Annual Report (Form 10-K), fiscal year 1994

Item 1. Business - ------------------
Piedmont Natural Gas Company, Inc. (the Company), originally incorporated in 1950, is an energy and services company primarily engaged in the transportation and sale of natural gas and the sale of propane to 560,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee.
The Company's utility operations serve over 512,000 natural gas customers. The Company and its non-utility subsidiaries and divisions are also engaged in acquiring, marketing and arranging for the transportation of natural gas to large volume purchasers, in retailing residential and commercial gas appliances and in the sale of propane to over 47,000 customers in and adjacent to the Company's three-state service area.
In the Carolinas, the service area is comprised of numerous cities, towns and communities including Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington and the Hickory area in North Carolina. In Tennessee, the service area is the metropolitan area of Nashville, including portions of eight adjoining counties. The Company's propane market is in and adjacent to its natural gas market in all three states.
On February 25, 1994, the Company's shareholders approved a change in the state of incorporation from New York to North Carolina. The reincorporation was effected March 1, 1994, by merging the Company, a New York corporation, into a wholly-owned subsidiary, PNG Acquisition Company, a North Carolina corporation. In connection with the merger, each share of the Company's Common Stock, $.25 par value per share, was exchanged for one share of Common Stock, no par value, of PNG Acquisition Company. Immediately following the merger, the name of the surviving corporation was changed to Piedmont Natural Gas Company, Inc.
Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. Such revenues totaled $575.4 million for the year ended October 31, 1994, of which 41% was from residential customers, 29% from commercial customers, 29% from industrial customers and 1% from various sources. Revenues from non-utility operations, less related costs and income taxes, are shown in the consolidated financial statements in other income. Non-utility revenues as a percentage of total revenues, including utility operations, were 8% in 1994. No single non-utility activity accounted for greater than 6% of total revenues. Income from non-utility activities as a percentage of total net income was 12% in 1994. No single non-utility activity accounted for more than 8% of net income.
The Company is principally engaged in the gas distribution industry and has no other reportable industry segments.
The Company's utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC) and the Tennessee Public Service Commission (TPSC) as to the issuance of securities, and by those commissions and by the Public Service Commission of South Carolina (PSCSC) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The Company is also subject to or affected by various federal regulations.
The Company holds non-exclusive franchises for natural gas service in all communities where required, with expiration dates from 1995 to 2044. The earliest date at which a franchise for a major service area expires is 1999. In the Company's opinion, the franchises are adequate for the operation of its gas distribution business and do not contain restrictions which are of a materially burdensome nature. In most cases, the loss of a franchise would not have a material effect on the Company's operations. The Company has never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action.
The Company's utility business and its non-utility propane activities are seasonal in nature as variations in weather conditions generally result in greater earnings during the winter months. The Company normally injects natural gas into storage during periods of warm weather (principally April 1 through October 31) for withdrawal from storage during periods of cold weather (principally November 1 through March 31) when sufficient quantities of flowing pipeline gas are not available to meet customer demand. During 1994, the amount of natural gas in storage varied from 4.4 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 16.4 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $10.5 million to $35.6 million.
The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1990 through 1994:
During 1994, the Company delivered 126.1 million dekatherms of natural gas to its customers, of which 22.5 million dekatherms were transported for the Company's largest industrial customers. This compares with 120.2 million dekatherms delivered in 1993, of which 14.5 million dekatherms were transported.
Sales to temperature-sensitive customers, whose consumption varies with the weather, were 65 million dekatherms in 1994, compared with 62.5 million dekatherms in 1993. Weather which was 2% warmer than normal was experienced in 1994, compared with 1% colder-than-normal weather in 1993. The Company sold or transported 61 million dekatherms to industrial users in 1994, compared with 57.5 million dekatherms in 1993. Industrial sales are the most price-sensitive of the Company's markets and are largely a function of the Company's ability to obtain reliable supplies of natural gas competitively priced with other industrial fuels.
Except as set forth below, all natural gas distributed by the Company is transported to the Company by one of five interstate pipelines, Transcontinental Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company (Tennessee Pipeline), Texas Eastern Transmission Corporation (Texas Eastern), Columbia Gas Transmission Company (Columbia Gas) and Columbia Gulf Transmission Corporation (Columbia Gulf).
As of November 1, 1994, suppliers have contracted to provide the following daily pipeline capacity in dekatherms of natural gas:
The Company has the following additional daily peaking capacity in dekatherms of natural gas to meet the firm demands of its markets. This availability varies from 10 days to 151 days.
From time to time, the Company is able to purchase gas from South Carolina Pipeline Corporation (SC Pipeline), an intrastate pipeline in South Carolina, at market prices on a month by month basis.
The Company utilizes a "best cost" gas purchasing philosophy that seeks to purchase gas on a short- or long-term basis by weighing cost against supply security and reliability factors. Of the 106.6 million dekatherms of natural gas purchased by the Company in 1994, approximately 15% was purchased under short-term contracts of less than one year, 14% under contracts of from one to three years and 71% under contracts of over three years. The majority of these purchases was from non-pipeline sources.
The Company owns or has under contract 19.7 million dekatherms of storage capability, either in the form of underground storage or liquefied natural gas. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.
For further information on gas supply and regulation, see "Gas Supply and Rate Proceedings" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report.
Currently, approximately 35% of the Company's annual gas deliveries are being made to industrial or large commercial customers who have the capability to burn a fuel other than natural gas. The alternate fuels are primarily fuel oil or 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 governmental regulations, the availability of gas from suppliers and the price of gas as compared with alternate fuels.
Filed tariffs with the NCUC, the PSCSC and the TPSC permit the Company to reduce its filed rates to meet competition. During 1994, the Company negotiated $11.6 million of rates to industrial and large commercial customers in North Carolina and South Carolina. The Company was able to recover these negotiated rates by purchasing and arranging interstate pipeline transportation for gas purchased at lower costs than that included in the Company's filed tariffs under procedures approved by the Federal Energy Regulatory Commission and state regulatory agencies. The ability to continue to offset revenue losses if prices of competitive fuels fall below the price of natural gas in the Company's tariffs depends on a number of factors, including the ability to obtain competitively priced gas from suppliers, the ability to obtain transportation for gas purchased from suppliers other than regulated pipelines, the ability of customers to obtain pipeline transportation for customer-owned gas and continued regulatory approval of these procedures.
Although local distribution companies, such as the Company, are generally concerned about the impact of the ability of a large commercial or industrial customer to bypass their systems, the Company does not view bypass from existing commercial and industrial customers as a major issue. For a customer economically to bypass the Company's distribution system under current conditions, the customer would need to have a large gas load, greater than 4,000 dekatherms per day, and/or close proximity to an interstate pipeline. With the exception of one customer located in Nashville, Tennessee, the Company does not believe any of its existing customers have the conditions that are conducive to bypass. However, the Company has a contract with this customer to provide services at rates which the Company believes makes it not economically feasible for the customer to choose to bypass.
In the residential and small commercial markets, natural gas competes primarily with electricity for such uses as cooking and water heating and with electricity and fuel oil for space heating.
During 1994, the Company's largest customer contributed $15.8 million, or 2.5%, to revenues.
The amount of research and development costs incurred in connection with Company-sponsored research is immaterial. The Company contributes to gas industry-sponsored research projects; however, the amounts contributed to such projects are minimal.
Compliance with federal, state and local environmental protection laws had no material effect on capital expenditures, earnings or competitive position during 1994. For further information on environmental issues, see "Environmental Matters" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report.
As of October 31, 1994, the Company had 1,968 employees, compared with 1,947 employees as of October 31, 1993.
Item 2.



Item 2. Properties - --------------------
The Company's properties consist primarily of distribution systems and related facilities to serve its utility customers. The Company has constructed and owns approximately 459 miles of lateral pipelines up to 16 inches in diameter which connect the distribution systems of the Company with the transmission systems of its pipeline suppliers. Natural gas is distributed through approximately 16,300 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.
The Company either owns or leases for varying periods district and regional offices for its utility and non-utility operations.
Information concerning oil and gas drilling and producing activities is not presented as these activities are not material to the Company's results of operations or financial position. During 1994, the Company sold its exploration and development properties. The disposition of these properties did not have a material effect on the Company's operations.
Item 3.

Item 3. Legal Proceedings - ---------------------------
There are a number of lawsuits pending against the Company for damages alleged to have been caused by negligence of the Company's employees. The Company has liability insurance which it believes is adequate to cover any material judgments which 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) The Company's Common Stock 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 (symbol PNY) for each quarterly period for the years ended October 31, 1994 and 1993.
(b) As of January 11, 1995, the Company's Common Stock was held by 12,498 shareholders of record.
(c) Information with respect to dividends paid on the Company's Common Stock for the years ended October 31, 1994 and 1993, is as follows:
The Company's note agreements under which long-term debt was issued contain provisions which restrict the amount of cash dividends that may be paid on Common Stock. As of October 31, 1994, all of the Company's retained earnings was free of such restrictions.
Item 6.

Item 6. Selected Financial Data - --------------------------------
Selected financial data for the years ended October 31, 1990 through 1994, is as follows:
Item 7.

Item 7. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations - ---------------------
Liquidity and Capital Resources
The Company has committed bank lines of credit totaling $57 million to finance current cash requirements. Additional uncommitted lines are also available on an as needed, if available, basis. Borrowings under the lines include bankers' acceptances, 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 gas distribution business is highly seasonal and requires the use of short-term debt to meet seasonal working capital requirements and to temporarily finance construction pending the issuance of long-term debt or common equity. Borrowings against the lines of credit during 1994 ranged from zero to a high of $68.5 million in September.
The Company had $318 million of long-term debt outstanding at October 31, 1994. Annual sinking fund requirements and maturities of this debt are $5 million in 1995, $7 million in 1996, $10 million in 1997, 1998 and 1999 and $276 million thereafter. Long-term debt retired in 1994 totaled $5 million.
On September 19, 1994, the Company sold $40 million of 8.45% Medium-Term Notes due 2024 under a $150 million shelf registration. Proceeds from the sale were used to reduce short-term debt and finance capital expenditures. The notes are to be redeemed in a single payment at maturity.
At October 31, 1994, the Company's capitalization ratio consisted of 51% long-term debt and 49% common equity. The
embedded cost of long-term debt at October 31, 1994, was 8.73%. The actual return on average common equity in 1994 was 12.10%.
Cash provided from operations and from financing was sufficient to fund investing activities, largely utility and non-utility construction, payments of debt principal and interest and dividend payments to shareholders.
Although local gas distribution companies (LDCs), such as the Company, are generally concerned about the impact of the ability of a large commercial or industrial customer to bypass their systems, the Company does not view bypass from existing commercial and industrial customers as a major liquidity issue. For a customer economically to bypass the Company's distribution system under current conditions, the customer would need to have a large gas load, greater than 4,000 dekatherms per day, and/or close proximity to an interstate pipeline. With the exception of one customer located in Nashville, Tennessee, the Company does not believe any of its existing customers have the conditions that are conducive to bypass. The Company has a contract with this customer to provide services at rates which the Company believes makes it not economically feasible for the customer to choose to bypass.
Capital expenditures for 1994 totaled $105.8 million for utility operations and $2.8 million for non-utility activities. Capital expenditures totaling $119.3 million for utility operations and $3.7 million for non-utility activities are budgeted for 1995. Cash requirements to fund these expenditures and to fund interest and sinking fund payments and dividends are expected to be provided by internally generated cash, issuance of Common Stock through dividend reinvestment and stock purchase plans, short-term bank borrowings, issuance of long-term debt and sale of equity securities.
On February 25, 1994, the Company's shareholders approved a change in the state of incorporation from New York to North Carolina. The reincorporation was effected March 1, 1994, by merging the Company, a New York corporation, into a wholly-owned subsidiary, PNG Acquisition Company, a North Carolina corporation. In connection with the merger, each share of the Company's Common Stock, $.25 par value per share, was exchanged for one share of Common Stock, no par value, of PNG Acquisition Company. Immediately following the merger, the name of the surviving corporation was changed to Piedmont Natural Gas Company, Inc.
Gas Supply and Rate Proceedings
Except as set forth below, all natural gas distributed by the Company is transported to the Company by one of five interstate pipelines, Transcontinental Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company (Tennessee Pipeline),
Texas Eastern Transmission Corporation (Texas Eastern), Columbia Gas Transmission Corporation (Columbia Gas) and Columbia Gulf Transmission Corporation, under tariffs regulated by the Federal Energy Regulatory Commission (FERC).
The majority of the Company's natural gas supply is purchased from sources in non-regulated transactions. The Company has supply agreements with some of the interstate pipelines which are primarily non-regulated; however, certain portions of the agreements are regulated by the FERC. The regulations under which the Company purchases and transports gas are in various stages of litigation or appeal to the courts. The final resolution of these matters could affect the rates paid by the Company to these interstate pipelines for past and future purchases and transportation of gas, the amount of refunds to which the Company may be entitled with respect to past amounts paid and the terms under which the Company may purchase and transport gas in the future. Based on past rate recovery decisions of the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Public Service Commission (TPSC), the Company expects to recover all such gas and transportation costs in its rates.
From time to time, the Company is able to purchase gas from South Carolina Pipeline Corporation (SC Pipeline), an intrastate pipeline in South Carolina, at market prices on a month by month basis.
The interstate gas pipeline industry was required to undergo a restructuring under FERC Order No. 636. Pursuant to Order No. 636, interstate pipelines were required to change their traditional role of gas merchants to LDCs by "unbundling" the gas sales, transportation and storage services provided by them and transporting gas to their customers. The FERC has approved mechanisms for the pipelines to recover from customers certain "transition costs" related to unbundling. The major component of these transition costs for most pipelines is the cost of realigning existing gas supply contracts (Gas Supply Realignment or GSR Costs).
In the Company's opinion, present rules and regulations of the NCUC, PSCSC and TPSC permit the Company to pass through to its customers any transition costs, including GSR costs. The Company has no assurance that the regulators will interpret these rules and regulations in the same manner as the Company or that these rules and regulations will not be modified or amended in the future. Effective November 1, 1993, the Company began recovering transition costs assessed by Tennessee Pipeline through purchased gas adjustment procedures approved by the TPSC. Since Transco realigned most of its gas supply contracts when it unbundled services several years ago, transition costs from Transco are expected to be minor. The FERC has ruled that Columbia Gas may not recover substantial portions of its GSR
costs; however, the FERC's ruling is subject to various appeals. In addition, the Company does not expect to be assessed substantial GSR costs by its other interstate pipeline suppliers.
Prior to 1990, the Company purchased gas for its North Carolina and South Carolina operations under a firm contract with SC Pipeline. In 1989, the PSCSC issued an order permitting SC Pipeline to recover take-or-pay costs from its customers with each customer's share being based on past purchasing practices (deficiency based allocation method). The decision of the PSCSC was appealed through the various courts which reversed the order, stayed its implementation, deemed that the deficiency based allocation method of recovery constituted retroactive ratemaking and remanded the methodology of recovery to the PSCSC. In April 1994, the PSCSC ordered that SC Pipeline could only recover take-or-pay costs on a prospective basis.
Prior to 1994, certain procedures of the NCUC with respect to the recovery of the wholesale cost of gas were challenged by a group of the Company's industrial customers in North Carolina. During 1994, the Company refunded certain amounts, for which adequate reserves had been previously provided, as required by the NCUC.
The Company is permitted to recover 100% of its prudently incurred gas costs, subject to annual prudence reviews covering an historical twelve-month period, in all three states in which the Company operates. During the year, the TPSC found the Company to be prudent in its gas purchasing practices and allowed 100% recovery of its gas costs. Prudency reviews in North Carolina and South Carolina have not been concluded; however, no adverse impact is anticipated based on the proceedings to date.
Since 1992, certain supplier refunds attributable to North Carolina operations have been held by the Company for possible inclusion in an expansion fund as legislated by the General Assembly of North Carolina to extend natural gas service to unserved areas of the state. As ordered by the NCUC, these refunds were deposited in a separate bank account and invested in short-term U.S. Treasury securities pending the establishment of an expansion fund. Additionally, other supplier refunds are being held by the Company for possible inclusion in an expansion fund. Such refunds, including interest earned to date, are included in restricted cash. In July 1994, the North Carolina Supreme Court affirmed the order of the NCUC which authorized the establishment of an expansion fund.
In September 1994, the Company filed a petition with the NCUC for a certificate of public convenience and necessity to serve four counties in North Carolina not presently receiving natural gas service and an application to establish an expansion fund and place $14.8 million of supplier refunds into the fund
for such expansion. A similar application to serve these counties has been filed by a company not currently operating in North Carolina. Hearings on these matters have been scheduled by the NCUC, and the outcome is not presently determinable.
In February 1994, the NCUC approved a settlement agreement in a general rate proceeding that provided for an increase in margin of $1.2 million during the period February 1 through October 31, 1994. In October 1994, the NCUC issued an order permitting the Company to increase its rates in North Carolina, effective November 1, 1994, by $5.2 million annually and its margin by $15.5 million. In addition, the order indicated that the NCUC will reopen the record for the purpose of receiving evidence concerning Cardinal Pipeline Company, L.L.C., and the approval of rates to cover investment and operating costs. See Other Matters.
In October 1994, the TPSC issued an order permitting the Company to increase its rates in Tennessee, effective October 28, 1994, by $6.8 million annually and its margin by $8.8 million.
Impact of Inflation
Inflation impacts the Company primarily in the prices it pays for labor, materials and services. Since the Company can adjust its rates to recover these costs only through the regulatory process, increased costs can have a significant impact on the results of operations. Under present regulatory commission orders, the Company passes on to its customers substantially all changes in the cost of gas through purchased gas adjustment procedures.
Results of Operations
Net income for 1994 was $35.5 million, compared with $37.5 million in 1993 and $35.3 million in 1992. The decrease in net income in 1994, compared with 1993, was primarily due to increases in operating and maintenance expenses, general taxes and utility interest charges, partially offset by higher rates billed, increased delivered volumes to residential and industrial customers and increased earnings from propane operations. The increase in net income in 1993, compared with 1992, was primarily due to higher rates billed and increased delivered volumes due to colder weather, partially offset by increases in operating expenses. Volumes of gas delivered to customers increased to 126.1 million dekatherms in 1994, compared with 120.2 million dekatherms in 1993 and 115.1 million dekatherms in 1992. Compared with the prior year, weather in the Company's service area was 3% warmer in 1994 and 9% and 15% colder in 1993 and 1992, respectively.
Operating revenues were $575.4 million in 1994, $552.8 million in 1993 and $459.9 million in 1992. The increases over
the previous years were primarily due to higher rates billed, increased delivered volumes, particularly increased sales to weather-sensitive residential and commercial customers on which a higher margin is earned, and a 6% increase in 1994 and a 5% increase in 1993 compared with the previous years, respectively, in the average number of customers billed. The weather normalization adjustment mechanism (WNA) in effect in all three states is designed to offset the impact that unusually cold or warm weather has on customer billings and the Company's operating margin. The WNA has been in effect in North Carolina and Tennessee for the past three years. The WNA became effective in South Carolina in December 1993. Weather which was 2% warmer than normal was experienced in 1994, compared with 1% colder-than-normal weather in 1993 and 8% warmer-than-normal weather in 1992.
For competitive reasons, the Company has for several years negotiated rates to industrial customers with alternate fuel capabilities. The Company has been able to offset such lower negotiated rates through decreases in the cost of gas paid to suppliers. Therefore, negotiation has resulted in reduced revenues but has not reduced margin. The Company negotiated $11.6 million of rates in 1994 to North Carolina and South Carolina customers. The ability to offset negotiated margin reductions through savings in the cost of gas is subject to continuing regulatory approval.
Cost of gas was $340.6 million in 1994, $328.9 million in 1993 and $253.8 million in 1992. The increase in 1994, compared with 1993, was primarily due to an increase in delivered volumes. The increase in 1993, compared with 1992, was primarily due to increases in delivered volumes, capacity costs, demand charges and commodity prices. Increases or decreases in purchased gas costs had no significant impact on margin as they were passed on to customers or used to offset negotiated margin reductions as noted above.
Margin was $234.8 million in 1994, $223.9 million in 1993 and $206.1 million in 1992. The increases over the previous years were primarily due to growth in the customer base and industrial customer usage. The margin earned per dekatherm of gas delivered remained unchanged in 1994, compared with 1993, and increased by $.07 in 1993 over 1992.
Other operations and maintenance expenses increased from $92.6 million to $108.2 million over the three-year period 1992 to 1994. The increases were primarily due to increases in the cost of maintenance and repair of mains, rents, utilities, uncollectibles, payroll and employee benefits.
Depreciation expense increased from $20 million to $24.6 million over the three-year period 1992 to 1994 due to the growth in plant in service.
General taxes increased from $21 million to $26.6 million over the three-year period 1992 to 1994 primarily due to increases in property taxes resulting from property tax rate increases and additions to taxable property and to increases in gross receipts taxes resulting from increased revenues.
Other income, net of income taxes, was $4.2 million in 1994, $2.9 million in 1993 and $3.5 million in 1992. The fluctuations were primarily due to variations from year to year in the allowance for equity funds used during construction and earnings from propane operations and other non-utility activities.
Utility interest charges were $24.5 million in 1994, $21.9 million in 1993 and $21.5 million in 1992. The increase in 1994, compared with 1993, was primarily due to increases in the balances of long-term debt outstanding even though at lower overall interest rates, amortization of debt expenses due to the issuance of debt in the last two years and interest charged on refunds due customers due to greater amounts outstanding. The increase in 1993, compared with 1992, was primarily due to increases in the balances outstanding during the year on long-term and short-term debt although at interest rates which were lower in 1993. These increases were partially offset by a decrease in interest charged on refunds due customers due to lower amounts payable.
Environmental Matters
The Company has owned or operated manufactured gas plant (MGP) facilities at 11 sites in its three-state service area. Four of these sites are still owned by the Company and the remaining seven are owned by other individuals or companies. Eight of the 11 sites involve other parties who either owned the property or operated the facilities. Currently, five of the eight sites in North Carolina are on the Comprehensive Environmental Response, Compensation and Liability Act Information System target list of the Environmental Protection Agency on the recommendation of the North Carolina Department of Environment, Health, and Natural Resources (the Department). This list identifies these sites for a preliminary assessment as to the danger posed to health and the environment. The North Carolina Superfund Section is in various stages of analyses on these five sites. The Company has not received any notification from the Department nor does it have other information which indicates significant remedial measures with respect to any of these sites. The Company has not been notified by any governmental agency in South Carolina or Tennessee with respect to MGPs in those states.
In 1992, the Department launched an initiative to encourage former owners and/or operators of MGP facilities to assess these sites and remediate where necessary. In late 1993, the North Carolina Manufactured Gas Plant Group, a group of former MGP
owners/operators in which the Company plays an active role, and the state finalized the first step in a cooperative effort to develop a uniform and reasonable framework and program for addressing the state's MGP sites. The MGP Group and the state have completed the negotiation of a model document that sets out the procedures for investigating an MGP site. The state has requested that the former owners/operators of one site at which the Company was involved for a brief period agree to the use of these procedures. The Company is currently discussing the state's request for that specific site with the state and with another former owner/operator. The Company is also discussing cost sharing arrangements with other potentially responsible parties.
Further evaluations of the MGP sites will determine any remediation requirements and associated costs and the involvement of the Company in the sharing of these costs. The Company cannot presently determine the liability with respect to individual MGP sites since site specific evaluations have not been performed and cost-sharing arrangements with other responsible parties have not been finalized.
The Company is in the process of evaluating and remediating sites with respect to its present or former ownership of underground tanks. As of October 31, 1994, comprehensive evaluations of underground tank sites were substantially complete. Of the 11 sites in North Carolina and South Carolina, six will require corrective action and varying degrees of remediation. The Department has established a trust fund which reimburses the owner or operator for the costs of evaluating and remediating the underground tank sites in excess of a designated variable dollar amount per site.
Based on a generic MGP site study and estimates determined in the underground storage tank comprehensive site evaluations, the Company has recorded a liability and an associated regulatory asset of $1.7 million for potential future environmental costs. The three state regulatory commissions regulating the Company have authorized deferral accounting, or the creation of a regulatory asset, for expenditures made in connection with environmental matters. A determination as to whether or not environmental expenditures, net of recoveries from other responsible parties, will be recovered from ratepayers will be made at the appropriate time in general rate case proceedings. In North Carolina, current procedures permit the Company to recover 100% of its prudently incurred MGP clean-up costs but do not permit the recovery of any carrying costs on such amounts from the time the amounts are expended until the time they are collected. Based on regulatory accounting directives and the emerging trend in the industry for regulators to permit substantial recovery of such costs, the Company believes that the resolution of these matters will not have a material adverse
effect on the Company's financial position or results of operations.
Accounting Pronouncements
The Company will adopt Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112), in its fiscal year beginning November 1, 1994. FAS 112 requires, among other things, the accrual for benefits provided to former or inactive employees after employment but before retirement and to their beneficiaries and covered dependents. Adoption of FAS 112 is not expected to have a material impact on the Company's financial position or results of operations.
Other Matters
The Company, in cooperation with another utility, formed Cardinal Pipeline Company, L.L.C. (Cardinal), in March 1994. Cardinal is a North Carolina limited liability company which is owned approximately 36% by Piedmont Intrastate Pipeline Company, a wholly-owned subsidiary of the Company. In July 1994, the NCUC granted Cardinal a certificate of public convenience and necessity to construct, own and operate a 24-inch natural gas pipeline from a connection with an interstate pipeline in Rockingham County, North Carolina, to Alamance County, North Carolina, where it connects with facilities owned by the Company and with facilities owned by the other utility company. The other utility is the operator of the pipeline. The pipeline was placed in service on December 31, 1994.
The Company, with two other energy marketing firms, formed Resource Energy Services Company, L.L.C. (RES), in January 1994. RES is a North Carolina limited liability company which is owned 51% by Piedmont Energy Company, a wholly-owned subsidiary of the Company. RES offers natural gas acquisition, transportation and storage services to industrial users and utilities in the mid-south and southeastern areas of the United States.
Item 8.


Item 8. Financial Statements and Supplementary Data - ----------------------------------------------------
The Company's consolidated financial statements and schedules required by this Item are listed in Item 14(a)1 and 2 in Part IV of this report.
CONSOLIDATED BALANCE SHEETS October 31, 1994 and 1993
ASSETS
CAPITALIZATION AND LIABILITIES
*Prior period amounts have been restated to reflect, effective March 1, 1994, the exchange of each share of common stock, $.25 par value per share, for one share of common stock, no par value.
STATEMENTS OF CONSOLIDATED INCOME For the Years Ended October 31, 1994, 1993 and 1992
STATEMENTS OF CONSOLIDATED CASH FLOWS For the Years Ended October 31, 1994, 1993 and 1992
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS For the Years Ended October 31, 1994, 1993 and 1992
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation. Piedmont Natural Gas Company, Inc. (the Company), an investor-owned public utility, distributes 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 the Company and its wholly-owned subsidiaries, Piedmont Exploration Company, Inc., Piedmont Energy Company, Piedmont Intrastate Pipeline Company and PNG Energy Company and its wholly-owned subsidiaries, Piedmont Propane Company and PNG Exploration Company. Significant intercompany amounts have been eliminated in consolidation where appropriate.
B. Utility Plant and Depreciation. Utility plant is stated at original cost. The cost of additions to utility plant includes direct labor and materials, allocable overheads and an allowance for funds used during construction (AFUDC). As prescribed in the applicable regulatory system of accounts, AFUDC is the allowance for borrowed and equity funds used to finance construction. The weighted average accrual rate was 9.30% for 1994, 10.52% for 1993 and 10.64% for 1992. The portion of AFUDC attributable to equity funds is included in other income, and the portion attributable to borrowed funds is shown as a reduction of utility interest charges. The costs of units of property retired are removed from utility plant and such costs, plus removal costs, less salvage, are charged to accumulated depreciation. Depreciation expense is computed using the straight-line method applied to average depreciable costs. The ratio of depreciation provisions to average depreciable property balances was 2.79% for 1994, 2.77% for 1993 and 2.76% for 1992.
C. Inventories. Inventories are maintained on the basis of the average cost charged thereto.
D. Deferred Purchased Gas Adjustment. The Company's rate schedules include purchased gas adjustment provisions that permit the recovery of purchased gas costs. The purchased gas adjustment factor is revised periodically without formal rate proceedings to reflect changes in the cost of purchased gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over or under recovered amounts is included in refunds due customers.
E. Income Taxes. Deferred income taxes are provided for differences between book and tax income, principally attributable to accelerated tax depreciation, the recording of revenues and cost of gas and accrued long-term incentive compensation. Investment tax credits allowed on certain qualified property were deferred and are being amortized to income over the estimated useful life of the related property.
Effective November 1, 1993, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." See Note 8.
F. Operating Revenues. The Company recognizes revenues from meters read on a monthly cycle basis which results in unrecognized revenue from the cycle date through month end. The cost of gas delivered to customers but not yet billed under the cycle billing method is deferred.
G. Earnings Per Share. Earnings per share are computed based on the weighted average number of shares of Common Stock outstanding during each year.
H. Regulation. Certain income, expense and capital items may be treated differently for ratemaking purposes by the state regulatory commissions which establish rates charged to customers.
I. Statement of Cash Flows. For purposes of reporting cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
J. Segment Reporting. The Company is principally engaged in the gas distribution industry and has no other reportable industry segments.
K. Reclassifications. Certain financial statement items for 1993 and 1992 have been reclassified to conform with the 1994 presentation.
2. Reincorporation
On February 25, 1994, the Company's shareholders approved a change in the state of incorporation from New York to North Carolina. The reincorporation was effected March 1, 1994, by merging the Company, a New York corporation, into a wholly-owned subsidiary, PNG Acquisition Company, a North Carolina corporation. In connection with the merger, each share of the Company's Common Stock, $.25 par value per share, was exchanged for one share of Common Stock, no par value, of PNG Acquisition Company. Immediately following the merger, the name of the surviving corporation was changed to Piedmont Natural Gas Company, Inc.
3. Regulatory Matters
The Company's utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC) and the Tennessee Public Service Commission (TPSC) as to the issuance of securities, and by those commissions and by the Public Service Commission of South Carolina (PSCSC) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation.
Pursuant to Order No. 636 of the Federal Energy Regulatory Commission (FERC), interstate pipelines were required to change their traditional role of gas merchants to local distribution companies (LDCs) by "unbundling" the gas sales, transportation and storage services provided by them and transporting gas to their customers. The FERC has approved mechanisms for the pipelines to recover from customers certain "transition costs" related to unbundling. The major component of these transition costs for most pipelines is the cost of realigning existing gas supply contracts (Gas Supply Realignment or GSR costs).
In the Company's opinion, present rules and regulations of the NCUC, PSCSC and TPSC permit the Company to pass through to its customers any transition costs, including GSR costs. Effective November 1, 1993, the Company is recovering transition costs assessed by Tennessee Gas Pipeline Company through purchased gas adjustment procedures. Since Transcontinental Gas Pipe Line Corporation (Transco) realigned most of its gas supply contracts when it unbundled services several years ago, transition costs from Transco are expected to be minor. The FERC has ruled that Columbia Gas Transmission Corporation may not recover substantial portions of its GSR costs; however, the FERC's ruling is subject to requests for rehearing and appeal. In addition, the Company does not expect to be assessed substantial GSR costs by its other interstate pipeline suppliers.
Prior to 1994, certain procedures of the NCUC with respect to the recovery of the wholesale cost of gas were challenged by a group of the Company's industrial customers in North Carolina. During 1994, the Company refunded certain amounts, for which adequate reserves had been previously provided, as required by the NCUC.
Since 1992, certain supplier refunds attributable to North Carolina operations have been held by the Company for possible inclusion in an expansion fund as legislated by the General Assembly of North Carolina to extend natural gas service to unserved areas of the state. As ordered by the NCUC, these refunds were deposited in a separate bank account and invested in short-term U.S. Treasury securities pending the establishment of an expansion fund. Additionally, other supplier refunds are being held by the Company for possible inclusion in an expansion fund. Such refunds, including interest earned to date, are included in restricted cash. In July 1994, the North Carolina Supreme Court affirmed the order of the NCUC which authorized the establishment of an expansion fund.
In September 1994, the Company filed a petition with the NCUC for a certificate of public convenience and necessity to serve four counties in North Carolina not presently receiving natural gas service and an application to establish an expansion fund and place $14,800,000 of supplier refunds into the fund for such expansion. A similar application to serve these counties has been filed by a company not currently operating in North Carolina. Hearings on these matters have been scheduled by the NCUC, and the outcome is not presently determinable.
In February 1994, the NCUC approved a settlement agreement in a general rate proceeding that provided for an increase in margin of $1,200,000 during the period February 1 through October 31, 1994. In October 1994, the NCUC issued an order permitting the Company to increase its rates in North Carolina, effective November 1, 1994, by $5,200,000 annually and its margin by $15,500,000. In addition, the order indicated that the NCUC will reopen the record for the purpose of receiving evidence concerning Cardinal Pipeline Company, L.L.C., and the approval of rates to cover its investment and operating costs. See Note 9.
In October 1994, the TPSC issued an order permitting the Company to increase its rates in Tennessee, effective October 28, 1994, by $6,800,000 annually and its margin by $8,800,000.
4. Long-Term Debt
Long-term debt at October 31, 1994 and 1993, is summarized as follows:
Annual sinking fund requirements and maturities through 1999 are $5,000,000 in 1995, $7,000,000 in 1996 and $10,000,000 in 1997, 1998 and 1999.
On September 19, 1994, the Company sold $40,000,000 of 8.45% Medium-Term Notes due 2024 under a $150,000,000 shelf registration. Proceeds from the sale were used to reduce short-term debt and finance capital expenditures. The notes are to be redeemed in a single payment at maturity.
The Company's note agreements under which the Company's long-term debt was issued contain provisions which restrict the amount of cash dividends that may be paid on Common Stock. At October 31, 1994, all of the Company's retained earnings was free of such restrictions.
5. Capital Stock
The changes in Common Stock for the years ended October 31, 1992, 1993 and 1994, are summarized as follows. See Note 2.
At October 31, 1994, 1,963,273 shares of Common Stock were reserved for issuance as follows:
6. Financial Instruments and Related Fair Value
The Company has committed bank lines of credit totaling $57,000,000 to finance current cash requirements. Additional uncommitted lines are also available on an as needed, if available, basis. Borrowings under the lines, with maturity dates of less than 90 days, include bankers' acceptances, 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, 1994, the lines of credit were on either a fee basis or compensating balance basis, with average annual balance requirements of $600,000.
At October 31, 1994, outstanding notes payable consisted of $60,000,000 in bankers' acceptances and $3,500,000 in overnight cost-plus loans. The weighted average interest rate on such borrowings was 5.13% for 1994, compared with 3.23% for 1993.
The Company's principal business activity is the sale and transportation of natural gas to customers located in North Carolina, South Carolina and Tennessee. At October 31, 1994, gas receivables totaled $14,516,000 and other receivables totaled $9,028,000. The uncollected balance of installment receivables transferred with recourse in 1992 was $22,138,000 and $22,131,000 at October 31, 1994 and 1993, respectively. The Company has provided an adequate allowance for any receivables which may not be ultimately collected, including the receivables transferred with recourse.
The following estimated fair values of financial instruments have been determined using available market information and commonly accepted valuation methodologies. Judgment is necessary in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions or estimation methodologies may have a material effect on the estimated fair values. The estimated fair values of the Company's financial instruments at October 31, 1994 and 1993, are as follows:
(1) The carrying amount in the consolidated balance sheets approximates fair value because of the short maturity of these instruments.
(2) The fair value is estimated by discounting the future cash flows using the current rates at which similar loans would be made to borrowers with similar credit ratings and for the same remaining maturities.
7. Employee Benefit Plans
The Company has a defined-benefit pension plan for the benefit of substantially all full-time regular employees of the Company and its subsidiaries. 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 his or her highest compensation. It is the Company's policy to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes under applicable federal regulations. Plan assets consist primarily of marketable securities with a minor investment in commercial real estate and cash equivalents.
The plan is amended from time to time in accordance with changes in tax law. The unrecognized prior service costs, if any, resulting from such amendments are amortized over the average remaining service life of active employees.
A reconciliation of the funded status of the plan to the amounts recognized in the consolidated financial statements at October 31, 1994 and 1993, is presented below:
Net periodic pension cost, excluding trustee fees and other expenses, for the years ended October 31, 1994, 1993 and 1992, includes the following components:
The Company provides certain postretirement health care and life insurance benefits to substantially all full-time regular employees of the Company and its subsidiaries. Effective November 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (FAS 106). Prior to adoption, the costs of such benefits, which were $946,000 in 1993 and $794,000 in 1992, were currently expensed as health care claims and premiums for health and life insurance were paid. As of October 31, 1994, the liability associated with such benefits was partially funded in irrevocable trust funds which can only be used to pay the benefits.
A reconciliation of the funded status of the plan to the amount recognized in the consolidated financial statements at October 31, 1994, is presented below:
Net periodic postretirement benefit cost for the year ended October 31, 1994, includes the following components:
A one-percentage point increase in the assumed health care cost trend rate would increase the accumulated postretirement benefit obligation at October 31, 1994, by $1,645,000 and the aggregate of the service and interest cost components of net periodic postretirement benefit cost by $129,000.
The Company is recovering FAS 106 costs from ratepayers in North Carolina, effective March 1, 1994, and in Tennessee, effective October 28, 1994, pursuant to rate orders in general rate proceedings. The Company has an order from the PSCSC allowing deferral of such costs attributable to South Carolina operations for recovery in a future general rate proceeding.
The Company maintains salary investment plans which are profit sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), and which include qualified cash or deferred arrangements under Tax Code Section 401(k). Employees of the Company and its affiliated companies 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, with the Company matching a portion of the participants' contributions. All contributions vest immediately. For the years ended October 31, 1994, 1993 and 1992, the Company contributed $1,824,000, $1,674,000 and $1,531,000, respectively, to the plans.
The Company will adopt SFAS No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112), in its fiscal year beginning November 1, 1994. FAS 112 requires, among other things, the accrual for benefits provided to former or inactive employees after employment but before retirement and to their beneficiaries and covered dependents. Adoption of FAS 112 is not expected to have a material impact on the Company's financial position or results of operations.
8. Income Taxes
The components of income tax expense for the years ended October 31, 1994, 1993 and 1992, 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, 1994, 1993 and 1992, is as follows:
Effective November 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes" (FAS 109), on a prospective basis. FAS 109 requires a liability approach for financial accounting and reporting of income taxes. While classification of certain items in the consolidated balance sheets has changed, principally due to deferred taxes recorded at higher historical tax rates, there was no material effect on the Company's results of operations.
At October 31, 1994, deferred income tax balances consisted of the following temporary differences:
Total deferred income tax liabilities were $95,972,000 and total deferred income tax assets were $12,500,000 at October 31, 1994.
The components of the deferred income tax provisions for the years ended October 31, 1993 and 1992, are summarized as follows:
9. Non-Utility Activities
For several years, PNG Energy Company acquired and marketed natural gas for the Company's system supply and other natural gas distribution companies. PNG Energy Company also acted as an agent for several of the Company's large industrial customers to arrange for the purchase and transportation of natural gas. Such activities are now being conducted primarily by Resource Energy Services Company, L.L.C., as explained below. Revenues earned by the Company for transporting this gas are included in utility operating revenues.
During 1994, the Company sold the exploration and development properties of Piedmont Exploration Company, Inc. (PEC), and PNG Exploration Company. Customers in North Carolina and South Carolina participated in the cost of and related benefits from certain commission-approved programs of PEC at levels ranging from 46% to 75%. The disposition of these properties did not have a material effect on the Company's operations.
Piedmont Energy Company is a 51% member of Resource Energy Services Company, L.L.C., a North Carolina limited liability company formed in January 1994. The new company offers natural gas acquisition, transportation and storage services to industrial users and utilities in the mid-south and southeastern areas of the United States.
The Company, in cooperation with another utility, formed Cardinal Pipeline Company, L.L.C.(Cardinal), in March 1994. Cardinal is a North Carolina limited liability company which is owned approximately 36% by Piedmont Intrastate Pipeline Company. In July 1994, the NCUC granted Cardinal a certificate of public convenience and necessity to construct, own and operate a natural gas pipeline from a connection with an interstate pipeline to facilities owned by the Company and facilities owned by the other utility company. The other utility will be the operator of the pipeline.
Through various operating divisions, the Company markets propane and propane appliances to residential, commercial and industrial customers within and adjacent to the Company's three-state natural gas service area. The Company is also engaged in various other non-utility activities, including the sale and financing of gas appliances and jobbing work performed on customer- owned property.
Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. Non-utility revenues as a percentage of total revenues, including utility operations, were 8% in 1994 and 1993 and 9% in 1992. No single non-utility activity accounted for greater than 6% of total revenues in any year. Income from non-utility activities as a percentage of total net income was 12% in 1994, 7% in 1993 and 8% in 1992. No single non-utility activity accounted for more than 8% of net income in any year.
10. Environmental Matters
The Company has owned or operated manufactured gas plant (MGP) facilities at 11 sites in its three-state service area. Four of these sites are still owned by the Company and the remaining seven are owned by other individuals or companies. Eight of the 11 sites involve other parties who either owned the property or operated the facilities. Currently, five of the eight sites in North Carolina are on the Comprehensive Environmental Response, Compensation and Liability Act Information System target list of the Environmental Protection Agency on the recommendation of the North Carolina Department of Environment, Health, and Natural Resources (the Department). This list identifies these sites for a preliminary assessment as to the danger posed to health and the environment. The North Carolina Superfund Section is in various stages of analyses on these five sites. The Company has not received any notification from the Department nor does it have other information which indicates significant remedial measures with respect to any of these sites. The Company has not been notified by any governmental agency in South Carolina or Tennessee with respect to MGPs in those states.
Further evaluations of the MGP sites will determine any remediation requirements and associated costs and the involvement of the Company in the sharing of these costs. The Company cannot presently determine the liability with respect to individual MGP sites since site specific evaluations have not been performed and cost-sharing arrangements with other responsible parties have not been finalized.
The Company is in the process of evaluating and remediating sites with respect to its present or former ownership of underground tanks. As of October 31, 1994, comprehensive evaluations of underground tank sites were substantially complete. Of the 11 sites in North Carolina and South Carolina, six will require corrective action and varying degrees of remediation. The Department has established a trust fund which reimburses the owner or operator for the costs of evaluating and remediating the underground tank sites in excess of a designated variable dollar amount per site.
Based on a generic MGP site study and estimates determined in the underground storage tank comprehensive site evaluations, the Company has recorded a liability and an associated regulatory asset of $1,670,000 for potential future environmental costs. The three state regulatory commissions regulating the Company have authorized deferral accounting, or the creation of a regulatory asset, for expenditures made in connection with environmental matters. A
determination as to whether or not environmental expenditures, net of recoveries from other responsible parties, will be recovered from ratepayers will be made at the appropriate time in general rate case proceedings. In North Carolina, current procedures permit the Company to recover 100% of its prudently incurred MGP clean-up costs but do not permit the recovery of any carrying costs on such amounts from the time the amounts are expended until the time they are collected. Based on regulatory accounting directives and the emerging trend in the industry for regulators to permit substantial recovery of such costs, the Company believes that the resolution of these matters will not have a material adverse effect on the Company's financial position or results of operations.
INDEPENDENT AUDITORS' REPORT
Piedmont Natural Gas Company, Inc.
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the Company) as of October 31, 1994 and 1993, and the related statements of consolidated income, retained earnings and cash flows for each of the three years in the period ended October 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. 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 the Company at October 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 8 to the consolidated financial statements, effective November 1, 1993, the Company changed its method of accounting for income taxes to conform with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes."
/s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP
Charlotte, North Carolina December 16, 1994
QUARTERLY FINANCIAL DATA
Quarterly financial data for the years ended October 31, 1994 and 1993, is summarized as follows:
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. Earnings per share are calculated based on 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.
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 the Company's proxy statement filed with the Securities and Exchange Commission (SEC) on or about January 24, 1995, and is incorporated herein by reference.
The names, ages and positions of all of the executive officers of the Company as of October 31, 1994, 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 of Directors 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 of Directors. 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 with Messrs. Maxheim and Denny.
*Retired November 30, 1994.
Item 11.

Item 11. Executive Compensation - --------------------------------
Information required under this item is contained in the Company's proxy statement filed with the SEC on or about January 24, 1995, 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 the Company's proxy statement filed with the SEC on or about January 24, 1995, and is incorporated herein by reference.
(b) Security Ownership of Management
Information with respect to security ownership of directors and officers is contained in the Company's proxy statement filed
with the SEC on or about January 24, 1995, and is incorporated herein by reference.
(c) Changes in Control
The Company knows 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 the Company's proxy statement filed with the SEC on or about January 24, 1995, 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, 1994, are included in Item 8 of this report as follows:
(a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULES -------------------------------------------------------
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 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, the Company will provide a copy of the exhibit at a nominal charge.
3.1 Copy of Articles of Incorporation of the Company, filed in the Department of State of the State of North Carolina on December 13, 1993 (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994).
3.2 Copy of By-Laws of the Company as amended (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994).
4.1 Copy of Note Agreement, dated as of August 30, 1988, between the Company and Jefferson-Pilot Life Insurance Company, et al (Exhibit 4.26, Form 10-K for the fiscal year ended October 31, 1988).
4.2 Copy of 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).
4.3 Copy of Note Agreement, dated as of August 31, 1989, between the Company and Teachers Insurance and Annuity Association of America (Exhibit 4.28, Form 10-K for the fiscal year ended October 31, 1989).
4.4 Copy of 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).
4.5 Copy of 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).
4.6 Form of Indenture, dated as of April 1, 1993, between the Company and Citibank, N.A., Trustee (Exhibit 4.1, Registration Statement No. 33-60108).
4.7 Copy of 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).
4.8 Copy of 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).
4.9 Copy of Medium-Term Note, Series A, dated as of September 19, 1994.
10.1 Copy of Employment Agreement between Tennessee Natural Resources, Inc., and J. William Denny, dated April 27, 1984 (Exhibit 10.17, Registration Statement No. 33-4767).
10.2 Copy of Termination and Severance Pay Agreement between the Company, Tennessee Natural Resources, Inc., and John C. Bolinger, Jr., dated February 7, 1985 (Exhibit 10.14, Registration Statement No. 33-4767).
10.3 Copy of the Company's Executive Long-Term Incentive Plan, as amended through December 2, 1994.
10.4 Copy of Employment Agreement between the Company and John H. Maxheim, dated February 26, 1993 (Exhibit 10.4, Form 10-K for the fiscal year ended October 31, 1993).
10.5 Copy of Articles of Organization of Cardinal Pipeline Company, L.L.C., dated April 5, 1994 (Exhibit 10.1, Form 10-Q for the quarterly period ended April 30, 1994).
10.6 Copy of Operating Agreement of Cardinal Pipeline Company, L.L.C., dated March 23, 1994 (Exhibit 10.2, Form 10-Q for the quarterly period ended April 30, 1994).
10.7 Copy of Construction, Operating and Management Agreement by and between Public Service Company of North Carolina, Inc. and Cardinal Pipeline Company, L.L.C., dated March 23, 1994 (Exhibit 10.3, Form 10-Q for the quarterly period ended April 30, 1994).
10.8 Copy of Service Agreement under Rate Schedule LG-A, dated January 15, 1971, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 67, Registration Statement No. 2-59631).
10.9 Copy of Service Agreement under Rate Schedule GSS, dated May 2, 1972, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 67, Registration Statement No. 2-59631).
10.10 Copy of Service Agreement under Rate Schedule WSS, dated August 6, 1981, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.5, Registration Statement No. 33-4767).
10.11 Copy of Firm Seasonal Gas Transportation Agreement (Southern Expansion, FT 53,000 mcf), dated June 29, 1990, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.25, Form 10-K for the fiscal year ended October 31, 1990).
10.12 Copy of Service Agreement (5,900 Mcf per day), 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).
10.13 Copy of Service Agreement (6,222 Mcf per day), 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).
10.14 Copy of Service Agreement Rate Schedule FS (20,000 Mcf per day), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.17, Form 10-K for the fiscal year ended October 31, 1992).
10.15 Copy of Service Agreement Rate Schedule FS (43,640 Mcf per day), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.18, Form 10-K for the fiscal year ended October 31, 1992).
10.16 Copy of Gas Transportation Agreement (FT, 24,505 Mcf per day, NIPPS), dated January 30, 1992, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.19, Form 10-K for the fiscal year ended October 31, 1992).
10.17 Copy of Service Agreement (FT, 205,200 Mcf per day), 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).
10.18 Copy of Service Agreement (FT-NT, 12,785 Mcf/day, Texas Gas/CNG), dated July 20, 1992, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.25, Form 10-K for the fiscal year ended October 31, 1993).
10.19 Copy of Amendment to Service Agreement (Southern Expansion, FT 53,000 mcf), dated February 1, 1993, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.27, Form 10-K for the fiscal year ended October 31, 1993).
10.20 Copy of 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).
10.21 Copy of Gas Storage Contract (for Use Under Rate Schedule FS) (Contract No. 2399) (FS, 2,901,943 Dt), dated September 1, 1993, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 1993).
10.22 Copy of Gas Transportation Agreement (for Use Under FT-A Rate Schedule) (Contract No. 237) (FTA, 130,000 Dt/day), dated September 1, 1993, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 1993).
10.23 Copy of Gas Storage Contract (for Use Under Rate Schedule FS) (Contract No. 2400) (FS, 672,091 Dt total capacity), dated September 1, 1993, between the Company and Tennessee
Gas Pipeline Company (Exhibit 10.31, Form 10-K for the fiscal year ended October 31, 1993).
10.24 Copy of FTS Service Agreement (23,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.25 Copy of Service Agreement under Rate Schedule FSS (2,263,920 Dt total capacity), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.26 Copy of Service Agreement under Rate Schedule SST (Winter: 10,000 Dt/day; Summer: 5,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.27 Copy of FTS Service Agreement (10,000 Dt/day), dated November 5, 1993, between the Company and Columbia Gas Transmission Corporation.
12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule.
99 Annual Report on Form 11-K.
(b) Reports on Form 8-K -------------------
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PIEDMONT NATURAL GAS COMPANY, INC. ------------------------------------- (Registrant)
Date January 25, 1995 By: /s/ John H. Maxheim ------------------- -------------------------------- John H. Maxheim Chairman of the Board, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEPENDENT AUDITORS' REPORT - ----------------------------
Piedmont Natural Gas Company, Inc.
We have audited the consolidated financial statements of Piedmont Natural Gas Company, Inc. and subsidiaries (the Company) as of October 31, 1994 and 1993, and for each of the three years in the period ended October 31, 1994, and have issued our report thereon dated December 16, 1994. Such consolidated financial statements and report are included herein. Our audits also included the supplemental consolidated financial statement schedule of the Company listed in Item 14. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion on this consolidated financial statement schedule based on our audits. In our opinion, such consolidated 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 DELOITTE & TOUCHE LLP
Charlotte, North Carolina December 16, 1994
Schedule II
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
(A) Uncollectible accounts written off, net of recoveries and adjustments.
Piedmont Natural Gas Company, Inc. Form 10-K For the Fiscal Year Ended October 31, 1994
Exhibits
4.9 Copy of Medium-Term Note, Series A, dated as of September 19, 1994.
10.3 Copy of the Company's Executive Long-Term Incentive Plan, as amended through December 2, 1994.
10.24 Copy of FTS Service Agreement (23,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.25 Copy of Service Agreement under Rate Schedule FSS (2,263,920 Dt total capacity), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.26 Copy of Service Agreement under Rate Schedule SST (Winter: 10,000 Dt/day; Summer: 5,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation.
10.27 Copy of FTS Service Agreement (10,000 Dt/day), dated November 5, 1993, between the Company and Columbia Gas Transmission Corporation.
12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule (for the SEC use only).
99 Annual Report on Form 11-K.