Item 1. Business
Piedmont Natural Gas Company, Inc., incorporated in 1950, is an energy services company primarily engaged in the distribution of natural gas to 740,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. We are the second-largest natural gas utility in the Southeast. Piedmont is also invested in a number of non-utility, energy-related businesses, including companies involved in unregulated retail natural gas and propane marketing and interstate and intrastate natural gas storage and transportation. We also sell residential and commercial gas appliances in Tennessee.
In the Carolinas, our service area is comprised of numerous cities, towns and communities including Anderson, Greenville, Spartanburg and Gaffney in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine and Reidsville in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville.
We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Based on products and services and regulatory environments, operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Greenbrier Pipeline Company through their investments in ventures accounted for under the equity method. Piedmont Intrastate is a 16.45% member of Cardinal Pipeline Company, L.L.C., which owns and operates a 104-mile intrastate natural gas pipeline in North Carolina. Piedmont Interstate is a 35% member of Pine Needle LNG Company, L.L.C., which owns a liquefied natural gas (LNG) storage facility in North Carolina. Piedmont Greenbrier Pipeline has a 33% equity interest in Greenbrier Pipeline Company, LLC, which proposes to build a 280-mile interstate gas pipeline originating in West Virginia and extending through Virginia to North Carolina. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company through its 30% interest in SouthStar Energy Services LLC, accounted for under the equity method. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States.
Our propane activities are conducted by Piedmont Propane Company through its ownership of 20.69% of the membership interest in US Propane, L.P., accounted for under the equity method. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P.
Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. The cost of purchased gas is a component of operating revenues. Increases or decreases in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. Operating revenues for the year ended October 31, 2002, totaled $832 million, of which 43% was from residential customers, 23% from commercial customers, 12% from industrial and power generation customers, 21% from secondary market activity and 1% from various other sources. Revenues from non-utility operations, less related costs, are shown in “Other Income (Expense)” in the statements of consolidated income in “Non-utility activities, at equity” or “Other.” For further information on equity investments and segments, see Notes 9 and 10 to the consolidated financial statements beginning on page 50 in Item 8 of this report.
Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also subject to regulation by the NCUC as to the issuance of securities. We are also subject to or affected by various federal and state regulations.
We hold non-exclusive franchises for natural gas service in more than 90 communities we serve, with expiration dates from 2003 to 2050. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. Two franchises that expired in 2000 and one franchise that expired in 2002 are currently being negotiated; however, we continue to operate in those areas with no significant impact on our business. We believe that these franchises will be renewed with no material adverse impact on us. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action. In most cases, the loss of a franchise would not have a material effect on operations.
Our utility business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months. We normally inject natural gas into storage during summer months (principally April 1 through October 31) for withdrawal from storage during winter months (principally November 1 through March 31) when customer demand is higher. During the year ended October 31, 2002, the amount of natural gas in storage varied from 4.9 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 22.2 million dekatherms, and the aggregate commodity cost of this gas in
storage varied from $17.2 million to $91.7 million.
The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1998 through 2002:
During the year ended October 31, 2002, 60.1 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 55.5 million dekatherms in 2001. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 65.9 million dekatherms in 2002, compared with 78.9 million dekatherms in 2001. Weather, as measured by degree days, was 15% warmer than normal in 2002 and 8% colder than normal in 2001.
As of November 1, 2002, we have contracted for the following pipeline firm transportation capacity in dekatherms of daily deliverability:
In addition, we have the following seasonal or peaking capacity in dekatherms of daily deliverability through local peaking facilities and storage contracts to meet the firm demands of our markets. This availability varies from five days to one year:
We own or have under contract 25.3 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.
We utilize a “best cost” gas purchasing philosophy that seeks to purchase gas on a portfolio basis by weighing cost against supply security and reliability factors. For further information on gas supply and regulation, see “Gas Supply and
Regulatory Proceedings” beginning on page 16 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
During the year ended October 31, 2002, 35% of gas deliveries were made to industrial or large commercial customers which 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. The ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under existing regulations of the Federal Energy Regulatory Commission (FERC), certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. To date, only minimal bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms. The future level of bypass activity cannot be predicted.
In the residential and small commercial markets, natural gas competes primarily with electricity for such uses as cooking, water heating and space heating.
During the year ended October 31, 2002, our largest customer contributed $1.7 million, or .2%, to total operating revenues.
We spend an immaterial amount for research and development costs. We contribute to gas industry-sponsored research projects; however, the amounts contributed to such projects are not material.
Compliance with federal, state and local environmental protection laws has no material effect on construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” beginning on page 28 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
At October 31, 2002, we had 1,715 employees, compared with 1,657 at October 31, 2001.
Item 2.
Item 2. Properties
Our properties consist primarily of distribution systems and related facilities to serve our utility customers. We have approximately 670 miles of lateral pipelines up to 16 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 20,500 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or private property with the permission of the individual owners.
We own or lease for varying periods district and regional offices for our operations.
Item 3.
Item 3. Legal Proceedings
There are a number of lawsuits pending against us in the ordinary course of business for damages alleged to have been caused by our employees. We have liability insurance which we believe is adequate to cover any material judgments that may result from these lawsuits.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
(a) 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 on the NYSE for each quarterly period for the years ended October 31, 2002 and 2001.
(b) At January 13, 2003, our Common Stock was owned by 16,186 shareholders of record.
(c) Information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2002 and 2001, is as follows:
The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in our articles of incorporation and in note agreements under which long-term debt was issued. At October 31, 2002, all retained earnings were free of such restrictions.
Item 6.
Item 6. Selected Financial Data
Selected financial data for the years ended October 31, 1998 through 2002 is as follows:
* The results for 2000 were impacted by the contribution of substantially all of Piedmont Propane Company’s assets in exchange for a partnership interest in Heritage Propane Partners, L.P. This transaction resulted in $5.1 million in net income, or earnings per share of $.16.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
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. Forward-looking statements concern, among others, plans, objectives, proposed capital expenditures and future events or performance. Such statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include:
•
Regulatory issues, including those that affect allowed rates of return, terms and condition of service, rate structures and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are
regulated by the Federal Energy Regulatory Commission (FERC) and the North Carolina Utilities Commission (NCUC), respectively.
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Residential, commercial and industrial growth in our service territories. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our local markets and the country.
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Deregulation, unanticipated impacts of restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies. As a result of deregulation, we expect this highly competitive environment to continue.
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The potential loss of large-volume industrial customers to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins.
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The ability to meet internal performance goals. Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our performance goals.
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The capital-intensive nature of our business, including governmental approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project.
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Changes in the availability and cost of natural gas. To meet customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts will allow us to remain competitive. Natural gas is an unregulated commodity subject to market supply and demand and price volatility. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging activity to minimize price volatility for our customers.
•
Changes in weather conditions. Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild or severe weather, either during the winter period or the summer period, can
have a significant impact on the demand for and the cost of natural gas.
•
Changes in environmental requirements and cost of compliance.
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Earnings from our equity investments. We have investments in unregulated retail energy marketing services, interstate liquefied natural gas (LNG) storage operations, intrastate and interstate pipeline operations and unregulated retail propane operations. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks.
All of these factors are difficult to predict and many are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.
Factors relating to regulation and management are also described or incorporated in our Annual Report on Form 10-K, as well as information included in, or incorporated by reference from, future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in the Annual Report to Shareholders. There also may be other factors besides those described above or incorporated in the Form 10-K that could cause actual conditions, events or results to differ from those in the forward-looking statements.
Forward-looking statements reflect our current expectations only as of the date they are made. We assume no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. Please reference our web site at www.piedmontng.com for current information.
Our Business
Piedmont Natural Gas Company, Inc., began operations in 1951, and is an energy services company primarily engaged in the distribution of natural gas to 740,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. Piedmont is also invested in a number of non-utility, energy-related businesses, including companies involved in unregulated retail natural gas and propane marketing and interstate and intrastate natural gas storage and transportation.
We also sell residential and commercial gas appliances in Tennessee.
Our utility operations are subject to regulation by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also subject to regulation by the NCUC as to the issuance of securities. We are also subject to or affected by various federal and state regulations.
We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us.
In the Carolinas, our service area is comprised of numerous cities, towns and communities including Anderson, Greenville, Spartanburg and Gaffney in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine and Reidsville in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville.
We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. For further information on segments, see Note 10 to the consolidated financial statements.
Liquidity and Capital Resources
We finance current cash requirements primarily from operating cash flows and short-term borrowings. Outstanding short-term borrowings under committed bank lines of credit totaling $150 million ranged from zero to $57 million during the year ended October 31, 2002, and interest rates ranged from 2.0663% to 2.6875%. At October 31, 2002, $46.5 million of short-term debt was outstanding at a weighted average interest rate of 2.2323%. Borrowings under these lines include LIBOR cost-plus loans, transactional borrowings and overnight cost-plus loans based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. The maximum annual fee for the committed lines of credit is $198,000. We have additional uncommitted lines of credit totaling $73 million on a no fee and as needed, if available, basis. At October 31, 2002, our current assets were less than our current liabilities due primarily to the $45 million long-term debt maturity in 2003; however, the lines of credit are adequate to provide the necessary near-term liquidity.
Our utility operations are weather sensitive. The primary
factor that impacts our cash flows from operations is weather. Warmer weather can lead to lower total margin from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but extremely cold weather may lead to conservation by our customers in order to reduce their consumption. Weather outside the normal range of temperatures can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements. During 2002, 55% of our sales and transportation revenues were from residential customers and 29% were from commercial customers, both of which are weather-sensitive customer classes. We have a weather normalization adjustment (WNA) mechanism in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for these weather-sensitive customers. The mechanism is most effective in a reasonable temperature range relative to normal weather using 30 years of history.
During 2002, 66% of our cash needs were funded through internal operations. The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas that are charged by suppliers and to increased gas supplies required to meet our customers’ needs during cold weather and to meet our storage needs. Short-term debt generally increases when wholesale prices for natural gas increase because we must pay suppliers for the gas before we recover our costs from customers through their monthly bills. We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. During 2002, we issued $18.5 million of equity through dividend reinvestment and stock purchase plans but none on the open market. We did not sell any long-term debt during the year. We anticipate selling long-term debt in the fourth quarter of 2003 under the $250 million combined debt and equity shelf registration statement filed with the SEC in 2001. Unless otherwise specified at the time such securities are offered for sale, the net proceeds will be used for general corporate purposes, including construction of additional facilities, repayment of short-term debt and working capital needs. Pending such use, we may temporarily invest the net proceeds in investment grade securities.
Our debt ratings are “A2” from Moody’s and “A” from Standard & Poor’s (S&P). We are well within the debt default provisions established for our senior notes, medium-term notes, short-term bank lines of credit and accounts receivable financings. Following the announcement of our proposed acquisition of North Carolina Natural Gas, as discussed in Note 2 to the consolidated financial statements, Moody’s and S&P placed our debt ratings under review for possible downgrade. The purchase price of $425 million will initially be funded with short-term debt that will be refinanced within six to nine months through the issuance of long-term debt and equity securities. While this acquisition will be positive in the long run by permitting us to expand our customer service base
with an additional 176,000 customers in North Carolina, it would have the initial effect of increased debt levels and reduced fixed charge coverages. See further discussion of this acquisition in Gas Supply and Regulatory Proceedings.
At October 31, 2002, we had $509 million of long-term debt outstanding. Annual sinking fund requirements and maturities of this debt over the next five years are $47 million in 2003, $2 million in 2004, zero in 2005, $35 million in 2006 and zero in 2007. We retired $2 million of long-term debt in 2002.
The financial condition of the pipelines and marketers that supply and deliver natural gas to our system can increase our exposure to supply and price fluctuations. The Williams Companies, Inc., whose subsidiary Transcontinental Gas Pipe Line Corporation (Transco) is the major pipeline which serves our Carolina service areas and whose subsidiary Williams Energy Services Company (Wesco) is a wholesale supplier of commodity natural gas service, has experienced financial difficulties. Wesco currently provides natural gas to us under several supply contracts. In all cases with Transco and Wesco, and with other suppliers with whom we have smaller contracts, the products and services are received by us prior to payment or are subject to payment netting agreements. We believe our risk exposure to the financial condition of these companies is minimal based on receipt of the products and other services prior to payment and the availability of other marketers of natural gas to meet our supply needs if necessary.
The natural gas business is seasonal in nature resulting in fluctuations primarily in balances in accounts receivable from customers, inventories of stored natural gas and accounts payable to suppliers in addition to short-term borrowings discussed above. Our accounts receivable and accounts payable balances were higher at October 31, 2002, compared with 2001, due in part to the purchase of the North Carolina Gas Service gas distribution system from NUI Utilities, Inc., as discussed in Note 2 to the consolidated financial statements. From April 1 to October 31, we build up natural gas inventories by injecting gas into storage for sale in the colder months. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year.
We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our approximately 4% current annual growth in customer base. Utility construction expenditures for 2002 were $83.7 million. Utility construction expenditures totaling $85.3 million, primarily to serve customer growth, are budgeted for 2003. Due to growth in our service area, significant utility construction expenditures are expected to continue. Short-term debt may be used to finance construction
pending the issuance of long-term debt or equity.
During 2002, cash provided from operations, from bank lines of credit and from the issuance of common stock through dividend reinvestment and stock purchase plans was sufficient to fund construction expenditures, pay debt principal and interest of $41.7 million and pay dividends to shareholders of $51.9 million.
Our expected future contractual obligations at October 31, 2002, for long-term debt, pipeline and storage capacity and gas supply and operating leases are as follows:
At October 31, 2002, our capitalization consisted of 44% in long-term debt and 56% in common equity. Our long-term targeted capitalization ratio is 45% in long-term debt and 55% in common equity. The embedded cost of long-term debt at October 31, 2002, was 7.71%. The return on average common equity for 2002 was 10.82%.
Critical Accounting Policies and Estimates
We prepare our 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.
Our domestic natural gas distribution segment is subject to regulation by certain state and federal authorities. We have accounting policies that conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effect of Certain Types of Regulation” (Statement 71), and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is
probable that those expenses and income will be allowed in the rate-setting 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. At October 31, 2002, we had $19.7 million of regulatory assets and $28.6 million of regulatory liabilities, including deferred income tax liabilities of $13 million. If, for any reason, we 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 these 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.
We believe the following represents the more significant judgments and estimates used in preparing our consolidated financial statements. For further discussion of significant accounting policies, see Notes 1, 9 and 11 to the consolidated financial statements.
Allowance for Uncollectible Accounts. We evaluate the collectibility of our trade accounts receivable based on our recent loss history and an overall assessment of past due trade accounts receivable amounts outstanding.
Employee Benefits. We have a defined-benefit pension plan for the benefit of eligible full-time employees. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to the plan. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases, within certain guidelines. In addition, our actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense recorded in future periods.
Self Insurance. We are self-insured for certain losses related to general liability, group medical benefits and workers’ compensation. We maintain stop loss coverage with third-party insurers to limit our total exposure. Our liabilities represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are not discounted and are established based upon analyses of historical data and actuarial estimates. We, along with independent actuaries, review
the liabilities at least annually to ensure that they are appropriate. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from our estimates.
Long-Term Incentive Plan. We have a Long-Term Incentive Plan (LTIP) covering five-year performance periods under which units are awarded to participants. Each unit is equivalent in value to one share of common stock. Following the end of the performance period, awards are distributed in the form of shares of common stock and cash withheld to pay taxes if performance measures are met. During the performance period, we calculate the expense and liability for the LTIP based on performance levels achieved or expected to be achieved and the estimated market value of common stock as of the distribution date. While we believe these estimates are reasonable based on the information available, actual amounts, which are not known until after the end of the performance period, could differ from our estimates.
Gas Supply and Regulatory Proceedings
To meet customer requirements, we acquire sufficient gas supplies and pipeline capacity to ensure delivery to meet the demands of our distribution system while also ensuring that supply and capacity contracts allow us to remain competitive. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers.
In our opinion, present rules and regulations of our three state regulatory commissions permit the pass-through of interstate pipeline capacity and storage service costs that may be incurred under orders or regulations of the FERC, as well as commodity gas costs from natural gas suppliers. The majority of our natural gas supply is purchased from producers and marketers in non-regulated transactions. Our rate schedules include provisions permitting the recovery of prudently incurred gas costs. The NCUC and the PSCSC require annual prudence reviews covering a historical twelve-month period. For the most recent period, the NCUC and the PSCSC found us to be prudent in our gas purchasing practices and allowed 100% recovery of our gas costs.
In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of the state. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. During 2000 and 2001, the NCUC allowed us to use $38.5 million of expansion funds to extend natural gas service to the counties of Avery, Mitchell and Yancey. As we believe that we have no other anticipated projects that qualify
for expansion funds as currently determined by the NCUC, we petitioned the NCUC on January 30, 2002, for permission to deposit supplier refunds held in escrow at that time and future supplier refunds in the appropriate gas costs deferred accounts for refund to customers. On February 21, the NCUC agreed and ordered that these supplier refunds be placed in the deferred accounts. At October 31, 2002, the balance in our expansion fund was $5.8 million and is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.
Effective January 1, 2001, we purchased for cash the natural gas distribution assets of Atmos Energy Corporation located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition was at net book value of $6.6 million and added 5,400 customers to our operations.
In September 2001, we filed a petition with the PSCSC seeking approval of a gas cost hedging plan for the purpose of cost stabilization for customers. On March 26, 2002, the PSCSC issued an order approving the plan on an experimental basis. The PSCSC ruled that all properly accounted for costs incurred in accordance with the plan, with the exception of certain personnel and administrative costs, would be deemed prudently incurred and would be recoverable in rates as a gas cost. We began hedging activities in April under the approved program.
In October 2001, we filed an application with the NCUC seeking approval to implement an experimental natural gas hedging program. At the time, the NCUC was engaged in a generic investigation into the hedging of natural gas commodity costs, and the NCUC took no action on our application pending further proceedings in the generic investigation.
On February 26, 2002, the NCUC issued an order in the generic proceeding that concluded, among other things, that hedging costs should be treated as gas costs and that pre-approval of a hedging program would be inconsistent with the procedures for the annual gas costs prudency reviews. In its order, the NCUC stated that hedging is an option that must be considered in connection with the gas purchasing practices of a local distribution company. The NCUC recognized that the review of the prudency of a decision to hedge or not to hedge, just like the review of the prudency of other gas purchasing decisions, must be made on the basis of the information available at the time the decision is made, not on the basis of the information available at the time of the annual prudency review proceeding. On April 10, we again asked the NCUC for approval to operate a hedging plan on an experimental basis for a period of two years and for reconsideration of the NCUC’s conclusion on the pre-approval of a hedging program. On October 18, the NCUC denied our request for pre-approval; however, the NCUC commended us for our hedging plan proposal and our contribution to the understanding of hedging by the NCUC. The NCUC made it clear that while it would not pre-approve the plan,
it recognized that the plan is experimental in nature and did not wish to be understood as having disapproved the plan or expressed the opinion that adoption of the plan would result in disallowances in an annual review of gas costs. Nothing in the order precluded us from implementing the plan if we chose to do so subject to the terms of the order in the generic proceeding. Given the favorable comments and assurances by the NCUC in both orders, we implemented a hedging program in North Carolina effective November 1, 2002.
On March 28, 2002, we filed an application with the NCUC requesting an annual increase in revenues of $28.2 million, an increase of 6.8%. In addition, we requested changes in cost allocations and rate design and changes in tariffs and service regulations. On August 5, a stipulation among Piedmont, the Public Staff of the NCUC and Carolina Utility Customers Association, Inc., an intervenor, was filed with the NCUC. The stipulation resolved all outstanding issues among the stipulating parties and provided for an annual increase in revenues of $13.9 million. A hearing was held on August 27. At the hearing and based on further residential rate design changes agreed to by us, the only intervenor who did not sign the stipulation did not oppose the stipulation. On October 28, the NCUC issued an order approving an annual revenue increase of $13.9 million, effective November 1, 2002.
On May 3, 2002, we filed an application with the PSCSC requesting an annual increase in revenues of $15.3 million, an increase of 10.5%. In addition, we requested approval of new depreciation rates, changes in cost allocations and rate design and changes in tariffs and service regulations. A hearing was held on September 4 and 5. On October 29, the PSCSC issued an order approving an annual revenue increase of $8.4 million, effective November 1, 2002. The Consumer Advocate of South Carolina has requested a rehearing of the order and we are unable to predict the outcome of that request.
Effective September 30, 2002, we purchased substantially all of the natural gas distribution assets and certain of the liabilities, including potential remediation costs of a manufactured gas plant site, of North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc., for $26 million in cash. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina. Included in the assets acquired was NCGS’s expansion fund in the amount of $2.2 million. At October 31, 2002, this amount is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.
On October 16, 2002, we entered into an agreement to purchase for $425 million in cash the stock of North Carolina Natural Gas (NCNG), a natural gas distribution subsidiary of Progress Energy, Inc., serving 176,000 customers in eastern North Carolina, and
Progress Energy’s 50% investment in Eastern North Carolina Natural Gas Company (EasternNC). EasternNC is a joint venture with Albemarle Pamlico Economic Development Corporation to bring natural gas service to 14 counties in eastern North Carolina. The transaction is subject to approvals by various regulatory agencies and is expected to close in mid-2003.
In 1996, the TRA approved a performance incentive plan, effective July 1, 1996, that eliminated annual prudence reviews in Tennessee and established an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices, together with margin from marketing transportation and capacity in the secondary market and from secondary market sales of gas. The plan is subject to an overall annual cap of $1.6 million on gains or losses by us. The benefits of the incentive plan are the elimination of annual gas purchase prudence reviews, reduction of gas costs for customers and potential earnings to shareholders by sharing in gas cost reductions. Initially approved for a two-year period, the plan now continues each July 1 until we notify the TRA of termination 90 days before the end of a plan year or until the plan is modified, amended or terminated by the TRA.
Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit wholesale margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. In North Carolina, a sharing mechanism is in effect where 75% of any margin earned is refunded to customers. In connection with the South Carolina rate case discussed above, this same sharing mechanism is in place in South Carolina effective November 1, 2002. Secondary market transactions in Tennessee are included in the performance incentive plan discussed above.
In 2002, 35% of gas deliveries were made to industrial or large commercial customers which 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. The ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under existing regulations of the FERC, certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. To date, only minimal bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms. The future level of bypass activity cannot be predicted.
In 2001, we requested special accounting treatment from the NCUC, the PSCSC and the TRA to allow us to defer for recovery in future rates the amounts of accounts receivable that were written off during 2001 in excess of amounts recovered through base rates. These higher write-offs resulted from the high gas prices and abnormally cold weather experienced during the 2000-2001 winter season. The PSCSC and the TRA approved deferral of only the gas cost portion of the excess write-offs, which totaled $1.3 million, for recovery under normal purchased gas cost adjustment (PGA) procedures. The NCUC did not approve our request.
Equity Investments
Piedmont Energy Partners, Inc. (PEP), is a wholly owned subsidiary that is a holding company for various other wholly owned non-utility subsidiaries.
Piedmont Intrastate Pipeline Company, a wholly owned subsidiary of PEP, is a 16.45% member of Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies, including Piedmont Natural Gas Company, for 100% of the 270 million cubic feet per day of firm transportation capacity on the pipeline. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is secured by Cardinal’s assets and by each member’s equity investment in Cardinal. In accordance with the NCUC’s order authorizing Cardinal to construct, own and operate the pipeline, Cardinal will file a general rate case on or before January 15, 2003.
Piedmont Interstate Pipeline Company, a wholly owned subsidiary of PEP, is a 35% member of Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the FERC. Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under firm service agreements with customers. We subscribe to slightly more than one-half of this capacity to provide gas for peak-use periods when demand is the highest. Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated
balance sheets as a hedge under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). Pine Needle’s long-term debt is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle. On August 1, 2002, Pine Needle filed a rate increase request with the FERC. We expect an order and new rates to be effective in early 2003.
Piedmont Propane Company, a wholly owned subsidiary of PEP, owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. Heritage Propane competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage Propane purchases propane at numerous supply points for delivery primarily via railroad tank cars and common carrier transport. Heritage Propane’s profitability is also sensitive to changes in the wholesale prices of propane. Heritage Propane utilizes hedging transactions to provide price protection against significant fluctuations in prices. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133. Heritage Propane also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments used in connection with this liquids trading activity are marked to market.
In July 2002, we recorded a pre-tax loss in value of $1.4 million on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane. This other than temporary loss was calculated based on estimated future cash flow projections that reflect actual and projected customer growth assumptions for Heritage Propane.
The limited partnership agreement of US Propane requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $10 million. At October 31, 2002, our capital account was positive.
Piedmont Energy Company, a wholly owned subsidiary of PEP, has a 30% interest in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other members are subsidiaries of AGL Resources, Inc., and Dynegy Inc. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. SouthStar was formed
and began marketing natural gas in Georgia in 1998 when that state implemented full natural gas retail competition. SouthStar conducts most of its business in Georgia, and the unregulated retail gas market in that state is highly competitive.
The Operating Policy of SouthStar contains a provision for the disproportionate sharing of earnings in excess of a threshold per annum, cumulative pre-tax return of 17%. This threshold is not reached until all prior period losses are recovered. Earnings below the 17% return threshold are allocated to members based on their ownership percentages. Earnings above the threshold are allocated at various percentages based on actual margin generated in four defined service areas. The earnings test is based on SouthStar’s fiscal year ending December 31, therefore, the actual impact, if any, of disproportionate sharing is not known until after December 31. At October 31, 2002, we estimated that a portion of SouthStar’s earnings for calendar year 2002 will be above the threshold, and that disproportionate sharing will occur for the first time. We reduced our portion of the equity earnings from SouthStar for the twelve months ended October 31, 2002, by $778,000, pre-tax, to reflect our estimate that our earnings from SouthStar will be at a level of approximately 26% of total earnings, rather than our equity ownership percentage of 30% of total earnings. Based on various calculation methodologies and interpretations of the Operating Policy, our pre-tax earnings reduction for 2002 due to disproportionate sharing could range from zero to $1.1 million.
SouthStar manages commodity price and weather risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. Financial contracts in the form of futures, options and swaps are used to hedge the price volatility of natural gas. These derivative transactions qualify as cash flow hedges. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133. Weather derivative contracts are used to preserve margins in the event of warmer-than-normal weather during the winter period. Such contracts are accounted for using the intrinsic value method under the guidelines of Emerging Issues Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”
Currently, SouthStar has exposure to supply fluctuations due to the financial condition of Dynegy. Dynegy has managed SouthStar’s capacity asset agreements and has supplied the majority of its gas. SouthStar is only obligated to purchase gas at market prices from Dynegy. Dynegy has announced that it is exiting the gas supply and capacity management businesses and is in the process of providing an orderly transition for its customers. SouthStar will perform in-house certain activities now provided by Dynegy. SouthStar’s portfolio of suppliers has been significantly expanded to mitigate the exposure to Dynegy. Also,
Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s bills for local delivery service. Piedmont Energy Company, through its parent, has guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $13.4 million that expires on August 5, 2003.
Piedmont Greenbrier Pipeline Company, LLC, a North Carolina limited liability company, is a wholly owned subsidiary that has a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier), a Delaware limited liability company. The other member is a subsidiary of Dominion Resources, Inc. Greenbrier, formed in 2001, proposes to build a 280-mile interstate gas pipeline linking multiple gas supply basins and storage to markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day to commence service in 2005. The pipeline would originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. This pipeline will broaden our access to competitive gas supplies and will also serve new power generation facilities in the region. The pipeline is expected to cost $497 million, with $150 million of the cost expected to be contributed as equity by the owners and the remainder expected to be provided by project-financed debt. As of October 31, 2002, we have made capital contributions to Greenbrier totaling $6.8 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On October 30, 2002, the FERC gave preliminary approval to the project regarding non-environmental issues. Construction of the pipeline is subject to a number of conditions, including final certificate approval by the FERC.
Results of Operations
Net income for 2002 was $62.2 million, compared with $65.5 million in 2001 and $64 million in 2000. Net income for 2002 decreased $3.3 million from 2001 primarily for the reasons listed below.
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Decrease in margin due to warmer weather resulting in fewer volumes of gas delivered to customers (system throughput).
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Increase in depreciation expense.
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Increase in interest expense.
These changes were partially offset by an increase in volumes delivered to industrial customers and an increase in earnings from unregulated retail energy marketing services.
Net income for 2001 increased $1.5 million over 2000 primarily for the reasons listed below.
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Rates charged to customers increased due to general rate increases in Tennessee effective July 1, 2000, and in North Carolina effective November 1, 2000.
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Even though total system throughput decreased, volumes delivered to residential and commercial customers from whom we earn a higher margin increased.
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Increase in the allowance for funds used during construction (AFUDC).
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Increase in interest income.
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Increase in earnings from unregulated retail energy marketing services.
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Increase in earnings from non-utility LNG operations.
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Increase in earnings from secondary market transactions.
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Addition of Gaffney customers in January 2001.
These changes were partially offset for the reasons listed below.
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Increase in operations and maintenance expenses.
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Increase in depreciation expense.
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Increase in general taxes.
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Increase in interest charges.
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Decrease in earnings from propane operations.
Compared with the prior year, weather in our service area, as measured by degree days, was 21% warmer in 2002, 23% colder in 2001 and 1% warmer in 2000. System throughput was 126.1 million dekatherms in 2002, compared with 134.4 million dekatherms in 2001, a decrease of 6%, and 135.1 million dekatherms in 2000. In addition to system throughput, secondary market sales volumes were 55.7 million dekatherms in 2002, compared with 29.5 million dekatherms in 2001 and 21.1 million dekatherms in 2000.
Operating revenues were $832 million in 2002, $1,107.9 million in 2001 and $830.4 million in 2000. Operating revenues for 2002 decreased $275.9 million from 2001 primarily for the reasons listed below.
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The commodity cost of gas decreased significantly during the winter of 2001-2002 resulting in a corresponding decrease in rates charged to customers.
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Decreased system throughput to all customer classes except industrial due to warmer weather.
These decreases were partially offset by increased secondary market activity.
Operating revenues for 2001 increased $277.5 million over 2000 primarily for the reasons listed below.
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The commodity cost of gas increased significantly during
the winter of 2000-2001 resulting in a corresponding increase in rates charged to customers.
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Increased customer growth and 23% colder weather.
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System throughput to higher-margin residential and commercial customers increased nine million dekatherms.
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Rates increased due to general rate increases as noted above.
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Increased secondary market activity.
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Addition of Gaffney customers in January 2001.
The WNA generated revenues from customers of $19.8 million in 2002, refunds to customers of $8.5 million in 2001 and revenues of $19.3 million in 2000. The WNA is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin. Weather 15% warmer than normal was experienced in 2002, compared with 8% colder than normal in 2001 and 13% warmer than normal in 2000.
In general rate proceedings, the state regulatory commissions authorize us to recover a margin, applicable rate less cost of gas, on each unit of gas sold. The commissions also authorize us to negotiate lower rates to industrial customers when necessary to remain competitive. We are generally permitted to recover margin losses resulting from these negotiated transactions. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.
Cost of gas for 2002 was $496.2 million, compared with $769.9 million in 2001 and $512 million in 2000. Cost of gas for 2002 decreased $273.7 million from 2001 primarily due to decreases in the wholesale commodity cost of gas from suppliers and decreases in volumes sold to residential and commercial customers.
Cost of gas for 2001 increased $257.9 million over 2000 primarily due to increases in the commodity cost of gas from suppliers. Wholesale market prices during the winter of 2000-2001 were more than double the prices of the previous winter. Increases in wholesale prices resulted in lower volumes sold to customers due to customer conservation and the loss of industrial volumes to oil due to price competition. We also curtailed interruptible industrial customers for system management during a portion of the 2000-2001 winter period. Increases or decreases in purchased gas costs from suppliers are passed on to customers through PGA procedures.
Margin (operating revenues less cost of gas) for 2002 was $335.8 million, compared with $338 million in 2001 and $318.3 million in 2000. Margin increased or decreased due to the changes in revenues and cost of gas noted above. The margin earned per dekatherm of system throughput increased by $.12 in 2002 over 2001 and by $.13 in 2001 over 2000.
Operations and maintenance expenses were $133.4 million in 2002 and 2001 and $127 million in 2000. Even though operations and maintenance expenses were even for 2002 and 2001, the following increases and decreases were experienced.
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Increase in payroll expense due to positions being filled by employees rather than by outside labor.
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Increase in other corporate expense due to increases in fees for committed lines of credit and net service fees to banks and increases in training expenses.
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Increase in employee benefits expense due to pension expense recorded in 2002 with pension income recorded in 2001 and increased health insurance premiums.
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Decrease in outside labor as explained above.
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Decrease in the provision for uncollectibles due to warmer weather and lower gas prices.
Operations and maintenance expenses for 2001 increased $6.4 million over 2000 primarily for the reasons listed below.
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Increase in transportation expense due to higher fuel costs and increases in license fees and taxes.
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Increase in utilities expense due to the installation of new communications units in service trucks and the higher volume of telephone calls to our customer information centers.
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Increase in bank charges for activity fees and for fees associated with higher committed bank lines.
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Increase in the provision for uncollectibles due to higher charge-offs for customers who could not pay their bills due to higher gas prices and colder-than-normal weather.
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Amortization of North Carolina environmental expense as recovered from customers beginning in November 2000.
These increases were partially offset by the following decreases.
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Decrease in employee benefits expense due primarily to a decrease in pension expense and the shift of the payment of administrative fees from benefit plan assets rather than by the sponsor.
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Decrease in outside consultants expense due to a reduction in the need for information systems upgrades.
Depreciation expense increased from $48.9 million to $57.6 million over the three-year period 2000 to 2002 primarily due to growth in plant in service.
General taxes increased from $18.8 million to $23.9 million over the three-year period 2000 to 2002 primarily due to increases in property taxes due to growth in plant in service, franchise
taxes due to a rate increase and payroll taxes due to increased payroll.
Other income (expense), net of income taxes, was $12.7 million in 2002, compared with $10.9 million in 2001 and $11.3 million in 2000. Other income (expense) for 2000 includes $5.1 million from a business combination affecting our propane operations. Other income (expense) for 2000 without this transaction would have been $6.2 million.
Prior to August 2000, Piedmont Propane Company marketed propane and propane appliances to residential, commercial and industrial customers within and adjacent to our three-state natural gas service area. In August, US Propane, L.P., was formed to combine our propane operations with the propane operations of three other companies. Piedmont Propane owns 20.69% of the membership interest in US Propane. Immediately after formation, US Propane combined with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (Heritage Propane), by contributing all of its assets to Heritage Holdings for $181.4 million in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage Holdings for $120 million. At the time of the combination, US Propane owned all of the general partnership interest and approximately 34% of the limited partnership interest in Heritage Propane. This combination, including a gain on the transfer of the propane assets, transaction costs and certain employee benefit plans’ gains and charges, contributed $5.1 million to net income in 2000.
Income from non-utility activities, at equity, before taxes, for 2002 increased $2.9 million over 2001 primarily due to an increase in earnings from unregulated retail energy marketing services. This increase was partially offset by a decrease in earnings from propane due to warmer weather experienced in 2002.
Income from non-utility activities, at equity, before taxes, for 2001 increased $8.7 million over 2000 primarily due to increases in earnings from unregulated retail energy marketing services, non-utility LNG operations and propane.
The equity portion of AFUDC, before taxes, was $2 million in 2002, compared with $1.8 million in 2001 and zero in 2000. AFUDC is allocated between equity and debt based on actual amounts computed and the ratio of construction work in progress to average short-term borrowings.
Other, before taxes, for 2002 was $511,000, compared with $192,000 in 2001 and $11 million in 2000. Other in 2000 includes the effect of the propane business combination discussed above. The increase in 2002 over 2001 was primarily due to an increase in earnings from merchandise operations and interest income. The decrease in 2001 from 2000, excluding the propane business
combination discussed above, was primarily due to a decrease in income from propane operations which we operated in 2000, partially offset by an increase in interest income.
Utility interest charges were $40.6 million in 2002, compared with $39.4 million in 2001 and $37 million in 2000. Utility interest charges for 2002 increased $1.2 million over 2001 primarily due to the following reasons.
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Increase in interest on long-term debt due to higher balances outstanding.
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Decrease in the portion of AFUDC attributable to borrowed funds.
These changes were partially offset by the following decreases.
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Decrease in interest on short-term debt due to lower balances outstanding at lower interest rates.
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Decrease in interest charged on refunds due customers due to lower balances outstanding.
Utility interest charges for 2001 increased $2.4 million over 2000 primarily due to the following reasons.
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Increase in interest on long-term debt due to higher balances outstanding.
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Increase in interest charged on refunds due customers due to higher balances outstanding.
These increases were partially offset by the following changes.
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Decrease in interest on short-term debt due to lower balances outstanding at lower interest rates.
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Increase in the portion of AFUDC attributable to borrowed funds.
Environmental Matters
Our three state regulatory commissions have authorized us to utilize deferral accounting, or to create a regulatory asset, in connection with environmental costs. Accordingly, we have established regulatory assets for environmental costs incurred and for estimated environmental liabilities.
In 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount that released us from any investigation and remediation liability. Three other MGP sites that we also have owned, leased or operated were not included in the settlement.
In September 2002, in connection with the purchase of the operations of NCGS discussed in Note 2 to the consolidated financial statements, we acquired the liability for an MGP site located in Reidsville, North Carolina. We had a limited assessment performed by a third party that consisted of an evaluation of documents, a site visit and an interview with an employee of the seller. This study concluded that a comprehensive baseline risk assessment would cost $150,000 and the maximum cost to remediate the site would be $487,000. Based on this study and the similar nature of the three sites not covered by the settlement, we increased our environmental liability in the fourth quarter of 2002 by $1.5 million, with an offsetting increase to a regulatory asset, to reflect a liability of $637,000 for each of the four sites.
At October 31, 2002, our undiscounted environmental liability totaled $2.9 million, consisting of $2.6 million for the four MGP sites and $320,000 for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries.
At October 31, 2002, our regulatory assets for environmental costs totaled $6.2 million, net of recoveries from customers, in connection with the estimated liabilities for the MGP sites and underground storage tanks and for environmental costs incurred, primarily legal fees and engineering assessments. The portion of the regulatory assets representing actual costs incurred is being amortized as recovered in current approved rates from customers in all three states.
Further evaluations of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on financial position or results of operations.
Accounting Pronouncements
Effective November 1, 2002, we will adopt SFAS No. 141, “Business Combinations” (Statement 141). Statement 141 requires that business combinations be accounted for using the purchase method. Statement 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination. The adoption of Statement 141 will not have a material effect on financial position or results of operations.
Effective November 1, 2002, we will adopt SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Statement 142 provides new guidance for accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be
accounted for subsequent to their initial recognition. The adoption of Statement 142 will not have a material effect on financial position or results of operations.
Effective November 1, 2002, we will adopt SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 addresses financial accounting and reporting for asset retirement obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that asset retirement obligations exist for our underground mains and services, however, the fair value of the obligation cannot be determined because the end of the system life is indeterminable.
Effective November 1, 2002, we will adopt SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Statement 144 provides one accounting model to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. The adoption of Statement 144 will not have a material effect on financial position or results of operations.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
All financial instruments discussed below are held by us for purposes other than trading.
We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Exposure to interest rate changes relates to both short- and long-term debt. Exposure to gas cost variations relates to the supply of and demand for natural gas.
Interest Rate Risk
We have short-term bank lines of credit available to provide working capital and general corporate funds. The level of borrowings under the lines varies from period to period, depending upon many factors, including our investments in capital projects. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.
At October 31, 2002, we had $46.5 million of short-term debt outstanding at a weighted average interest rate of 2.23%. The carrying amount of our short-term debt approximates fair value.
Information about our long-term debt at October 31, 2002, that is sensitive to changes in interest rates is presented below.
Commodity Price Risk
In the normal course of business, we utilize contracts of various duration for the forward sales and purchase of natural gas. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. Due to cost-based rate regulation, we have limited exposure to changes in commodity prices as substantially all changes in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures.
For further information on market risk, see “Liquidity and Capital Resources” beginning on page 11 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Item 8.
Item 8. Financial Statements and Supplementary Data
Consolidated financial statements and schedules required by this item are listed in Item 14(a)1 and 2 in Part IV of this report on page 67.
Consolidated Balance Sheets
October 31, 2002 and 2001
See notes to consolidated financial statements.
See notes to consolidated financial statements.
Statements of Consolidated Income
For the Years Ended October 31, 2002, 2001 and 2000
See notes to consolidated financial statements.
Statements of Consolidated Cash Flows
For the Years Ended October 31, 2002, 2001 and 2000
See notes to consolidated financial statements.
Statements of Consolidated Stockholders’ Equity
For the Years Ended October 31, 2002, 2001 and 2000
See notes to consolidated financial statements.
Notes To Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation.
Piedmont Natural Gas Company, Inc., is an investor-owned public utility primarily engaged in the sale and transportation of natural gas to residential, commercial and industrial customers in the Piedmont region of North Carolina and South Carolina and the metropolitan Nashville, Tennessee, area.
The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in non-utility activities are accounted for under the equity method. Our ownership interest in each entity is recorded in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in “Non-utility activities, at equity” in “Other Income (Expense)” in the statements of consolidated income. Revenues and expenses of all other non-utility activities are included in “Other” in “Other Income (Expense)” in the statements of consolidated income. Significant inter-company transactions have been eliminated in consolidation where appropriate. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation” (Statement 71), we have not eliminated inter-company profit on sales to affiliates.
B. Rate-Regulated Basis of Accounting.
Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we have capitalized certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery of or refunds to utility customers in future periods.
We monitor the regulatory and competitive environment in which we operate to determine that our regulatory assets continue to be probable of recovery. If we determine that all or a portion of these regulatory assets no longer meet the criteria for continued application of Statement 71, we would write off that portion which we could not recover, net of any regulatory liabilities which would be deemed no longer necessary. Our review has not resulted in any write offs of any regulatory assets or liabilities.
The amounts recorded as regulatory assets and liabilities in the consolidated balance sheets at October 31, 2002 and 2001, are summarized as follows:
C. Utility Plant and Depreciation.
Utility plant is stated at original cost, including direct labor and materials, allocable overheads and an allowance for borrowed and equity funds used during construction (AFUDC). AFUDC totaled $3,424,000 for 2002, $6,677,000 for 2001 and $3,321,000 for 2000. The portion of AFUDC attributable to equity funds is included in “Other Income (Expense)” and the portion attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the statements of consolidated income. The costs of property retired are removed from utility plant and such costs, including removal costs net of salvage, are charged to accumulated depreciation.
We compute depreciation expense using the straight-line method over a period of 5 to 72 years. The composite weighted-average depreciation rates were 3.55% for 2002, 3.45% for 2001 and 3.49% for 2000.
We review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Our reviews have not resulted in a material effect on results of operations or financial condition; however, we did write down our investment in propane during 2002 as discussed in Note 9.
D. Inventories.
We maintain inventories on the basis of average cost. Cost for gas in storage is defined as the amount recoverable under rate schedules approved by the state regulatory commissions.
E. Deferred Purchased Gas Adjustment.
Rate schedules include purchased gas adjustment provisions that permit the recovery of gas costs. We periodically revise rates without formal rate proceedings to reflect changes in the cost of gas. Charges 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 added to or deducted from cost of gas and included in “Refunds due customers” in the
consolidated balance sheets.
F. Income Taxes.
We provide deferred income taxes for differences between the book and tax basis of assets and liabilities, principally attributable to accelerated tax depreciation and equity investments, and the timing of the recording of revenues and cost of gas. We amortize deferred investment tax credits to income over the estimated useful life of the related property.
G. Operating Revenues.
We recognize revenues from meters read on a monthly cycle basis which results in unrecognized revenue from the cycle date through month end. We defer the cost of gas for volumes delivered to customers but not yet billed under the cycle-billing method.
H. Earnings Per Share.
We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2002, 2001 and 2000, is presented below:
I. Statement of Cash Flows.
For purposes of reporting cash flows, we consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents.
J. Recently Issued Accounting Standards.
Effective November 1, 2002, we will adopt SFAS No. 141, “Business Combinations” (Statement 141). Statement 141 requires that business combinations be accounted for using the purchase method. Statement 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination. The adoption of Statement 141 will not have a material effect on financial position or results of operations.
Effective November 1, 2002, we will adopt SFAS No. 142,
“Goodwill and Other Intangible Assets” (Statement 142). Statement 142 provides new guidance for accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be accounted for subsequent to their initial recognition. The adoption of Statement 142 will not have a material effect on financial position or results of operations.
Effective November 1, 2002, we will adopt SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 addresses financial accounting and reporting for asset retirement obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that asset retirement obligations exist for our underground mains and services; however, the fair value of the obligation cannot be determined because the end of the system life is indeterminable.
Effective November 1, 2002, we will adopt SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Statement 144 provides one accounting model to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. The adoption of Statement 144 will not have a material effect on financial position or results of operations.
K. Use of Estimates.
We make estimates and assumptions when preparing the consolidated financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.
L. Reclassifications.
We have reclassified certain financial statement items for 2001 and 2000 to conform with the 2002 presentation.
2. Regulatory Matters
Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also subject to regulation by the NCUC as to the issuance of securities.
In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of the state. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. During 2000 and 2001, the NCUC allowed us to use $38,527,000 of expansion funds to extend natural gas service to the counties of Avery, Mitchell and Yancey. As we believe that we have no other anticipated projects that qualify for expansion funds as currently determined by the NCUC, we petitioned the NCUC on January 30, 2002, for permission to deposit supplier refunds held in escrow at that time and future supplier refunds in the appropriate gas costs deferred accounts for refund to customers. On February 21, the NCUC agreed and ordered that these supplier refunds be placed in the deferred accounts. At October 31, 2002, the balance in our expansion fund was $5,843,000 and is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.
Effective January 1, 2001, we purchased for cash the natural gas distribution assets of Atmos Energy Corporation located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition was at net book value of $6,625,000 and added 5,400 customers to our operations.
In September 2001, we filed a petition with the PSCSC seeking approval of a gas cost hedging plan for the purpose of cost stabilization for customers. On March 26, 2002, the PSCSC issued an order approving the plan on an experimental basis. The PSCSC ruled that all properly accounted for costs incurred in accordance with the plan, with the exception of certain personnel and administrative costs, would be deemed prudently incurred and would be recoverable in rates as a gas cost. We began hedging activities in April under the approved program.
In October 2001, we filed an application with the NCUC seeking approval to implement an experimental natural gas hedging program. At the time, the NCUC was engaged in a generic investigation into the hedging of natural gas commodity costs, and the NCUC took no action on our application pending further proceedings in the generic investigation. On February 26, 2002, the NCUC issued an order in the generic proceeding that concluded, among other things, that hedging costs should be treated as gas costs and that pre-approval of a hedging program would be inconsistent with the procedures for the annual gas costs prudency reviews. In its order, the NCUC stated that hedging is an option that must be considered in connection with the gas purchasing practices of a local distribution company. The NCUC recognized that the review of the prudency of a decision to hedge or not to hedge, just like the review of the prudency of other gas purchasing decisions, must be made on the basis of the information available at the time the decision is made, not on the basis of the information available at the time of the annual prudency
review proceeding. On April 10, we again asked the NCUC for approval to operate a hedging plan on an experimental basis for a period of two years and for reconsideration of the NCUC’s conclusion on the pre-approval of a hedging program. On October 18, the NCUC denied our request for pre-approval; however, the NCUC commended us for our hedging plan proposal and our contribution to the understanding of hedging by the NCUC. The NCUC made it clear that while it would not pre-approve the plan, it recognized that the plan is experimental in nature and did not wish to be understood as having disapproved the plan or expressed the opinion that adoption of the plan would result in disallowances in an annual review of gas costs. Nothing in the order precluded us from implementing the plan if we chose to do so subject to the terms of the order in the generic proceeding. Given the favorable comments and assurances by the NCUC in both orders, we implemented a hedging program in North Carolina effective November 1, 2002.
On March 28, 2002, we filed an application with the NCUC requesting an annual increase in revenues of $28,182,000, an increase of 6.8%. In addition, we requested changes in cost allocations and rate design and changes in tariffs and service regulations. On August 5, a stipulation among Piedmont, the Public Staff of the NCUC and Carolina Utility Customers Association, Inc., an intervenor, was filed with the NCUC. The stipulation resolved all outstanding issues among the stipulating parties and provided for an annual increase in revenues of $13,889,000. A hearing was held on August 27. At the hearing and based on further residential rate design changes agreed to by us, the only intervenor who did not sign the stipulation did not oppose the stipulation. On October 28, the NCUC issued an order approving an annual revenue increase of $13,889,000, effective November 1, 2002.
On May 3, 2002, we filed an application with the PSCSC requesting an annual increase in revenues of $15,337,000, an increase of 10.5%. In addition, we requested approval of new depreciation rates, changes in cost allocations and rate design and changes in tariffs and service regulations. A hearing was held on September 4 and 5. On October 29, the PSCSC issued an order approving an annual revenue increase of $8,381,000, effective November 1, 2002. The Consumer Advocate of South Carolina has requested a rehearing of the order and we are unable to predict the outcome of that request.
Effective September 30, 2002, we purchased substantially all of the natural gas distribution assets and certain of the liabilities, including potential remediation costs of a manufactured gas plant site, of North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc., for $26,000,000 in cash. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina. Included in the assets acquired was NCGS’s expansion fund in the amount of
$2,185,000. At October 31, 2002, this amount is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.
On October 16, 2002, we entered into an agreement to purchase for $425,000,000 in cash the stock of North Carolina Natural Gas (NCNG), a natural gas distribution subsidiary of Progress Energy, Inc., serving 176,000 customers in eastern North Carolina, and Progress Energy’s 50% investment in Eastern North Carolina Natural Gas Company (EasternNC). EasternNC is a joint venture with Albemarle Pamlico Economic Development Corporation to bring natural gas service to 14 counties in eastern North Carolina. The transaction is subject to approvals by various regulatory agencies and is expected to close in mid-2003.
3. Long-Term Debt
Long-term debt at October 31, 2002 and 2001, is summarized as follows:
Annual sinking fund requirements and maturities over the next five years are $47,000,000 in 2003, $2,000,000 in 2004, zero in 2005, $35,000,000 in 2006 and zero in 2007.
The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in our articles of incorporation and in note agreements under which long-term debt was issued. At October 31, 2002, all retained earnings were free of such restrictions.
4. Capital Stock
The changes in Common Stock for the years ended October 31, 2000, 2001 and 2002, are summarized as follows:
At October 31, 2002, 1,475,000 shares of Common Stock were reserved for issuance as follows:
5. Financial Instruments and Related Fair Value
Various banks provide lines of credit totaling $150,000,000 to finance current cash requirements. We have additional uncommitted lines of credit totaling $73,000,000 on a no fee and as needed, if available, basis. Short-term borrowings under the lines, with maturity dates of less than 90 days, include LIBOR cost-plus loans, transactional borrowings and overnight cost-plus loans based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. At October 31, 2002, the committed lines of credit were on a fee basis, with a maximum annual fee of $198,000.
At October 31, 2002, outstanding borrowings under the lines of credit are included in “Notes payable” in the consolidated balance sheets and consisted of $34,000,000 in LIBOR cost-plus loans and $12,500,000 in overnight cost-plus loans. The weighted average interest rate on such borrowings was 2.23%.
Our principal business activity is the distribution of natural gas. At October 31, 2002, gas receivables totaled $33,003,000 and other receivables totaled $4,501,000, net of an allowance for doubtful accounts of $810,000. The uncollected balance of installment receivables that were transferred with recourse to a third party several years ago was $13,474,000 and $17,184,000 at October 31, 2002 and 2001, respectively. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected, including the receivables transferred with recourse.
The carrying amounts in the consolidated balance sheets of cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values due to the short-term nature of these financial instruments. Based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings, the estimated fair values of long-term debt at October 31, 2002 and 2001, including current portion, were as follows:
The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair values. The fair value amounts are not intended to reflect principal amounts that we will ultimately be required to pay.
We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service territory where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas adjustment mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.
During the year ended October 31, 2002, we purchased financial call options for natural gas for our Tennessee gas purchase portfolio. At October 31, 2002, such options were for gas supply for delivery in December 2002 through February 2003. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing transportation and capacity in the secondary market and margin from secondary market sales of gas, are subject to an overall annual cap of $1,600,000 for shareholder gains or losses. The net gains or losses on gas procurement costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas procurement costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders. This amount is subject to the overall annual cap and is placed in a regulatory asset to be collected from or refunded to customers.
Beginning in April 2002, we purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio under the experimental hedging program approved by the PSCSC. At October 31, 2002, such options were for gas supply for delivery in November 2002 through March 2003. The costs of these options are pre-approved by the PSCSC for recovery from customers. This plan operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange and is limited to 60% of our annual normalized sales volumes for South Carolina. The hedging program uses a matrix of historic, inflation-adjusted gas prices over the past four years plus the current season, with a heavier weighting on current data, as the basis for determining the purchase of financial instruments. The supply cost portfolio is diversified over a rolling 24 months with a short-term focus (one to 12 months) and a long-term focus (13 to 24 months). Purchases are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis. The plan is designed with limited subjective discretion in making purchases with little or no risk of speculation in the market.
6. Leases
We lease certain buildings, land and equipment for use in our operations. These leases are accounted for as operating leases. Operating lease rentals totaled $4,520,000 in 2002, $4,400,000 in 2001 and $4,153,000 in 2000.
Future minimum lease obligations, excluding taxes and other expenses, for leases in effect at October 31, 2002, are as follows (in thousands):
7. Employee Benefit Plans
We have a defined-benefit pension plan for the benefit of eligible full-time employees. An employee becomes eligible on the January 1 or July 1 following either the date on which he or she attains age 21 and completes 1,000 hours of service during the 12-month period commencing on the employment date or attains age 30. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for
income tax purposes. Plan assets consist primarily of marketable securities and cash equivalents. We amend the plan from time to time in accordance with changes in tax law.
We provide certain postretirement health care and life insurance benefits to eligible full-time employees. Employees are first eligible to retire and receive these benefits at age 55 with 10 or more years of service after the age of 45. The liability associated with such benefits is funded in irrevocable trust funds which can only be used to pay the benefits.
A reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2002 and 2001, and a statement of the funded status as recorded in the consolidated balance sheets at October 31, 2002 and 2001, are presented below:
Net periodic benefit cost for the years ended October 31, 2002, 2001 and 2000, includes the following components:
The curtailment expense included in the net periodic benefit cost for 2000 was the result of the contribution of substantially all of Piedmont Propane Company’s assets in exchange for a partnership interest in Heritage Propane Partners, L.P., as discussed in Note 9.
We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized net transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period of active employees. The method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation at October 31, 2002, 2001 and 2000, are presented below:
We anticipate that the discount rate and the expected long-term rate of return on plan assets to be used at the next valuation date of January 1, 2003, will be lower than the rate used in 2002 to reflect the prolonged general weakness in the economy.
The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation for the medical plans for participants aged less than 65 are 11.5% for 2002 and 10% for 2003, declining gradually to 5% in 2010 and remaining at that level thereafter. For those participants aged greater than 65, the assumed health care cost trend rates are 14.5% for 2002 and 13% for 2003, declining gradually to 5% in 2012 and remaining at that level thereafter. The health care cost trend rate assumptions have a significant effect on the amounts reported. A one-percentage point change in the assumed health care cost trend rates would have the following effects:
We maintain salary investment plans which are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). Employees who have completed six months of service are eligible to participate. Participants are permitted to defer a portion of their base salary to the plans and we match a portion of the participants’ contributions. All contributions vest immediately. There are numerous investment options available to enable participants to diversify their accounts. Participants can also invest in company stock up to a maximum of 20% of their account. For the years ended October 31, 2002, 2001 and 2000, we contributed $2,244,000, $2,189,000 and $2,273,000, respectively, in matching contributions to the plans.
8. Income Taxes
The components of income tax expense for the years ended October 31, 2002, 2001 and 2000, are as follows:
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2002, 2001 and 2000, is as follows:
At October 31, 2002 and 2001, deferred income taxes consist of the following temporary differences:
Total deferred income tax liabilities were $169,918,000 and $154,950,000 and total deferred income tax assets were $10,259,000 and $9,395,000 at October 31, 2002 and 2001, respectively.
9. Equity Investments
The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in non-utility activities are accounted for under the equity method. Some of these subsidiaries are subsidiaries of Piedmont Energy Partners, Inc., which acts as a holding company for these investments. Our ownership interest in each entity is recorded in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in
“Non-utility activities, at equity” in “Other Income (Expense)” in the statements of consolidated income.
Piedmont Intrastate Pipeline Company
Piedmont Intrastate Pipeline Company is a 16.45% member of Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies, including Piedmont Natural Gas Company, for 100% of the 270 million cubic feet per day of firm transportation capacity on the pipeline. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.
We have related party transactions with Cardinal as a transportation customer. We record in cost of gas the transportation costs charged by Cardinal. These gas costs were $1,475,000 for 2002, 2001 and 2000. At October 31, 2002 and 2001, we owed Cardinal $123,000.
Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the twelve months ended September 30, 2002, 2001 and 2000, and at September 30, 2002, 2001 and 2000, is presented below.
Piedmont Interstate Pipeline Company
Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation, and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under firm service agreements with customers. We subscribe to slightly more than one-half of this capacity to provide gas for peak-use periods when demand is the highest. Pine Needle enters into interest-rate
swap agreements to modify the interest characteristics of its long-term debt. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). Pine Needle’s long-term debt is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.
We have related party transactions with Pine Needle as a customer. We record in cost of gas the storage costs charged by Pine Needle. These gas costs were $10,898,000, $11,266,000 and $10,581,000 in 2002, 2001 and 2000, respectively. At October 31, 2002 and 2001, we owed Pine Needle $895,000 and $920,000, respectively.
Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for the twelve months ended September 30, 2002, 2001 and 2000, and at September 30, 2002, 2001 and 2000, is presented below.
Piedmont Propane Company
Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane was formed in 2000 to combine our propane operations with the propane operations of these other companies. In August 2000, US Propane combined with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network, by contributing all of its assets to Heritage Holdings for $181,395,000 in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage Holdings for $120,000,000. This combination, including a gain on the transfer of the propane assets, transaction costs and certain employee benefit plans’ gains and charges, resulted in an increase in our net income in 2000 of $5,063,000, or earnings per share of $.16.
US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane. Heritage Propane competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural
gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage Propane’s profitability is also sensitive to changes in the wholesale prices of propane. Heritage Propane utilizes hedging transactions to provide price protection against significant fluctuations in prices. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133. Heritage Propane also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments used in connection with this liquids trading activity are marked to market.
In July 2002, we recorded a pre-tax loss in value of $1,366,000 on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane. The other than temporary loss was calculated based on estimated future cash flow projections that reflect actual and projected customer growth assumptions for Heritage Propane.
The limited partnership agreement of US Propane requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $10,000,000. At October 31, 2002, our capital account was positive.
Summarized audited financial information provided to us by Heritage Propane for 100% of Heritage Propane for its fiscal years ended August 31, 2002 and 2001, and the eight months ended August 31, 2000, and at August 31, 2002, 2001 and 2000, is presented below.
Piedmont Energy Company
Piedmont Energy Company has a 30% interest in SouthStar Energy Services LLC, a Delaware limited liability company. The other members are subsidiaries of AGL Resources, Inc., and Dynegy Inc. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. SouthStar was formed and began marketing natural gas in Georgia in 1998 when that state implemented full natural gas retail competition.
SouthStar conducts most of its business in Georgia, and the unregulated retail gas market in that state is highly competitive.
The Operating Policy of SouthStar contains a provision for the disproportionate sharing of earnings in excess of a threshold per annum, cumulative pre-tax return of 17%. This threshold is not reached until all prior period losses are recovered. Earnings below the 17% return threshold are allocated to members based on their ownership percentages. Earnings above the threshold are allocated at various percentages based on actual margin generated in four defined service areas. The earnings test is based on SouthStar’s fiscal year ending December 31, therefore, the actual impact, if any, of disproportionate sharing is not known until after December 31. At October 31, 2002, we estimated that a portion of SouthStar’s earnings for calendar year 2002 will be above the threshold, and that disproportionate sharing will occur for the first time. We reduced our portion of the equity earnings from SouthStar for the twelve months ended October 31, 2002, by $778,000, pre-tax, to reflect our estimate that our earnings from SouthStar will be at a level of approximately 26% of total earnings, rather than our equity ownership percentage of 30% of total earnings. Based on various calculation methodologies and interpretations of the Operating Policy, our pre-tax earnings reduction for 2002 due to disproportionate sharing could range from zero to $1,114,000.
SouthStar manages commodity price and weather risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. Financial contracts in the form of futures, options and swaps are used to hedge the price volatility of natural gas. These derivative transactions qualify as cash flow hedges. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133. Weather derivative contracts are used to preserve margins in the event of warmer-than-normal weather during the winter period. Such contracts are accounted for using the intrinsic value method under the guidelines of Emerging Issues Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”
Currently, SouthStar has exposure to supply fluctuations due to the financial condition of Dynegy. Dynegy has managed SouthStar’s capacity asset agreements and has supplied the majority of its gas. SouthStar is only obligated to purchase gas at market prices from Dynegy. Dynegy has announced that it is exiting the gas supply and capacity management businesses and is in the process of providing an orderly transition for its customers. SouthStar will perform in-house certain activities now provided by Dynegy. SouthStar’s portfolio of suppliers has been significantly expanded to mitigate the exposure to Dynegy. Also, Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required
SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s bills for local delivery service. Piedmont Energy Company, through its parent Piedmont Energy Partners, has guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $13,400,000 that expires on August 5, 2003.
In 2000, the members of SouthStar entered into a capital contributions agreement that requires each member to contribute additional capital for SouthStar to pay invoices for goods or services provided from any member or affiliates of members whenever funds are not available to pay these invoices. These capital contributions are repaid as funds become available, but are subordinate to SouthStar’s revolving line of credit with a bank. During 2001, we contributed $13,800,000 under this agreement, of which $6,000,000 was repaid. There were no contributions or repayments during 2002.
We have related party transactions with SouthStar which purchases wholesale gas supplies from us. We record this activity in operating revenues at negotiated market prices. Such operating revenues totaled $10,744,000, $12,192,000 and $8,680,000 in 2002, 2001 and 2000, respectively. At October 31, 2002 and 2001, SouthStar owed us $1,162,000 and $1,015,000, respectively.
Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for the twelve months ended September 30, 2002, 2001 and 2000, and at September 30, 2002, 2001 and 2000, is presented below.
Piedmont Greenbrier Pipeline Company
Piedmont Greenbrier Pipeline Company, LLC, has a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier). The other member is a subsidiary of Dominion Resources, Inc. Greenbrier, formed in 2001, proposes to build a 280-mile interstate gas pipeline linking multiple gas supply basins and storage to markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day to commence service in 2005. The pipeline would originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. The pipeline is expected to cost $497,000,000, with $150,000,000 of the cost expected to be contributed as equity by the owners and the remainder expected to be provided by project-financed debt. As of October 31, 2002, we
have made capital contributions to Greenbrier totaling $6,761,000. We have signed a precedent agreement for firm transportation service with Greenbrier. On October 30, 2002, the FERC gave preliminary approval to the project regarding non-environmental issues. Construction of the pipeline is subject to a number of conditions, including final certificate approval by the FERC.
Summarized unaudited financial information provided to us by Greenbrier for 100% of Greenbrier for the twelve months ended October 31, 2002, and at October 31, 2002 and 2001, is presented below.
10. Business Segments
We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Based on products and services and regulatory environments, operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Greenbrier Pipeline Company through their investments in ventures accounted for under the equity method. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company through its investment in a venture accounted for under the equity method.
Activities included in “Other” in the segment tables consist primarily of propane operations conducted by Piedmont Propane Company. All of our activities other than the utility operations of the parent are included in “Other Income (Expense)” in the statements of consolidated income.
We evaluate performance based on margin, operations and maintenance expenses, operating income and income before taxes. All of our operations are within the United States. No single customer’s revenues to us exceed 10% of our consolidated revenues.
Operations by segment for the years ended October 31, 2002, 2001 and 2000, are presented below:
* Operating revenues and operating income shown in the consolidated financial statements represent utility operations only.
A reconciliation to the consolidated financial statements for the years ended October 31, 2002, 2001 and 2000, is presented below:
11. Environmental Matters
Our three state regulatory commissions have authorized us to utilize deferral accounting, or to create a regulatory asset, in connection with environmental costs. Accordingly, we have established regulatory assets for environmental costs incurred and for estimated environmental liabilities.
In 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount that released us from any investigation and remediation liability. Three other MGP sites that we also have owned, leased or operated were not included in the settlement.
In September 2002, in connection with the purchase of the operations of NCGS discussed in Note 2, we acquired the liability for an MGP site located in Reidsville, North Carolina. We had a limited assessment performed by a third party that consisted of an evaluation of documents, a site visit and an interview with an employee of the seller. This study concluded that a comprehensive baseline risk assessment would cost $150,000 and the maximum cost to remediate the site would be $487,000. Based on this study and the similar nature of the three sites not covered by the settlement, we increased our environmental liability in the fourth quarter of 2002 by $1,508,000, with an offsetting increase to a regulatory asset, to reflect a liability of $637,000 for each of the four sites.
At October 31, 2002, our undiscounted environmental liability totaled $2,868,000, consisting of $2,548,000 for the four MGP sites and $320,000 for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries.
At October 31, 2002, our regulatory assets for environmental costs totaled $6,153,000, net of recoveries from customers, in
connection with the estimated liabilities for the MGP sites and underground storage tanks and for environmental costs incurred, primarily legal fees and engineering assessments. The portion of the regulatory assets representing actual costs incurred is being amortized as recovered in current approved rates from customers in all three states.
Further evaluations of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on financial position or results of operations.
Management’s Responsibility For Financial Reporting
The management of Piedmont Natural Gas Company is responsible for the preparation and integrity of the accompanying consolidated financial statements and related notes. We prepared the statements in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and included amounts which are necessarily based on our best estimates and judgments made with due consideration to materiality. Financial information presented elsewhere in this report is consistent with that in the consolidated financial statements.
We have established and are responsible for maintaining a comprehensive system of internal accounting controls which we believe provides reasonable assurance that policies and procedures are complied with, assets are safeguarded and transactions are executed according to management’s authorization. We continually review this system for effectiveness and modify it in response to changing business conditions and operations and as a result of recommendations by internal and external auditors.
The Audit Committee of the Board of Directors, consisting solely of independent Directors, meets at least quarterly with Deloitte & Touche LLP, the internal auditors and representatives of management to discuss auditing and financial reporting matters. The Audit Committee reviews audit plans and results and accounting, financial reporting and internal control practices, procedures and results. Both Deloitte & Touche LLP and the internal auditors have full and free access to all levels of management.
/s/ Barry L. Guy
Barry L. Guy
Vice President and Controller
Independent Auditors’ Report
Piedmont Natural Gas Company, Inc.
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (Piedmont Natural Gas) as of October 31, 2002 and 2001, and the related statements of consolidated income, stockholders’ equity and cash flows for the three years in the period ended October 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of Piedmont Natural Gas’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 at October 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 12, 2002
Quarterly Financial Data (Unaudited) (In thousands except per share amounts)
The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.
*The results for 2001 were impacted by a change in estimate for lost and unaccounted for gas in unbilled revenues by SouthStar Energy Services LLC, of which we own a 30% interest and account for under the equity accounting method. Our portion of the adjustment was $(5) million, net of tax, or $(.15) per share.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information required under this item with respect to directors is contained in our proxy statement filed with the Securities and Exchange Commission (SEC) on or about January 20, 2003, and is incorporated herein by reference.
All of our officers’ names, ages and positions as of October 31, 2002, are listed below along with their business experience during the past five years.
So far as practicable, all elected officers are elected at the first meeting of the Board of Directors held following the annual meeting of shareholders in each year and hold office until the meeting of the Board following the annual meeting of shareholders in the next subsequent year and until their respective successors are elected and qualify. All other officers hold office during the pleasure of the Board. There are no family relationships among these officers.
There are no arrangements or understandings between any officer and any other person pursuant to which the officer was selected except for employment agreements and severence agreements with Messrs. Dzuricky, Killough, Schiefer, Skains and Yoho which were in effect during the year ended October 31, 2002.
*Mr. Schiefer will retire on February 28, 2003, at the Company’s annual meeting of shareholders. Mr. Skains has been elected President and Chief Executive Officer effective upon Mr. Schiefer’s retirement.
Item 11.
Item 11. Executive Compensation
Information required under this item is contained in our proxy statement filed with the SEC on or about January 20, 2003, and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
(a) Security Ownership of Certain Beneficial Owners
Information with respect to security ownership of certain beneficial owners is contained in our proxy statement filed with the SEC on or about January 20, 2003, and is incorporated herein by reference.
(b) Security Ownership of Management
Information with respect to security ownership of directors and officers is contained in our proxy statement filed with the SEC on or about January 20, 2003, and is incorporated herein by reference.
(c) Changes in Control
We know of no arrangements or pledges which may result in a change in control.
Item 13.
Item 13. Certain Relationships and Related Transactions
Information with respect to certain transactions with directors is contained in our proxy statement filed with the SEC on or about January 20, 2003, and is incorporated herein by reference.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) 1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company and its subsidiaries and the related independent auditors’ report for the year ended October 31, 2002, are included in Item 8 of this report as follows:
(a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
Schedules other than those listed above and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(a) 3. EXHIBITS
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
3.1
Articles of Incorporation of the Company, filed in the Department of State of the State of North Carolina on December 14, 1993 (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994).
3.2
Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed “Piedmont Natural Gas Company, Inc.” (Exhibits 3.2 and 3.1 to the Registration Statement on Form 8-B, dated March 2, 1994).
3.3
By-Laws of the Company, as amended, dated February 25, 2001 (Exhibit No. 3.1, Form 10-Q for the quarter ended January 31, 2001).
3.4
Articles of Amendment of the Company (Exhibit No. 3, Amendment to Form 10-Q for the period ended April 30, 1997).
4.1
Note Agreement, dated as of June 15, 1989, between the Company and The Mutual Life Insurance Company of New York (Exhibit 4.27, Form 10-K for the fiscal year ended October 31, 1989).
4.2
Note Agreement, dated as of July 30, 1991, between the Company and The Prudential Insurance Company of America (Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 1991).
4.3
Note Agreement, dated as of September 21, 1992, between the Company and Provident Life and Accident Insurance Company (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).
4.4
Indenture, dated as of April 1, 1993, between the Company and Citibank, N.A., Trustee (Exhibit 4.1, Registration Statement No. 33-60108).
4.5
Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7, Form 10-K for the fiscal year ended October 31, 1993).
4.6
Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
4.7
Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.8
Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
4.9
Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
4.10
Rights Agreement, dated as of February 27, 1998, between the Company and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1, Current Report on Form 8-K dated February 27, 1998).
4.11
Form of Master Global Note (executed September 9, 1999, substantially as filed as Exhibit 4.4, Registration Statement No. 333-26161).
4.12
Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Registration Statement Nos. 33-59369 and 333-26161).
4.13
Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Registration Statement Nos. 33-59369 and 333-26161).
4.14
Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement to Registration Statement No. 333-26161).
4.15
Form of Master Global Note (executed June 4, 2001, substantially as filed as Exhibit 4.4, Registration Statement No. 333-62222).
4.16
Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement to Registration Statement No. 333-62222).
10.1
Executive Long-Term Incentive Plan (Exhibit 99.1, Registration Statement No. 333-34435).
10.2
Service Agreement (5,900 Mcf per day) (Contract No. 4995), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.20, Form 10-K for the fiscal year ended October 31, 1991).
10.3
Service Agreement FT-Incremental Mainline (6,222 Mcf per day) (Contract No. 2268), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.16, Form 10-K for the fiscal year ended October 31, 1992).
10.4
Service Agreement (FT, 205,200 Mcf per day) (Contract No. 3702), dated February 1, 1992, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.20, Form 10-K for the fiscal year ended October 31, 1992).
10.5
Service Agreement (Contract #800059) (SCT, 1,677 dt/day), dated June 1, 1993, between the Company and Texas Eastern Transmission Corporation (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 1993).
10.6
FTS Service Agreement (23,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.24, Form 10-K for the fiscal year ended October 31, 1994).
10.7
Service Agreement under Rate Schedule FSS (2,263,920 dekatherm storage capacity quantity, 37,000 dekatherm maximum daily storage deliverability) (Contract No. 38015), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.25, Form 10-K for the fiscal year ended October 31, 1994).
10.8
Service Agreement under Rate Schedule SST (Winter: 10,000 Dt/day; Summer: 5,000 Dt/day) (Contract No. 38052), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1994).
10.9
FSS Service Agreement (10,000 dekatherms per day daily storage quantity) (Contract No. 38017), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1995).
10.10
SST Service Agreement (37,000 dekatherms per day) (Contract No. 38054), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.27, Form 10-K for the fiscal year ended October 31, 1995).
10.11
Service Agreement (20,504 Mcf per day), dated June 6, 1994, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 1995).
10.12
FTS-1 Service Agreement (5,000 dekatherms per day) (Contract No. 43462), dated September 14, 1994, between the Company and Columbia Gulf Transmission Company (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 1995).
10.13
FTS 1 Service Agreement (23,455 Dt per day)(Contract No. 43461), dated September 14, 1994, between the Company and Columbia Gulf Transmission Company (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 1996).
10.14
Firm Transportation Agreement (FT/NT), dated September 22, 1995, between the Company and Texas Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1996).
10.15
Service Agreement Applicable to Transportation of Natural Gas Under Rate Schedule FT (X-74 Assignment) (12,875 Dt per day), dated October 18, 1995, between the Company and CNG Transmission Corporation (Exhibit 10.27, Form 10-K for the fiscal year ended October 31, 1996).
10.16
Service Agreement (Southern Expansion, FT 53,000 Mcf per day peak winter months, 47,700 Mcf per day shoulder winter months) (Contract No. 0.4189), dated November 1, 1995, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 1996).
10.17
Service Agreement (12,785 Mcf per day) (Contract No. 1.1994, FT/NT), dated November 1, 1995, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.31, Form 10-K for the fiscal year ended October 31, 1996).
10.18
Rate Schedule GSS Service Agreement, dated May 15, 1996, between the Company and CNG Transmission Corporation (Exhibit 10.32, Form 10-K for the fiscal year ended October 31, 1996).
10.19
Employment Agreement between the Company and David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1999).
10.20
Employment Agreement between the Company and Ray B. Killough, dated December 1, 1999 (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1999).
10.21
Employment Agreement between the Company and Ware F. Schiefer, dated December 1, 1999 (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1999).
10.22
Employment Agreement between the Company and Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999).
10.23
Employment Agreement between the Company and Franklin H. Yoho, dated March 18, 2002.
10.24
Severance Agreement between the Company and David J. Dzuricky, dated December 1, 1999 (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1999).
10.25
Severance Agreement between the Company and Ray B. Killough, dated December 1, 1999 (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1999).
10.26
Severance Agreement between the Company and Ware F. Schiefer, dated December 1, 1999 (Exhibit 10.43, Form 10-K for the fiscal year ended October 31, 1999).
10.27
Severance Agreement between the Company and Thomas E. Skains, dated December 1, 1999 (Exhibit 10.44, Form 10-K for the fiscal year ended October 31, 1999).
10.28
Severance Agreement between the Company and Franklin H. Yoho, dated March 18, 2002.
10.29
Consulting Agreement between the Company and John H. Maxheim, dated March 1, 2000 (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2001).
10.30
Service Agreement (SE95/96), dated June 25, 1996, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1996).
10.31
FSS Service Agreement (25,000 dekatherms per day) (Contract No. 49775), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1997).
10.32
SST Service Agreement (25,000 dekatherms per day peak winter months, 12,500 dekatherms per day shoulder months) (Contract No. 49773), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1997).
10.33
FSS Service Agreement (1,150,166 dekatherms storage capacity quantity, 19,169 dekatherms maximum daily storage deliverability) (Contract No. 49777), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1998).
10.34
Columbia Gas SST Service Agreement (19,169 dekatherms per day) dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1998).
10.35
Transco Sunbelt Service Agreement & Precedent Agreement (41,400 dekatherms of transportation contract quantity per day), dated January 24, 1997, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1998).
10.36
CNG Service Agreement (7,000 dekatherms per day), dated May 15, 1996, between the Company and CNG Transmission Corporation (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1998).
10.37
Form of Director Retirement Benefits Agreement between the Company and its outside directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).
10.38
Service Agreement under Rate Schedule GSS (Storage withdrawal of 68,955 Mcf per day, Storage capacity of 3,858,940 Mcf), dated July 1, 1996, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.55, Form 10-K for the fiscal year ended October 31, 1999).
10.39
Service Agreement, dated January 29, 1997, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.57, Form 10-K for the fiscal year ended October 31, 1999).
10.40
Firm Transportation Agreement (60,000 Mcf per day), dated June 26, 1998, between the Company and Cardinal Extension Company, LLC (Exhibit 10.58, Form 10-K for the fiscal year ended October 31, 1999).
10.41
Service Agreement (15,000 dekatherms per day), dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.50, Form 10-K for the fiscal year ended October 31, 2000).
10.42
Letter of Right of First Refusal, dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.51, Form 10-K for the fiscal year ended October 31, 2000).
10.43
Letter of Agreement of Amendment No. 343 to Gas Transportation Agreement (dated September 1, 1993 - Contract No. 237) (FTA, 74,100 dekatherms per day), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.52, Form 10-K for the fiscal year ended October 31, 2000).
10.44
Letter of Agreement of Amendment No. 2A to Gas Storage Contract (dated September 1, 1993 - Contract No. 2400), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.53, Form 10-K for the fiscal year ended October 31, 2000).
10.45
Letter of Agreement of Amendment No. 2A to Gas Storage Contract (dated May 1, 1994 - Contract No. 6815), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 2000).
10.46
Service Agreement under FT-A Rate Schedule (Contract No. 24706) (55,900 dekatherms per day), dated August 12, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.55, Form 10-K for the fiscal year ended October 31, 2000).
10.47
Service Agreement under Rate Schedule WSS - Open Access (Contract No. 3.8399) (75,206 dekatherms per day maximum withdrawal quantity; storage capacity quantity of 6,392,383 dekatherms), dated April 1, 2001, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.48, Form 10-K for the fiscal year ended October 31, 2001).
10.48
Amended and Restated Operating Agreement of Greenbrier Pipeline Company, LLC, dated September 1, 2001.
10.49
Precedent Agreement for Firm Transportation Service (Greenbrier Pipeline Company), dated September 1, 2001, between the Company and Greenbrier Pipeline Company, LLC.
Computation of Ratio of Earnings to Fixed Charges.
Independent Auditors' Consent.
99.1
Annual Report on Form 11-K - Piedmont Natural Gas Company, Inc. Salary Investment Plan.
99.2
Annual Report on Form 11-K - Piedmont Natural Gas Company, Inc. Payroll Investment Plan.
(b) Reports on Form 8-K
On August 13, 2002, we filed a Form 8-K regarding a press release reporting that our Chief Executive Officer and Chief Financial Officer had voluntarily signed and filed sworn statements on August 9, 2002, with the Securities and Exchange Commission certifying the filings made by us with the SEC in 2001 and 2002. These filings include our 10-K for fiscal year ended October 31, 2001, our 10-Qs for our first and second quarters of fiscal year ending October 31, 2002, our 8-Ks filed subsequent to the 10-K for fiscal year ended October 31, 2001 and our proxy statement issued in January 2002 for fiscal year ended October 31, 2001.
On October 1, 2002, we filed a Form 8-K regarding a press release announcing the completion of the purchase of North Carolina Gas Service, the North Carolina natural gas division of NUI Corporation.
On October 18, 2002, we filed a Form 8-K regarding a press release announcing an agreement to purchase the stock of North Carolina Natural Gas, a natural gas distribution subsidiary of Progress Energy, and Progress Energy’s 50% investment in Eastern North Carolina Natural Gas Company for approximately $425 million in cash.
On October 30, 2002, we filed a Form 8-K regarding a press release announcing orders issued by the North Carolina Utilities Commission and the Public Service Commission of South Carolina approving rate increases totaling $22.3 million.
On November 6, 2002, subsequent to our year end, we filed a report on Form 8-K regarding a press release providing earnings guidance for fiscal year 2003 and reaffirming our previous earnings guidance for fiscal year 2002.
On December 23, 2002, subsequent to our year end, we filed a Form 8-K regarding a press release announcing that Ware F. Schiefer, Chief Executive Officer and Vice Chairman of the Board, would be retiring at the annual meeting of shareholders on February 28, 2003, and that Thomas E. Skains had been elected to the position of President and Chief Executive Officer effective upon Mr. Schiefer’s retirement. Further, John H. Maxheim, current Chairman of the Board, will retire as Chairman and as a Board member at the February 28 meeting.
On January 8, 2003, subsequent to our year end, we filed a report on Form 8-K regarding a press release announcing that our Board of Directors had elected Kim R. Cocklin to the position of Senior Vice President and General Counsel, effective February 3, 2003.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on January 23, 2003.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of January 23, 2003.
Signature
Title
/s/ Ware F. Schiefer
Ware F. Schiefer
Chief Executive Officer
and Director
/s/ Thomas E. Skains
Thomas E. Skains
President and Chief Operating Officer
and Director
/s/ David J. Dzuricky
David J. Dzuricky
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/ Barry L. Guy
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
CERTIFICATIONS
I, Ware F. Schiefer, certify that:
1.
I have reviewed this annual report on Form 10-K of Piedmont Natural Gas Company, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal controls and procedures for financial reporting (as defined in Exchange Act Rules 13a-14 and
15d-14) for the registrant and we have;
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls and procedures for financial reporting, or caused such internal controls and procedures for financial reporting to be designed under their supervision, to provide reasonable assurances that the registrant’s financial statements are fairly presented in conformity with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and internal controls and procedures for financial reporting as of the end of the period covered by this report (“Evaluation Date”);
d)
Presented in this report our conclusions about the effectiveness of the disclosure controls and procedures and internal controls and procedures for financial reporting based on our evaluation as of the Evaluation Date;
e)
Disclosed to the registrant’s auditors and the audit committee of the board of directors (or persons fulfilling the equivalent function):
(i)
All significant deficiencies and material weaknesses in the design or operation of internal controls and procedures for financial reporting which could adversely affect the registrant’s ability to record, process, summarize and report financial information required to be disclosed by the registrant in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.), within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms; and
(ii)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls and procedures for financial reporting; and
f)
Indicated in this report any significant changes in the registrant’s internal controls and procedures for financial reporting or in other factors that could significantly affect internal controls and procedures for financial reporting made during the period covered by this report, including any actions taken to correct significant deficiencies and material weaknesses in the registrant’s internal controls and procedures for financial reporting.
Date: January 23, 2003
/s/ Ware F. Schiefer
Ware F. Schiefer
Chief Executive Officer
CERTIFICATIONS
I, David J. Dzuricky, certify that:
1.
I have reviewed this annual report on Form 10-K of Piedmont Natural Gas Company, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal controls and procedures for financial reporting (as defined in Exchange Act Rules 13a-14 and
15d-14) for the registrant and we have;
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls and procedures for financial reporting, or caused such internal controls and procedures for financial reporting to be designed under their supervision, to provide reasonable assurances that the registrant’s financial statements are fairly presented in conformity with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and internal controls and procedures for financial reporting as of the end of the period covered by this report (“Evaluation Date”);
d)
Presented in this report our conclusions about the effectiveness of the disclosure controls and procedures and internal controls and procedures for financial reporting based on our evaluation as of the Evaluation Date;
e)
Disclosed to the registrant’s auditors and the audit committee of the board of directors (or persons fulfilling the equivalent function):
(i)
All significant deficiencies and material weaknesses in the design or operation of internal controls and procedures for financial reporting which could adversely affect the registrant’s ability to record, process, summarize and report financial information required to be disclosed by the registrant in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.), within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms; and
(ii)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls and procedures for financial reporting; and
f)
Indicated in this report any significant changes in the registrant’s internal controls and procedures for financial reporting or in other factors that could significantly affect internal controls and procedures for financial reporting made during the period covered by this report, including any actions taken to correct significant deficiencies and material weaknesses in the registrant’s internal controls and procedures for financial reporting.
Date: January 23, 2003
/s/ David J. Dzuricky
David J. Dzuricky
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Schedule II
Piedmont Natural Gas Company, Inc. and Subsidiaries
Valuation and Qualifying Accounts
For the Years Ended October 31, 2002, 2001 and 2000
(1)
Uncollectible accounts written off net of recoveries and adjustments.
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 2002
Exhibits
10.23
Employment Agreement between the Company and Franklin H. Yoho, dated March 18, 2002.
10.28
Severance Agreement between the Company and Franklin H. Yoho, dated March 18, 2002.
10.48
Amended and Restated Operating Agreement of Greenbrier Pipeline Company, LLC, dated September 1, 2001.
10.49
Precedent Agreement for Firm Transportation Service (Greenbrier Pipeline Project) between the Company and Greenbrier Pipeline Company, LLC, dated September 1, 2001.
Computation of Ratio of Earnings to Fixed Charges.
Independent Auditors’ Consent.
99.1
Annual Report on Form 11-K - Piedmont Natural Gas Company, Inc. Salary Investment Plan.
99.2
Annual Report on Form 11-K - Piedmont Natural Gas Company, Inc. Payroll Investment Plan.