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Piedmont Natural Gas Company 10-K 2011 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549
FORM 10-K (Mark One)
For the fiscal year ended October 31, 2011 or
For the transition period from to Commission file number 1-6196
Piedmont Natural Gas Company, Inc. (Exact name of registrant as specified in its charter)
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 x No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to section 13 or 15 (d) of the Act. Yes ¨ No x 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 x No ¨ 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 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. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2011. Common Stock, no par value - $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.
DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 8, 2012 are incorporated by reference into Part III.
Table of ContentsPiedmont Natural Gas Company, Inc. 2011 FORM 10-K ANNUAL REPORT
Table of ContentsPART I Item 1. Business Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina. Piedmont is an energy services company 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 51,800 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, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna. We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated segment include 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 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 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 12 and Note 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 through 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, 2011, 46% of our operating revenues were from residential customers, 27% from commercial customers, 10% from large volume customers, including industrial, power generation and resale customers, and 17% from secondary market activities. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our utility gas supply management program with regulator-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.”
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Table of ContentsOur 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. The NCUC also regulates 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 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 December 2011 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. Twenty-one franchise agreements have expired as of October 31, 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. 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 this Form 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 heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2011, the amount of natural gas in storage varied from 14.6 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 26.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $75.9 million to $133.2 million. During the year ended October 31, 2011, 181.2 million dekatherms of gas were sold to or transported for large volume customers compared with 154.3 million dekatherms in 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
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Table of Contentsand commercial customers, whose consumption varies with the weather, totaled 98.5 million dekatherms in 2011, compared with 98.3 million dekatherms in 2010. Weather, as measured by degree days, was 10% colder than normal in 2011 and 6% colder than normal in 2010. The following is a five-year comparison of operating statistics for the years ended October 31, 2007 through 2011.
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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, 2011, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.
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Table of ContentsAs of October 31, 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 from 5 days to one year.
As of October 31, 2011, we own or have under contract 36.1 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, particularly from power generation customers. To diversify our reliance away from the Gulf Coast region, we receive firm, long-term market area storage service from Hardy Storage Company, LLC (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 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 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. However, 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 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%.
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Table of ContentsWe 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, 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, 2011, no bypass occurred. The future level of bypass activity cannot be predicted. 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 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. The 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 in our market area. During the year ended October 31, 2011, our largest revenue generating customer contributed $49.5 million, or 3%, of total operating revenues. 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.
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Table of ContentsCompliance 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 this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. As of October 31, 2011, our fiscal year end, we had 1,782 employees compared with 1,788 as of October 31, 2010. Our reports on Form 10-K, Form 10-Q and Form 8-K, and any 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 (SEC). Item 1A. Risk Factors An 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. 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 to 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 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 high, our working capital costs could increase due to higher carrying costs of gas storage inventories, and customers may have trouble paying higher bills leading to bad debt expenses, which may reduce our earnings.
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Table of ContentsA decrease in the availability of adequate interstate pipeline transportation capacity and natural gas supply could reduce our earnings. We purchase all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to that supply or interstate pipeline capacity due to unforeseen events, including but not limited to, 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 and 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.
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Table of ContentsChanges 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 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, the Commodities Futures Trading Commission under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. Any federal legislation or agency regulation that has the effect of significantly raising costs that could not be recovered in rates from our customers or reducing the availability of supply or capacity, the liquidity of the natural gas supply market or our competitiveness could negatively impact our earnings. 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, including 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, if enacted or adopted, such legislation or regulation could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings. Regulatory 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 recovery 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, our 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
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Table of Contentsalternative 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. Our 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 recovery of these costs of gas supply procurement or risk management activities is excluded by our regulators in gas cost recovery proceedings. Operational interruptions to our gas distribution and transmission activities caused by accidents, work stoppage, severe weather conditions, including destructive weather patterns such as 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 the 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. Our 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 represented by unions, we are exposed to the risk of a work stoppage. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.
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Table of ContentsWe 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 obtain required approval from local, state and/or federal 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 our credit ratings could negatively affect our cost of and ability to access capital. Our ability to obtain adequate and cost effective financing depends on our credit 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. Such 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 ability 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.
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Table of ContentsChanges 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 systems. We also purchase natural gas for storage. 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 growth and profitability. We fund 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 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 cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of 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 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, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.
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Table of ContentsWe 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 to 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. The cost of providing pension benefits is subject to changes in pension fund values and other factors and could unfavorably impact our liquidity and results of operations. Our costs of providing a 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. Changes 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, 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 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. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations 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 customers. 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 material adverse effect on our business, results of operations or financial condition.
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Table of ContentsWe may invest in companies that have risks that are inherent in their businesses, and these 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 earnings from or return of our investment in these businesses. We could make future investments in similarly unregulated businesses that have the similar potential to adversely affect our earnings from or return of our investment in those businesses. All these adverse impacts could negatively affect our results of operations or financial condition. Our inability to attract and retain professional and technical employees could adversely 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 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 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. 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.
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Table of ContentsItem 1B. Unresolved Staff Comments None. 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 2,700 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 22,000 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near 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 such 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 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 our resource centers in the locations shown below. Lease payments for these various offices totaled $4 million for the year ended October 31, 2011.
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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 natural gas water heaters leased to commercial 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. We have only routine immaterial litigation in the normal course of business. Item 4. (Removed and Reserved)
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Table of ContentsPART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 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, 2011 and 2010.
Holders As of December 16, 2011, our common stock was owned by 13,916 shareholders of record. 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, 2011 and 2010. We expect that comparable cash dividends will continue to be paid in the future.
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, 2011, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.
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Table of ContentsShare Repurchases The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2011.
Comparisons of Cumulative Total Shareholder Returns The following performance graph compares our cumulative total shareholder return from October 31, 2006 through October 31, 2011 (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). 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.
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Table of ContentsThe graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2006 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.
LDC Peer 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. Item 6. Selected Financial Data The following table provides selected financial data for the years ended October 31, 2007 through 2011.
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Table of ContentsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Forward-Looking Statements This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and 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 the following, as well as those discussed in Item 1A. Risk Factors:
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Table of ContentsOther 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,” “assume,” “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 based 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. 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 SEC. Executive Overview Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 51,800 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, 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 year ended October 31, 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 12 and Note 14, respectively, to the consolidated financial statements.
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Table of ContentsOur utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates 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 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 results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal 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 increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is 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 changing 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 utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and
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Table of ContentsTennessee; and volumetric or periodic renegotiation of 12% of our utility margins. For the twelve months ended October 31, 2011, the margin decoupling mechanism in North Carolina reduced margin by $7 million, and the WNA in South Carolina and Tennessee 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 charges to all customers that would be effective March 1, 2012. We also requested 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 plant and changes to the existing service regulations and tariffs. For further information, see Note 2 to the consolidated financial statements. We have refined our strategic objectives to a customer-centered approach and what we believe is the inherent benefit of natural gas compared 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 technology. We want our customers to choose us because of the value of natural gas and the quality of our service to them. We strive to achieve excellence in 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 wake 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.
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Table of ContentsThe 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. Price 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%.
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Table of ContentsWe 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 our success 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 our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs. 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 projected rates of return commensurate with the 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 Several new laws were enacted in 2010 for health care reform and the regulation of U.S. financial markets. We continue to follow the progress of new regulations that are being issued and will be issued by various regulatory agencies. While we are not able to assess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material impact on our financial position, results of operations or cash flows. Also, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, 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 100% 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 law. 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 cash flows in the near term by reducing cash needed to pay federal income taxes.
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Table of ContentsResults of Operations The following tables present our financial highlights for the years ended October 31, 2011, 2010 and 2009. Income Statement Components
Gas Deliveries, Customers, Weather Statistics and Number of Employees
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Table of ContentsNet Income Net income decreased $28.4 million in 2011 compared with 2010 primarily due to the following changes which decreased net income:
These changes were partially offset by the following changes, which increased net income:
Net income increased $19.1 million in 2010 compared with 2009 primarily due to the following changes which increased net income:
These changes were partially offset by the following changes, which decreased net income:
Operating Revenues Operating revenues in 2011 decreased $118.4 million compared with 2010 primarily due to the following decreases:
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Table of ContentsThese decreases were partially offset by the following increases:
Operating revenues in 2010 decreased $85.8 million compared with 2009 primarily due to the following decreases:
These decreases were partially offset by the following increases:
Cost of Gas Cost of gas in 2011 decreased $139.4 million compared with 2010 primarily due to the following decreases:
These decreases were partially offset by the following increases:
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:
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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 passthrough of changes in wholesale commodity gas costs, which accounted for 47% of revenues for the twelve months ended October 31, 2011, and transportation and storage costs, which accounted for 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 in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the recovery 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 $21 million in 2011 compared with 2010 primarily due to the following increases:
Margin decreased $9 million in 2010 compared with 2009 primarily due to the following decreases:
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Operations and Maintenance Expenses Operations and maintenance expenses increased $5.5 million in 2011 compared with 2010 primarily due to the following increases:
Operations and maintenance expenses increased $11.7 million in 2010 compared with 2009 primarily due to the following increases:
Depreciation Depreciation expense increased from $97.4 million to $102.8 million over the three-year period 2009 to 2011 primarily due to increases in plant in service. General Taxes General taxes increased $4.5 million in 2011 compared with 2010 primarily due to the following increases:
General taxes decreased by an insignificant amount in 2010 compared with 2009.
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Table of ContentsOther 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 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 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 $4.8 million in 2011 compared with 2010 primarily due to a decrease of $4.5 million in earnings from SouthStar due to a full year of recording earnings at the 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 decreased $4.6 million in 2010 compared with 2009 due to a $4.5 million decrease in earnings from SouthStar primarily due to the 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 $.3 million in 2011 compared with 2010 primarily due to the following changes:
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Utility interest charges decreased $3 million in 2010 compared with 2009 primarily due to the following changes:
Financial Condition and Liquidity To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchases and 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%.
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Table of ContentsOur 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
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.
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Table of ContentsAs 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. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, seasonal construction activity and decreases in receipts from customers. During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity 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 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 weak economy, including continued high unemployment, we may incur additional bad debt expense 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, are expected to mitigate the impact these factors may have on our results of operations.
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Table of ContentsNet cash provided by operating activities was $311.2 million in 2011, $360.5 million in 2010 and $344.3 million in 2009. Net cash provided by operating activities reflects a $28.4 million decrease in net income for 2011 compared with 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:
Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated credits to customers of $4.9 million in 2011, $8.8 million in 2010 and $1.2 million in 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 “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism reduced margin by $7 million in 2011 and $5.9 million in 2010 and increased margin by $6 million in 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.
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Table of ContentsThe regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings. In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers. In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and operations and maintenance cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system. Cash Flows from Investing Activities. Net cash used in investing activities was $252.6 million in 2011, $128.6 million in 2010 and $129.6 million in 2009. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $243.6 million in 2011, a 22% increase from the $199.1 million in 2010, primarily due to $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. Significant utility construction expenditures are expected 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.
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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 previously announced Robeson liquefied natural gas storage project. The timing and design scope of the expansion of our facilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate. During the first quarter of fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a 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.
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Table of ContentsOn 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 received $57.5 million from GNGC. For further information regarding the sale, see Note 12 to the consolidated financial statements. In 2009, we contributed $.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. We made no contributions in 2010 and 2011 as Hardy 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 consolidated financial statements. Cash Flows from Financing Activities. Net cash used in financing activities was $57.5 million in 2011, $233.9 million in 2010 and $214.1 million in 2009. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock 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, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock. As of October 31, 2011, our current assets were $286 million and our current liabilities were $534.1 million, primarily due to seasonal requirements as discussed above. Outstanding short-term bank borrowings increased from $242 million as of October 31, 2010 to $331 million as of October 31, 2011 primarily due to higher capital expenditures and long-term debt maturities. Over the three-year period from 2009 to 2011, our short-term borrowings have included the replacement of our five-year revolving syndicated credit facility with our current three-year revolving syndicated credit facility and a syndicated seasonal credit facility in existence from December 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 retired our $60 million 6.55% medium-term notes, $60 million 7.8% medium-term notes and $30 million 7.35% medium-term notes in September 2011, September 2010 and September 2009, respectively, as they became due. On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal balance of $196.8 million with short-term bank borrowings under 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 reduce 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 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.
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Table of ContentsWe plan to issue approximately $300 million of 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 fiscal year 2012. During 2011, we issued $20.2 million of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. During 2010 and 2009, we issued $19.1 million and $14.4 million, respectively, through these plans. 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 2011, 2010 and 2009. Dividends of $82.9 million, $80.3 million and $78.4 million for 2011, 2010 and 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, 2011, our retained earnings were not restricted. On December 16, 2011, the Board of Directors declared a quarterly dividend on common stock of $.29 per share, payable January 13, 2012 to shareholders of record at the close of business on December 27, 2011. For further information, see Note 4 to the consolidated financial statements. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. As of October 31, 2011, our capitalization, including current maturities of long-term debt, if any, consisted of 40% in long-term debt and 60% in common equity. The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2011 and 2010 are summarized in the table below.
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Table of ContentsCredit 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:
Qualitative factors include, among other things:
As of October 31, 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. 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 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, 2011, there has been no event of default giving rise to acceleration of our debt. The default provisions of some or all of our senior debt include:
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Table of ContentsContractual Obligations and Commitments We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2011, our estimated recorded and unrecorded contractual obligations are as follows.
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Table of ContentsOff-balance Sheet Arrangements We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit and operating leases are discussed in Note 5 and Note 8, respectively, to the consolidated financial statements and are reflected in the table above. 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 the 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.
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Table of ContentsRegulatory assets as of October 31, 2011 and 2010 totaled $200.1 million and $197.8 million, respectively. Regulatory liabilities as of October 31, 2011 and 2010 totaled $467 million and $439.1 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 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 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 results in semi-annual rate adjustments to refund any over-collection or 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 and margin decoupling mechanisms, our operating revenues in 2011 and 2010 would have been higher by $11.9 million and $14.7 million, respectively, and lower by $4.8 million 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 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, 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. We have a traditional defined benefit pension plan (qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 9 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
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Table of Contentslower 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, 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 5.47% in 2010 to 4.67% in 2011. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 4.37% in 2010 to 4.10% in 2011. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 4.85% in 2010 to 4.36% in 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, the initial health care cost trend rate was assumed to be 7.80% in 2011 declining gradually to 5% 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 50% equity securities and 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% in 2009, 2010 and 2011. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.92% in 2009, decreasing to 3.87% in 2010 and further decreasing to 3.78% in 2011 due to changes in the demographics of the participants. 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.
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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 accounting methods consistently applied that are allowed under GAAP 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 The source of our gas supply that we 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 our long-term plan to diversify our reliance away from the Gulf Coast region, we have 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 that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. Natural gas demand is continuing to grow in our service area, particularly to provide natural gas delivery service to existing and future 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 12 to the consolidated financial statements.
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Table of ContentsSecondary 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 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. For further information on secondary market transactions, see Note 2 to the consolidated financial statements. We continue to work with our regulatory commissions to earn a fair rate of return for our shareholders and provide safe, reliable natural gas distribution service to our 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 12 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 8 to the consolidated financial statements. Accounting Guidance For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements. International Financial Reporting Standards (IFRS) In 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 remaining as the U.S. accounting standard setter. In November 2011, the SEC released two more Staff Papers as part of their work plan. The first paper was the SEC 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
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Table of Contentssufficient detail or clarity in the accounting policy disclosures; and (2) Diversity in the application of IFRS made comparability challenging with the diversity 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 IFRS with an inventorying 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 account for transactions across industries with limited specific guidance and stated exceptions and that fundamental differences exist between conceptual frameworks, including the level of authority and the definition and recognition of assets and liabilities. The Staff Paper provided a broad comparison of the requirements of both accounting standards, highlighting notable differences, but did not provide an analysis of the impact of those differences on the quality of IFRS. Although the SEC was expected to vote by the end 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 re-assessed when the SEC makes its final determination on the use of IFRS. Item 7A. Quantitative and Qualitative Disclosures about Market Risk We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with defined policies and procedures under an Enterprise Risk Management 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. In 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 and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
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Table of ContentsWe also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We have mitigated 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 our high risk customers that do not satisfy our predetermined credit 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, 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, 2011, we had $331 million of short-term debt outstanding under our syndicated revolving credit facility at an interest rate of 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 $2 million during 2011. As of October 31, 2011, information about our long-term debt is presented below.
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Table of ContentsCommodity Price Risk We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. As such, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers. We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments and have used over-the-counter instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval. 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 are designed to offset the impact of colder-than-normal or warmer-than-normal 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.
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Table of ContentsAdditional information concerning market risk is set forth 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. 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 this Form 10-K.
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Table of ContentsREPORT 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, 2011 and 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, 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 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, 2011, 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 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting. /s/ Deloitte & Touche LLP Charlotte, North Carolina December 23, 2011
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Table of ContentsConsolidated Balance Sheets October 31, 2011 and 2010 ASSETS
See notes to consolidated financial statements.
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Table of ContentsConsolidated Balance Sheets October 31, 2011 and 2010 CAPITALIZATION AND LIABILITIES
See notes to consolidated financial statements.
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Table of ContentsConsolidated Statements of Income For the Years Ended October 31, 2011, 2010 and 2009
See notes to consolidated financial statements.
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Table of ContentsConsolidated Statements of Cash Flows For the Years Ended October 31, 2011, 2010 and 2009
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Table of ContentsConsolidated Statements of Cash Flows For the Years Ended October 31, 2011, 2010 and 2009
See notes to consolidated financial statements.
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Table of ContentsConsolidated Statements of Stockholders’ Equity For the Years Ended October 31, 2011, 2010 and 2009
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Table of ContentsConsolidated Statements of Stockholders’ Equity For the Years Ended October 31, 2011, 2010 and 2009
The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 2011 and 2010 are as follows.
See notes to consolidated financial statements.
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Table of ContentsNotes to Consolidated Financial Statements 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 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 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 12 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 accounting regulations prescribed under rate-based regulation. We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware have been evaluated. 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.
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Table of ContentsSegment 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 Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings. Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 2011 and 2010 are presented below.
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