The primary changes to Other Income (Expense) in 2011 compared with 2010 were in income from equity method investments, the gain on the sale of half of our ownership interest in SouthStar Energy Services LLC (SouthStar) in 2010 and non-operating income discussed below. All other changes were not significant.

insignificant.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.3 million, or $.42 per diluted earnings per share, for 2010.

Income from equity method investments decreased $9.4$4.8 million in 20082011 compared with 20072010 primarily due to a decrease of $4.5 million in earnings from SouthStar due to a full year of recording earnings at the following changes:

• $9.9 million decrease in earnings from SouthStar primarily due to lower of cost or market inventory adjustments, lower contributions from the management of storage and transportation assets, a loss on weather derivatives and a Georgia Public Service Commission consent agreement related to retail pricing.
• $.9 million increase in earnings from Hardy Storage primarily due to its first full year of operations, partially offset by higher operations and maintenance expenses, depreciation and general taxes.
lower 15% ownership interest and unfavorable changes in SouthStar’s average customer usage due to warmer weather and retail pricing plan mix which were partially offset by decreases in operating expenses.

Non-operating income increased $1.1 million in 2011 compared with 2010 primarily due to increased revenues under our non-regulated home service warranty program, interest earned on installment loans made to our natural gas customers under our third party financing program and a state tax refund on behalf of a joint venture.

Income from equity method investments increased $7.2decreased $4.6 million in 20072010 compared with 20062009 due to a $4.5 million decrease in earnings from SouthStar primarily due to the following changes:

• $5.3 million increase in earnings from SouthStar primarily due to hedging activities and retail price spreads.
• $2.8 million increase in earnings from Hardy Storage primarily due to storage revenues in 2007 as phase one service to customers began in April 2007.
• $.6 million decrease in earnings from Pine Needle due to reduced rates approved by the FERC in Pine Needle’s 2007 rate proceeding.
recording of earnings at the new 15% ownership interest as of January 1, 2010 and a change in the retail pricing mix chosen by SouthStar customers with a decrease in the average number of customers, losses on weather derivatives and a decreased contribution from storage and transportation asset management due to higher transportation and commodity prices, partially offset by increased average customer usage due to colder weather, favorable changes in the lower of cost or market storage inventory adjustments and higher retail price spreads.

Utility Interest Charges

Utility interest charges increased $2$.3 million in 20082011 compared with 20072010 primarily due to the following changes:

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

$1.4 million increase in interest expense due to a decrease in interest in the borrowed allowance for funds used during construction (AFUDC), which is recorded as income, primarily due to the closing of approximately half of our construction expenditures to utility plant in service in the first half of the current year as compared with the prior year.

• $2.7 million increase in regulatory interest expense primarily due to interesttrue-ups related to amounts due to customers.
• $.3 million increase in interest on short-term debt due to higher balances outstanding.
• $.9 million decrease in interest expense related to a federal tax audit settlement in 2007.
• $.3 million decrease in interest on regulatory treatment of certain components of deferred income taxes.

$1.1 million increase in interest expense on short-term debt primarily due to average interest rates during the current period that were 44 basis points higher than the prior year period due to higher spreads under the new revolving syndicated credit facility that was put into place in January 2011.

$6.6 million decrease in interest on long-term debt primarily due to lower amounts of debt outstanding during the current period.

Utility interest charges increased $5decreased $3 million in 20072010 compared with 20062009 primarily due to the following changes:

• $5.5 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, which was partially offset by the retirement on July 30, 2006 of $35 million of senior notes.
• $.9

$9.1 million increase in net interest expense on regulatory treatment of certain components of deferred income taxes.

• $.9 million increase in interest expense related to a tax audit settlement.
• $2.1 million decrease in interest on short-term debt due to a decrease in interest charged on amounts due from customers (receivable), which earned a carrying charge, as those balances were lower balances outstanding in 2007 than in 2006 even though rates were slightly higher in the current period.
• $.4 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2007.


21


$7.7 million decrease in interest expense due to an increase in the borrowed AFUDC, which is recorded as income, primarily due to increased construction expenditures.

$2.4 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.

$1.8 million decrease in interest expense on short-term debt primarily due to lower levels of borrowing in the current period combined with an average interest rate for the current period approximately 35 basis points lower than the prior period.

Financial Condition and Liquidity

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

We access ourbelieve that the capacity of short-term credit facility to finance our working capital needs and growth. Recent adverse developments in financial and credit markets have made it more difficult and more expensive to access the short-term capital market to meet our liquidity needs. Although the credit markets tightened in the latter half of 2008, we believe that these sources, including amounts available to us under our existingrevolving syndicated credit facility and seasonal facilities,the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchases and dividend payments.

other cash needs.

Short-Term Borrowings. On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility. The new facility expires in January 2014 and has an option to expand up to $850 million. The three-year revolving syndicated credit facility has the same financial covenant as our previous syndicated credit facility and has additional provisions regarding defaulting lenders and replacement of lenders. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. During the three months ended October 31, 2011, short-term borrowing ranged from $165.5 million to $342.5 million, and interest rates ranged from 1.10% to 1.15%. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17%.

Our short-term borrowings, which consist only of the revolving syndicated credit facility as included in “Bank debt” in the consolidated balance sheets, are vital in order to meet working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity, capital expenditures and approved investments. We rely on short-term borrowings along with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support our system infrastructure and the growth in our customer base. We believe that our revolving syndicated credit facility, along with our access to capital markets, will allow us to meet the increased capital requirements anticipated to be spent over the next two years.

Highlights for our bank borrowings as of October 31, 2011 and for the quarter and year ended October 31, 2011 are presented below.

Bank Borrowings

In thousands

    

End of period (October 31, 2011):

  

Amount outstanding

  $331,000 

Weighted average interest rate

   1.15

During the period (August 1, 2011 - October 31, 2011):

  

Average amount outstanding

  $236,000 

Weighted average interest rate

   1.14

Maximum amount outstanding during the month:

  

August

  $269,500 

September

   288,500 

October

   342,500 

During the year ended October 31, 2011:

  

Average amount outstanding

  $203,500 

Weighted average interest rate

   .94

Maximum amount outstanding

  $426,000 

The level of short-term bank borrowings can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

As of October 31, 2011, we had $10 million available for letters of credit under our three-year revolving syndicated credit facility, of which $3.5 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2011, unused lines of credit available under our three-year revolving syndicated credit facility, including the issuance of the letters of credit, totaled $315.5 million.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations resulting from suchoperations. The major factors asthat affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas inwithdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season (November through March).season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases forinjected into storage, paying down short-term debt, seasonal construction activity and decreases in receipts from customers.

During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to volatilitychanges in the price of natural gas, which is a function of market fluctuations in the pricecommodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to/to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their heating bills. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Because of the economic recession in 2008,weak economy, including continued high unemployment, we may incur additional bad debt expense during the winter heating season, as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, willare expected to mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $69.2$311.2 million in 2008, $233.52011, $360.5 million in 20072010 and $103.8$344.3 million in 2006.2009. Net cash provided by operating activities reflects a $5.6$28.4 million increasedecrease in net income for 2008,2011 compared with 2007.2010, which included the gain on the sale of half our interest in SouthStar as discussed in “Results of Operations” above in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. The effect of changes in working capital on net cash provided by operating activities is described below:

• Trade accounts receivable and unbilled utility revenues increased $12.9 million in the current period primarily due to amounts billed to customers reflecting higher gas costs in 2008 as compared with 2007 and weather in the current period being 7% colder than the same prior period. Volumes sold to residential and commercial customers increased 5 million dekatherms as compared with the same prior period primarily due to the colder weather and customer growth. Total throughput increased 4.2

Trade accounts receivable and unbilled utility revenues increased $2.5 million in the current period primarily due to total throughput which increased 27.1 million dekatherms as compared with the same prior period, largely from the transportation of gas for industrial customers and for power generation along with an increase in unbilled volumes, slightly offset by amounts billed to customers reflecting lower gas costs in 2011 as compared with 2010. Weather during the current period was 3.6% colder than the same prior period. Volumes sold to residential and commercial customers increased .2 million dekatherms as compared with the same prior period.


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Net amounts due from customers decreased $26.3 million in the current period primarily due to the collection of deferred gas costs through rates.

Gas in storage decreased $10.6 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injections as well as decreased volumes in storage in 2011 as compared with 2010.

Prepaid gas costs decreased $.8 million in the current period primarily due to lower average cost of gas in prepaid storage. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

Trade accounts payable increased $1.6 million in the current period primarily due to gas purchases for storage to meet customer demand for the next winter heating season.

• Net amounts due from customers increased $105.9 million in the current period primarily due to the under-recovery of deferred gas and hedging costs. Included in the amounts due from customers were increased hedging costs from the extension of our hedging transactions over a longer term horizon and the expansion of those transactions to a greater percentage of sales quantities due to lower forward market prices.
• Gas in storage increased $58.8 million in the current period primarily due to a higher average cost of gas in storage as well as increased volumes in storage in 2008 as compared with 2007.
• Prepaid gas costs increased $20.5 million in the current period primarily due to the higher average cost of gas in prepaid storage. Prepaid gas costs represent purchases of gas during the summer months under gas supply contracts that are not available for sale, and therefore not recorded in inventory, until the winter heating season.
• Trade accounts payable decreased $7.4 million in the current period primarily due to gas purchases at lower costs during the fourth quarter.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated chargescredits to customers of $6.8$4.9 million in 2008, $6.42011, $8.8 million in 20072010 and $4.1$1.2 million in 2006.2009. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in a deferred account“Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism providedreduced margin of $25.4by $7 million in 20082011 and $32.7$5.9 million in 20072010 and $30.4increased margin by $6 million in 2006.2009. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary.

We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. 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 worldwide supply and demand and the policies of foreign and domestic governments and organizations.organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.


23


In an effort to keep customer rates competitive by holding downand to maximize earnings, we continue to implement business process improvement and operations and maintenance costs and as part of an ongoing effort aimed at improving business processes, capturingcost management programs to capture operational and organizational efficiencies andwhile improving customer service we are continuing the process of standardizing our customer payment and collection processes, streamlining business operationsmaintaining a safe and further consolidating our call centers. These specific initiatives were largely completed during 2008. For further information, see Note 12 to the consolidated financial statements.
reliable system.

Cash Flows from Investing Activities. Net cash used in investing activities was $177.4$252.6 million in 2008, $148.22011, $128.6 million in 20072010 and $167.6$129.6 million in 2006.2009. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $181$243.6 million in 2008,2011, a 34%22% increase from the $135.2$199.1 million in 2007,2010, primarily due to system infrastructure investments.

$103.6 million and $52.3 million, respectively, of investments in plant to serve power generation customers. Gross utility construction expenditures were $129 million in 2009 with $2.6 million of investments in plant to serve power generation customers.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $246.2 million, primarily to serve future customer growth, are budgeted for 2009. We are not contractually obligated to expend capital until the work is completed. Even though we are seeing a slower pace of customer growth in our service territory due to the downturn in the housing market and other economic factors, significantSignificant utility construction expenditures are expected to continue to meet long-term growth, including the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

We are contractually obligated to expend capital as the work is completed.

We anticipate making capital expenditures, including AFUDC, of $240 - 280 million and $80 - 90 million in our fiscal years 2012 and 2013, respectively, to provide natural gas service in the power generation market. These expenditures are significantly higher than we have traditionally expended. We intend to fund expenditures related to these projects in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. Additional detail for the anticipated capital expenditures follows.

In millions

  2012   2013   2014 

Utility capital expenditures

  $300 - 320    $270 - 300    $200 - 250  

Power generation related capital expenditures

   240 - 280     80 - 90     —    
  

 

 

   

 

 

   

 

 

 

Total forecasted capital expenditures

  $540 - 600    $350 - 390    $200 - 250  
  

 

 

   

 

 

   

 

 

 

In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct approximately 38 miles of 20-inch transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2012. We began construction in February 2010. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. To provide the additional delivery service, we have executed an agreement with Cardinal Pipeline Company, LLC (Cardinal) to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend an estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions to date related to this system expansion were $6.2 million. For further information regarding this agreement, see Note 12 to the consolidated financial statements.

In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement, also approved by the NCUC in May 2010, calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013. We began construction in May 2010. Our service to Progress Energy Carolinas is supported by a long-term service agreement. We anticipate that a portion of the cost of this project will be included in our North Carolina utility rate base.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our plan to provide safe, reliablepreviously announced Robeson liquefied natural gas distribution service tostorage project. The timing and design scope of the expansion of our growing customer base and manage our seasonal demand growth, we intend to design, construct, own and operate a LNG peak storage facility as a regulated utility projectfacilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina withdictate.

During the capacity to store approximately 1.25 billion cubic feetfirst quarter of fiscal 2011, we placed into service natural gas for use during times of peak demand. The LNG facility is plannedpipeline and compression facilities to be inprovide natural gas delivery service for the2012-2013 winter heating season. Preliminary estimates place the cost of the facility in the $300 million to $350 million range, with $1.5 million incurred in fiscal year 2008.

During 2007, $2.2 million of supplier refunds was recorded as restricted cash. In 2008, restrictions on cash totaling $2.2 million were removed pursuant to a 2007 NCUC order,Progress Energy Carolinas power generation facility located in Richmond County, North Carolina.

During the first quarter of fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a Duke Energy Carolinas power generation facility located in Rowan County, North Carolina. In a second agreement with Duke Energy Carolinas, we placed into service in December 2011 natural gas pipeline facilities we constructed to provide natural gas delivery service to their Rockingham County, North Carolina power generation facility.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to Georgia Natural Gas Company (GNGC) and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we liquidated all certificates of deposit and similar investments that held any supplier refunds due to customers and transferred these funds upon maturityreceived $57.5 million from GNGC. For further information regarding the sale, see Note 12 to the North Carolina deferred account. During 2006, the restrictions on cash totaling $13.2 million were removed in connection with implementing the NCUC order in a general rate proceeding.

consolidated financial statements.

In 2008,2009, we contributed $10.9$.9 million to our Hardy Storage Company, LLC (Hardy Storage) joint venture as part of our equity contribution for construction of the FERC regulated interstate storage facility.

During 2008, we sold various properties located We made no contributions in Burlington2010 and High Point, North Carolina, Spartanburg, South Carolina and Nashville, Tennessee for $13.2 million, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land from these sales2011 as a pre-tax gain of $1.2 million with a deferral of $.5 million relatedHardy Storage converted its construction interim notes in March 2010 into long-term project-financed debt. For further information on Hardy Storage, see Note 12 to the Nashville sale. The net pre-tax gain of $.7 million was recorded in “Other Income (Expense)” in the consolidated statements of income. We recorded a gain of $3.1 million on the disposition of the buildings as a charge to “Accumulated depreciation” in the consolidated balance sheets. We entered into a sale-leaseback agreement on the Nashville property for a lease of 18financial statements.

1/2 months, where the $.5 million deferred gain will be amortized on a straight-line basis over the life of the lease and recorded to “Other Income (Expense)” in the consolidated statements of income. During 2008, we recorded $38,636 of deferred gain.

Cash Flows from Financing Activities. Net cash provided by (used in)used in financing activities was $107.7$57.5 million in 2008, $(86.6)2011, $233.9 million in 20072010 and $65.6$214.1 million in 2006.2009. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock plans, net of purchases under the common stock repurchase program.purchase plans. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to retire long-term debt, pay down outstanding short-term bank borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of October 31, 2008,2011, our current assets


24


were $600.8$286 million and our current liabilities were $681.5$534.1 million, primarily due to seasonal requirements as discussed above.
As of October 31, 2008, we had committed lines of credit under our senior credit facility of $450 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million.

Outstanding short-term bank borrowings increased from $195.5$242 million as of October 31, 20072010 to $406.5$331 million as of October 31, 2008,2011 primarily due to higher storage inventory costs, costs associated withcapital expenditures and long-term debt maturities. Over the hedging programs,three-year period from 2009 to 2011, our short-term borrowings have included the purchasereplacement of shares under the ASR program and payments for interest on short-term debt and property taxes, partially offset by the collections of amounts that had been billed to customers during the winter months. During the twelve months ended October 31, 2008, short-term bank borrowings ranged from $9 million to $426 million, and interest rates ranged from 2.63% to 5.51% (weighted average of 3.79%).

On October 27 and 29, 2008, we entered into two short-term credit facilities with banks for unsecured commitments totaling $75 million expiring on December 1, 2008. On December 1, 2008, these commitments were extended to December 3, 2008. Advances under each short-term facility bear interest at a rate based on the30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings. We entered into these short-term facilities to provide lines of credit in addition to the seniorfive-year revolving syndicated credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements, including support forwith our gas supply procurement program as well as general corporate needs. No borrowings were outstanding at October 31, 2008.
Effective December 3, 2008, we entered intocurrent three-year revolving syndicated credit facility and a syndicated seasonal credit facility with aggregate commitments totaling $150 million. Advances under this seasonal facility bear interest at a rate based on the30-day LIBOR rate plusin existence from .75% to 1.75%, based on our credit ratings. Any borrowings under this agreement are due byDecember 3, 2008 through March 31, 2009. For further information on bank borrowings, see the previous discussion of “Short-Term Borrowings” in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We entered into this facility to provide lines of creditretired our $60 million 6.55% medium-term notes, $60 million 7.8% medium-term notes and $30 million 7.35% medium-term notes in addition to the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirementsSeptember 2011, September 2010 and general corporate needs.

As of October 31, 2008, under our senior credit facility,September 2009, respectively, as they became due. On June 1, 2011, we had available letters of credit of $5 million of which $1.9 million was issued and outstanding. The letters of credit are used to guarantee claims fromself-insurance under our general liability policies. As of October 31, 2008, unused lines of credit available under our credit facilities, including the issuanceredeemed all of the letters6.25% insured quarterly notes with an aggregate principal balance of credit, totaled $116.6 million.
The level of$196.8 million with short-term bank borrowings can vary significantly dueunder the revolving syndicated credit facility. On June 6, 2011, we issued $40 million of unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million of unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to changesreduce our short-term borrowings as well as for other general corporate purposes and working capital needs. The replacement of this higher rate debt with lower rate debt will provide annual interest savings of $4.3 million.

On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in the wholesale pricesour subsidiaries, and for repurchases of natural gas andshares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the level of purchases of natural gas supplies and hedging transactionspurposes mentioned above in investment grade securities.

We plan 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 fluctuate. If wholesale gas prices increase, we may incur more short-term debt for 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.

In September 2009, the balance of $30issue approximately $300 million of our 7.35% Medium-Term Notes is due. We anticipate issuing up to $125 million in long-term debt in our fiscal 2012 third quarter for general corporate purposes, including the funding of capital expenditures to serve new power generation projects. We continually monitor customer growth trends and opportunities in our markets along with the economic recovery of our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our ASR program as described in Note 6 to the consolidated financial statements. During 2011, we repurchased and retired .8 million shares for $23 million under our Common Stock Open Market Purchase Program, leaving a balance of 3,710,074 shares available for repurchase under the program. During 2010 and 2009, we repurchased 1.8 million shares and .7 million shares for $47.3 million and $17.9 million, respectively. We anticipate repurchasing .8 million shares of common stock through an ASR agreement in the first quarter of our fiscal year 2012 with no permanent reduction in shares outstanding for general operating purposes. The timing of this issuance has not yet been determined.

We had a shelf registration statement filed with the SEC that expired on December 1, 2008 that could have been used for the issuance of either debt or equity. The remaining balance of unused long-term financing available under this shelf registration statement as of October 31, 2008 was $109.4 million.
fiscal year 2012.

During 2008,2011, we issued $15.6$20.2 million of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. On November 2, 2007,During 2010 and 2009, we issued $19.1 million and $14.4 million, respectively, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $24.8 million. On January 15, 2008, we settled the transaction and paid an additional $1.3 million. Under the ASR agreement and the Common Stock Open Market Purchase Program discussed in Note 4 to the consolidated financial statements, we paid $42.7 million during 2008 for 1.6 million shares of common stock that are available for reissuance to these plans. During 2007, 2 million shares were repurchased for $54.2 million. During 2006, 2.1 million shares were repurchased for $50.2 million.


25


Through the ASR program, we may repurchase and subsequently retire up to approximately four million shares of common stock by no later than December 31, 2010. Through the ASR agreements, we have repurchased 3,850,000 shares as follows.
April 20061,000,000
November 20061,000,000
March 2007850,000
November 20071,000,000
Total3,850,000
These shares are in addition to shares that are repurchased on a normal basis through the open market program. During 2009, we do not intend to repurchase any shares under an ASR agreement or the Common Stock Open Market Purchase Program.
We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share in 2008, $.04 per share in 20072011, 2010 and $.05 per share in 2006.2009. Dividends of $75.5$82.9 million, $73.6$80.3 million and $72.1$78.4 million for 2008, 20072011, 2010 and 2006,2009, respectively, were paid on common stock. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2008,2011, our retained earnings were not restricted. On December 18, 2008,16, 2011, the Board of Directors declared a quarterly dividend on common stock of $.26$.29 per share, payable January 15, 200913, 2012 to shareholders of record at the close of business on December 26, 2008.27, 2011. For further information, see Note 34 to the consolidated financial statements.

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, 2008,2011, our capitalization, including current maturities of long-term debt, if any, consisted of 48%40% in long-term debt and 52%60% in common equity.

The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 20082011 and 20072010 are summarized in the table below.

                 
  October 31  October 31 
  2008  Percentage  2007  Percentage 
  In thousands 
 
Short-term debt $406,500   19% $195,500   10%
Current portion of long-term debt  30,000   1%     0%
Long-term debt  794,261   38%  824,887   44%
                 
Total debt  1,230,761   58%  1,020,387   54%
Common stockholders’ equity  887,244   42%  878,374   46%
                 
Total capitalization (including short-term debt) $2,118,005   100% $1,898,761   100%
                 

   October 31  October 31 

In thousands

  2011   Percentage  2010   Percentage 

Short-term debt

  $331,000    16  $242,000    12 

Current portion of long-term debt

   —       —    60,000    

Long-term debt

   675,000    34   671,922    35 
  

 

 

   

 

 

  

 

 

   

 

 

 

Total debt

   1,006,000    50   973,922    50 

Common stockholders’ equity

   996,923    50   964,941    50 
  

 

 

   

 

 

  

 

 

   

 

 

 

Total capitalization (including short-term debt)

  $2,002,923    100  $1,938,863    100 
  

 

 

   

 

 

  

 

 

   

 

 

 

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds. In determining our credit ratings, the rating agencies consider 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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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.

Qualitative factors include, among other things:

Stability of regulation in the jurisdictions in which we operate,

Consistency of our earnings over time,

• 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,
• Quality of business strategy and management,
• Corporate governance guidelines and practices,
• Industry position, and
• Contingencies.

Risks and controls inherent in the distribution of natural gas,

Predictability of cash flows,

Quality of business strategy and management,

Corporate governance guidelines and practices,

Industry position, and

Contingencies.

As of October 31, 2008,2011, 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 Service (Moody’s).Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. Credit ratings and outlooks are opinions of the rating agency and are subject to their ongoing review. A significant decline in our operating performance, capital structure, or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term bank borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2008, we are in compliance with all2011, there has been no event of default provisions.

giving rise to acceleration of our debt.

The default provisions of some or all of our senior notes are:debt include:

Failure to make principal or interest payments,

Bankruptcy, liquidation or insolvency,

• Failure to make principal, interest or sinking fund payments,
• Interest coverage of 1.75 times,
• Total

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

Specified events under the Employee Retirement Income Security Act of 1974,

Change in control, and

Failure to observe or perform covenants, including:

Interest coverage of at least 1.75 times. Interest coverage was 5.78 times as of October 31, 2011;

Funded debt cannot exceed 70% of total capitalization. Funded debt was 51% of total capitalization as of October 31, 2011;

Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded 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:subsidiaries as of October 31, 2011;

Restrictions on permitted liens;

• 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.


27

Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and

Restrictions on burdensome agreements.


Contractual Obligations and Commitments

We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2008,2011, our estimated future recorded and unrecorded contractual obligations are as follows.

                     
  Payments Due by Period 
  Less than
  1-3
  4-5
  After
    
  1 Year  Years  Years  5 Years  Total 
  In thousands 
 
Recorded contractual obligations
                    
Long-term debt(1) $30,000  $120,000  $100,000  $574,261  $824,261 
Short-term debt  406,500            406,500 
                     
Total $436,500  $120,000  $100,000  $574,261  $1,230,761 
                     

    Payments Due by Period 

In thousands

  Less than
1 year
   1-3
Years
   4-5
Years
   After
5 Years
   Total 

Recorded contractual obligations:

          

Long-term debt (1)

  $—      $100,000   $75,000   $500,000   $675,000 

Short-term debt (2)

   331,000    —       —       —       331,000 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $331,000   $100,000   $75,000   $500,000   $1,006,000 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)See Note 34 to the consolidated financial statements.
                     
  Less than
  1-3
  4-5
  After
    
  1 Year  Years  Years  5 Years  Total 
  In thousands 
 
Unrecorded contractual obligations and commitments(1)
                    
Pipeline and storage capacity(2) $148,907  $453,595  $168,998  $335,306  $1,106,806 
Gas supply(3)  23,340   369         23,709 
Interest on long-term debt(4)  56,115   149,655   86,917   626,733   919,420 
Telecommunications and information technology(5)  18,555   17,106         35,661 
Qualified and nonqualified pension plan funding(6)  11,618   34,714   11,480      57,812 
Postretirement benefits plan funding(6)  3,400   5,600   1,500      10,500 
Operating leases(7)  6,232   12,866   7,887   5,956   32,941 
Other purchase obligations(8)  32,093            32,093 
Letters of credit  2,335   7,005   4,670      14,010 
FIN 48 obligations  202   305         507 
                     
Total $302,797  $681,215  $281,452  $967,995  $2,233,459 
                     
(2)See Note 5 to the consolidated financial statements.

In thousands

  Less than
1 year
   1-3
Years
   4-5
Years
   After
5 Years
   Total 

Unrecorded contractual obligations and commitments: (1)

          

Pipeline and storage capacity (2)

  $151,456   $254,299   $112,774   $281,147   $799,676 

Gas supply (3)

   6,974    11    —       —       6,985 

Interest on long-term debt (4)

   40,181    113,198    69,423    289,479    512,281 

Telecommunications and information technology (5)

   11,055    14,921    —       —       25,976 

Qualified and nonqualified pension plan funding (6)

   1,052    19,140    6,731    —       26,923 

Postretirement benefits plan funding (6)

   1,600    4,000    1,300    —       6,900 

Operating leases (7)

   3,560    11,775    7,291    31,853    54,479 

Other purchase obligations (8)

   5,912    —       —       —       5,912 

Letters of credit (9)

   3,459    —       —       —       3,459 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $225,249   $417,344   $197,519   $602,479   $1,442,591 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)In accordance with generally accepted accounting principles (GAAP), these items are not reflected in our consolidated balance sheets.
(2)Recoverable through PGA procedures.
(3)Reservation fees are recoverable through PGA procedures.
(4)See Note 34 to the consolidated financial statements.
(5)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.
(6)Estimated funding beyond five years is not available. See Note 79 to the consolidated financial statements.
(7)See Note 68 to the consolidated financial statements.
(8)Consists primarily of pipeline products, vehicles, contractors and merchandise.
(9)See Note 5 to the consolidated financial statements.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases and letters of credit and operating leases. The letters of credit and operating leases are discussed in Note 65 and Note 5,8, respectively, to the consolidated financial statements thatand are reflected in the table above.


28


Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million and $1.3 million as of October 31, 2008 and 2007, respectively. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 10 to the consolidated financial statements.
Critical Accounting Estimates

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

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting 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 the Effects of Certain Types of Regulation” (Statement 71),accounting regulations required by rate regulated operations 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 on 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 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.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.

Regulatory assets as of October 31, 20082011 and 2007,2010 totaled $263.2$200.1 million and $134$197.8 million, respectively. Regulatory liabilities as of October 31, 20082011 and 2007,2010 totaled $383.7$467 million and $374$439.1 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1.B1 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. In South Carolina and Tennessee, we have WNA mechanisms that are designed to protect a portion of our revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism formerly known as the CUT, provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin earned monthly under the margin decoupling mechanism will resultresults in semi-annual rate adjustments to refund anyover-collection or


29


recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism. Without the WNA orand margin decoupling mechanism,mechanisms, our operating revenues in 2008, 20072011 and 20062010 would have been higher by $11.9 million and $14.7 million, respectively, and lower by $32.2$4.8 million $39.1 million and $34.6 million, respectively.
in 2009.

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, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanism, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.

Pension and Postretirement Benefits.  For eligible full-time employees hired on or before December 31, 2007 (December 31, 2008 for employees covered under the bargaining unit contract in Nashville, Tennessee), we We have a traditional defined benefit pension plan which was amended to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued.(qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible full-time employees. For further information and our reported costs of providing these benefits, see Note 79 to the consolidated financial statements. The costs of providing these benefits 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.

periods, and we cannot predict with certainty what these factors will be in the future.

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 Investors Service’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 plan changed from 6.43%5.47% in 20072010 to 8.15%4.67% in 2008.2011. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 6.06%4.37% in 20072010 to 8.46%4.10% in 2008.2011. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 6.25%4.85% in 20072010 to 8.5%4.36% in 2008.2011. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we maintained the sameinitial health care cost trend rate of 8.25%was assumed to be 7.80% in 2008 and 2007,2011 declining gradually to 5% in 2017.

by 2027.

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%50% equity securities and 40%50% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8.5% in 2006 and 2007, and 8% in 2008.2009, 2010 and 2011. Based on a fairly stagnantconstant inflation trend, our age-related assumed rate of increase in future compensation levels was 4.01%3.92% in 2006,2009, decreasing to 3.99%3.87% in 20072010 and further decreasing to 3.97%3.78% in 20082011 due to changes in the demographics of the participants.


30


Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.

During 2011, we recorded cost of $2.3 million related to our qualified pension plan and postretirement benefits plan. We estimate 2012 expenses for these two plans to be in the range of $5 to $6 million representing an increase of $3 to $4 million over 2011. These estimates reflect the discount rates and assumed rate of return on the plan assets discussed above for each plan.

The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.
             
  Change in
  Impact on 2008
  Impact on Projected
 
Actuarial Assumption
 Assumption  Pension Cost  Benefit Obligation 
  Increase (Decrease)
 
  In thousands 
 
Discount rate  (.25)% $715  $3,023 
Rate of return on plan assets  (.25)%  528   N/A 
Rate of increase in compensation  .25%  381   1,207 

Actuarial Assumption

  Change in
Assumption
  Impact on 2011
Benefit Cost
   Impact on Projected
Benefit Obligation
 
      Increase (Decrease)
In thousands
 

Discount rate

   (.25)%  $515   $5,973 

Rate of return on plan assets

   (.25)%   644    N/A  

Rate of increase in compensation

   .25  560    3,162 

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 2008
  Impact on Accumulated
 
  Change in
  Postretirement
  Postretirement Benefit
 
Actuarial Assumption
 Assumption  Benefit Cost  Obligation 
  Increase (Decrease)
 
  In thousands 
 
Discount rate  (.25)% $5  $511 
Rate of return on plan assets  (.25)%  51   N/A 
Health care cost trend rate  .25%  21   179 

Actuarial Assumption

  Change in
Assumption
  Impact on 2011
Postretirement
Benefit Cost
   Impact on Accumulated
Postretirement Benefit
Obligation
 
       Increase (Decrease)
In thousands
 

Discount rate

   (.25)%  $13   $796 

Rate of return on plan assets

   (.25)%   52    N/A  

Health care cost trend rate

   .25  9    177 

We utilize a number of accounting methods consistently applied that are allowed under generally accepted accounting principles (GAAP) thatGAAP which 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

The source of our gas supply portfolio through pipeline capacity arrangements that access new sourceswe distribute to our customers comes primarily from the Gulf Coast production region where it is purchased primarily from major and independent producers and marketers. As part of supply and market-area storage and thatour long-term plan to diversify supply concentrationour reliance away from the Gulf Coast region. In January 2008,region, we began receiving 120,000 dekatherms per day ofhave contracted for firm, long-term market area storage service in West Virginia from Hardy Storage, a venture in which we have a 50% equity interest, which is more fully discussed in Note 12 to the consolidated financial statements. We have also contracted for firm, long-term transportation contract service from Midwestern that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. In April 2007, we began receiving firm, long-term market-area storage

Natural gas demand is continuing to grow in our service from Hardy Storage in West Virginia. Hardy Storage willarea, particularly to provide us 58,700 dekatherms per day of storage withdrawalnatural gas delivery service during the winter of2008-2009,to existing and that service level is planned to increase to 68,800 dekatherms per day for the winter of2009-2010. We have a 50% equity interest in this project which is more fullyfuture power generation facilities as discussed in the preceding section of “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For further information on our equity venture with Cardinal to expand our firm capacity requirement in order to serve a power generation facility in Wayne County, North Carolina, see Note 1012 to the consolidated financial statements.

As part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand, we intend to design, construct, own and operate a LNG peak storage facility in Robeson County, North Carolina with the capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand. The LNG facility will be a part of our regulated utility segment and is planned to be in service for the2012-2013 winter heating season.

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 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. A sharing mechanism is in effect where 75% of any margin is passed through to customers in all of our jurisdictions. However,For further information on secondary market transactions, in Tennessee are included in the TIP discussed insee Note 2 to the consolidated financial statements.

We have been in discussionscontinue to work with FERC’s Officeour regulatory commissions to earn a fair rate of Enforcement (OE) regarding certain instances of possible non-compliance with FERC’s capacity release regulations regarding postingreturn for our shareholders and bidding requirements for short-term releases. We have provided relevant informationprovide safe, reliable natural gas distribution service to FERC OE Staff and are cooperating with


31


FERC in its investigation. We are continuing to meet with FERC’s OE staff to resolve this matter. We are unable to predict the outcome of the investigation at this time; however, we do not believe this matter will have a material effect on our earnings.
In October 2008, the NCUC approved a settlement in our general rate case proceeding that provides an annual revenue increase of $15.7 million and the continuation of the margin decoupling mechanism. The new rates become effective November 1, 2008. Also in October 2008, the PSCSC issued an order approving a settlement that provides for an annual decrease of $1.5 million in margin under the Natural Gas Rate Stabilization Act (RSA) mechanism based on a return on equity of 11.2%, effective November 1, 2008.customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial statements.

Equity Method Investments

For information about our equity method investments, see Note 1012 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 68 to the consolidated financial statements.

Accounting Pronouncements

Guidance

For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements.

International Financial Reporting Standards (IFRS)

In September 2006,early 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. In October 2010, the SEC staff issued its first public progress report on the work plan. Additionally, in December 2010, the SEC chairman publicly stated that companies would be allowed a minimum of four years to implement IFRS if it is mandated. In May 2011, an SEC Staff Paper was issued outlining a possible endorsement approach for incorporation of IFRS into the U.S. financial reporting system if the SEC were to decide that incorporation of IFRS is in the best interest of U.S. investors. Under this possible framework, IFRS would be incorporated into U.S. GAAP during a transition period of five to seven years with the Financial Accounting Standards Board (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)remaining as the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date.
• Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data.
• Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.
Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options under our gas hedging plans.
U.S. accounting standard setter.

In November 2007,2011, the FASB delayedSEC released two more Staff Papers as part of their work plan. The first paper was the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. 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 for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis. Accordingly, we will adopt Statement 157 for our fiscal year beginning November 1, 2008 with the exception ofSEC Staff’s observations regarding the application of IFRS in practice based on an analysis of 183 companies across 36 industries. The Staff found that company financial statements generally appeared to comply with IFRS requirements. Two observations made were: (1) Companies did not always provide relevant accounting policy disclosures or there was not

sufficient detail or clarity in the provision related to nonfinancial assetsaccounting policy disclosures; and liabilities. The


32


adoption(2) Diversity in the application of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.
In April 2007, the FASB issued FSPFIN 39-1 to amend paragraph 3 of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contractsIFRS made comparability challenging with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instrumentsdiversity attributed to be standard driven where options were permitted by IFRS or there was an absence of IFRS guidance or just noncompliance with IFRS. The second paper provided an assessment of a comparison of U.S. GAAP and Hedging Activities” (Statement 133). The FSP amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 for our fiscal year beginning November 1, 2008. Our policy has been to present our positions, exclusive of any receivable or payable, with the same counterparty on a net basis; however, we will elect “not to net” under FSPFIN 39-1 and will reflect minor reclassifications on our statement of financial position.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquistion contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (Statement 159). Statement 159 provides companiesIFRS with an optioninventorying of areas in which IFRS provides less or no guidance than U.S. GAAP. The fundamental differences noted were that IFRS contains broad principles to report selected financial assetsaccount for transactions across industries with limited specific guidance and liabilities at fair value. Its objective is to reducestated exceptions and that fundamental differences exist between conceptual frameworks, including the complexity in accounting for financial instrumentslevel of authority and to mitigate the volatility in earnings caused by measuring related assetsdefinition and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar typesrecognition of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted forThe Staff Paper provided a broad comparison of the requirements of both accounting standards, highlighting notable differences, but did not provide an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to electanalysis of the option to measure any applicable financial assets or liabilities at fair value pursuant toimpact of those differences on the provisionsquality of Statement 159.
In March 2008,IFRS.

Although the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Statement 161 also amended SFAS 107, “Disclosures about Fair Value of Financial Instruments” (Statement 107), to clarify that derivative instruments are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is notSEC was expected to have a material impact on our financial position, results of operations, or cash flows. We will adopt Statement 161 on February 1, 2009.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity


33


with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature establishedvote by the FASB. Statement 162end of 2011 on whether to require the use of IFRS and by what method, they have further delayed their decision to 2012 in order to complete a comprehensive work plan.

In late 2010 and early 2011, we completed a preliminary assessment of IFRS to understand the key accounting and reporting differences compared to U.S. GAAP and to assess potential organizational, process and system impacts that would be required. The accounting differences between U.S. GAAP and IFRS are complex and significant in many areas, and conversion to IFRS would have broad impacts to us. In addition to financial statement and disclosure changes, converting to IFRS would involve changes to processes and controls, regulatory and management reporting, financial reporting systems and other areas of the company. As a part of the IFRS assessment project, a preliminary conversion roadmap was created for reporting IFRS. This IFRS conversion roadmap and our strategy for addressing a potential mandate of IFRS will be effective sixty days followingre-assessed when the SecuritiesSEC makes its final determination on the use of IFRS.

Item 7A. Quantitative and Exchange Commission (SEC) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have any impact on our financial position, results of operations or cash flows. We will adopt Statement 162 when it becomes effective.

Item 7A.Quantitative and Qualitative Disclosures about Market Risk
Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage market risk and credit riskall of these risks in accordance with defined policies and procedures under an Enterprise Risk Management Policy.program and with the direction of the Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures.

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

Credit Risk

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

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

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

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2008,2011, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

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

As of October 31, 2008,2011, we had $406.5$331 million of short-term debt outstanding under our syndicated revolving credit facility at a weighted averagean interest rate of 2.84%1.15%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1.9$2 million during 2008.


34

2011.


As of October 31, 2008,2011, information about our long-term debt is presented below.
                                 
                       Fair Value as
 
  Expected Maturity Date  of October 31,
 
  2009  2010  2011  2012  2013  Thereafter  Total  2008 
           In millions          
 
Fixed Rate Long-term Debt $30  $60  $60  $  $  $674.3  $824.3  $798.1 
Average Interest Rate  7.35%  7.80%  6.55%        6.64%  6.72%    

                        Fair Value as
of  October 31,
2011
 
   Expected Maturity Date     

In millions

  2012  2013  2014  2015  2016  Thereafter  Total  

Fixed Rate Long-term Debt

  $—     $—     $100  $—     $40  $535.0  $675.0  $831.3 

Average Interest Rate

   —    —    5  —    2.92  6.38  5.97 

Commodity Price Risk

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

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

We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.

Weather Risk

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

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of thisForm 10-K.10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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.


35


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 20082011 and 2007,2010, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2008.2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 20082011 and 2007,2010, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2008,2011, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of October 31, 2008,2011, based on the criteria established inInternal Control — Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 29, 200823, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 29, 2008


3623, 2011


Piedmont Natural Gas Company, Inc.

October 31, 20082011 and 2007

         
  2008  2007 
  In thousands 
 
ASSETS
Utility Plant:        
Utility plant in service $2,997,186  $2,833,286 
Less accumulated depreciation  813,822   752,977 
         
Utility plant in service, net  2,183,364   2,080,309 
Construction work in progress  57,470   61,228 
         
Total utility plant, net  2,240,834   2,141,537 
         
Other Physical Property, at cost (net of accumulated depreciation of $2,351 in 2008 and $2,197 in 2007)  864   1,007 
         
Current Assets:        
Cash and cash equivalents  6,991   7,515 
Restricted cash     2,211 
Trade accounts receivable (less allowance for doubtful accounts of $1,066 in 2008 and $544 in 2007)  82,346   97,625 
Income taxes receivable  731   15,699 
Other receivables  393   649 
Unbilled utility revenues  51,819   24,121 
Inventories:        
Gas in storage  190,275   131,439 
Materials, supplies and merchandise  6,525   5,222 
Gas purchase options, at fair value     13,725 
Amounts due from customers  181,745   76,035 
Prepayments  79,831   61,007 
Other  96   96 
         
Total current assets  600,752   435,344 
         
Investments, Deferred Charges and Other Assets:        
Equity method investments in non-utility activities  99,214   95,193 
Goodwill  48,852   48,852 
Overfunded postretirement asset  6,797   36,256 
Regulatory asset for postretirement benefits  28,732   1,865 
Gas purchase options, at fair value  10,257    
Unamortized debt expense  9,915   10,565 
Regulatory cost of removal asset  6,398   11,939 
Other  40,965   37,760 
         
Total investments, deferred charges and other assets  251,130   242,430 
         
Total $3,093,580  $2,820,318 
         
 
CAPITALIZATION AND LIABILITIES
Capitalization:        
Stockholders’ equity:        
Cumulative preferred stock — no par value — 175 shares authorized $  $ 
Common stock — no par value — shares authorized: 200,000; shares outstanding: 73,246 in 2008 and 74,208 in 2007  471,565   497,570 
Paid-in capital  763   402 
Retained earnings  414,246   379,682 
Accumulated other comprehensive income  670   720 
         
Total stockholders’ equity  887,244   878,374 
Long-term debt  794,261   824,887 
         
Total capitalization  1,681,505   1,703,261 
         
Current Liabilities:        
Current maturities of long-term debt  30,000    
Notes payable  406,500   195,500 
Trade accounts payable  91,142   97,156 
Other accounts payable  45,148   46,411 
Income taxes accrued  4,414   1,224 
Accrued interest  22,777   21,811 
Customers’ deposits  23,881   22,930 
Deferred income taxes  6,878   16,422 
General taxes accrued  18,932   18,980 
Gas purchase options, at fair value  19,561    
Amounts due to customers     162 
Other  12,300   3,915 
         
Total current liabilities  681,533   424,511 
         
Deferred Credits and Other Liabilities:        
Deferred income taxes  305,362   267,479 
Unamortized federal investment tax credits  2,626   2,983 
Regulatory liability for postretirement benefits  372   13,876 
Accumulated provision for postretirement benefits  16,257   17,469 
Cost of removal obligations  367,450   351,738 
Other  38,475   39,001 
         
Total deferred credits and other liabilities  730,542   692,546 
         
Commitments and Contingencies (Note 6)      
         
Total $3,093,580  $2,820,318 
         
2010

ASSETS

In thousands

  2011   2010 

Utility Plant:

    

Utility plant in service

  $3,377,310   $3,176,312 

Less accumulated depreciation

   974,631    917,300 
  

 

 

   

 

 

 

Utility plant in service, net

   2,402,679    2,259,012 

Construction work in progress

   217,832    171,901 

Plant held for future use

   6,751    6,751 
  

 

 

   

 

 

 

Total utility plant, net

   2,627,262    2,437,664 
  

 

 

   

 

 

 

Other Physical Property, at cost (net of accumulated depreciation of $806 in 2011 and $729 in 2010)

   452    528 
  

 

 

   

 

 

 

Current Assets:

    

Cash and cash equivalents

   6,777    5,619 

Trade accounts receivable (less allowance for doubtful accounts of $1,347 in 2011 and $929 in 2010)

   57,035    62,370 

Income taxes receivable

   15,966    24,856 

Other receivables

   2,547    2,289 

Unbilled utility revenues

   28,715    21,337 

Inventories:

    

Gas in storage

   91,124    101,734 

Materials, supplies and merchandise

   1,368    4,547 

Gas purchase derivative assets, at fair value

   2,772    2,819 

Amounts due from customers

   38,649    62,336 

Prepayments

   39,128    39,832 

Deferred income taxes

   1,793    —    

Other current assets

   147    101 
  

 

 

   

 

 

 

Total current assets

   286,021    327,840 
  

 

 

   

 

 

 

Noncurrent Assets:

    

Equity method investments in non-utility activities

   85,121    80,287 

Goodwill

   48,852    48,852 

Marketable securities, at fair value

   1,439    997 

Overfunded postretirement asset

   22,879    17,342 

Regulatory asset for postretirement benefits

   81,073    64,775 

Unamortized debt expense

   11,315    8,576 

Regulatory cost of removal asset

   19,336    17,825 

Other noncurrent assets

   58,791    48,589 
  

 

 

   

 

 

 

Total noncurrent assets

   328,806    287,243 
  

 

 

   

 

 

 

Total

  $3,242,541   $3,053,275 
  

 

 

   

 

 

 

See notes to consolidated financial statements.


37


Consolidated Balance Sheets

October 31, 2011 and 2010

Piedmont Natural Gas Company, Inc.
CAPITALIZATION AND LIABILITIES

In thousands

  2011  2010 

Capitalization:

   

Stockholders’ equity:

   

Cumulative preferred stock - no par value - 175 shares authorized

  $—     $—    

Common stock - no par value - shares authorized: 200,000; shares outstanding: 72,318 in 2011 and 72,282 in 2010

   446,791   445,640 

Retained earnings

   550,584   519,831 

Accumulated other comprehensive loss

   (452  (530
  

 

 

  

 

 

 

Total stockholders’ equity

   996,923   964,941 

Long-term debt

   675,000   671,922 
  

 

 

  

 

 

 

Total capitalization

   1,671,923   1,636,863 
  

 

 

  

 

 

 

Current Liabilities:

   

Current maturities of long-term debt

   —      60,000 

Bank debt

   331,000   242,000 

Trade accounts payable

   85,721   66,019 

Other accounts payable

   43,959   49,645 

Accrued interest

   20,038   20,134 

Customers’ deposits

   25,462   25,631 

Deferred income taxes

   —      4,933 

General taxes accrued

   21,262   20,100 

Amounts due to customers

   2,617   —    

Other current liabilities

   4,073   10,098 
  

 

 

  

 

 

 

Total current liabilities

   534,132   498,560 
  

 

 

  

 

 

 

Noncurrent Liabilities:

   

Deferred income taxes

   512,961   429,225 

Unamortized federal investment tax credits

   2,004   2,145 

Accumulated provision for postretirement benefits

   14,671   14,805 

Cost of removal obligations

   466,000   436,072 

Other noncurrent liabilities

   40,850   35,605 
  

 

 

  

 

 

 

Total noncurrent liabilities

   1,036,486   917,852 
  

 

 

  

 

 

 

Commitments and Contingencies (Note 8)

   
  

 

 

  

 

 

 

Total

  $3,242,541  $3,053,275 
  

 

 

  

 

 

 

See notes to consolidated financial statements.

Page Intentionally Blank

Consolidated Statements of Income

For the Years Ended October 31, 2008, 20072011, 2010 and 2006

             
  2008  2007  2006 
  In thousands except per share amounts 
 
Operating Revenues $2,089,108  $1,711,292  $1,924,628 
Cost of Gas  1,536,135   1,187,127   1,401,149 
             
Margin  552,973   524,165   523,479 
             
Operating Expenses:            
Operations and maintenance  210,757   214,442   219,353 
Depreciation  93,121   88,654   89,696 
General taxes  33,170   32,407   33,138 
Income taxes  62,814   51,315   50,543 
             
Total operating expenses  399,862   386,818   392,730 
             
Operating Income  153,111   137,347   130,749 
             
Other Income (Expense):            
Income from equity method investments  27,718   37,156   29,917 
Non-operating income  1,320   2,218   1,147 
Charitable contributions  (1,327)  (587)  (321)
Non-operating expense  (864)  (164)  (106)
Income taxes  (10,678)  (14,311)  (11,887)
             
Total other income (expense), net of tax  16,169   24,312   18,750 
             
Utility Interest Charges:            
Interest on long-term debt  55,449   55,440   49,915 
Allowance for borrowed funds used during construction  (4,002)  (3,799)  (3,893)
Other  7,826   5,631   6,288 
             
Total utility interest charges  59,273   57,272   52,310 
             
Net Income $110,007  $104,387  $97,189 
             
Average Shares of Common Stock:            
Basic  73,334   74,250   75,863 
Diluted  73,612   74,472   76,156 
Earnings Per Share of Common Stock:            
Basic $1.50  $1.41  $1.28 
Diluted $1.49  $1.40  $1.28 
2009

   2011  2010  2009 

In thousands except per share amounts

    

Operating Revenues

  $1,433,905  $1,552,295  $1,638,116 

Cost of Gas

   860,266   999,703   1,076,542 
  

 

 

  

 

 

  

 

 

 

Margin

   573,639   552,592   561,574 
  

 

 

  

 

 

  

 

 

 

Operating Expenses:

    

Operations and maintenance

   225,351   219,829   208,105 

Depreciation

   102,829   98,494   97,425 

General taxes

   38,380   33,909   34,590 

Utility income taxes

   64,068   62,082   70,079 
  

 

 

  

 

 

  

 

 

 

Total operating expenses

   430,628   414,314   410,199 
  

 

 

  

 

 

  

 

 

 

Operating Income

   143,011   138,278   151,375 
  

 

 

  

 

 

  

 

 

 

Other Income (Expense):

    

Income from equity method investments

   24,027   28,854   33,464 

Gain on sale of interest in equity method investment

   —      49,674   —    

Non-operating income

   1,762   659   32 

Charitable contributions

   (1,818  (1,363  (2,011

Non-operating expense

   (1,204  (643  (1,558

Income taxes

   (8,218  (29,794  (11,803
  

 

 

  

 

 

  

 

 

 

Total other income (expense)

   14,549   47,387   18,124 
  

 

 

  

 

 

  

 

 

 

Utility Interest Charges:

    

Interest on long-term debt

   46,070   52,666   55,105 

Allowance for borrowed funds used during construction

   (8,619  (9,981  (2,298

Other

   6,541   1,026   (6,132
  

 

 

  

 

 

  

 

 

 

Total utility interest charges

   43,992   43,711   46,675 
  

 

 

  

 

 

  

 

 

 

Net Income

  $113,568  $141,954  $122,824 
  

 

 

  

 

 

  

 

 

 

Average Shares of Common Stock:

    

Basic

   72,056   72,275   73,171 

Diluted

   72,266   72,525   73,461 

Earnings Per Share of Common Stock:

    

Basic

  $1.58  $1.96  $1.68 

Diluted

  $1.57  $1.96  $1.67 

See notes to consolidated financial statements.


38


Piedmont Natural Gas Company, Inc.

For the Years Ended October 31, 2008, 20072011, 2010 and 2006

             
  2008  2007  2006 
  In thousands 
 
Cash Flows from Operating Activities:            
Net income $110,007  $104,387  $97,189 
             
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation and amortization  97,637   93,355   94,111 
Amortization of investment tax credits  (358)  (434)  (534)
Allowance for doubtful accounts  522   (695)  51 
Gain on sale of land  (711)      
Allowance for funds used during construction        (3,893)
Income from equity method investments  (27,718)  (37,156)  (29,917)
Distributions of earnings from equity method investments  34,060   27,884   28,442 
Deferred income taxes  28,370   23,854   22,021 
Stock-based compensation expense  338   336    
Changes in assets and liabilities:            
Receivables  (12,685)  14,892   19,395 
Inventories  (60,139)  7,743   12,791 
Amounts due from customers  (105,710)  13,599   (37,474)
Settlement of legal asset retirement obligations  (1,358)  (1,660)   
Overfunded postretirement asset  29,459   (36,256)   
Regulatory asset for postretirement benefits  (26,867)  (1,786)   
Other assets  (5,469)  (351)  7,581 
Accounts payable  (8,617)  13,069   (94,095)
Amounts due to customers  (162)  39   (17,001)
Regulatory liability for postretirement benefits  (13,504)  13,876    
Accumulated provision for postretirement benefits  (1,212)  17,469    
Other liabilities  33,319   (18,664)  5,146 
             
Total adjustments  (40,805)  129,114   6,624 
             
Net cash provided by operating activities  69,202   233,501   103,813 
             
Cash Flows from Investing Activities:            
Utility construction expenditures  (181,001)  (135,231)  (204,116)
Allowance for funds used during construction  (4,002)  (3,799)   
Reimbursements from bond fund        15,955 
Contributions to equity method investments  (10,917)  (12,914)  (23,696)
Distributions of capital from equity method investments  98   344   28,968 
Proceeds from sale of land and buildings  13,159       
Decrease (increase) in restricted cash  2,196   (2,211)  13,108 
Other  3,090   5,576   2,227 
             
Net cash used in investing activities  (177,377)  (148,235)  (167,554)
             
Cash Flows from Financing Activities:            
Increase in notes payable, net of expenses of $405 in 2006  211,000   25,500   11,095 
Proceeds from issuance of long-term debt, net of expenses        193,360 
Retirement of long-term debt  (626)  (113)  (35,000)
Expenses related to the issuance of long-term debt  (10)  (5)   
Expenses related to expansion of the short-term facility  (113)      
Issuance of common stock through dividend reinvestment and employee stock plans  15,591   15,782   18,377 
Repurchases of common stock  (42,678)  (54,240)  (50,163)
Dividends paid  (75,513)  (73,561)  (72,107)
             
Net cash provided by (used in) financing activities  107,651   (86,637)  65,562 
             
Net Increase (Decrease) in Cash and Cash Equivalents  (524)  (1,371)  1,821 
Cash and Cash Equivalents at Beginning of Year  7,515   8,886   7,065 
             
Cash and Cash Equivalents at End of Year $6,991  $7,515  $8,886 
             
Cash Paid During the Year for:            
Interest $63,769  $63,703  $54,669 
Income taxes  29,281   27,423   56,615 
             
Noncash Investing and Financing Activities:            
Accrued construction expenditures $1,340  $741  $2,837 
Guaranty  101   485   1,820 
See notes to consolidated financial statements.


39

2009


In thousands

  2011  2010  2009 

Cash Flows from Operating Activities:

    

Net income

  $113,568  $141,954  $122,824 

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

   107,046   102,776   102,592 

Amortization of investment tax credits

   (141  (277  (204

Allowance for doubtful accounts

   418   (61  (76

Gain on sale of interest in equity method investment, net of tax

   —      (30,286  —    

Net gain on sale of property

   —      (89  (495

Income from equity method investments

   (24,027  (28,854  (33,464

Distributions of earnings from equity method investments

   22,685   28,834   23,954 

Deferred income taxes, net

   76,962   21,831   81,468 

Changes in assets and liabilities:

    

Gas purchase derivatives, at fair value

   47   (30,863  18,741 

Receivables

   (3,019  23,493   25,018 

Inventories

   13,789   2,565   87,953 

Amounts due from/to customers

   26,304   133,794   (14,385

Settlement of legal asset retirement obligations

   (1,493  (1,141  (1,480

Overfunded postretirement asset

   (5,537  (17,342  6,797 

Regulatory asset for postretirement benefits

   (16,298  12,130   (48,173

Other assets

   972   18,184   (13,573

Accounts payable

   (4,085  (3,007  (22,154

Regulatory liability for postretirement benefits

   —      —      (372

Provision for postretirement benefits

   (134  (16,836  15,384 

Other liabilities

   4,188   3,706   (6,085
  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

   311,245   360,511   344,270 
  

 

 

  

 

 

  

 

 

 

Cash Flows from Investing Activities:

    

Utility construction expenditures

   (243,641  (199,059  (129,006

Allowance for funds used during construction

   (8,619  (9,981  (2,298

Contributions to equity method investments

   (6,222  —      (862

Distributions of capital from equity method investments

   3,029   18,260   32 

Proceeds from sale of interest in equity method investment

   —      57,500   —    

Proceeds from sale of property

   1,074   1,653   748 

Investments in marketable securities

   (486  (498  (380

Other

   2,292   3,554   2,154 
  

 

 

  

 

 

  

 

 

 

Net cash used in investing activities

   (252,573  (128,571  (129,612
  

 

 

  

 

 

  

 

 

 

Piedmont Natural Gas Company, Inc.
Cash Flows

For the Years Ended October 31, 2008, 20072011, 2010 and 2006

                     
           Accumulated
    
           Other
    
  Common
  Paid-in
  Retained
  Comprehensive
    
  Stock  Capital  Earnings  Income (Loss)  Total 
  In thousands except per share amounts 
 
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 
                     
Comprehensive Income:                    
Net income          104,387       104,387 
Other comprehensive income:                    
Minimum pension liability, net of tax of $18              24     
Unrealized gain from hedging activities of equity method investments, net of tax of $314              578     
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($762)              (1,276)  (674)
                     
Total comprehensive income                  103,713 
Adjustment to initially apply Statement 158, net of tax              54   54 
Common Stock Issued  19,046               19,046 
Common Stock Repurchased  (54,240)              (54,240)
Share-Based Compensation Expense      336           336 
Dividends — Incentive Compensation Plan      10   (10)       
Tax Benefit from Dividends Paid on ESOP Shares          101       101 
Dividends Declared ($.99 per share)          (73,561)      (73,561)
                     
Balance, October 31, 2007  497,570   402   379,682   720   878,374 
                     
Comprehensive Income:                    
Net income          110,007       110,007 
Other comprehensive income:                    
Unrealized gain from hedging activities of equity method investments, net of tax of $891              1,399     
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($922)              (1,449)  (50)
                     
Total comprehensive income                  109,957 
Common Stock Issued  16,673               16,673 
Common Stock Repurchased  (42,678)              (42,678)
Share-Based Compensation Expense      338           338 
Dividends — Incentive Compensation Plan      23   (23)       
Tax Benefit from Dividends Paid on ESOP Shares          93       93 
Dividends Declared ($1.03 per share)          (75,513)      (75,513)
                     
Balance, October 31, 2008 $471,565  $763  $414,246  $670  $887,244 
                     
2009

In thousands

  2011  2010  2009 

Cash Flows from Financing Activities:

    

Borrowings under bank debt

   1,723,000   1,058,000   1,075,000 

Repayments under bank debt

   (1,634,000  (1,122,000  (1,175,500

Proceeds from issuance of long-term debt

   200,000   —      —    

Retirement of long-term debt

   (256,922  (60,590  (31,749

Expenses related to issuance and reacquiring of debt

   (3,902  (46  —    

Issuance of common stock through dividend reinvestment and employee stock plans

   20,233   19,099   14,435 

Repurchases of common stock

   (23,004  (47,295  (17,857

Dividends paid

   (82,913  (80,255  (78,370

Other

   (6  (792  (50
  

 

 

  

 

 

  

 

 

 

Net cash used in financing activities

   (57,514  (233,879  (214,091
  

 

 

  

 

 

  

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

   1,158   (1,939  567 

Cash and Cash Equivalents at Beginning of Year

   5,619   7,558   6,991 
  

 

 

  

 

 

  

 

 

 

Cash and Cash Equivalents at End of Year

  $6,777  $5,619  $7,558 
  

 

 

  

 

 

  

 

 

 

Cash Paid During the Year for:

    

Interest

  $50,136  $56,554  $61,050 

Income Taxes:

    

Income taxes paid

   5,649   32,305   51,132 

Income taxes refunded

   16,958   1,845   345 
  

 

 

  

 

 

  

 

 

 

Income taxes, net

  $(11,309 $30,460  $50,787 
  

 

 

  

 

 

  

 

 

 

Noncash Investing and Financing Activities:

    

Accrued construction expenditures

  $18,055  $3,225  $1,305 

Guaranty

   —      1,234   —    

See notes to consolidated financial statements.

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2011, 2010 and 2009

In thousands except per share amounts

  Common
Stock
  Paid-in
Capital
  Retained
Earnings
  Accumulated
Other
Comprehensive
Income (Loss)
  Total 

Balance, October 31, 2008

  $471,565  $763  $414,246  $670  $887,244 
      

 

 

 

Comprehensive Income:

      

Net income

     122,824    122,824 

Other comprehensive income:

      

Unrealized gain from hedging activities of equity method investments, net of tax of ($3,886)

      (6,032  (6,032

Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,879

      2,915   2,915 
      

 

 

 

Total comprehensive income

       119,707 

Common Stock Issued

   17,861      17,861 

Common Stock Repurchased

   (17,857     (17,857

Share-Based Compensation Expense

    (730    (730

Dividends - Incentive Compensation Plan

    (33  33    —    

Tax Benefit from Dividends Paid on ESOP Shares

     93    93 

Dividends Declared ($1.07 per share)

     (78,370   (78,370
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, October 31, 2009

   471,569   —      458,826   (2,447  927,948 
      

 

 

 

Comprehensive Income:

      

Net income

     141,954    141,954 

Other comprehensive income:

      

Unrealized gain from hedging activities of equity method investments, net of tax of ($52)

      (88  (88

Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,291

      2,005   2,005 
      

 

 

 

Total comprehensive income

       143,871 

Common Stock Issued

   21,366      21,366 

Common Stock Repurchased

   (47,276     (47,276

Rescission Offer

   (19     (19

Costs of Rescission Offer

     (792   (792

Tax Benefit from Dividends Paid on ESOP Shares

     98    98 

Dividends Declared ($1.11 per share)

     (80,255   (80,255
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, October 31, 2010

   445,640   —      519,831   (530  964,941 
      

 

 

 

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2011, 2010 and 2009

In thousands except per share amounts

  Common
Stock
  Paid-in
Capital
   Retained
Earnings
  Accumulated
Other
Comprehensive
Income (Loss)
  Total 

Comprehensive Income:

         

Net income

      113,568      113,568 

Other comprehensive income:

         

Unrealized gain from hedging activities of equity method investments, net of tax of ($371)

         (576  (576

Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $420

         654   654 
         

 

 

 

Total comprehensive income

          113,646 

Common Stock Issued

   24,155         24,155 

Common Stock Repurchased

   (23,004        (23,004

Costs of Rescission Offer

      (6     (6

Tax Benefit from Dividends Paid on ESOP Shares

      104      104 

Dividends Declared ($1.15 per share)

      (82,913     (82,913
  

 

 

  

 

 

   

 

 

    

 

 

  

 

 

 

Balance, October 31, 2011

  $446,791  $—      $550,584    $(452 $996,923 
  

 

 

  

 

 

   

 

 

    

 

 

  

 

 

 

The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 20082011 and 20072010 are as follows.

         
  2008  2007 
  In thousands 
 
Hedging activities of equity method investments $670  $720 

In thousands

  2011  2010 

Hedging activities of equity method investments

  $(452 $(530

See notes to consolidated financial statements.


40


Piedmont Natural Gas Company, Inc.
1.  Summary of Significant Accounting Policies
A.  Operations and Principles of Consolidation.

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation 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, and regulated 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 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly owned subsidiaries.subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, 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.sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. 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 1012 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. 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 Statementaccounting regulations prescribed under rate-based regulation.

We monitor significant events occurring after the balance sheet date and prior to the issuance of Financialthe financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware have been evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.

Use of Estimates

The consolidated financial statements of Piedmont have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Segment Reporting

Our segments are based on the components of the company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision making activities. We evaluate the performance of the regulated utility 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.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the gas distribution business, including the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. See Note 14 for further discussion of segments.

Rate-Regulated Basis of 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 providesThe accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71,these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods.

Our regulatory assets are recoverable through either base rates or rate riders or base rates specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings. In the event that accounting for the provisionseffects of Statement 71regulation were no longer applicable, we would recognize a write-off of netthe regulatory assets (regulatory assets lessand regulatory liabilities)liabilities that would result in a chargean adjustment to net income. Although the natural gas distribution industry is becoming increasingly competitive, ourOur utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under Statement 71rate-based regulation remains appropriate. It is also our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a future rate recovery proceeding.


41

proceedings.


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 20082011 and 20072010 are as follows.
         
  2008  2007 
  In thousands 
 
Regulatory Assets:        
Unamortized debt expense $9,915  $10,565 
Amounts due from customers  181,745   76,035 
Environmental costs*  5,819   4,223 
Demand-side management costs*  1,608   2,631 
Deferred operations and maintenance expenses*  9,301   9,286 
Deferred pipeline integrity expenses*  6,008   4,417 
Deferred pension and other retirement benefits costs*  12,558   11,146 
FAS 158 pension and other retirement benefits costs*  28,732   1,865 
Regulatory cost of removal asset  6,398   11,939 
Other*  1,121   1,866 
         
Total $263,205  $133,973 
         
Regulatory Liabilities:        
Regulatory cost of removal obligations $359,302  $334,079 
Amounts due to customers     162 
Deferred income taxes  24,316   25,463 
FAS 158 pension and other retirement benefits costs  66   13,876 
Environmental liability due customers*     386 
         
Total $383,684  $373,966 
         
presented below.

In thousands

  2011   2010 

Regulatory Assets:

    

Unamortized debt expense

  $11,315   $8,576 

Amounts due from customers

   38,649    62,336 

Environmental costs *

   9,644    7,960 

Deferred operations and maintenance expenses *

   7,676    8,258 

Deferred pipeline integrity expenses *

   7,927    6,728 

Deferred pension and other retirement benefits costs *

   22,119    18,783 

Amounts not yet recognized as a component of pension and other retirement benefits costs

   81,073    64,775 

Regulatory cost of removal asset

   19,336    17,825 

Other *

   2,396    2,531 
  

 

 

   

 

 

 

Total

  $200,135   $197,772 
  

 

 

   

 

 

 

Regulatory Liabilities:

    

Regulatory cost of removal obligations

  $438,605   $412,776 

Amounts due to customers

   2,617    —    

Deferred income taxes*

   25,731    26,299 
  

 

 

   

 

 

 

Total

  $466,953   $439,075 
  

 

 

   

 

 

 

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

As of October 31, 2008,2011, we had regulatory assets totaling $6.2$.5 million on which we do not earn a return during the recovery period. The original amortization periodsperiod for these assets range from 3 tois 15 years and, accordingly, $.1 million will be fully amortized by 2010, $5.4 million will be fully amortized by 2011 and the remaining $.7$.5 million will be fully amortized by 2018. We have $55.9$4.5 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $28.7$81.1 million of regulatory postretirement assets, and $6.4$19.3 million of asset retirement obligations (AROs) and $9.6 million of estimated environmental costs on which we do not earn a return.

C.  Utility Plant and Depreciation.
Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

Utility Plant and Depreciation

Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, and pensions and insurance, and an allowance for funds used during construction (AFUDC). that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the cost of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery through rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in Other Income (Expense) in the consolidated statements of income.

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the consolidated statements of income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the consolidated statements of income. The costs of property retired are removed from utility plant and charged to accumulated depreciation.

AFUDC for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.

             
  October 31 
  2008  2007  2006 
  In thousands 
 
AFUDC $4,002  $3,799  $3,893 


42


In thousands

  2011   2010   2009 

AFUDC

  $8,619    $9,981    $2,298  

In accordance with utility accounting practice, we have classified expenditures associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina that has been delayed due to current economic conditions as “Plant held for future use” in the consolidated balance sheets. Another project under construction will create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The timing and design scope of the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate and such costs, approximately half being land purchase and preparation, will be moved to any such future project.

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
We compute depreciation expense using the straight-line method over periods ranging from four4 to 88 years. The composite weighted-average depreciation rates were 3.23%3.19% for 2008, 3.23%2011, 3.20% for 20072010 and 3.46%3.25% for 2006.
2009.

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. Our last depreciation study was completed in 2004, and new depreciation rates were approved effective November 1, 2005.file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina. We collect throughhave proposed the implementation of the new depreciation rates thein Tennessee beginning March 1, 2012. We anticipate new rates to become effective in North Carolina in connection with our next general rate case filing.

The estimated costs of removal on certain regulated properties are collected through depreciation expense through rates, with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we accrue estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rates.

D.  Asset Retirement Obligations.
SFAS No. 143, “Accounting for Asset Retirement Obligations” (AROs) (Statement 143), addressesrate.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the financial accounting and reporting for AROs associated with the retirementstatements of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires the recognition of the fair value of a liability for an ARO in the period in which the liability is incurred if a reasonable estimate of fair value can be made.cash flows. We have determined that AROs exist for our underground mains and 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, as stated above. 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 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.
In 2006, we applied Financial Accounting Standards Board (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires recognition of a liability for the fair value of a conditional ARO when incurred if the liability can be reasonably estimated. An ARO will be capitalized concurrently by increasing the carrying amount of the related asset by the same amount of the liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle the conditional ARO must be recognized. Any accretion will not be reflected in the income statement as we have received regulatory treatment for deferral as a regulatory asset with netting against a regulatory liability. We have recorded a liabilityno restrictions on our distribution and transmission mains and services.


43


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
The costcash balances that would impact the payment of removal obligations recorded in our consolidated balance sheetsdividends as of October 31, 20082011 and 2007 are shown below.
         
  2008  2007 
  In thousands 
 
Regulatory non-legal asset removal obligations $359,302  $334,079 
Conditional asset retirement obligations  8,148   17,659 
         
Total cost of removal obligations $367,450  $351,738 
         
A reconciliation of the changes in the FIN 47 conditional ARO2010.

Trade Accounts Receivable and Allowance for the year ended October 31, 2008 and 2007 is presented below.

         
  2008  2007 
  In thousands 
 
Beginning of period $17,659  $19,115 
Liabilities incurred during the period  2,004   2,564 
Liabilities settled during the period  (1,358)  (1,660)
Accretion  1,104   1,102 
Adjustment to estimated cash flows*  (11,261)  (3,462)
         
End of period $8,148  $17,659 
         
*Adjustment is primarily due to the change in the credit adjusted risk-free rate from 5.78% as of October 31, 2006 to 6.24% as of October 31, 2007 to 8.62% as of October 31, 2008.
E.  Trade Accounts Receivable and Allowance for Doubtful Accounts.
Doubtful Accounts

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. 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. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the North Carolina Utilities Commission (NCUC), and the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover all uncollected gas costs through the purchased gas cost deferral account.adjustment (PGA). 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. MerchandiseIn Tennessee, 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 Actual Cost Adjustment (ACA) filings; if the difference is greater, there would be a charge to customers through the ACA filing. Non-regulated merchandise and service work receivables due beyond one year are included in “Other”“Other noncurrent assets” in “Investments, Deferred Charges and Other“Noncurrent Assets” in the consolidated balance sheets.

We are exposed to credit risk when we enter into contracts with third parties to sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our internal credit policies require counterparties to have an investment-grade credit rating at the time of the contract. Where the counterparty does not have an investment-grade credit rating, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. We continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2011 and 2010, our trade accounts receivable consisted of the following.

In thousands

  2011  2010 

Gas receivables

  $55,928  $60,823 

Non-regulated merchandise and service work receivables

   2,454   2,476 

Allowance for doubtful accounts

   (1,347  (929
  

 

 

  

 

 

 

Trade accounts receivable

  $57,035  $62,370 
  

 

 

  

 

 

 

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2008, 20072011, 2010 and 20062009 is as follows.

             
  2008  2007  2006 
  (In thousands) 
 
Balance at beginning of year $544  $1,239  $1,188 
Additions charged to uncollectibles expense  5,308   4,981   4,706 
Accounts written off, net of recoveries  (4,786)  (5,676)  (4,655)
             
Balance at end of year $1,066  $544  $1,239 
             


44

presented below.


In thousands

  2011  2010  2009 

Balance at beginning of year

  $929  $990  $1,066 

Additions charged to uncollectibles expense

   4,842   4,886   5,570 

Accounts written off, net of recoveries

   (4,424  (4,947  (5,646
  

 

 

  

 

 

  

 

 

 

Balance at end of year

  $1,347  $929  $990 
  

 

 

  

 

 

  

 

 

 

Inventories

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
F.  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 arise during the year. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value.
Our annual goodwill impairment assessment was performed at October 31, 2008, and we determined that there was no impairment to the carrying value of our goodwill. No impairment has been recognized during the years ended October 31, 2008, 2007 and 2006.
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, 2008, 2007 and 2006 that resulted in any impairment charges. For further information on equity method investments, see Note 10 to the consolidated financial statements.
G.  Unamortized Debt Expense.
Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant 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.
H.  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.

We utilize asset management agreements with counterparties for certain natural gas storage and transportation assets. At October 31, 2008,2011 and 2010, such counterparties held natural gas storage assets, included in “Prepayments” in the consolidated balance sheets, with a value of $77.4$35.8 million and $36.6 million, respectively, through capacity release and agency relationships. Under the terms of the asset management agreements, we receive capacity and storage asset management fees.fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The asset management agreements expire at various times through April 30, 2009.

March 31, 2014. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

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

I.  Deferred Purchased Gas Adjustments.

Fair Value Measurements

Effective November 1, 2009, we adopted the additional authoritative guidance related to nonrecurring fair value guidance for certain nonfinancial assets and liabilities and the use of fair value in the impairment testing of goodwill, intangible assets and long-lived assets. In February 2010, we adopted the amended fair value guidance, which clarified disclosure requirements for fair value measurements and requires disclosure of transfers between Levels 1, 2 or 3. The adoption of the additional fair value guidance had no material impact on our financial position, results of operations or cash flows.

The carrying values of cash and cash equivalents, receivables, bank debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the consolidated balance sheets in accordance with derivative accounting standards and marketable securities, classified as trading securities, that are held in a rabbi trust established for our deferred compensation plans. Our pension and postretirement plan assets and liabilities are recorded at fair value in the consolidated balance sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level into the following fair value hierarchy levels as set forth in the fair value guidance.

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities hedge fund of funds, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and valuation policies and procedures.

Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining

life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a hedge fund of funds, diversified private equity fund of funds and commodities hedge fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.

Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as a Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the end of the reporting period.

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

Goodwill, Equity Method Investments and Long-Lived Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

We early adopted the accounting guidance issued September 2011 that simplifies how an entity tests goodwill for impairment. As part of our qualitative assessment, we considered macroeconomic conditions such as a general deterioration in economic condition, limitations on accessing capital, and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any change in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors such as increases in utility construction expenditures, labor, or other costs that would have a negative effect on earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility segment which would have a negative effect on the carrying value of the reporting unit.

Based on a qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2011. Annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment has been recognized during the years ended October 31, 2011, 2010 and 2009.

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, 2011, 2010 and 2009 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in a rabbi trust established for our deferred compensation plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in a rabbi trust. Trading securities are recorded at fair value on the consolidated balance sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. Any participant’s account that exceeds $25,000 will be paid over five years upon retirement. A lesser amount will be paid upon retirement in a lump sum. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in the consolidated balance sheets.

The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2011 and 2010 is as follows.

In thousands

  2011   2010 
   Cost   Fair Value   Cost   Fair Value 

Current trading securities:

        

Money markets

  $—      $—      $—      $—    

Mutual funds

   47    52    4    5 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current trading securities

   47    52    4    5 
  

 

 

   

 

 

   

 

 

   

 

 

 

Noncurrent trading securities:

        

Money markets

   217    217    254    254 

Mutual funds

   1,107    1,222    618    743 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total noncurrent trading securities

   1,324    1,439    872    997 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total trading securities

  $1,371   $1,491   $876   $1,002 
  

 

 

   

 

 

   

 

 

   

 

 

 

Unamortized Debt Expense

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term 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 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is three years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

Issuances and Repurchases of Common Stock

As discussed in Note 6 to the consolidated financial statements, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares. Currently, it is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.

Asset Retirement Obligations

The accounting guidance for AROs addresses the 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 assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that AROs exist for our underground mains and 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 the accounting guidance. Because these estimated removal costs meet the requirements of rate regulated accounting guidance, we have accounted for these non-legal AROs as a regulatory liability. We record the estimated non-legal AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in our 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.

In 2006, we applied the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. At the same time, the NCUC, the PSCSC and the TRA approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs. AROs will be capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. In periods subsequent to the initial measurement, any changes in the

liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.5% to 5.87% with a weighted average of 5.86% for the twelve months ended October 31, 2011. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. Any accretion will not be reflected in the income statement as we have received regulatory treatment for deferral as a regulatory asset with netting against a regulatory liability. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in our consolidated balance sheets as of October 31, 2011 and 2010 are presented below.

In thousands

  2011   2010 

Regulatory non-legal AROs

  $438,605   $412,776 

Conditional AROs

   27,395    23,296 
  

 

 

   

 

 

 

Total cost of removal obligations

  $466,000   $436,072 
  

 

 

   

 

 

 

A reconciliation of the changes in conditional AROs for the year ended October 31, 2011 and 2010 is presented below.

In thousands

  2011  2010 

Beginning of period

  $23,295  $23,331 

Liabilities incurred during the period

   3,102   137 

Liabilities settled during the period

   (1,493  (1,141

Accretion

   1,365   1,350 

Adjustment to estimated cash flows

   1,126   (382
  

 

 

  

 

 

 

End of period

  $27,395  $23,295 
  

 

 

  

 

 

 

Revenue Recognition

We record revenues when services are provided to our distribution service customers. 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. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March. The WNA is designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. In North Carolina, a year around margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism.

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, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanism, as applicable.

Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

Utility sales, transportation and secondary market revenues are reported on a net of tax basis. For further information regarding taxes, see “Taxes” in this Note 1 to the consolidated financial statements.

Cost of Gas and Deferred Purchased Gas Adjustments

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include purchased gas adjustment (PGA)PGA provisions that provide for the recovery of prudently incurred and allocated gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Under PGA provisions, charges to cost of gas are based on the amount 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.


45


We charge our secondary market customers for natural gas based on specified contract terms. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives.

Taxes

Piedmont Natural Gas Company, Inc.
NotesWe have two categories of income taxes in our consolidated statements of income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to Consolidated Financial Statements — (Continued)
J.  Taxes.
the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities in accordance with SFAS No. 109, “Accounting for Income Taxes,” and FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). Deferred taxes are primarily attributable to utility plant, equity method investments and revenues and cost of gas.liabilities. 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,in accordance with rate-regulated accounting provisions, 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.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in our consolidated balance sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions in operating expenses in the consolidated statements of income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use, public utility fees and other miscellaneous taxes.

K.  Revenue Recognition.
Utility sales and transportation revenues

Consolidated Statements of Cash Flows

With respect to cash overdrafts, book overdrafts 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. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter period November through March. The WNA is designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter season. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism.

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 or margin decoupling mechanism, as applicable.
Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices. See Note 2 regarding revenue sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported on a net basis. For further information, see Note 1.J to the consolidated financial statements.


46


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
L.  Earnings Per Share.
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2008, 2007 and 2006 is presented below.
             
  2008  2007  2006 
  In thousands except per share amounts 
 
Net Income $110,007  $104,387  $97,189 
             
Average shares of common stock outstanding for basic earnings per share  73,334   74,250   75,863 
Contingently issuable shares under the Executive Long-Term Incentive Plan and Incentive Compensation Plan  278   222   293 
             
Average shares of dilutive stock  73,612   74,472   76,156 
             
Earnings Per Share:            
Basic $1.50  $1.41  $1.28 
Diluted $1.49  $1.40  $1.28 
M.  Statements of Cash Flows.
For purposes of reportingincluded within operating cash flows we consider instruments purchasedwhile any bank overdrafts are included with an original maturity at date of purchase of three months or less to befinancing cash equivalents.
N.  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.
O.  Recently Issued Accounting Standards.
flows.

Recently Issued Accounting Guidance

In September 2006,June 2009, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhancedamended accounting guidance for using fair value to measure assetseliminate the quantitative approach that entities use to determine whether an entity has a controlling financial interest in a variable interest entity (VIE) and liabilities and applies whenever other standardsto require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based onwith a variable interest in a VIE qualitatively assess whether it has a controlling financial interest, and if so, determine whether it is the assumptions market participants would useprimary beneficiary. The guidance requires companies to continually evaluate the VIE for consolidation, rather than performing the assessment only when pricingspecific events occur. It also requires enhanced disclosures to provide more information about the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizesentity’s involvement with the information used to develop those assumptions into three levels as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date.
��• Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data.
• Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.


47


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options under our gas hedging plans.
In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. Statement 157VIE. The guidance is effective for fiscal periods beginning after November 15, 2009. Our adoption of this guidance on consolidation of VIEs, effective November 1, 2010, had no impact on our financial statementsposition, results of operations or cash flows. For information regarding disclosures related to variable interests in unconsolidated VIEs, see Note 13 to the consolidated financial statements.

In January 2010, the FASB issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements. The guidance will be effective for interim periods for fiscal years beginning after NovemberDecember 15, 2007,2010. We will adopt the guidance for Level 3 disclosure for recurring and interim periods within those fiscal years, with earlier application encouraged for financial assets and liabilities, as well as for any other assets and liabilities that are carried atnon-recurring items covered under the fair value on a recurring basis. Accordingly, we will adopt Statement 157guidance for the first quarter of our fiscal year beginning November 1, 2008 withending October 31, 2012. Since the exception of the application of the provisionguidance addresses only disclosures related to nonfinancial assets and liabilities. Thefair value measurements under Level 3, the adoption of Statement 157this guidance will not have a material impact on our financial position, results of operations or cash flows.

In April 2007,July 2010, the FASB issued FSPFIN 39-1accounting guidance to amend paragraph 3improve disclosures about the credit quality of FIN 39, “Offsettingan entity’s financing receivables and the reserves held against them. End of Amounts Related to Certain Contracts,” to replacereporting period disclosures are required for the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133).reporting period ending on or after December 15, 2010. The FSP amends paragraph 10 of FIN 39 to permitdisclosures about activity that occurred during a reporting entity to offset fair value amounts recognizedperiod were effective for interim and annual periods beginning on or after December 15, 2010. We adopted the guidance for the rightend of period disclosures as of January 31, 2011, and the guidance for the disclosures related to reclaim cash collateral oractivity in the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 forreporting period during our fiscal yearsecond quarter beginning NovemberFebruary 1, 2008. Our policy has been2011. Since the guidance addresses only disclosures related to present our positions, exclusivecredit quality of any receivable or payable, withfinancing receivables and the same counterparty onallowance for credit losses, the adoption of this guidance did not have a net basis; however, we will elect “not to net” under FSPFIN 39-1 and will reflect minor reclassificationsmaterial impact on our statement of financial position.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquistion contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (Statement 159). Statement 159 provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to elect the option to measure any applicable financial assets or liabilities at fair value pursuant to the provisions of Statement 159.
In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and


48


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations andor cash flows. Statement 161 also amended SFAS 107, “Disclosures about Fair Value

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Instruments” (Statement 107),Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that derivative instrumentsU.S. GAAP and IFRS fair value measurement and disclosure requirements are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 isdescribed in the same way. The guidance will be effective for financial statements issued for fiscal yearsinterim and interimannual periods beginning after NovemberDecember 15, 2008, with early2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. We do not expect the adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities,of this standard is not expectedguidance to have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of OCI in financial statements. The guidance gives businesses two options for presenting OCI. An OCI statement can be included with the statement of operations, and together the two will comprise the statement of comprehensive income. Alternatively, businesses can present a separate OCI statement, but that statement must appear consecutively with the statement of operations within the financial report. The guidance will be effective for interim and annual periods beginning after December 15, 2011. In October 2011, the FASB tentatively decided to indefinitely defer the provisions to require entities to present the adjustment of items reclassified from OCI to net income in both net income and OCI. We will adopt Statement 161 on February 1, 2009.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchyunaffected provisions of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifiesOCI presentation guidance for the sourcessecond quarter of accounting principles and the framework for selecting the principles used in the preparationour fiscal year ending October 31, 2012. The adoption of financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature established by the FASB. Statement 162this guidance will be effective sixty days following the Securities and Exchange Commission (SEC) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have anyno impact on our financial position, results of operations or cash flows. We will adopt Statement 162 whenintend to present net income and other comprehensive income in one continuous statement.

In September 2011, the FASB issued accounting guidance to simplify how an entity tests goodwill for impairment. An entity is allowed an option to first assess qualitative factors to determine whether it becomes effective.

2.  Regulatory Matters
is more likely than not (greater than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step quantitative impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. This guidance, which we early adopted for our goodwill assessment performed for October 31, 2011, is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

2. Regulatory Matters

Our utility operations are regulated by the NCUC, PSCSC and 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 long-term debt and equity securities.

In April 2005, we filed

The NCUC and the PSCSC regulate our gas purchasing practices under a general rate case with the NCUC requestingstandard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a consolidationgas supply incentive program which compares our actual costs to market pricing benchmarks. As part of the respective rate bases, revenues and expenses of Piedmont,this jurisdictional oversight, all three states address our gas supply hedging activities. Additionally, North Carolina Natural Gas Corporation (NCNG) and Eastern NorthSouth Carolina Natural Gas Company (EasternNC). In addition to a unified and uniform rate structureallow 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 consolidationand/or amortization of certain deferred accounts, changes to cost allocations and rate design including a 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 PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense. In Tennessee, to the extent that the gas cost deferred account.

In November 2005, the NCUC issued an order in this general rate case proceeding establishing a margin decoupling mechanism that provides for the recoveryportion of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism was experimentalnet write-offs for a three-year period, subjectfiscal year is less than the gas cost portion included in base rates, the difference would be refunded to review and approval for extension incustomers through the ACA filings; if the difference is greater, there would be a future general rate case proceeding. The margin decoupling mechanism, which replaced our WNA mechanism that adjusted margins for weather, has been operating for three years and reconciles our margin earned each month. We file for semi-annual rate adjustmentscharge to refund any over-collection of margin or recover any under-collection of margin. Each of these rate adjustments has been approved bycustomers through the NCUC.
Under the NCUC’s orders and the terms of a settlement with the ACA filing.

North Carolina Attorney General for the three years of the experimental margin decoupling program, we allocated $500,000 to energy conservation program funding and shared the first $3 million of the margin adjustment that was non-weather related. Annually, the first $3 million of non-weather related amounts will be allocated 25% to customer rate reduction, 25% to energy conservation program funding and 50% to us. Since the inception of the program on November 1, 2005, we have incurred charges of $6.3 million for the benefit of residential and commercial customers. The charges consist of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.3 million


49

Jurisdiction


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
for interest accruals on the conservation funding and reduction of customer rates. The conservation programs are subject to review and approval by the NCUC. At October 31, 2008 and 2007, we had liabilities for the conservation programs of $1.3 million and $1.5 million, respectively.
In March 2008, we filed a general rate case proceeding with the NCUC requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $40.5 million, or 4% above the current annual revenues. In October 2008, the NCUC approved a settlement between us, the North Carolina Public Staff and all intervening parties with the exception of the North Carolina Attorney General’s office, in which the parties agreed to an annual revenue increase of $15.7 million and the continuation of the margin decoupling mechanism. In addition to the revenue increase, the stipulation also includes cost allocation and rate design changes under our existing rate schedules, approval to implement energy conservation and efficiency programs of $1.3 million annually with appropriate cost recovery mechanisms and changes to the existing service regulations and tariffs. The new rates became effective November 1, 2008.
The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding EasternNCEastern North Carolina Natural Gas Company (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 feasibilityeconomic infeasibility of providing service and 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. WeWith the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% per annum. In December 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 a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005, $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred operations and maintenance expenses was $9 million at October 31, 2008. This balance is being amortized over a twelve-year periodaccruing interest at a rate of 7.84% per annum.

Inannum and is being amortized over a twelve year period. As of October 2004,31, 2011 and 2010, we filedhad unamortized balances of $7.7 million and $8.3 million, respectively.

With the inception of our North Carolina energy conservation program on November 1, 2005, we incurred charges of $6.4 million for the benefit of residential and commercial customers. The charges consisted of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.4 million for interest accruals on the conservation funding and reduction of customer rates. At October 31, 2010, we had a petition withliability for the NCUC seeking deferred accounting treatment forconservation programs of $.4 million and no liability as of October 31, 2011.

We incur 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 thesethe operations and maintenance costs applicable to all incremental expenditures beginning November 1, 2004. As a part of the 2005 general rate case discussed above, the balance of $.4 million in the deferred account as of June 30, 2005, is being amortized over three years beginning November 1, 2005, and subsequent expenditures that total $4.3 million as of October 31, 2007 will continue to be deferred. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million are subject to amortizationwere fully amortized over a three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continuecontinues until another recovery mechanism is established in a future rate proceeding. The unamortized balance as of October 31, 2008 that is not being amortized2011 that is subject to a future rate proceeding is $1.4$8 million.

On February 16, 2005, the Natural Gas Rate Stabilization Act (RSA) of 2005 became effective in South Carolina. The law provides electing natural gas utilities, including Piedmont, with a mechanism for the


50


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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. In April 2005, we filed an election with the PSCSC to adopt this new mechanism.
In June 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 $10.3 million. In September 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 RSA. In September 2006, the PSCSC issued an order approving a $5.6 million increase in margin based on 11.2% return on equity effective November 1, 2006.
In June 2007, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2007 and a cost and revenue study as permitted by the RSA requesting no change in margin. In October 2007, the PSCSC issued an order approving a settlement between us, the ORS and the SCEUC that resulted in a $2.5 million annual decrease in margin based on a return of equity of 11.2%. The new rates were effective November 1, 2007.
In June 2008, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2008 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2007 order. In the filing, we requested an increase in annual margin of $2 million. In October 2008, the PSCSC issued an order approving a settlement between us, the ORS and the SCEUC that resulted in a $1.5 million annual decrease in margin based on a return on equity of 11.2%, effective November 1, 2008.
All three jurisdictions regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. As part of this jurisdictional oversight, all three states address our gas supply hedging activities. Additionally, as detailed below, all three states allow for recovery of uncollectible gas costs through the PGA.
In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. WeCosts have never been found prudent in all past proceedings.
disallowed on the basis of prudence.

In August 2007,February 2010, the NCUC approved our accounting forof gas costs duringfor the twelve months ended May 31, 2006,2009, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 20062009 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In this order the NCUC also required us to discontinue the accounting practice of capitalizing and amortizing storage demand charges, effective no later than November 1, 2007. This action resulted in a margin decrease of $5.4 million in 2007.

During 2007, under the provisions of the August 2007 NCUC order, we recorded as restricted cash $2.2 million, including interest, of supplier refunds. In September 2007, we petitioned the NCUC for authority to liquidate all certificates of deposit and similar investments that held any supplier refunds due to customers. In October 2007, the NCUC approved the transfer of these restricted funds to the North Carolina deferred account. The various certificates of deposit matured by January 31, 2008.
In November 2007,2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2007,2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 20072010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.


51


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In August 2008,2011, we filed testimony in North Carolinawith the NCUC in support of our gas cost purchasing and accounting practices for the period endingtwelve months ended May 31, 2008.2011. A hearing on this matter was held on December 16, 2008.October 4, 2011. We are unable to determinepredict the outcome of thethis proceeding at this time.

Our gas cost hedging plan for North Carolina is designed for the purposeto provide some level of cost stabilization andprotection against significant price increases, targets 30%a percentage range of 22.5% to 60%45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina 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 gain or loss recognition under the hedging program are deemed to be reductionsis a reduction in or additionsan addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The August 2007 gas cost review orderorders issued February 2010 and our November 2007 gas cost review orderJanuary

2011 found our hedging activities during the two review periods to be reasonable and prudent.

Since As part of the February 2010 order, the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” as agreed to by us and the North Carolina Public Staff.

South Carolina Jurisdiction

We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA, the annual filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2009 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2008 order. In October 2009, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2005,2009.

In June 2010, we filed with the NCUC has allowedPSCSC a quarterly monitoring report for the recoverytwelve months ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $.75 million annual increase in margin on a return on equity of all uncollectible gas costs through11.3%, effective November 1, 2010.

In June 2011, we filed with the gasPSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost PGA deferral account. Asand revenue study as permitted by the RSA requesting a result,change in rates from those approved by the portionPSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of uncollectibles related to gas costs is recovered through the deferred account11.3% and only the non-gas costs, or margin, portiona decrease of uncollectibles is included$1.9 million in basedepreciation rates and uncollectibles expense.

for South Carolina utility plant in service, effective November 1, 2011.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. WeCosts have never been found prudent in all past proceedings.

disallowed on the basis of prudence.

In South Carolina, the PSCSC approved a settlement in August 2006 between us, the ORS and the SCEUC accepting our purchased gas adjustments and finding our gas purchasing policies prudent for the twelve months ended March 31, 2006. As part of this settlement, we began recovering uncollectible gas costs through the PGA effective November 1, 2006. In May 2008,2009, the PSCSC approved our purchased gas adjustments and found our gas purchasing policies prudent for the twelve months ended March 31, 2007.

In August 2008, the PSCSC approved our purchased gas adjustmentsPGAs and found our gas purchasing policies to be prudent for the period coveringtwelve months ended March 31, 2009.

In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2008.

2010.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets 30%a percentage range of 22.5% to 60%45% of annual normalized sales volumes for South Carolina and operates 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 gas costs. Any gain or loss recognitionrecognized under the hedging program are deemed to be reductionsis a reduction in or additionsan addition to gas costs, respectively, and are flowedflows through to South Carolina customers in rates.

In February 2011, the ORS requested that the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS’ motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings.

In August 2011, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging. At the PSCSC’s request, the ORS held a public briefing in November 2011 on the issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter.

In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.

Tennessee Jurisdiction

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA)ACA mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. The costs and benefits of hedging instruments and all other gas costs incurred are components of the TIP. 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 requests for proposal. In October 2007, the TRA approved our settlement with the staff of the TRA and the Tennessee Consumer Advocate Staff modifyingmodified our TIP with an effective date of July 1, 2006. The modificationsto clarify and simplify the calculation of allocatedallocating gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio, maintainratio. The TRA also maintained the current $1.6 million annual incentive cap for us on gains and losses, improveimproved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provideprovided for a triennial review of TIP operations by an independent consultant.


52


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
We haveIn December 2008, we filed an annual report for the twelve months ended December 31, 20062007 with the TRA that reflectsreflected the transactions in the deferred gas cost account for the ACA mechanism. In June 2008,April 2009, the TRA staff filed its final audit report, with which we concurred. In August 2008,

May 2009, the TRA issued an order adopting all findings from the staff audit. The order includesincluded cost of gas adjustments for the calendar year 20062007 review period. There was no material impact from these gas cost adjustments.

adjustments on our financial position, results of operations or cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.

In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments to our financial position, results of operations or cash flows. In October 2010, the TRA issued its order adopting the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report.

In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA issued an order approving the deferred gas cost account.

In September 2010, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.

In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. We are unable to predict the outcome of this proceeding at this time.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are unable to predict the outcome of this proceeding at this time.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 2003,1, 2012. A hearing on this matter has been scheduled for the week of January 23, 2012. We are unable to predict the outcome of this proceeding at this time.

In February 2010, we alongfiled a petition with two other natural gas companiesthe TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005,

which would deny recovery of $1.5 million for us. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in Tennessee,operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

In September 2010, we filed a petition with the TRA requesting deferred accounting treatment for the direct, incremental expenses incurred as a declaratory order that the gas cost portionresult of uncollectible accounts be recovered through PGA procedures. We requested thatour response to the extent thatsevere flooding in Nashville in May 2010. The TRA approved our petition in October 2010. The balance in the gas cost portiondeferred account is $1 million as of net write-offs for a fiscal year is less thanOctober 31, 2011 and 2010. We are seeking recovery of these deferred expenses in the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings. With TRA approval, this methodology was used on an experimental basis for two years. In August 2006,general rate application filed with the TRA approved the methodology permanently.

in September 2011.

All Jurisdictions

Due to the seasonal nature of our business, 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 sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million.

We filed petitions with In all three jurisdictions for the NCUC, the PSCSC and the TRA in September 2006 for authorization to place certain ARO costs in deferred accounts so that the regulatory treatment for these costs will not be altered due to our adoption of FIN 47. The petitions were approved in all of the jurisdictions in November 2007, effectivetwelve months ended October 31, 2006.
2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us. In August 2007,all three jurisdictions for the twelve months ended October 31, 2010, we filed petitions withgenerated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us. In all three jurisdictions for the NCUC, the PSCSCtwelve months ended October 31, 2009, we generated $46 million of margin from secondary market activity, $34.5 million which is allocated to customers as gas cost reductions and the TRA requesting the ability$11.5 million as margin allocated to place certain defined benefit postretirement obligations related to the implementation of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158) in a deferred account instead of OCI. The petitions were approved in all of the jurisdictions.
us.

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas into our system in order to mitigate the risk exposure to the financial condition of the marketers.


53


3. Earnings Per Share

We compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
3.  Long-Term Debt
A reconciliation of basic and diluted EPS for the years ended October 31, 2011, 2010 and 2009 is presented below.

In thousands except per share amounts

  2011   2010   2009 

Net Income

  $113,568   $141,954   $122,824 
  

 

 

   

 

 

   

 

 

 

Average shares of common stock outstanding for basic earnings per share

   72,056    72,275    73,171 

Contingently issuable shares under incentive compensation plans

   210    250    290 
  

 

 

   

 

 

   

 

 

 

Average shares of dilutive stock

   72,266    72,525    73,461 
  

 

 

   

 

 

   

 

 

 

Earnings Per Share of Common Stock:

      

Basic

  $1.58   $1.96   $1.68 

Diluted

  $1.57   $1.96   $1.67 

4. Long-Term Debt

All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 20082011 and 20072010 is as follows.

         
  2008  2007 
  In thousands 
 
Senior Notes:        
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 
Insured Quarterly Notes:        
6.25%, due 2036  199,261   199,887 
         
Total  824,261   824,887 
Less current maturities  30,000    
         
Total $794,261  $824,887 
         

In thousands

  2011   2010 

Senior Notes:

    

2.92%, due 2016

  $40,000   $—    

8.51%, due 2017

   35,000    35,000 

4.24%, due 2021

   160,000    —    

Medium-Term Notes:

    

6.55%, due 2011

   —       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 

Insured Quarterly Notes:

    

6.25%, due 2036

   —       196,922 
  

 

 

   

 

 

 

Total

   675,000    731,922 

Less current maturities

   —       60,000 
  

 

 

   

 

 

 

Total

  $675,000   $671,922 
  

 

 

   

 

 

 

Current maturities for the next five years ending October 31 and thereafter are as follows.

     
  In thousands 
 
2009 $30,000 
2010  60,000 
2011  60,000 
2012   
2013   
Thereafter  674,261 
     
Total $824,261 
     
We had a shelf registration statement filed with the SEC that could have been used for either the issuance of debt or equity securities that expired on December 1, 2008. The remaining balance of unused long-term financing available under this shelf registration statement was $109.4 million.

In thousands

    

2012

  $—    

2013

   —    

2014

   100,000 

2015

   —    

2016

   40,000 

Thereafter

   535,000 
  

 

 

 

Total

  $675,000 
  

 

 

 

Payments of $.1 million and $.6 million in 2011 and $.1 million in 2008 and 2007,2010, respectively, were paid to noteholders of the 6.25% insured quarterly notes based on a redemption right upon the death of the owner of the notes, within specified limitations.

We redeemed all of the 6.25% insured quarterly notes on June 1, 2011, which had an aggregate principal balance of $196.8 million. We retired the balance of $60 million of our 6.55% medium-term notes and $60 million of our 7.8% medium-term notes in September 2011 and September 2010, respectively, as they became due.

On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term borrowings used to finance the redemption of the 6.25% insured quarterly notes, as well as for other general corporate purposes and working capital needs.

On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries, and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or


54


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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, 2008,2011, our retained earnings were not restricted becauseas the amount available for restricted payments was greater than our actual retained earnings as of this date as presented below.
     
  In thousands 
 
Amount available for restricted payments $538,383 
Retained earnings  414,246 

In thousands

    

Amount available for restricted payments

  $605,481 

Retained earnings

   550,584 

We are subject to default provisions related to our long-term debt and short-term debt. FailureSince there are cross default provisions in all of our debt agreements, failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2008,2011, we are in compliance with all default provisions.

4.  Capital Stock and Accelerated Share Repurchase

5. Short-Term Debt Instruments

On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility that expires in January 2014. The new facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $3.5 million was issued and outstanding at October 31, 2011. The prior five-year revolving syndicated credit facility provided a line of credit for letters of credit of $5 million, of which $2.7 million was issued and outstanding at October 31, 2010. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from 65 to 150 basis points, based on our credit ratings. Amounts borrowed remain outstanding until repaid and do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

Our outstanding short-term bank borrowings, as included in “Bank debt” in the consolidated balance sheets, were $331 million, as of October 31, 2011, under our three-year revolving syndicated credit facility and $242 million, as of October 31, 2010, under our five-year revolving syndicated credit facility, in LIBOR cost-plus loans at a weighted average interest rate of .94% in 2011 and .50% in 2010. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17% when borrowing. Our three-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 51% at October 31, 2011.

6. Capital Stock and Accelerated Share Repurchase

Changes in common stock for the years ended October 31, 2006, 20072011, 2010 and 20082009 are as follows.

         
  Shares  Amount 
  In thousands 
 
Balance, October 31, 2005  76,698  $562,880 
Issued to participants in the Employee Stock Purchase Plan (ESPP)  36   882 
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)  735   17,496 
Issued to participants in the Executive Long-Term Incentive Plan (LTIP)  75   1,669 
Shares repurchased under Common Stock Open Market Repurchase Plan  (1,080)  (25,871)
Shares repurchased under Accelerated Share Repurchase (ASR) Plan  (1,000)  (24,292)
         
Balance, October 31, 2006  75,464   532,764 
Issued to ESPP  34   809 
Issued to DRIP  593   14,973 
Issued to LTIP  117   3,264 
Shares repurchased under Common Stock Open Market Repurchase Plan  (150)  (3,953)
Shares repurchased under ASR Plan  (1,850)  (50,287)
         
Balance, October 31, 2007  74,208   497,570 
Issued to ESPP  33   838 
Issued to DRIP  567   14,753 
Issued to LTIP  40   1,082 
Shares repurchased under Common Stock Open Market Repurchase Plan  (1,000)  (26,139)
Shares repurchased under ASR Plan  (602)  (16,539)
         
Balance, October 31, 2008  73,246  $471,565 
         

In thousands

  Shares  Amount 

Balance, October 31, 2008

   73,246  $471,565 

Issued to participants in the Employee Stock Purchase Plan (ESPP)

   37   875 

Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)

   565   13,560 

Issued to participants in the Executive Long-Term Incentive Plan (LTIP)

   89   2,755 

Issued to participants in the Incentive Compensation Plan (ICP)

   29   671 

Shares repurchased under Accelerated Share Repurchase (ASR) agreement

   (700  (17,857
  

 

 

  

 

 

 

Balance, October 31, 2009

   73,266   471,569 

Issued to ESPP

   35   899 

Issued to DRIP

   676   17,663 

Issued to ICP

   106   2,804 

Shares repurchased under ASR agreement

   (1,800  (47,276

Shares repurchased under rescission offer

   (1  (19
  

 

 

  

 

 

 

Balance, October 31, 2010

   72,282   445,640 

Issued to ESPP

   30   870 

Issued to DRIP

   657   18,834 

Issued to ICP

   149   4,451 

Shares repurchased under ASR agreement

   (800  (23,004
  

 

 

  

 

 

 

Balance, October 31, 2011

   72,318  $446,791 
  

 

 

  

 

 

 

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of 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 cancelled and become authorized but unissued shares available for issuance under the ESPP, DRIP and LTIP.

ICP.

On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved


55


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
on that date an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock 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. The additional four million shares arewere referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, and have an expiration date of December 31, 2010.
which were consolidated.

On November 1, 2007,January 10, 2011, we entered into an ASR agreement. On November 2, 2007,agreement where we purchased and retired 1 million800,000 shares of our common stock from an investment bank at the closing price that day of $24.70$27.79 per share. The settlement and retirement of those shares occurred on January 11, 2011. Total consideration paid to purchase the shares of $24.8$22.2 million including $92,500 in commissions and other fees, was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets.

As part of the ASR, agreement, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 6048 trading days.days, or March 18, 2011. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 1 million800,000 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, less a $.10 per

share discount, was higher than the November 2, 2007initial purchase 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, less a $.10 per share discount, for the shares purchased was lower than the November 2, 2007initial purchase closing price. At settlement on January 15, 2008,March 21, 2011, we paid cash of $1.3$.8 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction inof “Common stock”Stock” in the consolidated balance sheets. The $1.3$.8 million was the difference between the investment bank’s weighted average purchase price of $26.0459$28.8551 per share less a discount of $.10 per share for a settlement price of $28.7551 per share and the November 2, 2007initial purchase closing price of $24.70$27.79 per share multiplied by 1 million800,000 shares.

As of October 31, 2008, 2.9 million2011, our shares of common stock were reserved for issuance as follows.

In thousands

    
In thousands

ESPP

   75273 

DRIP

   3291,431 

LTIP and ICP

   2,490901 

ICP

   1,171 

Total

   2,8943,776 
  

 
5.  Financial Instruments and Related Fair Value
On January 16, 2008,

In late 2009, we increased the aggregate commitmentsdiscovered that we had inadvertently sold more shares under our syndicated five-year revolving credit facility from $350DRIP than were registered with the SEC and authorized by our Board of Directors for issuance under the DRIP as well as having an expired registration statement. To correct these issuances, our Board of Directors ratified the authorization and issuance of the excess number of shares, we filed a registration statement in November 2009 covering the sale and issuance of an additional 2.75 million shares of our common stock under our DRIP, and we filed a registration statement in February 2010, which offered to $450 million to meet working capital requirements. This facility may be increased up to $600 million and includes annual renewal options and lettersrescind the purchase of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million of which $1.9 million and $1.5 million were issued and outstanding at October 31,the shares sold under the DRIP between December 1, 2008 and 2007, respectively. These lettersNovember 16, 2009 and registered all previously unregistered shares issued under the DRIP during that period. All related unauthorized shares and related proceeds received by us and the repurchase of credit are usedrescinded shares and consideration paid were immaterial. We reported these events to guarantee claims from self-insurancethe relevant regulatory authorities, including the SEC and the NCUC. We have not been subjected to enforcement actions, penalties or fines by these regulatory authorities.

7. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our general liability policies.gas cost hedging plans. The credit facility bears interest based on the30-day LIBOR rate plus from .15%accounting guidance related to .35%,derivatives and hedging requires that we use a gross presentation, based on our credit ratings.

On October 27election, for the fair value amounts of our derivative instruments and 29, 2008, we entered into two short-term credit facilities with banks for unsecured commitments totaling $75 million expiring on December 1, 2008. On December 1, 2008, these commitments were extendedthe fair value of the right to December 3, 2008. Advances under each short-term facility bear interest at a rate based on the30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings.reclaim cash collateral. We entered into these short-term facilitiesuse long position gas purchase options to provide linessome level of credit above the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements, including supportprotection for our gas supply


56


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
procurement program as well as general corporate needs. No borrowings under these facilities were outstanding at October 31, 2008.
customers in the event of significant commodity price increases. As of October 31, 20082011 and 2007, outstanding short-term borrowings under2010, we had long gas purchase options providing total coverage of 38.1 million dekatherms and 33.5 million dekatherms, respectively. The long gas purchase options held at October 31, 2011 are for the credit facilityperiod from December 2011 through October 2012.

Fair Value Measurements

We use financial instruments to mitigate commodity price risk for our customers. We also have marketable securities that are held in a rabbi trust established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as includedset forth in “Notes payable”the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of October 31, 2011 and 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2011 and 2010.

Recurring Fair Value Measurements as of October 31, 2011 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
   Significant
Other
Observable
Inputs
(Level 2)
   Significant
Unobservable
Inputs
(Level 3)
   Total
Carrying
Value
 

Assets:

        

Derivatives held for distribution operations

  $2,772   $—      $—      $2,772 

Debt and equity securities held as trading securities:

        

Money markets

   217    —       —       217 

Mutual funds

   1,274    —       —       1,274 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total fair value assets

  $4,263   $—      $—      $4,263 
  

 

 

   

 

 

   

 

 

   

 

 

 

Recurring Fair Value Measurements as of October 31, 2010 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
   Significant
Other
Observable
Inputs
(Level 2)
   Significant
Unobservable
Inputs
(Level 3)
   Total
Carrying
Value
 

Assets:

        

Derivatives held for distribution operations

  $2,819   $—      $—      $2,819 

Debt and equity securities held as trading securities:

        

Money markets

   254    —       —       254 

Mutual funds

   748    —       —       748 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total fair value assets

  $3,821   $—      $—      $3,821 
  

 

 

   

 

 

   

 

 

   

 

 

 

Our utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net costs and the gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” or “Amounts due from customers” in the consolidated balance sheets were $406.5 millionsheets. These derivative instruments reflect exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and $195.5 million, respectively,are classified within Level 1.

Trading securities include assets in LIBOR cost-plus loansa rabbi trust established for our deferred compensation plans and are included in “Marketable securities, at a weighted average interest rate of 2.84% in 2008 and 4.96% in 2007. Our credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2008. As of October 31, 2008, the unused committed lines of credit totaled $116.6 million.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2008 and 2007, our trade accounts receivable consisted of the following.
         
  2008  2007 
  In thousands 
 
Gas receivables $81,234  $95,918 
Merchandise and jobbing receivables  2,178   2,251 
Allowance for doubtful accounts  (1,066)  (544)
         
Trade accounts receivable $82,346  $97,625 
         
The carrying amountsfair value” in the consolidated balance sheetssheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

In developing the fair value of our long-term debt, we use a discounted cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values dueflow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given to 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 similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the estimatedcurrent portion, are shown below.

In thousands

  Carrying
Amount
   Fair Value 

As of October 31, 2011

  $675,000   $831,323 

As of October 31, 2010

   731,922    890,277 

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and do not reflect any netting of long-term debtasset and liability amounts or cash collateral amounts under master netting arrangements.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 20082011 and 2007, including current portion, were as follows.

                 
  2008  2007 
  Carrying
  Fair
  Carrying
  Fair
 
  Amount  Value  Amount  Value 
  In thousands 
 
Long-term debt $824,261  $798,057  $824,887  $892,506 
The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair value amounts. The fair value amounts reflect principal amounts that we will ultimately be required to pay.
2010.

Fair Value of Derivative Instruments 

In thousands

  Fair Value
October 31, 2011
   Fair Value
October 31, 2010
 

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:

    

Asset Financial Instruments

    

Current Assets - Gas purchase derivative assets (December 2011 - October 2012)

  $2,772   
  

 

 

   

Current Assets - Gas purchase derivative assets (December 2010 - November 2011)

    $2,819 
    

 

 

 

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. 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 to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide increasedsome level of protection against significant price stabilityincreases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives generally has no earnings impact.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of income for our customers. We have a management-level Energy Risk Management Committee that monitors compliance with our risk management policies.

In 2008, we purchased and sold financial options for natural gas for our Tennessee gas supply portfolio. As ofthe twelve months ended October 31, 2008, we had forward positions for December 2008 through March 2010. The costs2011 and 2010, absent the regulatory treatment under our approved PGA procedures.

In thousands

  Amount of Loss Recognized
on Derivative Instruments
   Amount of Loss Deferred
Under PGA Procedures
   Location of Loss
Recognized through
PGA Procedures
   Twelve Months Ended
October 31
   Twelve Months Ended
October 31
    
   2011   2010   2011   2010    

Gas purchase options

  $10   $62,516   $10   $62,516   Cost of Gas

In Tennessee, the cost of thesegas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA.

In 2008, we purchased and sold financial options for natural gas for our South Carolina, gas supply portfolio. As of October 31, 2008, we had forward positions for December 2008 through October 2010. Thethe costs of thesegas purchase options are pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC.


57


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In 2008, we purchased and sold financial options for natural gas for our North Carolina, gas supply portfolio. As of October 31, 2008, we had forward positions for December 2008 through October 2010. Costscosts associated with our North Carolina hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC.
Current period changes in the assets

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and liabilities from thesemanage risk management activities are recorded as a component of gas costs in amounts due to customers or amounts due from customers in accordance with Statement 71. We mark the derivative instruments to marketdefined policies and procedures under an Enterprise Risk Management program. In addition, we have an Energy Price Risk Management Committee that monitors compliance with a corresponding entry to “Amounts due to customers” or “Amounts due from customers” in the consolidated balance sheets. Accordingly, there is no earnings impact of theour hedging programs, on the regulated utility segment as a result of the use of these financial derivatives. The total fair value of gas purchase options included in the consolidated balance sheets as of October 31, 2008policies and 2007 is presented as follows.

         
  2008  2007 
  In thousands 
 
Current portion — gas purchase options $(19,561) $13,725 
Non-current portion — gas purchase options  10,257    
         
Total $(9,304) $13,725 
         
6.  Commitments and Contingent Liabilities
procedures.

8. Commitments and Contingent Liabilities

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Operating lease payments for the years ended October 31, 2008, 20072011, 2010 and 20062009 are as follows.

             
  2008  2007  2006 
  In thousands 
 
Operating lease payments $5,483  $6,587  $7,246 

In thousands

  2011   2010   2009 

Operating lease payments

  $4,496   $5,303     $6,173 

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

     
  In thousands 
 
2009 $6,232 
2010  4,739 
2011  4,098 
2012  4,029 
2013  3,973 
Thereafter  9,870 
     
Total $32,941 
     

In thousands

    

2012

  $3,560 

2013

   4,068 

2014

   3,941 

2015

   3,766 

2016

   3,720 

Thereafter

   35,424 
  

 

 

 

Total

  $54,479 
  

 

 

 

Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to fifteentwenty-one years. The time periods for gas supply contracts range from one to fourunder two years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and


58


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
long-distance costs and wireless service range from one to fourthree years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

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

As of October 31, 2008,2011, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

                     
        Telecommunications
       
  Pipeline and
     and Information
       
  Storage Capacity  Gas Supply  Technology  Other  Total 
  In thousands 
 
2009 $148,907  $23,340  $18,555  $32,093  $222,895 
2010  152,305   214   10,306      162,825 
2011  151,210   119   4,598      155,927 
2012  150,080   36   2,202      152,318 
2013  97,293            97,293 
Thereafter  407,011            407,011 
                     
Total $1,106,806  $23,709  $35,661  $32,093  $1,198,269 
                     

In thousands

  Pipeline and
Storage
Capacity
   Gas
Supply
   Telecommunications
and Information
Technology
   Other   Total 

2012

  $151,456   $6,974   $11,055   $5,912   $175,397 

2013

   100,637    11    6,855    —       107,503 

2014

   80,603    —       6,108    —       86,711 

2015

   73,059    —       1,958    —       75,017 

2016

   57,154    —       —       —       57,154 

Thereafter

   336,767    —       —       —       336,767 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $799,676   $6,985   $25,976   $5,912   $838,549 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Legal

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

We do not expect any of these routine litigation matters to have a material effect on our financial position, results of operations or cash flows.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.9$3.5 million in letters of credit that were issued and outstanding at October 31, 2008.2011. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.

Environmental Matters

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

Several years ago,

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid 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. On one of these nine properties, we performed additionalclean-up activities, including the removal of an underground storage tank, in anticipation of an impending sale.

There are threefour other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we acquired the liability for an MGPRemediation work on our Reidsville site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI Utilities, Inc.


59


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
As part of a voluntary agreement with theunder our North Carolina Department of Environment and Natural Resources (NCDENR), approved plan is scheduled to be completed in fiscal 2012.

As part of a voluntary agreement with the NCDENR, we startedconducted and completed the initial stepssoil and groundwater remediation for investigating the Hickory, North Carolina MGP site. The soil and groundwater remediation report was approved by the NCDENR. We continue to conduct periodic groundwater monitoring at this site in 2007. Basedaccordance with our site remediation plan. We have incurred $1.4 million of remediation costs on a limitedthis site assessment report in 2007, we concluded that gas plant residuals remaining on the Hickory site were thought to be mostly contained within two former tar separators associated with the site’s operations. During 2008, more extensive testing was conducted and completed, including soil investigation and phase 1 of the groundwater investigation. The investigation report from these tests was submitted to the NCDENR in the first quarter of fiscal 2009. Based on the report, we have revised our estimate of the total cost to remediate the Hickory MGP site to be approximately $1 million.

During 2008, we completed the remediation of our MGP site located in Nashville at a cost of $1.4 million. through October 31, 2011.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation.Conservation (TDEC). Remediation has been completed, and a consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The public comment period has ended, and we continue to conduct semi-annual groundwater monitoring at the site per the final consent order. We have not yet received the Department’s determination as to whether additional steps, if any, are required for the site.

During 2008, we became awareincurred $1.5 million of and began investigating three contaminated areas at our Huntersville liquefied natural gas (LNG) facility. The first area of investigation is an area potentially contaminated with trichloroethylene, a chlorinated hydrocarbon used in degreasing operations. At the Huntersville LNG facility, trichloroethylene may have been used to clean equipment. The second area is an area in which molecular sieve was buried and potentially contaminated with hydrocarbons and trichloroethylene. The third area to be potentially remediated is an area that may contain lead contamination. The Huntersville LNG facility was originally coated with lead based paint. As a precautionary measure to ensure that no lead contamination has occurred, we plan on removing all lead based paint from the site and sampling soil around the equipment to ensure that no contamination has occurred. Our estimate of the total cost to remediate these areas is $1.1 million. In accordance with the deferral accounting authorized by our regulatory commissions, we adjusted the regulatory asset and the estimated liability for this additional amount.
As ofremediation costs through October 31, 2008, our undiscounted environmental liability totaled $4.1 million, and consisted of $2.5 million for the four MGP sites for which we retain remediation responsibility, $1.1 million for the LNG facility and $.5 million for five underground storage tanks not yet remediated. We increased the liability in 2008 by $.2 million and in 2007 by $.1 million to reflect the impact of inflation based on the consumer price index.
As of October 31, 2008, our regulatory assets for unamortized environmental costs totaled $5.8 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.
2011.

In connection with the 2003 NCNGNorth Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc.’s (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 costs 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 anythird-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.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required for the Huntersville LNG molecular sieve issue. In October 2003,September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site and imposing a fine in connection with a 2003 NCNG general rate case proceeding,an amount that will be less than $100,000. We are currently negotiating the NCUC ordered an environmental regulatory liability of $3.5 million be established for refundACO. Plans to customers overinvestigate the three-year period beginning November 1, 2003. This liability resulted from a payment made to NCNG by its insurers prior to our acquisition of NCNG. As partextent of the 2005 general rate case proceeding discussed in Note 2groundwater contamination related to the consolidated financial statements,sieve burial are being developed and are tentatively scheduled to be implemented in the NCUC orderedfirst quarter of our fiscal year 2012. The Huntersville LNG facility also was originally coated with lead-based paint. As a new three-year amortization periodprecautionary measure to ensure that no lead contamination occurs, removal of lead-based paint from the site was initiated in spring 2010. We have incurred $3.2 million to remediate the Huntersville LNG site through October 31, 2011. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work tentatively scheduled for our fiscal year 2012.

During the unamortized balance as of June 30, 2005, beginning November 1, 2005.twelve months ended October 31, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility. As of October 31, 2008,2011, our estimate of the total cost to remediate the property is $.5 million, and we have incurred $.4 million through October 31, 2011. This work is scheduled to be completed in our fiscal year 2012.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina district continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina districts had their USTs removed, and we do not anticipate significant environmental remediation with respect to the removal process. As of October 31, 2011, our estimated undiscounted environmental liability was completely amortized.


60for USTs for which we retain remediation responsibility is $.3 million.


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with an underground storage tankUST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 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 in June 1988. Our current estimate of the cost to remediate the site is approximately $136,400.$144,540. 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 liabilitiesliability for $34,100,$36,135, one-fourth of the estimated cost.

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

As of October 31, 2011, our estimated undiscounted environmental liability totaled $2.8 million, and consisted of $1.5 million for the MGP sites for which we retain remediation responsibility, $1 million for the LNG facilities and $.3 million for USTs not yet remediated.

As of October 31, 2011, our regulatory assets for unamortized environmental costs totaled $9.6 million. We sought recovery of $2 million in the pending Tennessee rate case. We will seek recovery of the remaining balance in future rate proceedings.

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

During 2008, through the normal course of an on-going business review, one of our operating districts was found to have coatings on their pipes containing asbestos. We have taken action to educate employees on the hazards of asbestos and to implement procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. We continue to determine the impacts and related costs to us, if any, and the impact to employees and contractors, if any.
Other
We have been in discussions with FERC’s Office of Enforcement (OE) regarding certain instances of possible non-compliance with FERC’s capacity release regulations regarding posting and bidding requirements for short-term releases. We have provided relevant information to FERC OE Staff and are cooperating with FERC in its investigation. We are continuing to meet with FERC’s OE staff to resolve this matter. We are unable to predict the outcome of the investigation at this time; however, we do not believe this matter will have a material effect on our earnings.
7.  Employee Benefit Plans
operations or cash flows.

9. Employee Benefit Plans

Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our defined contribution401(k) plans. These amendments applyapplied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments will applyapplied to all employees, including those covered by the Nashville, Tennessee bargaining unit contract.

Under GAAP, we are required to recognize all obligations related to defined benefit pension and OPEB plans and quantify the plans’ funding status as an asset or liability on our consolidated balance sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost under the authoritative guidance; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OBEB costs. Our plans’ assets are required to be accounted for at fair value. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability.

Pension Benefits

We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit ofthat an eligible full-time employees.participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 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 prior to retirement or termination 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. Effective January 1, 2008, the defined benefitqualified pension plan was amended for all employees not covered by the bargaining unit contract in Nashville, Tennessee to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued in the future for existing employees. Employees hired prior to January 1, 2008 will continue to participate in the amended traditional defined benefitqualified pension plan. The amendment does not affect any pension benefit earned as of December 31, 2007. For service earnedEmployees are vested after December 31, 2007, a consistent rate will be applied to each year of service so that employees accrue benefits more evenly. For service earned prior to January 1, 2008, the rate used in the formula to calculate an employee’s pension benefit is greater for the first twentyfive years of service than it is for the next fifteen years of service. Employeesand can be credited with up to a total of 35 years of service. When ana vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007


61


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
under the old formula plus the accrued benefit under the new formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the new formula. These amendments will bewere effective on January 1, 2009 for employees covered by the bargaining unit contract in Nashville, Tennessee.

The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.

Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:

Achieve full funding over the longer term, and

Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.

We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.

The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds, asset-backed securities and derivatives. The derivatives must be fully collateralized so that they either hedge an existing position or there is a cash position for an equivalent value of the underlying principal. No leveraged position greater than 10% within the fixed income portfolio can be taken with derivatives, and the aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.

Employees hired or rehired after December 31, 2007 (or December 31, 2008 for employees covered by the bargaining unit contract in Nashville, Tennessee) will notcannot participate in the amended traditional pension plan but will beare participants in the new Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments. Full-timeinvestments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we will annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution will be equal toequals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base.base up to the Internal Revenue Service (IRS) compensation limit. The participant becomesis vested in this plan after three years of service.

During the year ended October 31, 2011, we contributed $.3 million to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. 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. Retirees not in the grandfathered group have 80% of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008 (January 1, 2009 for new employees covered under the bargaining unit contract in Nashville, Tennessee), new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits will beare provided to those employees after age 65 when they are automatically eligible for Medicare benefits to

cover health costs.

In connection with the September 2003 acquisition of NCNG, we acquired certain pension and Our OPEB obligations of former employees of NCNG. The accrued pension benefits for this group were placed in a separate “frozen” plan at this date. The transferred active pension plan participants began accruing benefits under the Piedmont pension plan as of October 1, 2003. There were no assets attributable to the OPEB liability transferred from Progress. We merged the “frozen” qualified NCNG pension plan with the Piedmont pension plan as of December 31, 2006.
As a result of the Medicare Prescription Drug Improvement and Modernization Act of 2003, we amended our postretirement benefit plan in August 2005 to eliminate prescription drug coverage beginning January 1, 2006 for retirees who are Medicare eligible. This prescription drug benefit was replaced byincludes a defined dollar benefit to pay the premiums for Medicare Part D.
Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.

OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is the same as the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or the surviving spouse. There are no assets related to thethese SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. These nonqualified plans are presented below.

On September 4, 2008, the Compensation Committee of our Board of Directors terminated a former SERP effective October 31, 2008. The supplemental retirement benefit was replaced with a non-qualified defined contribution restoration plan (DCR plan), effective January 1, 2009. Benefits payable under the new plan are informally funded through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each executive. An additional one-time contribution was made for all eligible officers in January 2009 equal to the greater of:

13% of base salary paid in November 2008 and December 2008 (to the extent that calendar year-to-date base salary exceeded the 2008 annual limit), or

Two monthly premiums (without adjustment for taxes) under the former SERP.

In addition, an opening balance that totaled $.3 million was established for four Vice Presidents to compensate them for the loss of future benefits under the new plan. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption, of annual company contributions, and prospective five-year cliff vesting for the opening balances of the four Vice Presidents. If the officer severs employment before the expiration of the relevant five-year period, he or she receives nothing from that portion of the DCR plan. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant. The insurance portion of the SERP benefit was maintained in the form of new term life insurance as discussed below.

Also on September 4, 2008, the Compensation Committee of our Board of Directors approved a voluntary deferred compensation plan, effective January 1, 2009, for the benefit of all officers and director-level employees. Benefits under this plan, known as the Voluntary Deferral Plan, are also haveinformally funded through a SERP covering allrabbi trust with a bank as the trustee. There are no company contributions to the Voluntary Deferral Plan. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

The funding to the DCR plan accounts for the years ended October 31, 2011 and 2010, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2011 and 2010 are presented below.

In thousands

  2011   2010 

Funding

  $352   $444 

Liability:

    

Current

   52    5 

Noncurrent

   1,766    1,293 

We provide term life insurance policies for officers at the vice president level and above. It provides supplemental retirement income for officers whose benefits underabove who were participants in the Company’s qualified retirement plan are limited by tax code provisions. Theformer SERP that terminated on October 31, 2008; the level of the insurance benefit and target retirement income benefits intended to be provided under the SERP dependis dependent upon the position of the officer. The SERP is funded byThese life insurance policies covering each officer, and the policy isare owned exclusively by each officer. Premiums on these policies are paid and expensed, by us, as grossed up for taxes to the individual officer,officer. Beginning on December 1, 2008, we provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the years ended October 31, 2008, 2007 and 2006 arecost of the policies. The cost of these premiums is presented below.

             
  2008  2007  2006 
  In thousands 
 
SERP premiums $446  $455  $709 


62


In thousands

  2011   2010   2009 

Term life policies of former SERP officers

  $56   $57   $59 

Officers and director-level employees

   24    24    20 

Actuarial Plan Information

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, 20082011 and 2007,2010, and a statement of the funded status and the amounts reflected in the consolidated balance sheets for the years ended October 31, 20082011 and 20072010 are presented below.
                         
  Qualified Pension  Nonqualified Pension  Other Benefits 
  2008  2007  2008  2007  2008  2007 
  In thousands 
 
Accumulated benefit obligation at year end $135,516  $169,367  $4,194  $4,845   N/A   N/A 
                         
Change in benefit obligation:                        
Obligation at beginning of year $188,698  $236,329  $4,845  $4,342  $33,612  $34,252 
Adjustment to reflect prior obligation           857       
Service cost  7,634   11,142   27   60   1,250   1,324 
Interest cost  11,408   12,926   277   276   2,011   1,886 
Plan amendments  (4,133)  (29,795)  127          
Actuarial gain  (43,208)  (14,844)  (532)  (95)  (5,895)  (778)
Benefit payments  (16,939)  (27,060)  (550)  (595)  (2,866)  (3,072)
                         
Obligation at end of year $143,460  $188,698  $4,194  $4,845  $28,112  $33,612 
                         
Change in fair value of plan assets:                        
Fair value at beginning of year $224,954  $211,926  $  $  $20,435  $16,800 
Actual return on plan assets  (68,351)  24,045         (5,671)  1,169 
Employer contributions  11,000   16,500   550   595   3,624   5,538 
Administrative expenses  (407)  (457)            
Benefit payments  (16,939)  (27,060)  (550)  (595)  (2,866)  (3,072)
                         
Fair value at end of year $150,257  $224,954  $  $  $15,522  $20,435 
                         
Noncurrent assets $6,797  $36,256  $  $  $  $ 
Current liabilities        (528)  (553)      
Noncurrent liabilities        (3,666)  (4,292)  (12,591)  (13,177)
                         
Net amount recognized $6,797  $36,256  $(4,194) $(4,845) $(12,591) $(13,177)
                         
Amounts Not Yet Recognized as a Component of Cost and Recognized as Regulatory Asset or Liability(1):                        
Unrecognized transition obligation $  $  $  $  $(3,335) $(4,002)
Unrecognized prior service (cost) credit  28,231   25,991   (127)         
Unrecognized actuarial gain (loss)  (54,616)  (12,170)  498   (34)  989   2,227 
                         
Regulatory (asset) liability  (26,385)  13,821   371(3)  (34)(2)  (2,346)  (1,775)
Cumulative employer contribution in excess of cost  33,182   22,435   (4,565)  (4,811)  (10,245)  (11,402)
                         
Net amount recognized $6,797  $36,256  $(4,194) $(4,845) $(12,591) $(13,177)
                         
(1)As the future recovery of pension and OPEB costs is probable, we were granted permission to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability.
(2)Amount is composed of a regulatory asset of $89 and a regulatory liability of $55.
(3)Amount is composed of a regulatory asset of $2 and a regulatory liability of $373.


63


   Qualified Pension  Nonqualified Pension  Other Benefits 

In thousands

  2011  2010  2011  2010  2011  2010 

Accumulated benefit obligation at year end

  $205,159  $182,822  $5,219  $5,039   N/A    N/A  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in projected benefit obligation:

       

Obligation at beginning of year

  $211,003  $195,329  $5,039  $4,828  $31,919  $35,523 

Service cost

   8,508   8,069   45   38   1,398   1,337 

Interest cost

   11,024   10,898   209   243   1,495   1,906 

Plan amendments

   —      —      290   —      —      —    

Actuarial (gain) loss

   16,896   7,549   130   420   (327  (3,769

Participant contributions

   —      —      —      —      898   883 

Administrative expenses

   (391  (306  —      —      —      —    

Benefit payments

   (10,408  (10,536  (494  (490  (3,483  (3,961
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Obligation at end of year

  $236,632  $211,003  $5,219  $5,039  $31,900  $31,919 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in fair value of plan assets:

       

Fair value at beginning of year

  $228,345  $184,277  $—     $—     $21,636  $19,278 

Actual return on plan assets

   19,965   32,910   —      —      792   2,841 

Employer contributions

   22,000   22,000   494   490   2,202   2,595 

Participant contributions

   —      —      —      —      898   883 

Administrative expenses

   (391  (306  —      —      —      —    

Benefit payments

   (10,408  (10,536  (494  (490  (3,483  (3,961
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Fair value at end of year

  $259,511  $228,345  $—     $—     $22,045  $21,636 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Noncurrent assets

  $22,879  $17,342  $—     $—     $—     $—    

Current liabilities

   —      —      (517  (517  —      —    

Noncurrent liabilities

   —      —      (4,702  (4,522  (9,855  (10,283
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net amount recognized

  $22,879  $17,342  $(5,219 $(5,039 $(9,855 $(10,283
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred

       

Regulatory Account:

       

Unrecognized transition obligation

  $—     $—     $—     $—     $(1,334 $(2,001

Unrecognized prior service (cost) credit

   21,638   23,836   (358  (88  —      —    

Unrecognized actuarial loss

   (99,653  (85,661  (941  (852  (424  (9
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Regulatory asset

   (78,015  (61,825  (1,299  (940  (1,758  (2,010

Cumulative employer contribution in excess of cost

   100,894   79,167   (3,920  (4,099  (8,097  (8,273
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net amount recognized

  $22,879  $17,342  $(5,219 $(5,039 $(9,855 $(10,283
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCI as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Net periodic benefit cost for the years ended October 31, 2008, 20072011, 2010 and 20062009 includes the following components.
                                     
  Qualified Pension  Nonqualified Pension  Other Benefits 
  2008  2007  2006  2008  2007  2006  2008  2007  2006 
  In thousands 
 
Service cost $7,634  $11,142  $10,972  $27  $60  $66  $1,250  $1,324  $1,134 
Interest cost  11,408   12,926   13,436   277   276   239   2,011   1,886   1,747 
Expected return on plan assets  (16,895)  (17,013)  (17,112)           (1,461)  (1,273)  (1,151)
Amortization of transition obligation                    667   667   667 
Amortization of prior service cost  (1,893)  590   933                   
Amortization of actuarial loss (gain)     1,027 �� 604                  (218)
                                     
Net periodic benefit cost  254   8,672   8,833   304   336   305   2,467   2,604   2,179 
                                     
Other changes in plan assets and benefit obligation recognized through regulatory asset or liability:                                    
Prior service cost (credit)  (4,133)  N/A   N/A   127   N/A   N/A      N/A   N/A 
Net loss (gain)  42,446   N/A   N/A   (532)  N/A   N/A   1,237   N/A   N/A 
Amounts recognized as a component of net periodic benefit cost:                                    
Transition obligation     N/A   N/A      N/A   N/A   (667)  N/A   N/A 
Prior service credit  1,893   N/A   N/A      N/A   N/A      N/A   N/A 
                                     
Total recognized in regulatory asset (liability)  40,206         (405)        570       
                                     
Total recognized in net periodic benefit cost and regulatory asset (liability) $40,460  $8,672  $8,833  $(101) $336  $305  $3,037  $2,604  $2,179 
                                     

   Qualified Pension  Nonqualified Pension  Other Benefits 

In thousands

  2011  2010  2009  2011  2010  2009  2011  2010  2009 

Service cost

  $8,508  $8,069  $5,733  $45  $38  $25  $1,398  $1,337  $885 

Interest cost

   11,024   10,898   11,240   209   243   325   1,495   1,906   2,267 

Expected return on plan assets

   (20,608  (18,773  (16,755  —      —      —      (1,534  (1,381  (1,104

Amortization of transition obligation

   —      —      —      —      —      —      667   667   667 

Amortization of prior service cost (credit)

   (2,198  (2,198  (2,198  20   20   20   —      —      —    

Amortization of actuarial loss (gain)

   3,547   1,998   —      41   9   (20  —      236   —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net periodic benefit (income) cost

   273   (6  (1,980  315   310   350   2,026   2,765   2,715 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Other changes in plan assets and benefit obligation recognized through regulatory asset or liability:

          

Prior service cost

   —      —      —      290   —      —      —      —      —    

Net loss (gain)

   17,539   (6,587  39,631   130   420   923   415   (5,229  6,464 

Amounts recognized as a component of net periodic benefit cost:

          

Transition obligation

   —      —      —      —      —      —      (667  (667  (667

Amortization of net (loss) gain

   (3,547  (1,998  —      (41  (9  20   —      (236  —    

Prior service (cost) credit

   2,198   2,198   2,198   (20  (20  (20  —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total recognized in regulatory asset (liability)

   16,190   (6,387  41,829   359   391   923   (252  (6,132  5,797 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total recognized in net periodic benefit cost and regulatory asset (liability)

  $16,463  $(6,393 $39,849  $674  $701  $1,273  $1,774  $(3,367 $8,512 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The 20092012 estimated amortization of the following items, thatwhich are recorded inas a regulatory asset or liability instead of accumulated OCI discussed above, and expected refunds for our plans are as follows.

             
  Qualified
  Nonqualified
  Other
 
  Pension  Pension  Benefits 
  In thousands 
 
Amortization of transition obligation $  $  $667 
Amortization of unrecognized prior service credit  (2,198)  20    
Amortization of unrecognized actuarial loss     (20)   
Refunds expected  (2,198)     667 
In addition, equity

In thousands

  Qualified Pension  Nonqualified Pension   Other Benefits 

Amortization of transition obligation

  $—     $—      $667 

Amortization of unrecognized prior service cost (credit)

   (2,198  81    —    

Amortization of unrecognized actuarial loss

   5,478   49    —    

Refunds expected

   3,280   130    667 

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 Investors Service’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. The discount rate can vary from plan year to plan year. As of October 31, 2011, the benchmark by plan was as follows.

Pension plan

4.67

NCNG SERP

4.01

Directors’ SERP

4.26

Piedmont SERP

3.50

OPEB

4.36

Equity market performance has a significant effect on our market-related value of plan assets. 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.recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. 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.


64


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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 Investors Service’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. As of October 31, 2008, the benchmark by plan was as follows.
Pension plan8.15%
NCNG SERP8.45%
Directors’ SERP8.56%
Piedmont SERP8.23%
Tennessee SERP8.07%
OPEB8.50%
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, 20082011 and 20072010 are presented below.

                         
        Other
 
  Qualified Pension  Nonqualified Pension  Benefits 
  2008  2007  2008  2007  2008  2007 
 
Discount rate  8.15%  6.43%  8.46%  6.06%  8.50%  6.25%
Rate of compensation increase  3.97%  3.99%  N/A   N/A   N/A   N/A 

   Qualified Pension  Nonqualified Pension  Other Benefits 
   2011  2010  2011  2010  2011  2010 

Discount rate

   4.67  5.47  4.10  4.37  4.36  4.85

Rate of compensation increase

   3.78  3.87  N/A    N/A    N/A    N/A  

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2008, 20072011, 2010 and 20062009 are presented below.

                         
  Qualified Pension  Nonqualified Pension 
  2008  2007  2006  2008  2007  2006 
 
Discount rate  6.43%  5.78%  6.00%  6.06%  5.67%  5.75%
Expected long-term rate of return on plan assets  8.00%  8.50%  8.50%  N/A   N/A   N/A 
Rate of compensation increase  3.99%  4.01%  4.05%  N/A   N/A   N/A 
             
  Other Benefits 
  2008  2007  2006 
 
Discount rate  6.25%  5.74%  5.89%
Expected long-term rate of return on plan assets  8.00%  8.50%  8.50%
Rate of compensation increase  N/A   N/A   N/A 
The weighted average asset allocations by asset category for the pension plan and the OPEB plan as of October 31, 2008, 2007 and 2006 are presented below.
                         
  Pension Benefits  Other Benefits 
  2008  2007  Target  2008  2007  Target 
 
Domestic equity securities  43%  48%  50%  35%  42%  50%
International equity securities  8%  10%  10%  23%  8%  10%
Fixed income securities  44%  41%  40%  37%  26%  40%
Cash  5%  1%  %  5%  24%  %
                         
Total  100%  100%  100%  100%  100%  100%
                         


65


   Qualified Pension  Nonqualified Pension 
   2011  2010  2009  2011  2010  2009 

Discount rate

   5.47  5.99  8.15  4.37  5.28  8.46

Expected long-term rate of return on plan assets

   8.00  8.00  8.00  N/A    N/A    N/A  

Rate of compensation increase

   3.87  3.92  3.97  N/A    N/A    N/A  

   Other Benefits 
   2011  2010  2009 

Discount rate

   4.85  5.58  8.50

Expected long-term rate of return on plan assets

   8.00  8.00  8.00

Rate of compensation increase

   N/A    N/A    N/A  

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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. We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund. 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 both domestic and international equity securities, we invest in a diversified portfolio which includes a significant exposure to these investments. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We intend to use 8% as the expected long-term rate of return on the pension and OPEB plans for 2009.
Specific financial targets include:
• Achieve full funding over the longer term for our defined benefit pension plan,
• Control fluctuation in pension expense from year to year,
• Achieve satisfactory performance relative to other similar pension plans, and
• Achieve positive returns in excess of inflation over short to intermediate time frames.
We anticipate that we will contribute the following amounts to our plans in 2009.
     
  In thousands 
 
Qualified pension plan $11,000 
Nonqualified pension plans  528 
OPEB plan  3,400 
Because 2008 is the first year of the MPP plan, we have made no contributions to the plan to date. We anticipate contributing $90,000 to the MPP plan in January 2009.
2012.

In thousands

Qualified pension plan

$—  

Nonqualified pension plans

517

MPP plan

535

OPEB plan

1,600

The Pension Protection Act of 2006 (PPA) contains newspecified funding requirements for single employer defined benefit pension plans. The PPA establishesestablished a 100% funding target for plan years beginning after December 31, 2007. We contributed more than was required for our qualified plan2007, and we are in 2008.

compliance.

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

             
  Qualified
  Nonqualified
  Other
 
  Pension  Pension  Benefits 
  In thousands 
 
2009 $11,689  $528  $2,884 
2010  11,491   531   2,888 
2011  10,839   517   2,855 
2012  12,207   486   2,836 
2013  12,063   480   2,877 
2014-2018  66,110   2,063   16,342 


66


In thousands

  Qualified
Pension
   Nonqualified
Pension
   Other
Benefits
 

2012

  $21,486   $517   $1,992 

2013

   16,161    484    2,031 

2014

   13,946    450    2,233 

2015

   14,827    461    2,330 

2016

   15,452    436    2,381 

2017 - 2021

   94,812    1,977    13,151 

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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, 20082011 and 20072010 are presented below.
         
  2008  2007 
 
Health care cost trend rate assumed for next year  8.25%  8.25%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)  5.00%  5.00%
Year that the rate reaches the ultimate trend rate  2017   2012 

   2011  2010 

Health care cost trend rate assumed for next year

   7.70  7.80

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

   5.00  5.00

Year that the rate reaches the ultimate trend rate

   2027   2027 

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.

         
  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, 2008 $81  $(88)
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2008  725   (709)

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, 2011

  $37   $(38

Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2011

   693    (706

Fair Value Measurements

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

   Qualified Pension Plan as of October 31, 2011 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs

(Level 3)
  Total
Carrying
Value
  % of
Total
 

Cash and cash equivalents

  $5,891  $2  $—      5,893   2
      

 

 

 

Fixed Income Securities:

       45
      

 

 

 

U.S. treasuries

   —      11,109   —      11,109   4

Long duration bonds (1)

   66,824   —      —      66,824   26

Corporate bonds

   —      24,383   —      24,383   9

High yield bonds (2)

   12,504   —      —      12,504   5

Collateralized mortgage obligations

   —      1,448   —      1,448   1

Municipals

   —      324   —      324   —  

Derivatives

   (25  437   —      412   —  
      

 

 

 

Equity Securities: (3)

       35
      

 

 

 

Large cap core index (4)

   11,206   —      —      11,206   4

Large cap value

   8,623   —      —      8,623   3

Large cap growth

   15,897   —      —      15,897   6

Small cap

   23,827   —      —      23,827   9

International value

   13,770   —      —      13,770   6

International growth

   18,057   —      —      18,057   7
      

 

 

 

Real Estate:

       6
      

 

 

 

Global REIT

   14,909   —      —      14,909   6
      

 

 

 

Other Investments:

       12
      

 

 

 

Hedge fund of funds (5)

   —      10,089   6,207   16,296   6

Private equity fund of funds (6)

   —      —      1,925   1,925   1

Commodities (7)

   —      3,632   8,472   12,104   5
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets at fair value

  $191,483  $51,424  $16,604  $259,511   100
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Percent of fair value hierarchy

   74  20  6  100 
  

 

 

  

 

 

  

 

 

  

 

 

  

   Qualified Pension Plan as of October 31, 2010 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs

(Level 3)
  Total
Carrying
Value
  % of
Total
 

Cash and cash equivalents

  $1,969  $—     $—      1,969   1
      

 

 

 

Fixed Income Securities:

       50
      

 

 

 

U.S. treasuries

   —      26,886   —      26,886   12

Long duration bonds (1)

   60,393   —      —      60,393   26

Corporate bonds

   —      13,063   —      13,063   6

High yield bonds (2)

   11,509   —      —      11,509   5

Derivatives

   (27  1,694   —      1,667   1
      

 

 

 

Equity Securities: (3)

       39
      

 

 

 

Large cap core index (4)

   10,815   —      —      10,815   5

Large cap value

   10,640   —      —      10,640   5

Large cap growth

   12,601   —      —      12,601   5

Small cap

   21,748   —      —      21,748   9

International value

   17,170   —      —      17,170   7

International growth

   17,243   —      —      17,243   8
      

 

 

 

Real Estate:

       5
      

 

 

 

Global REIT

   12,070   —      —      12,070   5
      

 

 

 

Other Investments:

       5
      

 

 

 

Hedge fund of funds (5)

   —      4,795   5,196   9,991   5

Private equity fund of funds (6)

   —      —      580   580   —  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets at fair value

  $176,131  $46,438  $5,776  $228,345   100
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Percent of fair value hierarchy

   77  20  3  100 
  

 

 

  

 

 

  

 

 

  

 

 

  

(1)This category represents actively managed long duration fixed income funds.
(2)This category represents actively managed high yield fixed income funds.
(3)This category represents actively managed equity funds and separate accounts with diversified investment strategies with the exception of the Large Cap Core Index Fund category.
(4)This category represents low-cost equity index funds not actively managed that track the S&P 500 index.
(5)This category represents investments across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments.
(6)This category represents exposure to a diversified private equity fund of funds investment. The target allocation is 5% but is still being funded through capital calls. Until a 5% allocation can be achieved, the balance of the 5% allocation is invested in a low-cost equity fund managed to track the S&P 500 index.
(7)This category represents exposure to a commodities fund of funds investment, which is comprised of actively managed commodity market-oriented strategies through opportunistic investments in a well diversified group of underlying managers.

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

In thousands

  Hedge
Fund

of Funds
  Private
Equity
Fund

of  Funds
  Commodities  Total 

Balance, October 31, 2009

  $—     $—     $—     $—    

Actual return on plan assets:

     

Relating to assets still held at the reporting date

   307   (4  —      303 

Relating to assets sold during the period

   —      —      —      —    

Purchases, sales and settlements (net)

   4,889   584   —      5,473 

Transfer in/out of Level 3

   —      —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, October 31, 2010

   5,196   580   —      5,776 

Actual return on plan assets:

     

Relating to assets still held at the reporting date

   (1,236  66   (488  (1,658

Relating to assets sold during the period

   —      —      —      —    

Purchases, sales and settlements (net)

   2,247   1,279   8,960   12,486 

Transfer in/out of Level 3

   —      —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, October 31, 2011

  $6,207  $1,925  $8,472  $16,604 
  

 

 

  

 

 

  

 

 

  

 

 

 

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

   Other Benefits (1) as of October 31, 2011 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs

(Level 3)
  Total
Carrying
Value
  % of
Total
 

Cash and cash equivalents

  $1,011  $—     $—     $1,011   5
      

 

 

 

Fixed Income Securities:

       45
      

 

 

 

U.S. treasuries

   2,162   —      —      2,162   10

Corporate bonds (2) / Asset-backed securities

   7,790   —      —      7,790   35
      

 

 

 

Equity Securities:

       45
      

 

 

 

Large cap value

   1,108   —      —      1,108   5

Large cap growth

   1,107   —      —      1,107   5

Small cap value

   1,092   —      —      1,092   5

Small cap growth

   1,131   —      —      1,131   5

Large cap index

   1,996   —      —      1,996   9

International blend

   3,557   —      —      3,557   16
      

 

 

 

Real Estate:

       5
      

 

 

 

Global REIT

   1,091   —      —      1,091   5
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets at fair value

  $22,045  $—     $—     $22,045   100
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Percent of fair value hierarchy

   100  —    —    100 
  

 

 

  

 

 

  

 

 

  

 

 

  

   Other Benefits (1) as of October 31, 2010 

In thousands

  Quoted Prices
in Active
Markets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs

(Level 3)
  Total
Carrying
Value
  % of
Total
 

Cash and cash equivalents

  $526  $—     $—     $526   3
      

 

 

 

Fixed Income Securities:

       45
      

 

 

 

U.S. treasuries

   2,164   —      —      2,164   10

Corporate bonds (2) / Asset-backed securities

   7,603   —      —      7,603   35
      

 

 

 

Equity Securities:

       47
      

 

 

 

Large cap value

   1,131   —      —      1,131   5

Large cap growth

   1,152   —      —      1,152   5

Small cap value

   1,158   —      —      1,158   5

Small cap growth

   1,162   —      —      1,162   5

Large cap index

   2,019   —      —      2,019   10

International blend

   3,650   —      —      3,650   17
      

 

 

 

Real Estate:

       5
      

 

 

 

Global REIT

   1,071   —      —      1,071   5
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets at fair value

  $21,636  $—     $—     $21,636   100
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Percent of fair value hierarchy

   100  —    —    100 
  

 

 

  

 

 

  

 

 

  

 

 

  

(1)The plan assets are invested in mutual funds.
(2)This category represents primarily investment grade corporate securities even though the plan maintains a 5% allocation to a high yield bond fund.

401(k) Plan

We maintain a 401(k) plans which areplan that is a profit-sharing plansplan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includeincludes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plans areplan is subject to the provisions of the Employee Retirement Income Security Act. Full-timeEligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plansplan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.

Effective

Beginning January 1, 2008 we made changes(January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees receive a company match of 100% up to our 401(k) plans.the first 5% of eligible pay contributed. Prior to January 1, 2008, we matched 50% of employee contributions up to the first 10% of pay contributed. Beginning January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees are able to receive a company match of 100% up to the first 5% of eligible pay contributed. Employees are still able tomay contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution limit. We automatically enroll all affected non-participating employees in the 401(k) plan as of January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee) at a 2% contribution rate unless the employee chooses not to participate by notifying our plan administrator.record keeper. For employees who are automatically enrolled in the 401(k) plan, we will automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio

of stocks and bonds. Participants may invest in Piedmont stockdirect up to a maximum of 20% of their account.contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2008, 20072011, 2010 and 2006,2009, we made matching contributions to participant accounts as follows.

             
  2008  2007  2006 
  In thousands 
 
401(k) matching contributions $4,252  $3,191  $3,288 

In thousands

  2011   2010   2009 

401(k) matching contributions

  $5,203   $5,269     $4,698 

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into ourthe participants’ 401(k) plans.accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and 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.


67


10. Employee Share-Based Plans

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
8.  Employee Share-Based Plans
Under the LTIP and Incentive Compensation Plan (ICP),our shareholder approved by the Company’s shareholders in March 2006, the Board of Directors has awarded units toincentive compensation plans, eligible officers and other participants. Dependingparticipants are awarded units that pay out depending upon the level of performance achieved by Piedmont during multi-yearthree-year incentive plan performance periods, distributionperiods. Distribution of those awards may be made in the form of shares of common stock and cash withheldwithholdings for payment of applicable taxes on the compensation. The LTIP and ICPThese plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2008, 20072011, 2010 and 2006,2009, we recorded compensation expense, and as of October 31, 20082011 and 2007,2010, we have accrued amountsa liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date. Shares of common stock to be issued under the LTIP and ICP are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

We have three awards under the LTIP and ICPapproved incentive compensation plans with three-year performance periods ending October 31, 2008,2011, October 31, 20092012 and October 31, 2010. Fifty percent2013. 50% of the units awarded will be based on achievement of a target annual compounded increase in basic earnings per share (EPS).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 (increase in our common stock price plus dividends paidreinvested over the specified period of time) in comparison to a peer group consistingwhich consists of the natural gas distribution companies formerly comprising the A. G. Edwards Large Natural Gas Distribution Index (peer group).companies. The total shareholder return performance measure will be the registrant’sour 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

In December 2010, a long-term retention award under the incentive compensation plan was approved for eligible officers and other participants. This retention award will be distributed to participants who have one additional award withmet the retention requirements at the end of a five-year performancethree-year period thatending in

December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of a participant’s retention units. For the twelve months 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 A. G. Edwards Large Natural Gas Distribution Index industry peer group and in the same percentile rankings. The payout under this award will occur over a three-year period. The second payout occurred in fiscal 2008.

Information for the LTIP and ICP for the years ended October 31, 2008, 2007 and 2006,2011, we recorded compensation expense, and as of October 31, 2008 and 20072011, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is presented below.
             
  2008  2007  2006 
  In thousands 
 
Compensation expense $6,689  $1,666  $5,356 
Tax benefit  1,723   654   2,111 
Liability  10,749   6,200     
Based on current accrual assumptions,re-measured to market value at the expected payout for performance periods ending October 31, 2008, 2009 and 2010 will occur in the following fiscal years.
             
  2009  2010  2011 
  In thousands 
 
Amount of payout $5,329  $2,990  $1,941 


68

settlement date.


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
UnderAlso under our ICP,approved incentive compensation plan, 65,000 restrictedunvested shares of our common stock with a value at the date of grant of $1.7 million were granted to our President and Chief Executive Officer in September 2006. The restricted shares shall vest and be payable onDuring the following schedule only if he is an employee on the vesting date for each tranche:
     
  Projected
 
  Amount 
  In thousands 
 
20% on September 1, 2009 $374 
30% on September 1, 2010  562 
50% on September 1, 2011  936 
During thefive-year vesting period, any dividends paid on these shares will bewere accrued and converted into additional shares at the closing price on the date of the dividend payment. The restricted shares and any additional shares accrued through dividends will vest according toIn accordance with the vesting schedule above. We are recording20%, 30% and 50% of the shares vested on September 1, 2009, 2010 and 2011, respectively.

The compensation underexpense related to the ICP on the straight-line method.

Information for the restricted sharesincentive compensation plans for the years ended October 31, 2008, 20072011, 2010 and 2006 is2009, and the amounts recorded as liabilities as of October 31, 2011 and 2010 are presented below.
             
  October 31 
  2008  2007  2006 
  In thousands, except shares 
 
Number of shares granted          65,000 
Value at date of grant         $1,700 
Compensation expense $338  $336  $56 
Tax (expense) benefit  (168)  132   22 

In thousands

  2011   2010   2009 

Compensation expense

  $2,604   $6,118   $2,487 

Tax benefit

   673    1,756    207 

Liability

   5,015    9,914   

Based on current accrual assumptions as of October 31, 2011, the expected payout for the approved incentive compensation plans ending October 31, 2011, 2012 and 2013 will occur in the following fiscal years.

In thousands

  2012   2013   2014 

Amount of payout

  $—      $2,719     $2,296 

On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.

As discussed in Note 4, 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.


69


11. Income Taxes

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
9.  Income Taxes
The components of income tax expense for the years ended October 31, 2008, 20072011, 2010 and 20062009 are presented below.
                         
  2008  2007  2006 
  Federal  State  Federal  State  Federal  State 
  In thousands 
 
Charged to operating income:                        
Current $27,971  $6,679  $28,233  $4,987  $27,470  $4,977 
Deferred  24,285   4,237   15,250   3,279   14,775   3,855 
Amortization of investment tax credits  (358)     (434)     (534)   
                         
Total  51,898   10,916   43,049   8,266   41,711   8,832 
                         
Charged to other income (expense):                        
Current  10,040   1,786   7,557   1,153   9,052   1,427 
Deferred  (1,025)  (123)  4,644   957   1,107   301 
                         
Total  9,015   1,663   12,201   2,110   10,159   1,728 
                         
Total $60,913  $12,579  $55,250  $10,376  $51,870  $10,560 
                         

   2011  2010   2009 

In thousands

  Federal  State  Federal  State   Federal  State 

Charged (Credited) to operating income:

        

Current

  $(11,403 $4,209  $18,133  $3,928   $(7,774 $181 

Deferred

   64,806   6,597   33,432   6,866    65,828   12,047 

Tax Credits

        

Utilization

   184   —      105   —       130   —    

Amortization

   (325  —      (382  —       (333  —    
  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Total

   53,262   10,806   51,288   10,794    57,851   12,228 
  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Charged (Credited) to other income (expense):

        

Current

   3,263   (36  22,519   3,755    7,764   1,064 

Deferred

   4,167   824   2,963   557    2,492   483 
  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Total

   7,430   788   25,482   4,312    10,256   1,547 
  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Total

  $60,692  $11,594  $76,770  $15,106   $68,107  $13,775 
  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.

             
  2008  2007  2006 
  In thousands 
 
Federal taxes at 35% $64,225  $59,504  $55,867 
State income taxes, net of federal benefit  8,176   6,745   6,864 
Amortization of investment tax credits  (358)  (434)  (534)
Other, net  1,449   (189)  233 
             
Total $73,492  $65,626  $62,430 
             

In thousands

  2011  2010  2009 

Federal taxes at 35%

  $65,049  $81,841  $71,647 

State income taxes, net of federal benefit

   7,536   9,819   8,954 

Amortization of investment tax credits

   (325  (382  (333

Other, net

   26   598   1,614 
  

 

 

  

 

 

  

 

 

 

Total

  $72,286  $91,876  $81,882 
  

 

 

  

 

 

  

 

 

 

As of October 31, 20082011 and 2007,2010, deferred income taxes consisted of the following temporary differences.

         
  2008  2007 
  In thousands 
 
Utility plant $271,060  $239,448 
Equity method investments  19,241   20,554 
Revenues and cost of gas  17,370   23,741 
Deferred cost  25,605   21,594 
Other, net  (21,036)  (21,436)
         
Net deferred income tax liabilities $312,240  $283,901 
         

In thousands

  2011  2010 

Deferred tax assets:

   

Benefit of loss carryforwards

  $2,474  $2,474 

Employee benefits and compensation

   10,267   13,082 

Revenue requirement

   10,306   10,530 

Utility plant

   10,799   9,183 

Other

   6,043   4,958 
  

 

 

  

 

 

 

Total deferred tax assets

   39,889   40,227 

Valuation Allowance

   (505  (1,324
  

 

 

  

 

 

 

Total deferred tax assets, net

   39,384   38,903 
  

 

 

  

 

 

 

Deferred tax liabilities:

   

Utility plant

   437,388   370,348 

Revenues and cost of gas

   6,896   14,976 

Equity method investments

   32,296   27,244 

Deferred costs

   55,142   46,387 

Other

   18,830   14,106 
  

 

 

  

 

 

 

Total deferred tax liabilities

   550,552   473,061 
  

 

 

  

 

 

 

Net deferred income tax liabilities

  $511,168  $434,158 
  

 

 

  

 

 

 

As of October 31, 20082011 and 2007, total deferred income tax liabilities were $345 million and $321.3 million and total net deferred income tax assets were $32.8 million and $37.4 million, respectively. As of October 31, 2008 and 2007, these2010, total net deferred income tax assets were net of a valuation allowance of $1.1 million and $.4 million, respectively, to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 20082011 and 2007,2010, we had federal net operating loss carryforwards of $6.2 million and $6.5 million, respectively, which expire from 2024 through 2026. As of October 31, 2011 and 2010, we had state net operating


70


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
loss carryforwards of $6.6$7 million and $6.9$7.1 million, respectively, thatwhich expire from 20172018 through 2025. We may use the loss carryforwards to offset taxable income,income. Of the loss carryforwards, $6.2 million are subject to an annual limitation of $.3 million.
During

Our return for the tax year ended October 31, 2007,2008 is currently under examination by the Internal Revenue Service finalized itsIRS. We do not expect the audit of our returns for the tax years ended October 31, 2003 through 2005. The audit results, which did notto have a material effect on our financial position, or results of operations have been reflected in the consolidated financial statements.or cash flows. We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2005,2007, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2003.

2007.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.

             
  2008  2007  2006 
  In thousands 
 
Balance at beginning of year $394  $568  $583 
Charged (credited) to income tax expense  720   (174)  (15)
             
Balance at end of year $1,114  $394  $568 
             
We adopted the provisions of FIN 48 on November 1, 2007. As a result of the implementation of FIN 48, there was no material impact on the consolidated financial statements, and no adjustment to retained earnings. The amount of unrecognized tax benefits at November 1, 2007 and October 31, 2008 was $.5 million, of which $.3 million would impact our effective income tax rate if recognized.

In thousands

  2011  2010  2009 

Balance at beginning of year

  $1,324  $1,400  $1,114 

Charged (credited) to income tax expense

   (819  (76  286 
  

 

 

  

 

 

  

 

 

 

Balance at end of year

  $505  $1,324  $1,400 
  

 

 

  

 

 

  

 

 

 

A reconciliation of the unrecognized tax benefits for the yearyears ended October 31, 20082011 and 2010 is presented below.

     
  In thousands 
 
Balance, beginning of year (date of adoption) $474 
Increase from prior year’s tax positions  72 
Decrease from settlements with taxing authority  40 
     
Balance, end of year $506 
     
We recognize accrued interest and penalties related to unrecognized tax benefits in operating expenses in the consolidated statements of income, which is consistent with the recognition of these items in prior reporting periods.

In thousands

  2011   2010 

Balance, beginning of year

  $—      $293 

Decrease from settlements with taxing authorities

   —       —    

Decrease from expiration of statute of limitations

   —       293 
  

 

 

   

 

 

 

Balance, end of year

  $—      $—    
  

 

 

   

 

 

 

We recorded $.1 million ofno interest related to unrecognized tax benefits during the year ended October 31, 2008.

For state tax purposes, we have unrecognized tax benefits related to2011 and only immaterial amounts of interest during the treatment of sales of certain assets that we anticipate will decrease by $.2 million due to a settlement with taxing authorities or the expiration of the statute of limitations within the next twelve months.
10.  Equity Method Investments
year ended October 31, 2010.

12. 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, 2008,2011, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.


71


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

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), 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%. 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 nonrecourse to the members and is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.

In October 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend an estimated $48 million for a new compressor station and expanded meter stations in order to increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and another customer. As an equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions related to this expansion were $6.2 million.

The members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to be June 2012. Our service subscription to Cardinal’s capacity following the system expansion will increase from approximately 37% to approximately 53%. The NCUC issued a formal certificate order to Progress Energy Carolinas for their Wayne County generation project in October 2009.

We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For each of the years ended October 31, 2008, 20072011, 2010 and 2006,2009, these transportation costs and the amounts we owed Cardinal as of October 31, 20082011 and 20072010 are as follows.

             
  2008  2007  2006 
  In thousands 
 
Transportation costs $4,116  $4,549  $4,684 
Trade accounts payable  349   349     

In thousands

  2011   2010   2009 

Transportation costs

  $4,104   $4,104   $4,104 

Trade accounts payable

   349    349   

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.

             
  2008  2007  2006 
  In thousands 
 
Current assets $10,010  $8,706  $  
Non-current assets  80,851   83,388     
Current liabilities  5,229   3,814     
Non-current liabilities  31,439   33,637     
Revenues  13,670   15,369   15,524 
Gross profit  13,670   15,369   15,524 
Income before income taxes  7,050   8,371   8,785 

In thousands

  2011   2010   2009 

Current assets

  $25,868   $9,239   

Non-current assets

   88,329    75,508   

Current liabilities

   5,665    3,977   

Non-current liabilities

   24,225    26,592   

Revenues

   13,633    13,633   $13,633 

Gross profit

   13,633    13,633    13,633 

Income before income taxes

   6,473    6,375    6,893 

Pine Needle LNG Company, L.L.C.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), 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 Hess Corporation. Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the 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 itslong-term debt. Our 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 nonrecourse to the members and 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, 2008, 20072011, 2010 and 2006,2009, these gas storage costs and the amounts we owed Pine Needle as of October 31, 20082011 and 20072010 are as follows.

             
  2008  2007  2006 
  In thousands 
 
Gas storage costs $11,516  $11,727  $12,704 
Trade accounts payable  1,019   932     


72


In thousands

  2011   2010   2009 

Gas storage costs

  $10,677   $12,158   $12,364 

Trade accounts payable

   849    985   

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, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.
             
  2008  2007  2006 
  In thousands 
 
Current assets $12,618  $11,178  $  
Non-current assets  81,934   85,506     
Current liabilities  10,846   9,401     
Non-current liabilities  25,175   29,862     
Revenues  18,694   18,668   19,231 
Gross profit  18,694   18,668   19,231 
Income before income taxes  8,227   8,827   10,047 

In thousands

  2011   2010   2009 

Current assets

  $10,984   $15,593   

Non-current assets

   74,472    78,863   

Current liabilities

   1,826    3,923   

Non-current liabilities

   35,657    35,007   

Revenues

   17,666    18,808   $18,744 

Gross profit

   17,666    18,808    18,744 

Income before income taxes

   5,763    8,317    8,381 

SouthStar Energy Services LLC

We own 30%15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement (Restated Agreement), earnings and losses are allocated 25% to us and 75% to theThe other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc., with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia.

The SouthStar Restated Agreement includes a provision granting GNGC the option to purchase On January 1, 2010, we sold half of our ownership30% membership interest in SouthStar. By November 1, 2009,SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.3 million, or $.42 per diluted share for 2010. GNGC has no further rights to acquire our remaining 15% interest. We will continue to account for our 15% membership interest in SouthStar using the optionequity method, as we retain board representation with voting rights equal to purchase our entire 30% interest effectiveGNGC on January 1, 2010. If GNGC exercises its option,significant governance matters and policy decisions, and thus, exercise significant influence over the purchase price would be based on the market valueoperations of SouthStar as defined in the Restated Agreement.
SouthStar.

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 and natural gas consumption is higher. 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 and weather changes on the timing of its earnings, wholesale price and weather 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. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive income”loss” in the consolidated balance sheets.

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, 2008, 20072011, 2010 and 2006,2009, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 20082011 and 20072010 are as follows.

             
  2008  2007  2006 
  In thousands 
 
Operating revenues $14,624  $8,866  $21,598 
Trade accounts receivable  1,202   1,650     


73


In thousands

  2011   2010   2009 

Operating revenues

  $4,961   $5,083   $8,226 

Trade accounts receivable

   736    713   

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.
             
  2008  2007  2006 
  In thousands 
 
Current assets $238,662  $204,598  $  
Non-current assets  13,463   8,899     
Current liabilities  144,552   60,783     
Non-current liabilities  338   53     
Revenues  941,123   908,416   1,053,770 
Gross profit  143,534   177,822   155,416 
Income before income taxes  73,224   112,260   88,765 

In thousands

  2011   2010   2009 

Current assets

  $169,286   $167,218   

Non-current assets

   9,292    9,382   

Current liabilities

   62,869    62,899   

Non-current liabilities

   141    160   

Revenues

   733,987    843,483   $854,455 

Gross profit

   176,010    183,748    169,639 

Income before income taxes

   103,704    107,096    98,308 

Hardy Storage Company, LLC

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, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Phase one service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals, and Phase II service levels began on April 1, 2008. Hardy Storage is now in the final stages of phase III project construction. Hardy Storage has firm service contracts for 100% of itsthe storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

On

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

For 2008, we made equity contributions of $10.9 million to fund additional construction expenditures, with our total equity contributions for the project totaling $23.8 million at October 31, 2008. Upon completion of project construction, including any contingency wells if needed, the members intend to target a capitalization structure of 70% debt and 30% equity. After the satisfaction of certain conditions in the note purchase agreement, amounts outstanding under the interim notes will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur in May 2010. To the extent that more funding is needed, the members will evaluate funding options at that time.
2007. The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. Ourfinancing as well as a separate guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly owned subsidiary of Piedmont and a sister company50% of Piedmont Hardy. Our shareconstruction expenditures should contingency wells be required based on the performance of the guaranty is capped at $111.5 million. Depending upon the facility’s performancefacility over the first three years after the in-service date, there could be additional construction expendituresdate. The Guaranty of up to $10 million for contingency wells,Principal and Residual Guaranty were executed by a wholly owned subsidiary of which PEP will guarantee 50%.
Piedmont, Piedmont Energy Partners, Inc. Securing PEP’sour guaranty iswas a pledge of intercompany notes issued by Piedmont held byto its non-utility subsidiaries of PEP. Shouldheld under its wholly owned subsidiary. Also pledged was our membership interest in Hardy Storage.

In March 2010, Hardy Storage be unablepaid $3.6 million on the interim notes to perform its payment obligation underenable completion of their conversion to long-term project financing of $119.8 million due in 2023 at an interest rate of 5.88%. As a result of the constructionconversion, our Guaranty of Principal and Residual Guaranty, as executed in connection with the interim financing, PEP will call on Piedmontterminated with no payments having been made. The long-term project financing is nonrecourse to the members of Hardy Storage and their parent entities.

Prior to the long-term financing, we had recorded a liability of $1.2 million for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interests in Hardy Storage.

We record a liability at fair value forof this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter with the risk of the project evaluated at each quarter end, with a corresponding increase to our investment account in


74


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
the venture. As our risk in the project changes, the fair valueUpon completion of the guaranty ispermanent financing in March 2010, the liability was reversed, and our investment account was adjusted accordingly through a quarterly evaluation. The detailsto reflect the elimination of the guaranty at October 31, 2008 and 2007 are as follows.
         
  2008 2007
  In thousands
 
Guaranty liability $1,234  $1,336 
Amount outstanding under the construction financing  123,410   133,556 
guaranty.

We have related party transactions as a customer of Hardy Storage and record in cost of gas the Hardy storage costs charged to us.by Hardy Storage. For the years ended October 31, 20082011, 2010 and 2007,2009, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 20082011 and 20072010 are as follows.

         
  2008  2007 
  In thousands 
 
Gas storage costs $9,219  $3,505 
Trade accounts payable  774   791 

In thousands

  2011   2010   2009 

Gas storage costs

  $9,702   $9,386   $9,340 

Trade accounts payable

   808    808   

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 20082011 and 2007,2010, and for the twelve months ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.

             
  2008  2007  2006 
  In thousands 
 
Current assets $27,760  $19,972  $  
Non-current assets  168,160   160,326     
Current liabilities  5,878   21,388     
Non-current liabilities  123,410   123,410     
Revenues  23,658   13,902   * 
Gross profit  23,658   13,902   * 
Income before income taxes  9,297   8,918   707 
*Hardy Storage was not “in service” during the period 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. 2006 includes interest expense from a construction loan and operating expenses in addition to AFUDC.
11.  Business Segments
We

In thousands

  2011   2010   2009 

Current assets

  $7,358   $13,070   

Non-current assets

   167,221    170,693   

Current liabilities

   10,945    15,280   

Non-current liabilities

   102,490    109,495   

Revenues

   24,378    23,562   $23,465 

Gross profit

   24,378    23,562    23,465 

Income before income taxes

   9,657    8,249    8,155 

13. Variable Interest Entities

Effective November 1, 2010, we adopted the FASB guidance that requires us to evaluate our variable interest in a VIE to qualitatively assess whether we have two reportablea controlling financial interest, and if so, determine whether we are the primary beneficiary. Under accounting guidance, a VIE is a legal entity that conducts a business segments, regulated utilityor holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and non-utility activities. These segments were identified based on productsthat interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, and services, regulatory environments and our current corporate organization and business decision-making activities. Operationsthe obligation to absorb losses of our regulated utility segmentthe entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As of October 31, 2011, we have determined that we are conductednot the primary beneficiary, as defined by the parent company. Operations of our non-utility activities segment are comprisedauthoritative guidance related to consolidations, in any of our equity method investments, as discussed in joint ventures.

Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2011 and 2010, our investment balances are as follows.

In thousands

  October 31,
2011
   October 31,
2010
 

Cardinal

  $18,323   $11,837 

Pine Needle

   18,690    21,810 

SouthStar

   17,536    17,146 

Hardy Storage

   30,572    29,494 
  

 

 

   

 

 

 

Total equity method investments in non-utility activities

  $85,121   $80,287 
  

 

 

   

 

 

 

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

14. Business Segments

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

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.


75


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Operations by segment for the years ended October 31, 2008, 20072011, 2010 and 2006,2009, and as of October 31, 20082011, 2010 and 20072009 are presented below.
             
  Regulated
  Non-Utility
    
  Utility  Activities  Total 
  In thousands 
 
2008            
Revenues from external customers $2,089,108  $  $2,089,108 
Margin  552,973      552,973 
Operations and maintenance expenses  210,757   160   210,917 
Depreciation  93,121   29   93,150 
Income from equity method investments     27,718   27,718 
Interest expense  59,273   79   59,352 
Operating income (loss) before income taxes  215,925   (277)  215,648 
Income before income taxes  156,400   27,099   183,499 
Total assets  2,908,690   99,699   3,008,389 
Equity method investments in non-utility activities     99,214   99,214 
Construction expenditures  181,012      181,012 
             
2007            
Revenues from external customers $1,711,292  $  $1,711,292 
Margin  524,165      524,165 
Operations and maintenance expenses  214,442   325   214,767 
Depreciation  88,654   29   88,683 
Income from equity method investments     37,156   37,156 
Interest expense  57,272      57,272 
Operating income (loss) before income taxes  188,662   (518)  188,144 
Income before income taxes  133,726   36,287   170,013 
Total assets  2,655,311   95,707   2,751,018 
Equity method investments in non-utility activities     95,193   95,193 
Construction expenditures  135,241      135,241 
             
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  130,730   28,889   159,619 
Construction expenditures  196,730   551   197,281 


76


In thousands

  Regulated
Utility
   Non-Utility
Activities
  Total 

2011

     

Revenues from external customers

  $1,433,905   $—     $1,433,905 

Margin

   573,639    —      573,639 

Operations and maintenance expenses

   225,351    109   225,460 

Depreciation

   102,829    28   102,857 

Income from equity method investments

   —       24,027   24,027 

Interest expense

   43,992    —      43,992 

Operating income (loss) before income taxes

   207,079    (120  206,959 

Income before income taxes

   161,925    23,929   185,854 

Total assets

   2,968,574    85,519   3,054,093 

Equity method investments in non-utility activities

   —       85,121   85,121 

Construction expenditures

   243,641    —      243,641 

In thousands

  Regulated
Utility
   Non-Utility
Activities
  Total 

2010

     

Revenues from external customers

  $1,552,295   $—     $1,552,295 

Margin

   552,592    —      552,592 

Operations and maintenance expenses

   219,829    301   220,130 

Depreciation

   98,494    29   98,523 

Income from equity method investments

   —       28,854   28,854 

Gain on sale of interest in equity method investment

   —       49,674   49,674 

Interest expense

   43,711    —      43,711 

Operating income (loss) before income taxes

   200,360    (697  199,663 

Income before income taxes

   155,923    77,907   233,830 

Total assets

   2,784,087    80,808   2,864,895 

Equity method investments in non-utility activities

   —       80,287   80,287 

Construction expenditures

   199,059    —      199,059 

In thousands

  Regulated
Utility
   Non-Utility
Activities
  Total 

2009

     

Revenues from external customers

  $1,638,116   $—     $1,638,116 

Margin

   561,574    —      561,574 

Operations and maintenance expenses

   208,105    326   208,431 

Depreciation

   97,425    29   97,454 

Income from equity method investments

   —       33,464   33,464 

Interest expense

   46,675    34   46,709 

Operating income (loss) before income taxes

   221,454    (503  220,951 

Income before income taxes

   171,752    32,954   204,706 

Total assets

   2,919,260    104,891   3,024,151 

Equity method investments in non-utility activities

   —       104,429   104,429 

Construction expenditures

   129,006    —      129,006 

Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Reconciliations to the consolidated financial statements for the years ended October 31, 2008, 20072011, 2010 and 2006,2009, and as of October 31, 20082011 and 20072010 are as follows.
             
  2008  2007  2006 
  In thousands 
 
Operating Income:            
Segment operating income before income taxes $215,648  $188,144  $180,669 
Utility income taxes  (62,814)  (51,315)  (50,543)
Non-utility activities before income taxes  277   518   623 
             
Total $153,111  $137,347  $130,749 
             
Net Income:            
Income before income taxes for reportable segments $183,499  $170,013  $159,619 
Income taxes  (73,492)  (65,626)  (62,430)
             
Total $110,007  $104,387  $97,189 
             
Consolidated Assets:            
Total assets for reportable segments $3,008,389  $2,751,018     
Eliminations/Adjustments  85,191   69,300     
             
Total $3,093,580  $2,820,318     
             
12.  Restructuring and Other Termination Benefits
In 2006, we restructured our management group

In thousands

  2011  2010  2009 

Operating Income:

    

Segment operating income before income taxes

  $206,959  $199,663  $220,951 

Utility income taxes

   (64,068  (62,082  (70,079

Non-utility activities operating loss before income taxes

   120   697   503 
  

 

 

  

 

 

  

 

 

 

Total

  $143,011  $138,278  $151,375 
  

 

 

  

 

 

  

 

 

 

Net Income:

    

Income before income taxes for reportable segments

  $185,854  $233,830  $204,706 

Income taxes

   (72,286  (91,876  (81,882
  

 

 

  

 

 

  

 

 

 

Total

  $113,568  $141,954  $122,824 
  

 

 

  

 

 

  

 

 

 

In thousands

  2011   2010 

Consolidated Assets:

    

Total assets for reportable segments

  $3,054,093   $2,864,895 

Eliminations/Adjustments

   188,448    188,380 
  

 

 

   

 

 

 

Total

  $3,242,541   $3,053,275 
  

 

 

   

 

 

 

15. Subsequent Events

We monitor significant events occurring after the balance sheet date and recognized a liability and expense of $7.9 million, which was included inprior to the regulated utility segment in operations and maintenance expense for the costissuance of the restructuring program. This restructuring wasfinancial statements to determine the beginningimpacts, if any, of an ongoing, larger effort aimed at streamlining business processes, capturing operational and organizational efficiencies and improving customer service. This liability included early retirement for 22 employeesevents on the financial statements to be issued. All subsequent events of the management group and severance for 17 additional employees through further consolidation. Duewhich we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, see Note 2 to the short discount period, the liability for the program was recorded at its gross value. As of October 31, 2008 and 2007, there was no remaining liability for the management group restructuring program.

In 2007, we implemented additional organizational changes under our business process improvement program to streamline business processes, capture operational and organizational efficiencies and improve customer service. As a part of this effort, we began initiating changes in our customer payment and collection processes, including no longer accepting customer payments in our business offices and streamlining our district operations. We also further consolidated our call centers. Collections of delinquent accounts have been consolidated in our central business office. These specific initiatives were largely completed as of October 31, 2008.
We have accrued costs in connection with these initiatives in the form of severance benefits to employees who will be either voluntarily or involuntarily severed. These benefits are under existing arrangements and are accounted for in accordance with SFAS No. 112, “Employers’ Accounting for Postemployment Benefits.” All costs are included in the regulated utility segment in “Operations and maintenance” expenses in the consolidated statements of income.


77

financial statements.


Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
A reconciliation of activity to the liability as of October 31, 2008 and 2007 is as follows.
         
  2008  2007 
  In thousands 
 
Beginning liability $1,459  $ 
Costs incurred and expensed     3,648 
Costs paid  (1,132)  (2,189)
Adjustment to accruals  (305)   
         
Ending liability $22  $1,459 
         
13.  Subsequent Events
On November 25, 2008, we filed an expedited petition with the PSCSC requesting approval to reduce the hedging horizon from 24 months to twelve months under the gas cost hedging plan, effective December 1, 2008. The PSCSC approved the request on December 10, 2008.
* * * * * *
16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
                         
              Earnings (Loss)
 
           Net
  Per Share of
 
  Operating
     Operating
  Income
  Common Stock 
  Revenues  Margin  Income  (Loss)  Basic  Diluted 
 
Fiscal Year 2008                        
January 31 $788,470  $227,026  $91,936  $82,268  $1.12  $1.12 
April 30  634,178   161,281   51,822   48,624   0.66   0.66 
July 31  354,709   77,020   2,619   (7,678)  (0.10)  (0.10)
October 31  311,751   87,646   6,734   (13,207)  (0.18)  (0.18)
Fiscal Year 2007                        
January 31 $677,241  $208,485  $81,697  $70,716  $0.95  $0.94 
April 30  531,579   159,727   50,621   51,120   0.69   0.69 
July 31  224,442   75,158   1,021   (9,140)  (0.12)  (0.12)
October 31  278,030   80,795   4,008   (8,309)  (0.11)  (0.11)

                 Earnings (Loss)
Per Share of
Common Stock
 
           Operating
Income
(Loss)
  Net
Income
(Loss)
  
   Operating
Revenues
         
     Margin     Basic  Diluted 

Fiscal Year 2011

         

January 31

  $652,056   $230,006   $90,869  $84,440  $1.17  $1.16 

April 30

   392,567    172,931    52,927   47,408   0.66   0.66 

July 31

   197,274    81,963    389   (8,703  (0.12  (0.12

October 31

   192,008    88,739    (1,174  (9,577  (0.13  (0.13

Fiscal Year 2010

         

January 31

  $673,736   $222,942   $87,801  $113,749  $1.55  $1.55 

April 30

   472,846    168,678    52,225   46,825   0.65   0.65 

July 31

   211,603    77,897    (3,471  (9,518  (0.13  (0.13

October 31

   194,110    83,075    1,723   (9,102  (0.13  (0.13

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs 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.


78


Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9.  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.  Controls and Procedures
Item 9A. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined inRules 13a-15(e) and15d-15(e) under the Exchange Act. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that,Act as of the end of the period covered by thisForm 10-K, our10-K. Such disclosure controls and procedures were effective in that theyare designed to provide reasonable assurancesassurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specifiedrequired by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-K, our disclosure controls and procedures were effective at the reasonable assurance level.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined inRules 13a-15(f) and15d-15(f) under the Exchange Act during the fourth quarter of fiscal 20082011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


79


MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

December 29, 2008

23, 2011

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 Ethics and 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 - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2008,2011, our internal control over financial reporting was effective.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31, 2008.

2011.

Piedmont Natural Gas Company, Inc.
/s/  Thomas E. Skains
Thomas E. Skains
Chairman, President and Chief Executive Officer
/s/  David J. DzurickyPiedmont Natural Gas Company, Inc.
David J. Dzuricky
Senior Vice President and Chief Financial Officer
/s/    THOMAS E. SKAINS        

Thomas E. Skains

Chairman, President and Chief Executive Officer

/s/    KARL W. NEWLIN        

Karl W. Newlin

Senior Vice President and Chief Financial Officer

/s/    JOSE M. SIMON        

Jose M. Simon

Vice President and Controller

Jose M. Simon
Vice President and Controller


80


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2008,2011, based on the criteria established inInternal Control — Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’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, included in the accompanying Management’s Report on Internal Control Overover Financial Reporting. Our responsibility is to express an opinion on the Company’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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2008,2011, 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 as of and for the year ended October 31, 20082011 of the Company and our report dated December 29, 200823, 2011 expressed an unqualified opinion on those financial statements.

/s/  Deloitte & Touche LLP
Charlotte, North Carolina
December 29, 2008


81


Item 9B.Other Information/s/ Deloitte & Touche LLP
None.
PART III
Item 10.Charlotte, North Carolina
Directors, Executive Officers and Corporate GovernanceDecember 23, 2011

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning our executive officers and directors is set forth in the sections entitled “Information Regarding the Board of Directors” and “Executive Officers” in our Proxy Statement for the 20092012 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 20092012 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 experts is set forth in the section entitled “Committees of the Board” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.

We have adopted a Code of Ethics and 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. We have also adopted Special Provisions Relating to the Company’s Principal Executive Officer and Senior Financial Officers (Special Provisions) that are part of our Corporate Governance Guidelines and that apply to our principal executive officer, principal financial officer and principal accounting officer. The Code of Ethics and 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 isSpecial Provisions are available on the “For Investors-Corporate Governance” section of our website atwww.piedmontng.com.www.piedmontng.com. If we amend the Code of Business Conduct and Ethics or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct and Ethicsor Special Provisions that apply to the principal executive officer, principal financial officer and controller or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) ofRegulation S-K, we will disclose the amendment or waiver on the “About Us-Corporate“For Investors-Corporate Governance” section of 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,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our Proxy Statement for the 20092012 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 section entitled “Security Ownership of Management and Certain Beneficial Owners” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section 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 concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.

Item 13.Certain Relationships and Related Transactions, and Director Independence

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information for this item is set forth in the section entitled “Independence of Board Members and Related PartyPerson Transactions” in our Proxy Statement for the 20092012 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 table entitled “Fees For Services” in “Proposal B —2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2009”2012” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.


82


PART IV

Item 15. Exhibits, Financial Statement Schedules

Item 15.(a)Exhibits, 1.Financial Statement SchedulesStatements
(a) 1. Financial Statements

The following consolidated financial statements for the year ended October 31, 2008,2011, are included in Item 8 of this report as follows:

2010

  37
2009  38
2009  39
2009  40
  
41Report of Independent Registered Public Accounting Firm  
(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 10.21 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 of Piedmont Natural Gas Company, Inc., dated December 15, 2006 (Exhibit 3.3,Form 10-K for the fiscal year ended October 31, 2007).
 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 Amendment to Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.2,Form 10-K for the fiscal year ended October 31, 2007).
 4.3 Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (Exhibit 4.1,Form S-3 Registration StatementNo. 33-59369).
 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 Form of Master Global Note (Exhibit 4.4,Form S-3 Registration StatementNo. 33-59369).
 4.8 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).
 4.9 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).


83


(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 10.21 are management contracts or compensatory plans or arrangements.
3.1Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009).
3.2By-laws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (Exhibit 3.1, Form 8-K dated September 13, 2011).
4.1Note 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).

4.2Amendment to Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
4.3Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).
4.4Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
4.5First 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).
4.6Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.7Form of Master Global Note (Exhibit 4.4, Form S-3 Registration Statement No. 33-59369).
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).
4.10Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).
4.11Pricing 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).
4.12Second 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).
4.13Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1, Form 8-K, dated December 23, 2003).
4.14Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2, Form 8-K, dated December 23, 2003).

     
 4.10 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).
 4.11 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).
 4.12 Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4,Form S-3 Registration StatementNo. 333-26161).
 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 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).
 4.15 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).
 4.16 Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4,Form S-3 Registration StatementNo. 333-62222).
 4.17 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).
 4.18 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).
 4.19 Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1,Form 8-K, dated December 23, 2003).
 4.20 Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2,Form 8-K, dated December 23, 2003).
 4.21 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).
 4.22 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).
 4.23 Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among the registrant, Citibank, N.A., and The Bank of New York Trust Company, N.A. (Exhibit 4.1,Form 10-Q for quarter ended April 30, 2007).
    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 Establishment of Measures for Long-Term Incentive Plan 10 (filed inForm 8-K dated October 20, 2006, as Item 1.01).
 10.3 Form of Award Agreement under Executive Long-Term Incentive Plan (Exhibit 10.5,Form 10-K for the fiscal year ended October 31, 2006).
 10.4 Employment Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37,Form 10-K for the fiscal year ended October 31, 1999).
 10.5 Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40,Form 10-K for the fiscal year ended October 31, 1999).
 10.6 Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23,Form 10-K for the fiscal year ended October 31, 2002).
 10.7 Employment Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2006).
 10.8 Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.2,Form 10-Q for the quarter ended April 30, 2006).
 10.9 Form of Severance Agreement with Thomas E. Skains, dated September 4, 2007 (Substantially identical agreements have been entered into as of the same date with David J. Dzuricky, Franklin H. Yoho, Michael H. Yount, Kevin M. O’Hara, June B. Moore and Jane R. Lewis-Raymond) (Exhibit 10.2,Form 10-Q for the quarter ended July 31, 2007).


84

4.15Third 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).
4.16Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007).
4.17Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (Exhibit 10, Form 8-K, dated May 12, 2011).
4.18Form of 2.92% Series A Senior Notes due June 6, 2016 (Exhibit 4.1, Form 8-K dated May 12, 2011).
4.19Form of 4.24% Series B Senior Notes due June 6, 2021 (Exhibit 4.2, Form 8-K dated May 12, 2011).
4.20Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386).
4.21Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011).
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).
10.2Establishment of Measures for Long-Term Incentive Plan 10 (filed in Form 8-K dated October 20, 2006, as Item 1.01).
10.3Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999).
10.4Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 2002).
10.5Employment Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2006).


10.6Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2006).
10.7Form of Severance Agreement with Thomas E. Skains, dated September 4, 2007 (Substantially identical agreements have been entered into as of the same date with Franklin H. Yoho, Michael H. Yount, Kevin M. O’Hara and Jane R. Lewis-Raymond) (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007).
10.8Schedule of Severance Agreements with Executives (Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007).
10.9Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (Appendix A, Form DEF14A dated January 14, 2011).
10.10Form of Performance Unit Award Agreement (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011).
10.11Resolution of Board of Directors, June 3, 2011, establishing compensation for non-management directors (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2011).
10.12Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009).
10.13Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009).
10.14Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (Exhibit 4.1, Form 8-K dated April 3, 2009).
10.15Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009).
10.16Form of Amendment No. 1 to Employment Agreement between Piedmont Natural Gas Company, Inc. and Thomas A. Skains, dated as of June 4, 2010 (Substantially identical agreements have been entered into as of the same date with Kevin M. O’Hara, Michael H. Yount and Franklin H. Yoho) (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2010).

10.17Employment Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2010).
10.18Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010).
10.19Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011.
10.20Form of 2013 Retention Award Agreement (Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011).
10.21Consulting Agreement dated as of November 1, 2011 between David J. Dzuricky and Piedmont Natural Gas Company, Inc.
Other Contracts:
10.22Amended 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).
10.23First 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 (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006).
10.24Amendment 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 (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006).
10.25Amendment 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 (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006).
10.26Equity 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).

     
 10.10 Schedule of Severance Agreements with Executives (Exhibit 10.2a,Form 10-Q for the quarter ended July 31, 2007).
 10.11 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).
 10.12 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).
 10.13 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).
 10.14 Piedmont Natural Gas Company, Inc. Incentive Compensation Plan (Exhibit 10.1,Form 8-K dated March 3, 2006).
 10.15 Restricted Stock Award Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated September 1, 2006 (Exhibit 10.26,Form 10-K for the fiscal year ended October 31, 2006).
 10.16 Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2007).
 10.17 Form of Performance Unit Award Agreement (Exhibit 10.1,Form 10-Q for the quarter ended July 31, 2007).
 10.18 Amendment No. 1 to the Piedmont Natural Gas Company Executive Long-Term Incentive Plan, dated September 7, 2007 (Exhibit 10.22,Form 10-K for the fiscal year ended October 31, 2007).
 10.19 Resolution of Board of Directors, September 7, 2007, establishing compensation for non-management directors (Exhibit 10.23,Form 10-K for the fiscal year ended October 31, 2007).
 10.20 Incentive Compensation Plan Interpretive Guidelines as of September 7, 2007 (Exhibit 10.24,Form 10-K for the fiscal year ended October 31, 2007).
 10.21 Executive Long-Term Incentive Plan, dated February 27, 2004 (Corrected) (Exhibit 10.1,Form 10-Q for quarter ended April 30, 2008).
    Other Contracts:
 10.22 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).
 10.23 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 (Exhibit 10.28,Form 10-K for the fiscal year ended October 31, 2006).
 10.24 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 (Exhibit 10.29,Form 10-K for the fiscal year ended October 31, 2006).
 10.25 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 (Exhibit 10.30,Form 10-K for the fiscal year ended October 31, 2006).
 10.26 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).
 10.27 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).
 10.28 Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3,Form 8-K dated November 16, 2004).
 10.29 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).
 10.30 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).


85

10.27Construction, 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).
10.28Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3, Form 8-K dated November 16, 2004).

10.29

Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009).

10.30

Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.1, Form 8-K dated August 4, 2009).

10.31

Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.2, Form 8-K dated August 4, 2009).

10.32

Assignment and Assumption between Citibank, N.A. and Northern Trust Company, dated as of September 18, 2009 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 2009).

10.33

Credit Agreement dated as of January 25, 2011 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender, and L/C Issuer, Branch Banking and Trust Company and U.S. Bank National Association as Co-Syndication Agents, and the other Lenders party thereto (Exhibit 10.1, Form 8-K filed January 31, 2011).

10.34

Amendment No. 1 to Credit Agreement dated as of March 21, 2011 by and among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the Lenders thereunder (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2011).

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.

101.INS

XBRL Instance Document (1)

101.SCH

XBRL Taxonomy Extension Schema (1)

101.CAL

XBRL Taxonomy Calculation Linkbase (1)

101.DEF

XBRL Taxonomy Definition Linkbase (1)

101.LAB

XBRL Taxonomy Extension Label Linkbase (1)

101.PRE

XBRL Taxonomy Extension Presentation Linkbase (1)

(1)Furnished, not filed.

Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2011 and 2010; (3) Consolidated Statements of Income for the years ended October 31, 2011, 2010 and 2009; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2011, 2010 and 2009; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2011, 2010 and 2009; and Notes to Consolidated Financial Statements.

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

     
 10.31 Credit Agreement dated as of April 25, 2006 among Piedmont Natural Gas Company, Inc. and Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, and The Other Lenders Party Hereto (Exhibit 10.1,Form 10-Q for the quarter ended January 31, 2008).
 10.32 Revolving Credit Facility between Piedmont Natural Gas Company, Inc. and Bank of America, N.A., dated October 27, 2008.
 10.33 Revolving Credit Facility between Piedmont Natural Gas Company, Inc. and Branch Banking and Trust Company, dated October 29, 2008.
 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.


86

SIGNATURES


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

and Chief Executive Officer

Date: December 23, 2011
Thomas E. Skains
Chairman of the Board, President
and Chief Executive Officer
Date: December 29, 2008

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
Signature

/s/    THOMAS E. SKAINS        

Thomas E. Skains

  
Title
  
/s/  Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and

Chief Executive Officer

(Principal Executive Officer)

Date: December 23, 2011

  
Date: December 29, 2008  

/s/    KARL W. NEWLIN        

Karl W. Newlin

  
/s/  David J. Dzuricky

David J. Dzuricky
  

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Date: December 23, 2011

  
Date: December 29, 2008  

/s/    JOSE M. SIMON        

Jose M. Simon

  
/s/  Jose M. Simon

Jose M. Simon
  

Vice President and Controller

(Principal Accounting Officer)

Date: December 23, 2011

  
Date: December 29, 2008  


87


Signature     Title
Signature

/s/    E. JAMES BURTON        

E. James Burton

  
Title
  

Director

/s/  Jerry W. Amos

Jerry W. Amos
Director

/s/    MALCOLME. James Burton


E. James Burton
Director
/s/  EVERETT III        

Malcolm E. Everett III


Malcolm E. Everett III

  Director
  

Director

/s/    JOHN W. HARRIS        

John W. Harris

John W. Harris

  Director
  

Director

/s/    AUBREY B. HARWELL, JR.        

Aubrey B. Harwell, Jr.

Aubrey B. Harwell, Jr.

  Director
  

Director

/s/    FRANK B. HOLDING, JR.        

Frank B. Holding, Jr.

Frank B. Holding, Jr.

  Director
  

Director

/s/    FRANKIE T. JONES, SR.        

Frankie T. Jones, Sr.

Frankie T. Jones, Sr.

  Director
  

Director

/s/    VICKI MCELREATH        

Vicki McElreath

Vicki McElreath

  Director
  

Director

/s/    MINOR M. SHAW        

Minor M. Shaw

Minor M. Shaw

  Director
  

Director

/s/    MURIEL W. SHEUBROOKS        

Muriel W. Sheubrooks

Muriel W. Sheubrooks

  Director
  

Director

/s/    DAVID E. SHI        

David E. Shi

David E. Shi

  

Director


88

Piedmont Natural Gas Company, Inc.

Form 10-K

For the Fiscal Year Ended October 31, 2011

Exhibits

10.19Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011
10.21Consulting Agreement between Piedmont Natural Gas Company, Inc. and David J. Dzuricky, dated as of November 1, 2011
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