PNY Piedmont Natural Gas Company, Inc.

 

 

Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code

(704) 364-3120

 

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

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the securities Act.  Yes  þ      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  þ

 

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  þ      No  o

 

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

 

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

Large accelerated filer  þ      Accelerated filer  o      Non-accelerated filer  o      

 

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

 

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2007.

 

Common Stock, no par value — $1,931,426,121

 

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

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 6, 2008, are incorporated by reference into Part III.

 

 

Piedmont Natural Gas Company, Inc.

 

2007 FORM 10-K ANNUAL REPORT

 

TABLE OF CONTENTS

 

 

PART I

 

of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed or service continued in the ordinary course of business 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.

 

The natural gas distribution business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. During the year ended October 31, 2007, the amount of natural gas in storage varied from 11.9 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 24.2 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $93.8 million to $185.1 million.

 

During the year ended October 31, 2007, 122.3 million dekatherms of gas were sold to or transported for large volume customers, including industrial, power generation and resale customers, compared with 115.1 million dekatherms in 2006. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 83.7 million dekatherms in 2007, compared with 83.6 million dekatherms in 2006. Weather in 2007, as measured by degree days, was 12% warmer than normal and in 2006 was 6% warmer than normal.

 

The following is a five-year comparison of operating statistics for the years ended October 31, 2003 through 2007. The information presented is not comparable for all periods due to the acquisitions of North Carolina Natural Gas Corporation (NCNG) and an equity interest in Eastern North Carolina Natural Gas Company (EasternNC) effective September 30, 2003, and the remaining 50% interest of EasternNC effective October 25, 2005.

 

 

We purchase natural gas under firm contracts to meet our design-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.

As of October 31, 2007, we had contracts for the following pipeline firm transportation capacity in dekatherms per day:

 

 

In January 2008, additional transportation capacity of 80,000 dekatherms is anticipated to be added from Midwestern Gas Transmission Company (Midwestern).

 

As of October 31, 2007, we had the following assets or contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets. This deliverability varies from five days to one year:

 

 

As of October 31, 2007, we own or have under contract 34.2 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 producers and marketers. The natural gas production, processing and pipeline infrastructure in the Gulf of Mexico has recovered from the hurricane-related supply disruptions of 2005-2006. Natural gas demand is continuing to grow in our service area. As part of our long-term plan to diversify our reliance away from the Gulf Coast region, we are now receiving firm storage service from the Hardy Storage Company, LLC underground facility in West Virginia and firm transportation service from Midwestern that accesses gas supplies from Canada and the Rocky Mountains. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K and Note 3 to the consolidated financial statements.

 

During the year ended October 31, 2007, approximately 5% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under FERC regulations, certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2007, no bypass activity was experienced. The future level of bypass activity cannot be predicted.

 

The regulated utility competes in the residential and commercial customer markets with other energy products. The most significant competition is between natural gas and 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 reliability, comfort, convenience and environmental factors. Natural gas has historically maintained a price advantage over electricity in our service areas; however, with a tighter national supply and demand balance, wholesale natural gas prices and price volatility have increased over recent years. Increases in the price of natural gas can negatively impact our competitive position by decreasing or eliminating the price benefits of natural gas to the consumer.

 

As indicated above, many of our customers can utilize a fuel other than natural gas, and our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market prices of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our revenues could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

 

During the year ended October 31, 2007, our largest customer contributed $13.2 million, or less than 1%, to total operating revenues.

 

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

 

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

 

As of October 31, 2007, our fiscal year end, we had 1,876 employees, compared with 2,051 as of October 31, 2006.

 

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

 

Changes in federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacity and/or gas supply and thereby reduce our earnings.   The FERC has the power to regulate the interstate transportation of natural gas and the terms and conditions of service. Additionally, Congress has enacted laws that deregulate the price of natural gas sold at the wellhead. Any Congressional legislation or agency regulation that would alter these or other similar statutory and regulatory structures in a way to significantly raise costs that could not be recovered in rates from our customers, that would reduce the availability of supply or capacity, or that would reduce our competitiveness would negatively impact our earnings. Furthermore, Congress has for some time been considering various forms of climate change legislation. There is a possibility that, when and if enacted, the final form of such legislation could impact the company’s growth and put upward pressure on wholesale natural gas prices.

 

Weather conditions may cause our earnings to vary from year to year.   Our earnings can vary from year to year, depending in part on weather conditions. Currently, we have in place regulatory mechanisms that account for this and normalize our margin for weather, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. We estimate that approximately 50% to 60% of our annual gas sales are to temperature-sensitive customers. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell and deliver in any year. If our rates and tariffs were modified to eliminate weather protection, then we would be exposed to significant risk associated with weather and our earnings could vary as a result.

 

Governmental actions at the state level could result in lower earnings.   Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. If a state regulatory commission were to prohibit us from setting rates that timely recover our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers (including margin decoupling, weather normalization and cost of gas) or other tariff provisions, then our earnings could be impacted. Additionally, the state agencies foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there were changes in regulatory philosophies that altered our ability to compete for these customers, then we could lose customers, or incur significant unrecoverable expenses to retain them. Both scenarios would impact our earnings.

 

Operational interruptions to our gas distribution activities caused by accidents, strikes, severe weather such as a major hurricane, pandemic or acts of terrorism could adversely impact earnings.   Inherent in our gas distribution activities are a variety of hazards and operation risks, such as leaks, ruptures and mechanical problems that, if severe enough or led to operational interruptions, could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Additionally, we have a workforce that is partially represented by the union that exposes us to the risk of a strike. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.

 

Increases in our debt ratios could adversely affect our ability to service our debt obligations and our ability to access capital on favorable terms.   An increase in our leverage could adversely affect us by:

 

 

 

We do not generate sufficient cash flows to meet all our cash needs.   Historically, we have made large capital expenditures in order to finance the expansion and upgrading of our distribution system. We have also purchased and will continue to purchase natural gas to store in inventory. Moreover, we have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our revenues and profits. We have funded a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new securities in the market. Our dependency on external sources of financing creates the risks that our profits could decrease as a result of high capital costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us.

 

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.   The terms of our senior indebtedness, including our credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us.

 

We are exposed to credit risk of counterparties with whom we do business.   Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments or fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligation could adversely affect our financial position, results of operations or cash flows.

 

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.   Our costs of providing a non-contributory defined benefit pension plan is 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, future government regulation and our required or voluntary contributions made to the plan. Without sustained growth in the pension investments over time to increase the value of our plan assets and depending upon the other factors impacting our cost as listed above, 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 for clean-up costs and damages arising out of contaminated properties. Failure to comply may result in fines, penalties and injunctive measures affecting operating assets.

 

An overall economic downturn could negatively impact our earnings.   A lower level of economic activity in our markets could result in a decline in customer additions and energy consumption which could adversely affect our revenues or restrict our future growth. Additionally, a significant slow down in the housing market in our service area could restrict our future growth and negatively impact our earnings.

Our inability to attract and retain professional and technical employees could impact our earnings.   Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract and retain a technically skilled workforce. Without such a skilled workforce, our ability to provide quality service to our customers and meet our regulatory requirements will be challenged and this could negatively impact our earnings.

 

 

 

 

 

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, 2007, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

 

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the fourth quarter ended October 31, 2007.

 

 

 

Comparisons of Cumulative Total Shareholder Returns

 

The following performance graph compares the Company’s cumulative total shareholder return from October 31, 2002, through October 31, 2007 (a five-year period), with 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 the LDC Peer Group index.

 

The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2002, and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performances.

 

Comparisons of Five-Year Cumulative Total Returns
Value of $100 Invested as of October 31, 2002

 

 

 

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

 

 

 

 

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

 

Forward-looking statements are only as of the date they are made and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Please reference our website at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Overview

 

Piedmont Natural Gas Company is an energy services company whose principal business is the distribution of natural gas to residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments — the regulated utility segment and the non-utility activities segment.

 

The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the twelve months ended October 31, 2007, 79% of our earnings before taxes came from our regulated utility segment.

 

The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.

 

Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are generated during the winter season. During warm winters or unevenly cold winters, heating customers may significantly reduce their consumption of natural gas. In South Carolina and Tennesee, we have weather normalization adjustment (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 Customer Utilization Tracker (CUT) provides for the recovery of our approved margin from residential and commercial customers independent of both weather and other consumption patterns. For further information, see Note 3 to the consolidated financial statements.

 

The majority of our natural gas supplies come from the Gulf Coast region. We believe that diversification of our supply portfolio is in our customers’ best interest. In January 2008, we anticipate receiving firm, long-term transportation contract service from Midwestern Gas Transmission Company (Midwestern) that will provide access to Canadian and Rocky Mountain gas supplies and 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, LLC (Hardy Storage), a new storage facility in West Virginia.

 

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. Part of our strategic plan is to manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers and the pursuit of 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.

 

As part of our ongoing effort to improve business processes and customer service, and capture operational and organizational efficiencies, we are in the process of standardizing our customer payment and collection processes and streamlining business operations.

 

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.

Results of Operations

 

The following tables present our financial highlights for the years ended October 31, 2007, 2006 and 2005.

 

 

Net income increased $7.2 million in 2007 compared with 2006 primarily due to the following changes which increased net income:

 

 

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

 

 

Net income decreased $4.1 million in 2006 compared with 2005 primarily due to the following changes which decreased net income:

 

 

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

 

 

Operating revenues in 2007 decreased $213.3 million compared with 2006 primarily due to the following decreases:

 

 

These decreases were partially offset by the following increases:

 

 

Operating revenues in 2006 increased $163.5 million compared with 2005 primarily due to the following increases:

 

 

These increases were partially offset by the following decreases:

 

 

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.

 

Cost of gas in 2007 decreased $214 million compared with 2006 primarily due to decreases of $212.9 million from lower commodity gas costs passed through to sales customers.

 

Cost of gas in 2006 increased $139.2 million compared with 2005 primarily due to $197.8 million from increased commodity gas costs, partially offset by the following decreases:

 

 

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for upstream capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity gas costs, which account for approximately 62% of revenues for the twelve months ended October 31, 2007. The company is authorized to recover from customers all prudently incurred wholesale commodity gas costs.

 

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

 

Margin increased $.7 million in 2007 compared with 2006 primarily due to the following increases:

 

 

These increases were partially offset by the following decreases:

 

 

 

Margin increased $24.3 million in 2006 compared with 2005 primarily due to growth in the residential and commercial customer base, plus base rate increases of $22.8 million. This net increase was negatively impacted by decreased consumption because of conservation in the residential and commercial classes in South Carolina and Tennessee.

 

Operations and maintenance expenses decreased $4.9 million in 2007 compared with 2006 primarily due to the following decreases:

 

 

These decreases were partially offset by the following increases:

 

 

Operations and maintenance expenses increased $12.4 million in 2006 compared with 2005 primarily due to the following increases:

 

 

These increases were partially offset by the following decreases:

 

 

Depreciation expense increased from $85.2 million to $88.7 million over the three-year period 2005 to 2007 primarily due to increases in plant in service, partially offset by plant retirements of short-lived technology assets in 2007.

General taxes decreased $.7 million in 2007 compared with 2006 primarily due to the following changes:

 

 

General taxes increased $3.3 million in 2006 compared with 2005 primarily due to the following changes:

 

 

Income from equity method investments increased $7.2 million in 2007 compared with 2006 due to the following changes:

 

 

Income from equity method investments increased $2.3 million in 2006 compared with 2005 primarily due to increases in earnings from SouthStar of $.9 million, Pine Needle of $.3 million and Hardy Storage of $1 million.

 

The gain on sale of marketable securities of $1.5 million in 2005 resulted from the sale in February 2005 of common units of Energy Transfer Partners, L.P., which we received in connection with the sale of our propane interests in 2004.

 

Non-operating income is comprised of non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating income in 2005 included a pre-tax gain on the sale of the corporate office land of $1.7 million.

 

Charitable contributions decreased $1.4 million in 2006 compared with 2005 primarily due to the $1 million contribution made to the Piedmont Natural Gas Foundation in 2005.

 

Utility interest charges increased $5 million in 2007 compared with 2006 primarily due to the following changes:

 

 

Utility interest charges increased $8.1 million in 2006 compared with 2005 primarily due to the following changes:

 

 

Our Business

 

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 and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 62,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

 

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

 

We continually assess the nature of our business and explore alternatives in our core business of traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional opportunities and challenges for us. We also regularly evaluate opportunities for obtaining natural gas supplies from different production regions and supply sources to maximize our natural gas portfolio flexibility and reliability. For further information, see “Gas Supply and Regulatory Proceedings” below and Note 3 and Note 6 to the consolidated financial statements.

 

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 12 to the consolidated financial statements.

 

Our utility operations are regulated by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the FERC that affect the availability of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

 

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.

 

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially offset the impact of colder-than-normal or warmer-than-normal weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the WNA. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin from residential and commercial customers independent of both weather and other consumption patterns. The CUT tracks our margin earned monthly and results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. For further information on the CUT, see Note 3 to the consolidated financial statements.

 

We invest in joint ventures to complement or supplement income from our regulated utility operations. If an opportunity aligns with our overall business strategies and allows us to leverage the strengths of our markets along with our core abilities, we analyze and evaluate the project with a major factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding existing joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

 

Financial Condition and 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. We believe that these sources will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions and dividend payments.

 

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 such factors as weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas in storage and the collection of amounts billed to customers during the peak heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, paying down short-term debt and decreases in receipts from customers.

 

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

 

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to

reduce their heating bills. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

 

Net cash provided by operating activities was $233.5 million in 2007, $103.8 million in 2006 and $183.4 million in 2005. Net cash provided by operating activities reflects a $7.2 million increase in net income for 2007, compared with 2006, as well as changes in working capital as described below:

 

 

Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have had a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder-than-normal 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 charges to customers of $6.4 million in 2007, $4.1 million in 2006 and $3.7 million in 2005. In Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or refund to all customers in the class. Effective November 1, 2005, we have a CUT mechanism in North Carolina that provides for any over- or under-collection of approved margin per customer that operates independently of both weather and consumption patterns of residential and commercial customers. The CUT mechanism provided margin of $32.7 million in 2007 and $30.4 million in 2006 as compared to North Carolina WNA that generated charges to customers of $4.7 million in 2005. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the CUT.

 

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 commission approval in North Carolina, South Carolina and Tennessee that places additional 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, such as price volatility, the availability of natural gas in relation to other energy forms, general economic conditions, weather, energy conservation, conservation and energy efficiency programs approved by regulatory bodies and the ability to convert from natural gas to other energy sources. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer.

This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

 

In an effort to keep customer rates competitive by holding down operations and maintenance costs and as part of an ongoing effort aimed at improving business processes, capturing operational and organizational efficiencies and improving customer service, we are continuing the process of standardizing our customer payment and collection processes, streamlining business operations and further consolidating our call centers. We estimate termination benefits to employees of $3.6 million over the next four years which was recorded in 2007 resulting from this business process improvement initiative.

 

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 growth in consumption exceeding growth of supply resulting in a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments and organizations. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

 

Cash Flows from Investing Activities.   Net cash used in investing activities was $148.2 million in 2007, $167.6 million in 2006 and $159 million in 2005. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $135.2 million in 2007, a 34% decrease from the $204.1 million in 2006, primarily due to the automated meter reading project in the prior year. Reimbursements from the bond fund decreased $13.9 million in 2006 from 2005 as construction of gas infrastructure in eastern North Carolina has now been completed. For further information about the bond fund, see Note 3 to the consolidated financial statements.

 

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. Gross utility construction expenditures totaling $168.5 million, primarily to serve customer growth, are budgeted for 2008; however, we are not contractually obligated to expend capital until the work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

 

During 2007, we contributed $12.9 million to Hardy Storage Company LLC, a joint venture investee of one of our non-utility subsidiaries, as part of our equity contribution for construction of a FERC regulated interstate storage facility. On November 1, 2007 and December 3, 2007, we contributed an additional $8.8 million to Hardy Storage, which brought our investment in Hardy Storage to $21.7 million. We anticipate contributing up to an additional $8.3 million to Hardy Storage during the fiscal 2008 year. To the extent that more funding is needed, the members will evaluate funding options at that time.

 

During 2007, $2.2 million of supplier refunds was recorded as restricted funds. 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 all customers 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.

 

On May 12, 2005, we sold our corporate office building located in Charlotte, North Carolina for $6.7 million in cash, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land as a pre-tax gain of $1.7 million in “Other Income (Expense)” in the consolidated statement of income and a loss of $1.8 million on the disposition of the building as a charge to “Accumulated depreciation” in the consolidated balance sheet, based on the sales price allocation from an independent third party. Under the terms of the purchase and sale agreement, we leased back the building from the new owner until our new office space was ready for occupancy. We relocated to our new office space in November 2005 under a

negotiated ten-year lease with renewal options. The lease payments for the ten-year term range from $3 million to $3.4 million annually.

 

We received $2.4 million in cash in 2005 from the sale of marketable securities which we received in connection with the sale of our propane interests in 2004.

 

Cash Flows from Financing Activities.   Net cash provided by (used in) financing activities was $(86.6) million in 2007, $65.6 million in 2006 and $(22.9) million in 2005. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and employee stock plans, net of purchases under the common stock repurchase program. When required, we sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term borrowings, to repurchase common stock under the common stock repurchase program, and the payment of quarterly dividends on our common stock. As of October 31, 2007, our current assets were $435.3 million and our current liabilities were $424.5 million, primarily due to seasonal requirements as discussed above.

 

As of October 31, 2007, we had committed lines of credit under our senior credit facility effective April 24, 2006 of $350 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 $350 million. Outstanding short-term borrowings increased from $170 million as of October 31, 2006 to $195.5 million as of October 31, 2007, primarily due to our commitment to fill storage capacity under various contracts. During the twelve months ended October 31, 2007, short-term borrowings ranged from zero to $280.5 million, and when borrowing, interest rates ranged from 4.96% to 6.08% (weighted average of 5.57%).

 

As of October 31, 2007, under our credit facility, we had available letters of credit of $5 million of which $1.5 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. Effective November 1, 2007, the letters of credit were increased to $1.9 million.

 

As of October 31, 2007, including the issuance of the letters of credit, unused lines of credit available under our senior credit facility totaled $153 million.

 

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. With higher wholesale gas prices, we may incur more short-term debt to pay 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.

 

During 2007, we issued $15.8 million of common stock through dividend reinvestment and stock purchase plans. On November 7, 2006, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $26.6 million. On January 19, 2007, we settled the transaction and paid an additional $.8 million. On April 2, 2007, through an ASR agreement, we repurchased and retired 850,000 shares of common stock for $22.5 million. On May 23, 2007, we settled the transaction and paid an additional $.4 million. During 2007 under the ASR and the Common Stock Open Market Purchase Program discussed in Note 5 to the consolidated financial statements, we paid $54.2 million for 2 million shares of common stock that are available for reissuance to these plans. During 2006, 2.1 million shares were repurchased for $50.2 million. During 2005, 1.1 million shares were repurchased for $26.1 million.

 

On November 1, 2007, we entered into another ASR agreement. On November 2, 2007, we purchased and retired 1 million shares of our common stock from an investment bank at the closing price of $24.70 per share. Total consideration paid to purchase the shares was $24.8 million, including $92,500 in commission and fees. Through December 14, 2007, the investment bank had purchased 708,000 shares at a cumulative weighted average price of $25.8733 per share.

 

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 on November 1, 2007, we

have repurchased 3,850,000 shares as follows: one million shares repurchased in April 2006, one million shares repurchased in November 2006, 850,000 shares repurchased in March 2007 and one million shares repurchased on November 1, 2007. These shares are in addition to shares that are repurchased on a normal basis through the open market program.

 

We increased our common stock dividend on an annualized basis by $.04 per share in 2007, $.05 per share in 2006 and $.06 per share in 2005. Dividends of $73.6 million, $72.1 million and $69.4 million for 2007, 2006 and 2005, respectively, were paid on common stock. 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; however, as of October 31, 2007, our retained earnings were not restricted. For further information, see Note 4 to the consolidated financial statements.

 

We have a shelf registration statement that can be used for either debt or equity filed with the SEC. The remaining balance of unused long-term financing available under this shelf registration statement as of October 31, 2007 is $109.4 million. Under this shelf registration, we sold $200 million of long-term debt on June 20, 2006 that was used to pay off $188 million of short-term debt on June 20 and to pay off a portion of the $35 million sinking fund on the 9.44% Senior Notes due July 30, 2006.

 

Our long-term targeted capitalization ratio is 45% to 50% in long-term debt and 50% to 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, 2007, our capitalization consisted of 48% in long-term debt and 52% in common equity.

 

The components of our total debt outstanding to our total capitalization as of October 31, 2007 and 2006 are summarized in the table below.

 

 

As of October 31, 2007, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

 

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:

 

 

Qualitative factors include, among other things:

 

 

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

 

 

The default provisions of our medium-term notes are:

 

 

There are cross-default provisions in all of our debt agreements, and thus event of default under one agreement may result in total outstanding issues of debt becoming due. As of October 31, 2007, we are in compliance with all default provisions.

As of October 31, 2007, our estimated future contractual obligations were as follows.

 

 

 

 

Off-balance Sheet Arrangements

 

We have no off-balance sheet arrangements other than operating leases that are reflected in the table above and discussed in Note 7 to the consolidated financial statements.

 

Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded $1.3 million and $1.8 million as of October 31, 2007 and 2006, 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 11 to the consolidated financial statements.

 

Critical Accounting Policies and Estimates

 

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

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 has discussed the selection and development of the critical accounting policies and estimates presented below with the Audit Committee of the Board of Directors.

 

Regulatory Accounting.   Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71), and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues 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. Regulatory assets as of October 31, 2007 and 2006, totaled $134 million and $143.5 million, respectively. Regulatory liabilities as of October 31, 2007 and 2006, totaled $374 million and $337 million, respectively. The detail of these regulatory assets and liabilities is presented in Note 1.B to the consolidated financial statements.

 

Revenue Recognition.   Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. Through October 31, 2005, a WNA factor, based on the margin or base rate component of the billing rate, was included in rates charged to residential and commercial customers during the winter period of November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact of warmer-than-normal or colder-than-normal weather on customer billings during the winter season. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin from residential and commercial customers independent of both weather and other consumption patterns. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. Without the CUT or WNA, our operating revenues in 2007, 2006 and 2005 would have been lower by $39.1 million, $34.6 million and $8.4 million, respectively.

 

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 approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, changes in weather during the period and the impact of the WNA or CUT mechanisms, as applicable. Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on contract or market prices.

 

Pension and Postretirement Benefits.   We have a defined-benefit pension plan for the benefit of eligible full-time employees. We also provide certain postretirement health care and life insurance benefits to eligible full-time employees. Our reported costs of providing these benefits, as described in Note 8 to the consolidated financial statements, are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.

Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.

 

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s AA or better-rated non-callable bonds. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plans changed from 5.78% in 2006 to 6.43% in 2007. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 5.67% in 2006 to 6.06% in 2007. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 5.74% in 2006 to 6.25% in 2007. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we changed our health care cost trend rate from 9% in 2006 to 8.5% in 2007, declining gradually to 5% in 2012.

 

In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 60% equity securities and 40% fixed income securities. The expected long-term rate of return on plan assets was 8.5% in 2005, 2006 and 2007, and will be changed to 8% in 2008. Based on a fairly stagnant inflation trend, our age-related assumed rate of increase in future compensation levels was 4.05% in 2005 and decreased to 4.01% in 2006 and 3.99% in 2007 due to changes in the demographics of the participants.

 

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.

 

 

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.

 

 

We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

Gas Supply and Regulatory Proceedings

 

We continue to pursue the diversification of our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. In January 2008, we anticipate that we will receive firm, long-term transportation service from Midwestern of 120,000 dekatherms per day that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. We are currently using 40,000 dekatherms per day of this capacity under a short-term agreement with the above mentioned contract anticipated to become available in January 2008. As of April 2007, we began receiving firm, long-term market-area storage service from Hardy Storage in West Virginia that will provide 39,100 dekatherms per day of withdrawal service for the winter of 2007-2008. Hardy Storage withdrawal capabilities will increase over three phases. Phase 1 (2007-2008 heating season) began at 57% of capacity, phase 2 (2008-2009 heating season) is planned at 85% of capacity, and phase 3 (2009-2010 heating season) is planned at 100% of capacity. We have a 50% equity interest in this project which is more fully discussed in Note 11 to the consolidated financial statements.

 

Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit wholesale margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. A sharing mechanism is in effect where 75% of any margin is passed through to customers in all of our jurisdictions. However, secondary market transactions in Tennessee are included in the performance incentive plan discussed in Note 3 to the consolidated financial statements.

 

Regulatory proceedings in South Carolina under the South Carolina Rate Stabilization Act were completed during 2007 that will impact 2008 earnings by decreasing annual margin by $2.5 million based on an 11.2% return on equity effective November 1, 2007. For further information about these regulatory proceedings and other regulatory information, see Note 3 to the consolidated financial statements.

 

In the November 2005 North Carolina general rate case order, the CUT was established as an experimental tariff for a three-year period ending November 1, 2008, subject to review in a future general rate case. In accordance with that requirement, it is our intent to file a general rate case in North Carolina to be effective November 1, 2008.

 

Equity Method Investments

 

For information about our equity method investments, see Note 11 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 7 to the consolidated financial statements.

 

Accounting Pronouncements

 

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes,” and in May 2007 issued Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48,” (FSP 48-1). FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure

and transition requirements in accounting for uncertain tax positions. FSP 48-1 clarifies when a tax position is considered effectively settled under FIN 48. FIN 48 is effective the beginning of the first annual period beginning after December 15, 2006, and the guidance under FSP 48-1 should be applied upon the adoption of FIN 48. Accordingly, we will adopt FIN 48 and FSP 48-1 in our fiscal year 2008. We have assessed the impact FIN 48 may have on our consolidated financial statements. The adoption will not have a material impact on our financial position, results of operations or cash flows.

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under Statement 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. On November 14, 2007, the FASB delayed 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 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.

 

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158). Statement 158 requires an employer to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in the financial statements by recognizing in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status rather than only disclosing the funded status in the footnotes to the financial statements. Statement 158 requires employers to recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Under Statement 158, gains and losses, prior service costs and credits, and any remaining transition amounts that have not yet been recognized through net periodic benefit cost will be recognized in accumulated other comprehensive income (OCI), net of tax effects, until they are amortized as a component of net periodic cost. Statement 158 also requires that the company measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year. We are already in compliance with this requirement as our pension plans’ measurement dates are already the same as our fiscal year end date.

 

The requirement to recognize the funded status of a benefit plan and the related disclosure requirements applied as of the end of the fiscal year ending after December 15, 2006. Accordingly, we adopted the funded status portion of Statement 158 as of October 31, 2007. Adoption of Statement 158 on our financial position is shown below. The adoption of Statement 158 did not have a material effect on our results of operations or cash flows.

 

In August 2007, we filed petitions with the NCUC, the PSCSC and the TRA requesting the ability to place certain defined benefit postretirement obligations related to the implementation of Statement 158 in a regulatory deferred account instead of OCI. The petitions have been approved in all of the jurisdictions.

Based on the measurement of the various postretirement plans’ assets and benefit obligations as of October 31, 2007, the effect on our consolidated balance sheet of adopting Statement 158 is as follows.

 

 

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (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 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 159 will not have a material impact on our financial position, results of operations or cash flows.

 

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 $1.2 million during 2007.

 

As of October 31, 2007, information about our long-term debt is presented below.

 

 

Commodity Price Risk

 

We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. In the normal course of business, we utilize exchange-traded contracts of various duration for the forward purchase of a portion of our natural gas requirements. Due to cost-based rate regulation in our utility operations, our prudently incurred purchased gas costs and the prudently incurred costs of hedging our gas supplies are passed on to customers through PGA procedures.

 

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

 

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (“Piedmont”) as of October 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2007. These financial statements are the responsibility of Piedmont’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

 

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

 

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

 

As discussed in Note 8 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective October 31, 2007.

 

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, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated December 28, 2007 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 

 

Charlotte, North Carolina

December 28, 2007