Item 1. Business
General
North Carolina Natural Gas Corporation (Company), whose principal office is located at 15O Rowan Street, Fayetteville, North Carolina, was incorporated in 1955 under the laws of the State of Delaware. It is engaged in the transmission and distribution of natural gas through approximately 1,006 miles of transmission pipeline and approximately 2,490 miles of distribution mains. Natural gas is sold under regulated rates to approximately 135,500 customers in 63 cities and towns and four municipal gas distribution systems in eastern and southcentral North Carolina.
The Company purchases and transports natural gas under long-term contracts with Transcontinental Gas Pipe Line Corporation (Transco), Columbia Gas Transmission Corporation (Columbia) and several major oil and gas producers. Approximately 75% of NCNG's total available gas supply in 1994 was purchased under long-term contracts, in the spot market or with non-pipeline suppliers for system supply. The Company also serves propane gas to approximately 8,200 customers and sells gas appliances and home insulation services to gas customers and new home builders.
NCNG Exploration (NCNGE) was organized in 1974 and another subsidiary, Cape Fear Energy Corporation (CFEC), was organized in 1980, both under the laws of the State of North Carolina. These subsidiaries have been engaged in prior years in the exploration and production of natural gas and oil. All of NCNG Exploration's operating assets were sold for a small gain in June 1994. Cape Fear Energy Corporation is now primarily engaged in the purchase of natural gas for the Company's system supply and for sale to large industrial plants and the municipalities served by the Company.
Financial Information About Industry Segments - ---------------------------------------------
The Company is engaged in principally one industry as described above and has no other reportable industry segments.
Narrative Description of Business - ---------------------------------
General -
The Company distributes natural gas to residential, commercial, industrial and municipal customers in a substantial portion of the southcentral and eastern sections of North Carolina. The population in the Company's franchised territory is approximately 1,957,000. Principal cities or towns served include Albemarle, Dunn, Fayetteville, Goldsboro, Greenville, Kinston, Lumberton, New Bern, Monroe, Roanoke Rapids, Rockingham, Rocky Mount, Smithfield/Selma, Southern Pines, Wilmington and Wilson.
The Company's service area is attractive to industry due largely to good climate, favorable labor relations, responsible local and state government, good transportation, and the proximity of this area to major markets.
Item 1. Business (Continued)
Industrial activities in the service area are diverse. The Company serves customers engaged in the manufacture of chemicals, fertilizers, glass, nuclear fuels, textiles, brick, plywood and other wood products, and in the processing of metals, tobacco, rubber, dairy and food products. The Company also provides natural gas service to three large military bases and two electric utilities.
Following is a summary of operating revenues (in 000's) by major customer classification for the years 1990 through 1994:
1990 1991 1992 1993 1994 ---- ---- ---- ---- ---- Residential & Commercial $ 46,099 $ 46,023 $ 47,534 $ 57,163 $ 58,748 Municipalities for Resale 16,653 16,236 21,448 22,312 23,471 Industrial/electric power generation 65,787 64,342 81,528 93,670 78,118 ------- ------- ------- ------- ------ Total Operating Revenues $128,539 $126,601 $150,510 $173,145 $160,337 ======= ======= ======= ======= =======
The above amounts include revenues from both gas sold to customers and for transportation of customer-owned gas. The Company's revenues from transportation are lower than from sales because it does not incur or bill the commodity cost of gas for transported volumes. However, the Company generally earns the same margin on a dekatherm of gas whether transported or sold because transportation rates exclude only the commodity cost of gas which the customer pays directly to his supplier.
Operating revenues decreased to $126.6 million in 1991 from $128.5 million in 1990 due to a combination of factors, primarily winter weather that was 24% warmer than normal and 7% warmer than 1990, transportation which replaced sales and a continuing decline in the cost of purchased gas which was passed on to the Company's customers. The warmer than normal winter period weather had a significant impact on the sale and transportation of gas for 1991. Sales volumes declined 1,145,000 Dt in 1991, while transportation volumes increased 2,425,000 Dt. The switch from sales to transportation volumes resulted in an approximate revenue reduction of $4.5 million in 1991, but did not impact the Company's margin.
Operating revenues increased to $150.5 million in 1992 from $126.6 million in 1991 due to a combination of factors, primarily the shift of 8,165,000 Dt from transportation to sales, the increase in total throughput and the impact of the December 1991 general rate increase (see "Regulations and rates", Page 8). Those increases were partially offset by a decline in the unit cost of purchased gas passed along to all customers. The shift from transportation to sales resulted in a revenue increase of $15.5 million in 1992, but did not impact the Company's margin.
Operating revenues increased to $173.1 million in 1993 from $150.5 million in 1992 due to a combination of factors, primarily the increase in the customer base and total throughput, and increased gas costs passed on to customers and a full year's impact of the general rate increase.
Item 1. Business (Continued) - ----------------------------
Operating revenues declined to $160.3 million in 1994 from $173.1 million in 1993 due to a combination of factors, primarily lower gas costs passed on to customers and the shift to more transportation service and less sales to large customers in 1994 compared to 1993. The strong customer growth and slight increase in net throughput volumes increased revenues but only partially offset these factors causing revenues to decline.
Natural gas supply -
During 1994, the Company received 4,681,000 Dt of natural gas under its firm sales contract with Transco. It purchased 30,224,000 Dt in the spot market or from other non-traditional sources, including long-term contracts with seven major producers. The Company also transported 13,400,000 Dt of customer-owned gas in 1994. The outlook for natural gas supplies in the Company's service area remains favorable as both Transco and Columbia are "open access" pipelines, and the Company has many sources of gas, available on a firm basis. Nationally, gas supplies are plentiful and no supply curtailments are anticipated, although pipeline capacity is expected to be tight if winter weather is colder than normal. Effective November 1, 1993, both Transco and Columbia implemented FERC Order 636. The Company has not experienced any changes in its daily operations because of implementation.
See Pages 9 and 10 of this report for additional information regarding federal regulation of interstate pipelines.
Item 1. Business (Continued) - -----------------------------
The following table summarizes the supply sources which are under contract or otherwise available to the Company as of November 1, 1994: Daily Maximum Contract Deliver- Annual Expiration ability (a) Quantity (a) Date ------- -------- ---------- (Dt) (Dt) Transco - Firm Transportation (FT) 145,935(b) 53,266,275 2013 Firm Sales (FS) 55,935 20,416,275 2001 General Storage 2,070 103,500 2013(c) Washington Storage 32,154(d) 2,734,180 1998 Liquefied Gas Storage 5,320 26,600 1991(h) Southern Expansion (FT) 16,871(e) 3,070,522 2005 Eminence Storage 34,123(i) 240,268 2013
Columbia Gas Transmission (F) - Firm Transportation (FT) 19,801(b) 7,227,365 2004 Firm Storage Service (FSS) 5,199 223,238 2004
Amerada Hess Firm Sales 15,000(g) 2,488,500 2003
Enron Gas Marketing Firm Sales 15,500(g) 2,340,500 1998
Exxon Company, U.S.A. - Firm Sales 14,903(g) 5,439,595 2003
Mobil Natural Gas, Inc. Firm Sales 24,903(g) 9,089,595 1998
Natural Gas Clearinghouse - Firm Sales 9,995(g) 1,509,245 1997
Texaco Firm Sales 5,000(g) 1,825,000 1996
Texaco Firm Sales 12,500(g) 2,957,500 1997
Union Pacific Firm Sales 9,400(g) 2,489,000 1996
BP Gas 9,715(g) 3,545,975 1998
Vastar (Arco) 10,000(g) 1,510,000 1998
LNG Plant (Company owned) 70,000(j) 1,000,000 N/A
(a) Quantities are shown in dekatherms (Dt) (one Dt equals 1,000,000 Btu or one Mcf at 1000 Btu/cu. ft.) and are based on current heating values used by Transco and the Company.
Item 1. Business (Continued) - -----------------------------
(b) Firm Transportation (FT) contracts are for pipeline capacity only. The Company is responsible for acquiring its own gas supplies to be transported on a firm basis under the FT contracts. Gas supplies are available under Transco's FS Agreement, other long-term agreements (see (g) below), multi-month term agreements or one-month agreements for supplies purchased in the spot market.
(c) The Company has entered into a new contract with Transco which expires on March 31, 2013 for 56,267 dekatherms of General Storage Service provided under Transco's agreements with Consolidated Natural Gas Transmission Corporation (CNG). The Company anticipates that Transco will continue to provide the balance of the Company's service entitlement under its Rate Schedule GSS tariff pending new agreements between Transco and other storage operators utilized by Transco to provide General Storage Service.
(d) Washington Storage volumes may be withdrawn to the extent that the basic contract gas from Transco or other suppliers is unavailable on any day or if the Company elects to take such gas instead of other supplies.
(e) Winter months only (October through March).
(f) In December 1989, the Company became the first natural gas distribution company in North Carolina to have a hard-pipe connection with two interstate pipelines as it began receiving gas from Columbia at Pleasant Hill, North Carolina, a delivery point near the North Carolina/Virginia border.
(g) The Amerada Hess, Enron, Exxon, Mobil, Natural Gas Clearinghouse, Texaco, BP, Vastar (Arco) and Union Pacific contracts are for gas supply only - no pipeline capacity is included. Supplies purchased from these suppliers flow on the Company's FT contracts with Transco and Columbia (see (b) above).
(h) The primary term of the Company's contract with Transco for LGA storage service expired on October 31, 1991. The Company anticipates that Transco will continue to provide this service under its Rate Schedule LGA tariff.
(i) Transco salt dome storage capacity allocated to customers of Transco FS sales service by mandate of FERC Order 636. Transco will continue to schedule injections and withdrawals of gas from this storage capacity under agency agreements with the Company and the other FS sales service customers.
(j) The deliverability away from the LNG Plant is limited by the Company's pipeline capacity. The Company is currently on a four-year plan to increase the capacity which will ultimately increase the LNG output to 120,000 Mcf/day.
Item 1. Business (Continued) - ----------------------------- As part of the Company's plan to diversify its supply sources, NCNG has converted 100% of its original Transco sales contract to firm transportation (FT), thus giving the Company an FT contract of 145,935 Dt per day on Transco. Also, the Company has approximately 17,000 Dt per day of additional winter season FT capacity from Transco's Southern Expansion. The Company has also converted 100% of its original Columbia sales contract to a combination of firm transportation and firm storage service under Columbia's November 1, 1993 service restructuring mandated by the Federal Energy Regulatory Commission's Order 636. The FT contracts enable the Company to acquire gas directly from producers or other natural gas marketers and have the gas transported on a firm basis at delivered costs that reflect the market price of natural gas in any month. Many of the Company's industrial and large commercial customers have the capability to burn a fuel other than natural gas, and these customers will generally switch from gas when it costs more than the alternative fuel (primarily residual oil, distillate oil or propane). Some of these same customers prefer to acquire their own gas supplies and the Company works with each pipeline and the customers to arrange transportation service for them when possible. End-user transportation volumes increased 42% in 1994 from 1993 due primarily to favorable spot market gas prices available to those customers during the summer period (April - October) and the continuation of a temporary increment in the Company's natural gas sales rates, but not its transportation rates, to recover base period margin losses under the Industrial Sales Tracker (IST) ratemaking mechanism. The Company's primary objectives are to secure adequate and reliable gas supplies on reasonable terms and conditions consistent with its obligation to provide service to its customers at the lowest reasonable cost. Spot market purchases will continue to be utilized primarily in the off-peak months (generally March through November) when such transactions offer economic savings compared to other firm purchase options.
As of November 1, 1994, the Company had entered into long-term gas supply contracts with major producers or national natural gas marketers for firm supplies in the winter season totaling 126,916 Dt/day on Transco and Columbia. Additionally, the Company has a firm sales contract with Transco to provide gas supplies of 55,935 Dt/day which the Company uses as its primary "swing" supply to accommodate changes in the level of demand on its system. The Company renegotiated its long-term contract with Mobil Natural Gas, Inc. to extend the primary term of that contract two years, to October 31, 1998.
The Company has a liquefied natural gas (LNG) storage plant which provides 70,000 dekatherms per day to the Company's peak day delivery capability.
Franchises - The Company holds a certificate of public convenience and necessity granted by the North Carolina Utilities Commission (NCUC) to provide service to the area now being served. Under North Carolina law, no company may construct or operate properties for the sale or distribution of natural gas without having obtained such a certificate, except that no certificate is required for construction in the ordinary course of business or for construction into territory contiguous to that already occupied by a company and not receiving similar service from another utility.
Item 1. Business (Continued) - ----------------------------
The Company has nonexclusive franchises from 48 municipalities in which it distributes natural gas and four municipalities to which the Company sells or transports gas for resale. The expiration dates of those franchises which have specific expiration provisions are from 1999 to 2011. The franchises are substantially uniform in nature. They contain no restrictions of a materially burdensome nature and are adequate for the Company's business as presently and as now proposed to be conducted. The Company, in addition, serves 15 communities from which no franchises are required.
Seasonal nature of business -
The Company's business is seasonal in nature. Cold weather affects customer demand in high priority markets and generally results in greater earnings during the winter months. However, the Company's deliveries to high load factor industrial customers, together with summer season deliveries for agricultural crop drying and electricity generation, help to minimize quarterly variations in throughput volumes and earnings. In 1991, however, the seasonal fluctuation in earnings became more pronounced due to the increase in pipeline fixed charges. In the Company's December 1991 general rate order, seasonal rates were adopted, having the effect of increasing winter period margins and reducing summer period margins compared to the rates previously in effect, further increasing the seasonal variation in revenues and earnings.
The Company normally injects gas into storage during periods of warm weather and withdraws it during periods of cold weather. The storage and various other contracts as shown on Pages 4 and 5 provide adequate daily supply to meet the Company's peak day requirements.
Short-term debt is used for the seasonal financing of stored gas inventories and for the Company's ongoing construction program prior to obtaining long-term financing. These loans, either conventional notes or bankers' acceptances, are normally repaid from the funds generated by the winter sale of the stored gas. At September 30, 1994, $26.0 million in short-term debt was outstanding compared to $15.5 million at September 30, 1993. The increase was due primarily to increased construction expenditures in Fiscal 1994.
Item 1. Business (Continued) - ----------------------------
Exploration and development -
NCNGE was formed in 1974 when the North Carolina Utilities Commission approved and authorized customer participation in four exploration and development programs. Effective June 7, 1994, the Company and the other three natural gas distribution utilities in North Carolina sold their combined interests in all of the exploration and development programs in which NCNGE was involved. NCNGE's share of the net proceeds was $615,000, of which $144,500 was deposited in an escrow account to remain until December 31, 1995 to cover any potential claims presented by the buyers. NCNGE recognized a pretax gain of $58,000 (shareholders' portion) on the sale, excluding the amount held in escrow. Approximately 75% of the net proceeds from the sale, along with net revenues and expenses of the programs prior to the sale, will be considered in the final amounts due to or from customers under these programs.
CFEC was formed in fiscal 1980 to make investments without customer participation in future exploration and drilling programs. CFEC has no material remaining commitments but will make some minor additional investment for development of successful prospects. In 1994, Cape Fear sold 2.2 million Dt of natural gas to NCNG customers and earned a profit margin of $43,000 on such sales.
Regulations and rates -
The Company is subject to regulation by the North Carolina Utilities Commission (NCUC) as to rates, service area, adequacy of service, safety standards, acquisition, extension and abandonment of facilities, accounting and issuance of securities. The Company operates only in the State of North Carolina and is not subject to Federal regulation as a "natural gas company" under the Natural Gas Act.
The NCUC authorized a general rate increase for the Company effective December 6, 1991 providing $2.6 million in additional revenues, a 12.7% return on common equity, and approved the establishment of demand/ commodity rates for six large, firm service customers; seasonal rate differentials for all customer classes; increases in facilities charges and reconnection fees for residential and commercial customers; and the establishment of a Weather Normalization Adjustment (WNA) Rider.
The Weather Normalization Adjustment benefits both the Company and its space heating customers by reducing large swings in customers' bills and Company revenues due to fluctuations in winter weather. This WNA Rider increases margins to the Company on its temperature sensitive load during warmer than normal winter weather and decreases the margin during colder than normal weather. During 1994, the WNA Rider provided $462,000 in revenues to offset lower volume gas sales to temperature sensitive customers due to 3% warmer than normal weather.
Item 1. Business (Continued) - -----------------------------
The Company's rate tariff contains an Industrial Sales Tracker (IST) Rider. The purpose of the IST is to stabilize the Company's margin (difference between revenues and purchased gas cost) earned from sales or transportation to interruptible industrial customers who use heavy fuel oil as an alternative fuel. To the extent that actual margins realized from sales or transportation to such customers exceed, or are less than, the margins included in the Company's most recent general rate case for IST volumes, refunds payable or additional receivables are recorded. The actual margins earned from IST deliveries were less than the base period margin by $3,940,000 and $5,166,000 in 1994 and 1993, respectively.
The NCUC, in a general rulemaking proceeding, revised its Purchased Gas Adjustment (PGA) procedures in April 1992. The revised procedures continue to allow the Company to recover all of its prudently incurred gas costs, but such procedures provide for several significant changes which include: (1) the establishment of a benchmark commodity cost of gas which represents the Company's estimate of the actual commodity cost of gas from all suppliers that it will incur in a future period; (2) the recovery of 100% of prudently incurred fixed costs of pipeline capacity and storage costs, including costs of any new capacity added since the last general rate case; (3) the notice period for requesting PGA rate changes was reduced to 14 days from 30 days; (4) the establishment of a tariff provision which allows the Company to recover margin losses from negotiated rates to non-IST large commercial and industrial customers; (5) a true-up of fixed gas costs recovered from the Company's customers; (6) a true-up of the Company's lost, unaccounted for and Company use volume compared to such volumes included in the last general rate case; and (7) an annual review of the Company's gas costs, including the prudence thereof, by the Public Staff of the NCUC and a hearing before the NCUC. The Company's second annual review of its gas costs for the 12 months ended November 30, 1993 was held in April 1994. The NCUC found the Company's gas costs and gas purchasing practices to be prudent, as it had for the first annual review in 1993.
In August 1994, the Company filed with the NCUC its second annual true-up of lost, unaccounted for and company use volumes for 12 months ended June 30, 1994. Because such volumes exceeded the base period amounts included in the last general rate case, the Company recouped $1,292,000 in 1994 from the true-up by charging that amount to the deferred gas cost account for future recovery in rates from customers.
The Federal Energy Regulatory Commission (FERC) issued its landmark Order 636 in April 1992. Essentially, Order 636 introduces more competition into the natural gas industry as pipelines must "unbundle" their merchant services from their transportation services. The Company's major pipeline supplier, Transco, largely completed the unbundling of its services in 1991, and NCNG has been purchasing its gas supplies directly from producers and marketers operating on the Transco system for a number of years. The Company's other pipeline supplier, Columbia Gas Transmission, has offered a bundled sales/transportation service to the Company since 1989, but it has implemented Order 636 effective November 1, 1993, as has Transco.
Item 1. Business (Continued) - -----------------------------
Another significant aspect of Order 636 is capacity release and assignment. To manage its supply portfolio most effectively and also to permit its large customers and independent marketers selling gas to end users on the NCNG system to obtain access to firm capacity on Transco, the Company entered into several agreements which permit end-use customers or marketers access to the Company's firm transportation on Transco while paying NCNG a fee for the use of its capacity. While Order 636 transfers the risk of gas supply management from the pipeline to the local distribution company such as NCNG, the Company has been working in such an environment for several years, and has carefully planned for the full implementation of Order 636. In July 1994, the NCUC issued a rulemaking order in which it required that all natural gas utilities flow through to customers 90% of the net compensation received for capacity release and similar transactions while retaining 10% of such compensation. The Company had been accounting for such transactions in accordance with the 90/10 sharing mechanism pursuant to a previous Commission Order issued in 1993.
Competition - With the exception of four municipalities that operate municipal gas distribution systems within the Company's service territory, the Company is the sole distributor of natural gas in its franchise service territory. Natural gas competes with electricity, residual fuel oil, propane and, to a lesser extent, coal. The Company has the lowest residential rates in North Carolina and is in a favorable competitive position. However, competition for every customer or potential customer is becoming more intense throughout the energy industry. The electric utilities in North Carolina have become more active in promoting high-efficiency heat pumps to counter the growth of natural gas in the home space-heating market. Such competition intensified to the point during 1994 that the NCUC established a separate docket to investigate competition between electric and natural gas utilities. The Commission required all companies to file testimony on competitive issues and scheduled a hearing to be held on December 6, 1994.
During 1994, approximately 65% of total throughput on the Company's system was to customers having alternative fuel usage capabilities under interruptible rates. However, the Company's tariffs (Industrial Sales Tracker ("IST") for heavy fuel oil customers and PGA Rider B for others) allow it to negotiate rates lower than the filed tariff rates and recover the lost margin from core market customers to keep industrial customers from leaving the system when the price of their alternative fuel is lower than the gas tariff rate. In exchange for the Company's having the right to recover negotiated losses, the IST requires that when margin is earned from the delivery of volumes to IST customers in excess of a base level set in the Company's last general rate case, that margin must be returned to the core market customers. That is not the case for additional margin earned from sales or transportation to non-IST industrial customers. Although the Company has benefitted from the favorable spread between both the price of delivered No. 2 fuel oil and propane compared to natural gas and has remained competitive in many instances with No. 6 fuel oil, the market could be affected by volatility in the price of fuel oil as well as increases in the price of natural gas. The Company's sales or transportation to IST customers were up 290,000 Dt in fiscal 1994 due to lower wellhead gas prices during the summer period.
Item 1. Business (Continued) - -----------------------------
Sales to higher margin non-IST industrial customers and electric generation facilities having No. 2 fuel oil, propane or no alternative fuels increased by a net amount of 417,817 Dt due to customer growth and lessened price competition from No. 2 oil. However, deliveries for electric power generation were adversely affected by other factors described below.
The Company's largest electric power generation customer is the Public Works Commission of the City of Fayetteville (PWC). For several years PWC had been considering the feasibility of eliminating entirely its purchases of bulk power from Carolina Power & Light Company (CP&L), its primary supplier of electric power, and instead relying on its existing generating plant, which is served by NCNG, and to consider entering into an agreement with a private contractor who would construct an additional gas-fired or coal-fired power plant for PWC's base-load requirements. In February 1994, PWC elected to accept a competitive proposal from CP&L because, in PWC's opinion, the CP&L proposal would be a lower cost option with more electric power supply security. Accordingly, CP&L and PWC entered into an agreement in May 1994 which provides, among other things, that CP&L would lower its rates charged to PWC and, in exchange for that, CP&L would assume control of the dispatch of PWC's existing power plant. This agreement, along with much milder weather during the summer of 1994, resulted in a significant reduction in the dispatch of PWC's power plant with a negative impact on the Company from a reduction in gas load of 1,729,000 Dts, or 61% less gas delivered to the plant than in 1993.
Environmental matters -
The Company is subject to regulation with regard to environmental matters by various Federal, state and local authorities. During fiscal year 1991, the North Carolina Department of Environment, Health and Natural Resources advised the Company of possible environmental contamination arising from Company-owned property in Kinston, North Carolina, which is the former site of a manufactured gas plant. The Company retained an environmental services consulting firm which has estimated the costs of investigation and remediation of this site based on its work to date to be between $1.4 million and $2.8 million over a four-to-six- year period. The Company owns another site of a former manufactured gas plant site in New Bern, North Carolina, and was the former owner of three other similar sites on which no significant environmental problems have arisen. The Company believes that any appreciable costs not previously provided for will be recovered from third parties, including liability insurance carriers, or in natural gas rates. In 1992, the Company received from third parties $457,000 relating to the Kinston site; an additional $24,000 and $28,000 was received in 1994 and 1993, respectively, and no significant additional costs were incurred.
The passage by Congress of The Clean Air Act of 1990 is generally beneficial to the natural gas industry because of the clean-burning characteristics of natural gas compared to oil and coal. Also, the Energy Policy Act of 1992 is generally beneficial to the natural gas industry because of provisions regarding alternative fuels for vehicles, taxation, and reform of the Public Utility Holding Company Act to allow a new class of electricity producers known as "Exempt Wholesale Generators".
Item 1. Business (Continued) - -----------------------------
Other -
Effective October 1, 1993, the Company adopted FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," on a prospective basis. This statement requires accounting for these benefits on an accrual basis using a single actuarial method which spreads the expected cost of such benefits to each year of an employee's service until the employee becomes fully eligible to receive the benefits. Prior to October 1, 1993, the Company accounted for these benefits on a cash basis consistent with current ratemaking treatment. The costs of such benefits charged to expense amounted to $501,000 in 1993 and $568,000 in 1992. The NCUC, in rate cases where Statement No. 106 accounting has been presented, has expressed its preference for the accrual basis of accounting and, accordingly, the Company expects that the regulatory treatment of these costs under Statement No. 106 in the Company's next general rate case will be the same prospectively as the accrual method that has been adopted. The Company is not currently funding this plan.
Effectively October 1, 1993, the Company adopted FASB Statement No. 109, "Accounting for Income Taxes". The adoption of Statement No. 109 resulted in cumulative adjustments to the balance sheet and had no effect on consolidated net income. As a result of Statement No. 109, the Company reduced accumulated deferred income taxes and recorded related regulatory assets and liabilities. The regulatory liability related to income taxes, net is due primarily to deferred income taxes recognized in years prior to 1987 at rates higher than currently enacted.
NCNG's service area of southcentral and eastern North Carolina is economically underdeveloped in many ways, including availability of natural gas service. The extension of natural gas service to currently unserved areas of North Carolina is a high priority with the Company and many state officials. NCNG is very interested in extending its pipeline system into other parts of its service territory where economically feasible to help promote economic development and provide future growth opportunities for the Company. Construction is currently underway on a 13-mile extension of the Company's system into a portion of Wayne County that does not have natural gas service. NCNG expects to begin construction soon on a 16-mile transmission pipeline to extend service to the southwest portion of Columbus County. This project will be financed through a cooperative effort between Columbus County and NCNG.
Natural gas expansion funds were authorized for use by the North Carolina natural gas companies through legislation passed in 1991 by the North Carolina General Assembly, and an expansion fund for NCNG was approved by the North Carolina Utilities Commission in February 1993. However, use of these funds was delayed by appeal of the Commission's decision to the courts by parties representing some of the Company's industrial and municipal customers. In July of this year, the North Carolina Supreme Court issued a decision which affirmed
Item 1. Business (Continued) - -----------------------------
the Commission's Order. There are approximately $13.5 million in gas supplier refunds currently available for possible inclusion in the Company's natural gas expansion fund. The Company will soon file for Commission approval to use money from this fund, together with Company funds, to make economically feasible the extension of NCNG's pipeline system into one or more other unserved areas of eastern North Carolina.
Employees -
At September 30, 1994, the Company had 536 full time employees. Employee relations are good and the Company has not had any material work stoppage due to labor disagreements. The Company has a noncontributory Employee Retirement Plan for substantially all regular employees, provides a group life and extended hospital insurance program, and other employee benefits, including an employee stock purchase plan which became effective in mid-1990. Shares were purchased by employees in 1994, 1993, 1992 and 1991.
EXECUTIVE OFFICERS OF THE COMPANY Date Elected Name and Age* Title An Officer - ----------------------- ----------------------- ----------
Calvin B. Wells Chairman, President and O9/11/74 Age - 58 Chief Executive Officer Gerald A. Teele Senior Vice President and O1/O8/8O Age - 50 Chief Financial Officer James C. Buie Vice President - 01/13/87 Age 47 Computer Services Terrence D. Davis Vice President - Operations 01/07/91 Age - 49 and Industrial Sales Cecil C. Dew Vice President and Treasurer O1/13/7O Age - 64 Stuart B. Dixon Vice President 01/10/89 Age 57 Government Relations Louis L. Hanemann Vice President - Human Resources 01/10/89 Age - 46 E. J. Mercier, Jr. Vice President - O9/O7/77 Age - 56 Customer Service
		
* As of December 3, 1994
The executive officers of the Company are appointed annually by the Board of Directors immediately following the annual meeting of stockholders. The present term of all executive officers expires on January 10, l995, the date of the next annual meeting of stockholders.
All of the executive officers have been employed by the Company in the position indicated or other similar managerial positions for more than five years except for Terrence D. Davis who was employed on January 7, 1991 as Vice President. He has over 20 years experience in the natural gas industry. Prior to joining the Company, he was Vice President of Operations at Chesapeake Utilities Corporation in Delaware.
There is no family relationship between any of the executive officers or directors.
There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
Item 2.
Item 2. Properties - -------------------
The Company owns approximately 1,006 miles of transmission pipelines of two to 16 inches in diameter which connect its distribution systems with the Texas-to-New York transmission system of Transco and the southern end of Columbia's transmission system. Transco delivers gas to the Company at various points conveniently located with respect to the Company's distribution area. Columbia delivers gas to one delivery point near the North Carolina-Virginia border. Gas is distributed by the Company through 2,490 miles of distribution mains. These transmission pipelines and distribution mains are located primarily on rights-of-way held under easement, license or permit on lands owned by others.
During Fiscal 1994, the Company invested approximately $20.8 million in new plant facilities. Approximately 8,000 natural gas and 500 propane residential and small commercial customers were added along with several new industrial customers. In Fiscal 1986, the Company completed and placed in service a liquefied natural gas storage plant on its system to provide additional peak day gas supply for future growth in customer demand. The LNG plant enabled the Company to establish an all-time high peak-day sendout of 249,260 dekatherms on January 19, 1994.
As discussed elsewhere in this report, NCNG Exploration Corporation and Cape Fear Energy Corporation participated in several oil and gas exploration and development programs for several years. The Company's interest in these oil and gas programs is not material to the Company's overall operations, and all of the NCNGE properties have been sold.
Item 3.
Item 3. Legal Proceedings - --------------------------
None, other than those related to issues before the North Carolina Utilities Commission and the North Carolina Department of Environment, Health and Natural Resources discussed above and in Note 10 to the Company's Consolidated Financial Statements for the year ended September 30, 1994, and other routine litigation incidental to the Company's business.
Item 4.
Item 4. Submission - --------------------
No matters were submitted to a vote of NCNG's security holders during the three months ended September 30, 1994.
PART II -------
Item 5.
Item 5. Market for the Registrant's Common Equity 	 and Related Stockholder Matters 	 -----------------------------------------
Principal market - The Company's common stock is traded on the New York Stock Exchange.
Approximate number of holders of common stock - The number of holders of record of the Company's common stock as of September 30, 1994: 5,250
Stock price and dividend information -
The table below presents the reported high and low common stock sale prices along with cash dividends declared per share for each quarter of fiscal 1994 and 1993.
Sept.30 Jun.30 Mar.31 Dec.31 Sept.30 Jun.30 Mar.31 Dec.31 Quarter Ended 1994 1994 1994 1993 1993 1993 1993 1992
COMMON STOCK PRICES- High ............. $24.00 $25.13 $27.38 $29.13 $29.38 $28.63 $26.75 $24.38 Low ................ 22.00 22.63 24.25 24.86 26.63 26.13 21.88 21.00
Cash dividends per share ........ .29 .29 .29 .27 .27 .27 .27 .25
A quarterly dividend of $0.29 per share was declared by the Board of Directors payable on December 15, 1994 to holders of record on December 1, 1994. Cash dividends have been paid on common shares every year since 1969 and the annual dividend rate has been increased each year since 1978. Under terms of the Company's debt agreements, there are various provisions relating to the maintenance of certain financial ratios and conditions. At September 30, 1994, approximately $17,838,000 of the Company's retained earnings is unrestricted.
Item 6.
Item 6. Selected Financial Data - --------------------------------
Years Ended September 30 1994 1993 1992 1991 1990 ----------------------------------------------- . (Amounts in Thousands Except Per Share Data) Operating revenues...........$160,337 $173,145 $150,510 $126,601 $128,539 Gross margin.................. 55,097 54,045 50,162 42,234 40,026 Net income.................... 11,150 10,977 9,697 7,014 7,441 Earnings per share (1)......... 1.76 1.84 1.79 1.31 1.04 Cash dividends declared per share (1)............... 1.14 1.06 .983 .923 .87 Total assets................ 205,173 194,178 186,550 151,714 138,472 Net utility plant in service .................. 164,843 152,543 144,412 127,205 111,644 Capital expenditures........ 20,756 15,469 23,773 21,200 16,483 Long-term debt.............. 37,000 39,000 45,088 23,452 27,741 Common equity .............. 86,399 80,944 57,413 51,967 49,106 Book value per share....... $ 13.57 $ 12.85 $ 10.54 $ 9.65 $ 9.20 Average number of common shares outstanding...... 6,331 5,981 5,414 5,362 5,311 Rate of return on year-end common equity.......... 12.91% 13.56% 16.89% 13.50% 15.15%
(1) Prior period amounts have been restated to reflect a 3-for-2 common stock split effective October 30, 1992.
Item 7.
Item 7. Management's Discussion and Analysis of Financial 	 Condition and Results of Operations - ----------------------------------------------------------- GENERAL
North Carolina Natural Gas Corporation is engaged primarily in the business of transporting and distributing natural gas at regulated rates to customers in 63 cities, towns and communities in southcentral and eastern North Carolina, with approximately 135,500 natural gas customers as of September 30, 1994. The Company also has a propane division with 8,200 customers. NCNG continues to expand its transmission and distribution systems to keep pace with the economic development and residential, commercial and industrial growth in its service area. The Company's financial condition and results of operations are substantially dependent upon its receiving adequate and timely increases in rates, which are regulated by the North Carolina Utilities Commission (NCUC).
LIQUIDITY AND CAPITAL RESOURCES
The Company has bank lines of credit for a total amount of $35.5 million including amounts based upon the cost of gas in storage. Borrowings under the lines can include bankers' acceptances and promissory notes not to exceed 90 days, with a maximum rate of the lending bank's commercial prime interest rate. At September 30, 1994, $26.0 million was outstanding at interest rates ranging from 5.065% to 5.35% and $9.5 million was available under these arrangements. At September 30, 1993, borrowings of $15.5 million were outstanding.
North Carolina Natural uses short-term bank loans temporarily, along with net cash provided from operating activities, to finance construction expenditures, and it replaces the bank loans with permanent financing when total borrowings approach the maximum amount provided under the lines of credit. Construction expenditures for 1994 were $20.8 million, an increase of $5.3 million from 1993 primarily because of construction in 1994 to expand the vaporization of the LNG plant and to strengthen two pipeline laterals. The Company has budgeted construction expenditures of $25.3 million for 1995. The construction program includes $3.0 million for an expansion project into an unserved area and $2.3 million to loop a section of the pipeline between NCNG's LNG plant and Fayetteville.
The Company's ratio of long-term debt to total capitalization was 31% at September 30, 1994, down from 36% at September 30, 1993, due to sinking fund payments of $6,088,000 made on debt issues and growth in common equity from retained earnings and proceeds from the sale of stock in the Company's dividend reinvestment and employee stock purchase plans. The Company did not issue any new long-term debt in 1994 but may seek long-term debt financing during Fiscal 1995 or early in Fiscal 1996.
RESULTS OF OPERATIONS
NCNG earned $11.1 million or $1.76 per share in 1994, compared to $11.0 million or $1.84 per share in 1993 and $9.7 million or $1.79 per share in 1992. The slight increase in earnings in 1994 was due to increased earnings in the Company's nonutility division, including its subsidiaries, and lower utility interest charges, which offset a decline in operating income. Reduction of throughput volumes in the electric power generation market caused 1994 operating income and net income to decline $472,000, or $.07 per share.
Item 7. Management's Discussion and Analysis of 	 Financial Condition and Results of Operations (Continued) --------------------------------------------------------
The increase in earnings in 1993 was primarily due to (1) increased margin resulting from increased sales and transportation (throughput) volumes to all customer classes due to customer growth and weather that was 6% colder than the prior year, and (2) lower interest expenses. Earnings per share in both 1994 and 1993 were diluted by the effect of the 786,500 additional shares issued in a public offering in February 1993. The increase in earnings in 1992 was primarily due to the general rate increase that became effective in December 1991, together with increased throughput volumes to all customer classes due to customer growth and weather that, even though 12% warmer than normal, was 18% colder than the prior year.
The Company's total throughput volumes in 1994 increased only 107,000 dekatherms (dt), or 0.23%, to 47,000,000 dt. However, throughput volumes to the Company's firm service customers and interruptible industrial customers increased substantially, due to strong customer growth (up 6.2%) and the recapture of some industrial load that had been using residual oil in 1993, while throughput to one market segment - interruptible electric power generation - declined 1,729,000 dt (or 61%). Weather in both 1994 and 1993 was approximately 4% warmer than normal, so the weather had no significant impact on annual throughput.
The significant volume decline in the electric power generation market occurred primarily during the fourth quarter of Fiscal 1994 due to (1) a new power supply and operating agreement between the Public Works Commission of Fayetteville (PWC), the Company's largest electric power generation customer, and Carolina Power & Light Company (CP&L), PWC's supplier of bulk electricity; and (2) much milder weather in the summer of 1994 compared to 1993. The new agreement between PWC and CP&L, effective in May 1994, provides, among other things, that CP&L will charge PWC lower rates for the power CP&L sells to PWC and that CP&L will assume control of the dispatch of PWC's power generating plant served by the Company. The practical effect of this arrangement is to reduce usage of gas at PWC's generating plant unless CP&L must dispatch the plant at times of high peak demand on CP&L's system or when one or more of its base load nuclear or coal-fired plants is out of service. In the summer of 1994, all of CP&L's base load plants were operating and PWC's plant was dispatched only a few days, whereas in 1993, it generated power using natural gas on a regular basis even when temperatures were relatively mild.
The increase in throughput to the firm service customers, who pay the highest rates, together with increased facilities charges from customer growth; the increase in throughput to the interruptible industrial customers (except those having residual oil as their alternative fuel); substantial overrun penalties paid by industrial customers related to cold weather operations in January 1994; an increase in contract demand by three of the four municipal customers and the Company's 10% share of interstate pipeline firm transportation capacity release cost recoupment enabled the Company to increase its margin by $1,839,000 in 1994 over 1993. However, the loss of throughput in the electric power generation market caused a margin decline of $787,000, so the net margin growth in 1994 was $1,052,000.
Item 7. Management's Discussion and Analysis of 	 Financial Condition and Results of Operations (Continued) 	 --------------------------------------------------------- The period-to-period comparison of changes in operating revenues and cost of gas is not a reliable indication of the Company's level of operations. Transportation gas volumes purchased directly from producers or other marketers by large industrial and municipal customers reached 14,547,000 dt or approximately one-third of the Company's total throughput in 1991, but declined to 6,381,000 dt in 1992, and then increased to 9,480,000 dt in 1993 and increased again to 13,511,000 dt in 1994. In general, the margin earned on gas transported is equal to the margin earned on gas sold; however, transportation which replaces sales results in lower revenues as transportation rates exclude the commodity cost of gas which is paid by the customer directly to its gas supplier. The Company, however, still delivers the gas and earns transportation revenue equivalent to the margin contained in a comparable sales rate.
Operating revenues declined to $160.3 million in 1994 from $173.1 million in 1993 due to a combination of factors, primarily lower gas costs passed on to customers and the shift to more transportation service and less sales to large customers in 1994 compared to 1993. The strong customer growth and slight increase in net throughput volumes increased revenues but only partially offset these factors causing revenues to decline. The revenue increase to $173.1 million in 1993 from $150.5 million in 1992 was also due to a variety of factors, primarily an increase in the customer base and total throughput, increased gas costs passed on to customers and the full year's impact of the December 1991 general rate increase.
The Company continued to have significant volumes of negotiated sales in 1994, primarily due to the ongoing price competition in the residual fuel oil market, but such negotiations did not result in a loss of margin due to the operation of the IST and the Company's PGA procedures.
Cost of gas declined to $105.2 million in 1994 from $119.1 million in 1993 due to three factors: (1) a decline in the volumes of gas purchased in 1994 due to the increase in gas purchased directly by end users for transportation on the Company's system; (2) a decline in the average gas commodity price paid by the Company to $2.21 per dt in 1994 from $2.39 per dt in 1993; and (3) a decrease of $1.1 million in net fixed charges paid to interstate pipelines and other gas suppliers due to capacity release credits and restructuring of some contracts. Natural gas commodity prices were higher during the winter months of 1993/94, but declined significantly throughout the summer of 1994. FERC Order 636 permits holders of firm transportation capacity on interstate pipelines to release any portion of it, even for just one day at a time, to others at market-based prices not to exceed the pipeline's rate. NCUC rules require that 90% of any cost recoupment be passed on to the Company's customers while the Company can retain 10% of the capacity release credits. During each month of the summer of 1994, the Company released some capacity deemed excess to its needs and recouped $1 million in pipeline FT reservation charges.
Cost of gas increased to $119.1 million in 1993 from $100.3 million in 1992, primarily due to higher gas commodity prices in 1993 when the gas market recovered from abnormally low levels in 1992. Additionally, the Company incurred an increase of $4.7 million in fixed charges for pipeline capacity and storage services caused by a full year's effect of general rate increases for both pipelines in 1992 when they changed their rate designs to the straight fixed-variable method which increases fixed charges.
Item 7. Management's Discussion and Analysis of 	 Financial Condition and Results of Operations 	 --------------------------------------------- Margin increased $1,052,000 to $55,097,000 in 1994 for reasons explained above. In 1993, margin increased $3,883,000 to $54,045,000 from $50,162,000 in 1992 because of substantial customer growth and throughput increases to the residential, commercial, municipal and non-IST industrial markets.
The slow down in margin growth in 1994, coupled with expected increases in operations and maintenance expenses, depreciation and general taxes, caused utility operating income to decline $689,000 in 1994 following substantial increases in 1993 and 1992.
Operations and maintenance expenses increased to $19.5 million in 1994 from $18.4 million in 1993 and $17.8 million in 1992 primarily because of the Company's growing customer base which requires more employees (19 added in 1994) to serve additional customers and expand, operate and maintain the Company's distribution, transmission and storage facilities. Additionally, the Company adopted FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" effective October 1, 1993, which increased expenses approximately $500,000 in 1994. Wage and salary increases granted to employees and officers averaged 4.5% in 1994. Decreases in expenses in 1994 occurred in the areas of sales promotion due to cost-cutting efforts and transmission maintenance due to nonrecurring work in 1993 on the main transmission line. Expenses in 1993 also increased because of rapid customer growth, additional employees and wage and salary increases. In 1992, additional maintenance costs of $500,000 relating to environmental matters were incurred; such costs did not recur in either 1993 or 1994.
Depreciation expense increased from $6.1 million to $7.4 million from 1992 to 1994 due to the substantial growth in plant in service, particularly from transmission line extensions and new compressors and, also, distribution mains and service line extensions into Cumberland, New Hanover, Johnston and Union counties. Depreciation rates were approximately the same in all years.
The federal and state income tax provision in 1994 was essentially unchanged from 1993 because, even though operating income declined in 1994, utility interest charges also declined and the 35% federal tax rate was in effect for all of 1994 compared to only nine months in 1993. Tax provisions for each of the years 1994, 1993 and 1992 were reduced by approximately $200,000 due to amortization of excess deferred income taxes authorized in the December 1991 general rate order. The Company's adoption of FASB Statement No. 109 on accounting for income taxes effective October 1, 1993, had no appreciable impact on the income tax provision. Earnings from the Company's nonutility division increased to $723,000 in 1994 from $313,000 in 1993 due to continuing growth in propane gas operations and the reduction of 1993 earnings caused by the writedown of the carrying value of certain nonutility assets.
Utility interest charges decreased to $4.1 million in 1994 from $4.4 million in 1993 and $5.0 million in 1992 because of several factors. Long-term debt, including current maturities, decreased to $39,000,000 at September 30, 1994 from $45,088,000 at September 30, 1993 and $48,452,000 at September 30, 1992 through sinking fund payments, including the prepayment on September 1, 1994 of the remaining $4,088,000 principal balance of the 12 7/8% Debentures due September 1, 1996. The $17.5 million net proceeds from a public offering of common stock in February 1993 were used entirely to reduce short-term debt then outstanding. While short-term debt has increased to $26 million
Item 7. Management's Discussion and Analysis of 	 Financial Condition and Results of Operations (Continued) 	 ---------------------------------------------------------
at September 30, 1994 from $15.5 million at September 30, 1993, and short-term interest rates have increased in 1994, the reduction in long-term debt interest expense has more than offset the increased cost of short-term borrowings in 1994. Another factor causing the decline in utility interest charges in 1994 is the increase in the allowance for funds used during construction (AFUDC) to $500,000 in 1994 from $204,000 in 1993 due to the higher level of construction spending in 1994 compared to 1993 and a resulting increase in construction work in progress on which AFUDC is taken. Partially offsetting these factors was a net decrease in recoverable purchased gas costs. Under NCUC rules, amounts owed to, or due from, customers for purchased gas cost and IST over or under collections accrue interest at the rate of 10% per annum.
IMPACT OF INFLATION Inflation impacts the Company primarily in the prices it pays for labor, materials and services. Because the Company can adjust its rates to recover cost increases 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 increases or decreases in the cost of gas which comprises approximately two-thirds of the Company's revenues.
OTHER MATTERS
In 1991, the North Carolina Department of Environment, Health and Natural Resources advised the Company of possible environmental contamination arising from the site of a former manufactured gas facility in Kinston, North Carolina. The Company retained an environmental services consulting firm which has estimated the costs of investigation and remediation based on its work to date to be between $1.4 million and $2.8 million over a four-to-six year period. The Company believes that any appreciable costs not previously provided for will be recovered from third parties, including liability insurance carriers, or in natural gas rates.
The Company also owns another site of a former manufactured gas plant in New Bern, North Carolina, and was a previous owner of three small former manufactured gas plant sites on which no significant problems have arisen.
SIGNIFICANT TRENDS The implementation in November 1993 of FERC Order 636 by all U.S. interstate pipelines, including the two serving the Company, essentially completes the decade-long process of restructuring, at the federal regulatory level, the natural gas industry into a more competitive environment. The new rules provide the natural gas industry more freedom in the way it operates, and the increasing competition is changing the way local distribution companies (LDCs) such as NCNG conduct business with the result that consumers have more choices and lower gas costs than they had before. Also, LDCs, including NCNG, have more risk as they assume the majority of the gas supply aggregation burden formerly shouldered almost exclusively by the pipelines. The Company has developed strategic goals and action plans to compete successfully in the new era, and Management believes that additional opportunities for growth in the Company's service area continue to be abundant.
Item 7. Management's Discussion and Analysis of 	 Financial Condition and Results of Operaitons (Continued) 	 ---------------------------------------------------------
While the Company, since 1990, has extended its pipeline to serve the Johnston County towns of Smithfield, Selma and Clayton; built a 27-mile, 12" pipeline to serve a major industrial plant in Brunswick County; expanded its distribution system in Union County; and is presently extending its pipeline 13 miles to serve the Town of Mount Olive in southern Wayne County, there remain several counties in the Company's service area with no natural gas service. The North Carolina General Assembly in 1991 passed legislation that authorized creation of an expansion fund for each local natural gas distribution company.
The Company applied to the NCUC for establishment of an expansion fund in 1992 and for approval of an expansion project. By Order of the NCUC dated February 8, 1993, an Expansion Fund for the Company was created, but the NCUC did not rule on the proposed expansion project. This Commission decision was opposed by several major existing industrial and municipal customers who subsequently appealed the NCUC Order to the Supreme Court of North Carolina. In July 1994, the Court upheld the Commission's Order, thus clearing the way for the Company to apply once again for authorization from the NCUC to extend its pipeline into one or more unserved areas utilizing its Expansion Fund. On October 20, 1994, the Company transferred an additional $6.6 million to its Expansion Fund administered by the NCUC which, when a previous transfer in April 1993 and cumulative interest earned to date are considered, brings the total amount in the Expansion Fund to $10.8 million at that date. Additionally, the Company had on hand at September 30, 1994 an additional $2.7 million of pipeline refunds which have not been transferred yet to the Expansion Fund because Transco has appealed FERC's rate order directing Transco to make such refunds.
Item 8.
Item 8. Financial Statements and Supplementary Data - ---------------------------------------------------- Consolidated Balance Sheets as of September 30, 1994 1993 ---- ---- Assets
GAS UTILITY PLANT: In service $240,270,999 $224,127,260 Less - Accumulated depreciation 79,033,948 72,402,705 	and amortization ----------- ----------- 161,237,051 151,724,555 Construction work in progress 3,605,664 818,641 ----------- ----------- 164,842,715 152,543,196 ----------- ----------- INVESTMENTS: Nonutility property, less accumulated depreciation (1994, $2,417,285; 1993, $2,195,826) 2,867,415 2,448,454 Investment in exploration and development activities, net of accumulated depletion and amortization (1994 $3,052,534; 1993 $9,441,190) 90,227 180,177 ----------- ----------- 2,957,642 2,628,631 ----------- ----------- CURRENT ASSETS: Cash and temporary cash investments 158,432 1,591,512 Restricted temporary cash investment 9,281,583 4,862,746 Accounts receivable, less allowance for doubtful accounts (1994, $416,049; 1993, $434,375) 11,795,395 12,796,224 Recoverable purchased gas costs 1,505,124 6,396,284 Inventories, at average cost -- Gas in storage 8,091,210 7,169,436 Materials and supplies 2,634,021 1,973,181 Merchandise 1,415,030 1,312,719 Deferred gas cost - unbilled volumes 473,136 638,265 Prepaid expenses and other 387,125 383,659 ----------- ----------- 35,741,056 37,124,026 ----------- ----------- DEFERRED CHARGES AND OTHER: Debt discount and expense, being amortized over lives of related debt 300,477 379,036 Prepaid pension cost 1,178,344 1,368,736 Other 67,036 134,465 ----------- ----------- 1,545,857 1,882,237 ----------- ----------- $205,087,270 $194,178,090 =========== ===========
(The accompanying notes are an integral part of these financial statements.)
					 Stockholders' Investment and Liabilities as of September 30, 1994 1993 ---- ----- 					 CAPITALIZATION (see accompanying statements): Stockholders' investment $ 86,398,741 $ 80,944,184 Long-term debt 37,000,000 39,000,000 ----------- ----------- 123,398,741 119,944,184 ----------- -----------
CURRENT LIABILITIES: Current maturities of long-term debt 2,000,000 6,088,000 Notes payable 26,000,000 15,500,000 Accounts payable 9,675,443 14,723,470 Customer deposits 1,994,444 1,882,568 Restricted supplier refunds 9,281,583 4,862,746 Accrued interest 1,599,999 1,662,655 Accrued income and other taxes 1,684,596 2,427,561 Other 2,395,492 2,235,894 ----------- ----------- 54,631,557 49,382,894 ----------- ----------- OTHER CREDITS: Deferred income taxes 18,279,090 20,363,137 Regulatory liability related to income 3,922,719 -- Unamortized investment tax credits 3,121,692 3,324,492 Postretirement benefit liability 633,666 -- Miscellaneous 1,099,805 1,163,383 ----------- ----------- 27,056,972 24,851,012 ----------- ----------- 	 $205,087,270 $194,178,090 =========== ===========
(The accompanying notes are an integral part of these financial statements.)
Consolidated Statements of Income For the Years Ended September 30, 1994 1993 1992 ---- ---- ----
OPERATING REVENUES $160,336,678 $173,145,401 $150,509,653 COST OF GAS 105,239,767 119,100,211 100,347,522 ----------- ----------- ----------- GROSS MARGIN 55,096,911 54,045,190 50,162,131 ----------- ----------- ----------- OPERATING EXPENSES AND TAXES: Operations 16,739,190 15,512,283 14,619,132 Maintenance 2,738,814 2,872,565 3,183,799 Depreciation 7,372,928 6,891,264 6,125,136 General taxes 7,524,483 7,374,822 6,833,926 Income taxes -- Federal 4,995,000 4,942,000 3,990,200 State 1,323,000 1,360,000 1,179,100 ----------- ----------- ----------- TOTAL OPERATING EXPENSES AND TAXES 40,693,415 38,952,934 35,931,293 ----------- ----------- -----------
OPERATING INCOME 14,403,496 15,092,256 14,230,838 OTHER INCOME, NET 722,582 313,276 450,025 INCOME (LOSS) FROM SUBSIDIARIES 79,274 (4,129) 26,579 ----------- ----------- ----------- GROSS INCOME 15,205,352 15,401,403 14,707,442 ----------- ----------- ----------- UTILITY INTEREST CHARGES: Interest on long-term debt 4,126,636 4,454,556 4,521,555 Other interest 349,980 129,609 1,006,456 Amortization of debt discount and expense 78,559 44,546 42,409 Allowance for funds used during construction (499,754) (204,386) (559,644) ----------- ----------- ----------- TOTAL UTILITY INTEREST CHARGES 4,055,421 4,424,325 5,010,776 ----------- ----------- -----------
NET INCOME $ 11,149,931 $ 10,977,078 $ 9,696,666 =========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING 6,331,155 5,981,248 5,414,495 =========== =========== ===========
EARNINGS PER SHARE $1.76 $1.84 $1.79 =========== =========== ===========
(The accompanying notes are an integral part of these financial statements.)
Consolidated Statements of Cash Flows For the Years Ended September 30, 1994 1993 1992 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $11,149,931 $10,977,078 $9,696,666 Add (deduct) items which did not use (provide) cash- Depreciation charged to: Operating expenses 7,372,927 6,891,264 6,125,136 Other income 340,888 296,749 267,174 Amortization of deferred charges 168,954 98,923 65,784 Deferred income taxes 1,838,672 1,500,000 (395,000) Investment tax credits, net (202,800) (202,800) (198,000) Depletion and amortization of investment in exploration and development activities 23,018 30,219 53,192 Other 514,451 (253,194) 997,573 Changes in other assets and liabilities: Accounts receivable, net 989,329 (921,536) (2,690,373) Refundable income taxes -- -- 345,355 Gas in storage (921,775) (1,098,888) (114,122) Materials, supplies and merchandise (763,150) 20,755 (33,288) Accounts payable (5,048,026) (1,759,499) 4,817,661 Refunds payable and recoverable purchased gas costs 4,442,298 545,700 (22,697,407) Accrued income and other taxes (742,965) (2,821,460) 3,999,244 Other 439,298 503,752 721,476 ---------- ---------- ---------- Net cash provided by 	 operating activities 19,601,050 13,807,063 961,071 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (20,756,334) (15,468,859) (23,772,900) Proceeds from sale of property 1,076,210 -- -- Other, net (70,632) (50,121) (38,650) ---------- ---------- ---------- Net cash used in investing activities (19,750,756) (15,518,980) (23,811,550) ---------- ---------- ---------- 			 CASH FLOWS FROM FINANCING ACTIVITIES: Sale of Debentures, Series C -- -- 25,000,000 Increase (decrease) in notes payable 10,500,000 (7,000,000) 5,500,000 Retirement of long-term debt (6,088,000) (3,364,000) (3,364,000) Cash dividends paid (7,215,800) (6,447,579) (5,322,452) Issuance of common stock through dividend reinvestment plan 1,255,984 1,123,266 969,492 Issuance of common stock through employee stock purchase plan 264,442 228,846 102,416 Issuance of common stock through public offering -- 17,518,306 -- Issuance of common stock through key employee stock option plan -- 131,400 -- ---------- ---------- ---------- Net cash (used in) provided by financing activities (1,283,374) 2,190,239 22,885,456 ---------- ---------- ---------- Net increase (decrease) in cash and temporary cash investments (1,433,080) 478,322 34,977 Cash and temporary cash investments, beginning of year 1,591,512 1,113,190 1,078,213 ---------- ---------- ---------- Cash and temporary cash investments, end of year $158,432 $1,591,512 $1,113,190 ========== ========== ========== Cash paid for: Interest (net of amounts capitalized) $4,533,508 $4,796,222 $4,656,005 Income taxes (net of refunds) 5,653,288 7,654,079 2,742,540
(The accompanying notes are an integral part of these financial statements.)
Consolidated Statements of Capitalization as of September 30, 1994 1993 ---- ----
STOCKHOLDERS' INVESTMENT : Common stock, par value $2.50; 12,000,000 shares authorized; shares outstanding: 1994-6,366,544; 1993-6,300,999 $ 15,916,360 $ 15,752,498 Capital in excess of par value 25,498,420 24,141,856 Retained earnings 44,983,961 41,049,830 ----------- ----------- Total stockholders' investment 86,398,741 80,944,184 ----------- ----------- LONG-TERM DEBT: Debentures, 12 7/8% Series A, due September 1, 1996 -- 4,088,000 Debentures, 8 3/4% Series B, due June 15, 2001 14,000,000 16,000,000 Debentures, 9.21% Series C, due November 15, 2011 25,000,000 25,000,000 ----------- ----------- 39,000,000 45,088,000 Less - Current maturities (2,000,000) (6,088,000) ----------- ----------- Total long-term debt 37,000,000 39,000,000 ----------- ----------- TOTAL CAPITALIZATION $123,398,741 $119,944,184 =========== ===========
CAPITALIZATION RATIOS: Stockholders' investment 68.9% 64.2% Long-term debt (including current maturities) 31.1% 35.8% ----------- ----------- 100.0% 100.0% =========== ===========
Consolidated Statements of Retained Earnings For the Years Ended September 30, 1994 1993 1992 ---- ---- ----
BALANCE AT BEGINNING OF YEAR $41,049,830 $36,520,331 $36,686,439
Net Income 11,149,931 10,977,078 9,696,666 Cash dividends on common stock (per share - $1.14 in 1994, $1.06 in 1993 and $.983 in 1992) (7,215,800) (6,447,579) (5,322,452) Stock split effected in the form of a stock dividend -- -- (4,540,322) ---------- ---------- ---------- BALANCE AT END OF YEAR $44,983,961 $41,049,830 $36,520,331 ========== ========== ==========
(The accompanying notes are an integral part of these financial statements.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1994)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation - The consolidated financial statements include North Carolina Natural Gas Corporation (the Company) and its wholly owned subsidiaries, NCNG Exploration Corporation (NCNGE) and Cape Fear Energy Corporation (Cape Fear). All significant intercompany transactions have been eliminated in consolidation.
Utility Plant - Gas utility plant is stated at original cost. Such cost includes payroll-related costs such as taxes, pension and other fringe benefits, general and administrative costs and an allowance for funds used during construction. The Company capitalizes funds used during construction based on the overall cost of capital, which includes the cost of both debt and equity funds used to finance construction. The cost of depreciable property retired, plus the cost of removal less salvage, is charged to accumulated depreciation.
Depreciation - Depreciation is provided on the straight-line method over the estimated useful lives of the assets. The current rates have been approved by the North Carolina Utilities Commission (NCUC). Depreciation was approximately 3.2% of the cost of total depreciable property in 1994 and 1993, and 3.1% in 1992.
Income Taxes - The Company uses comprehensive interperiod income tax allocation (full normalization) to account for temporary differences in the recognition of revenues and expenses for financial and income tax reporting purposes.
In years prior to 1994, income taxes were accounted for under Accounting Principles Board Opinion No. 11. Effective October 1, 1993, the Company adopted FASB Statement No. 109, "Accounting for Income Taxes". Statement No. 109 required, among other things, a change to
the liability method of accounting for deferred income taxes. See Note 3 for more information regarding income taxes.
The Company uses the deferred method of accounting for investment tax credits. Investment tax credits generated in prior years have been deferred and are being amortized to income over the service life of the related property, which is approximately 30 years.
Recognition of Revenue - The Company follows the practice of rendering customer bills on a cyclical basis throughout each month and recording revenue at the time of billing. The Company defers the cost of gas delivered but unbilled due to cycle billing.
Gas in Storage - Inventories of gas in storage are maintained on the basis of average cost. Such cost is recovered from customers at the time the gas is withdrawn from storage and sold.
Temporary Cash Investments - Temporary cash investments are securities with maturities of 90 days or less. For purposes of the Consolidated Statements of Cash Flows, temporary cash investments are considered cash equivalents.
Restricted Temporary Cash Investments and Restricted Supplier Refunds - In February 1993, the NCUC issued its Order establishing an Expansion Fund for the Company to be funded initially by refunds the Company had received from its pipeline suppliers. The investment and use of these funds have been restricted by a previous Order of the NCUC. Pursuant to the February 1993 Order, the Company remitted $3,795,000 to the NCUC for the Expansion Fund in April 1993. At September 30, 1993, the refunds received plus interest, which had not been remitted to the NCUC, amounted to $4,863,000 and were reported on the balance sheet in restricted temporary cash investments and restricted supplier refunds.
During 1994 an additional $4.2 million of pipeline refunds were received which, together with interest earned on funds invested by the Company, brought the amount reported on the balance sheet as restricted temporary cash investments and restricted supplier refunds to $9,282,000 at
September 30, 1994. In October 1994, the Company remitted an additional $6,645,000 to the NCUC for the Expansion Fund.
Pursuant to the NCUC Orders, the funds not yet transferred to the Expansion Fund administered by the NCUC are to remain segregated from the Company's general funds and, pending further order of the NCUC, may be remitted to the NCUC and used for expansion of the Company's facilities into unserved areas of the Company's franchised territory or, if not used for expansion, refunded to the Company's customers. Amounts remitted to the NCUC through September 30, 1994 are not included in the Company's financial statements.
Fair Value of Financial Instruments - FASB Statement No. 107, "Disclosure About Fair Value of Financial Instruments" requires disclosure of the fair value of financial instruments, both assets and liabilities, for which it is practicable to estimate fair value.
The fair value of the Company's long-term debt is estimated using a discounted cash flow methodology. Based on published corporate borrowing rates for debt instruments with similar terms and average maturities, the estimated fair value of the Company's long-term debt (including current maturities) at September 30, 1994 is approximately $39.7 million as compared to a carrying value of $39.0 million and at September 30, 1993 the estimated fair value was approximately $52.3 million as compared to a carrying value of $45.1 million.
Reclassifications - Certain Financial Statement items in 1993 and 1992 have been reclassified to conform with the 1994 presentation.
2. REGULATORY AND GAS SUPPLY MATTERS:
In the general rate case filed in May 1991, the NCUC granted, effective December 6, 1991, additional annual revenues of $2,565,000 and rates of return of 11.16% and 12.70% on net investment and common equity, respectively. Additionally, the NCUC allowed the Company to continue to include in its rate tariff an Industrial Sales Tracker (IST) which is designed to stabilize the Company's margin (difference between revenues and purchased gas costs) earned from sales and transportation to interruptible industrial customers who use heavy fuel oil as an
alternative fuel. To the extent that actual margins realized from deliveries to such customers exceed, or are less than, the base period margins included in the general rate case from IST sales or transportation, refunds payable or additional receivables are recorded. The actual margins earned from IST deliveries were less than the base period margin by $3,940,000 and $5,166,000 in 1994 and 1993, respectively.
Also as part of the December 6, 1991 rate Order, the NCUC approved the Company's application to establish a Weather Normalization Adjustment (WNA) for the space heating market. The WNA stabilizes the Company's winter revenues and customers' bills by adjusting rates when weather deviates from normal. The nongas component of rates for space heating customers is adjusted upward when weather is warmer than normal and downward when weather is colder than normal. In Fiscal 1994, winter weather was 3% warmer than normal and, accordingly, the WNA increased net billings to customers by $462,000.
The NCUC, in a general rulemaking proceeding, revised its Purchased Gas Adjustment (PGA) procedures in April 1992. The revised procedures continue to allow the Company to recover all of its prudently incurred gas costs, but such procedures provide for several significant changes which include: (1) the establishment of a benchmark commodity cost of gas which represents the Company's estimate of the actual commodity cost of gas from all suppliers that it will incur in a future period; (2) the recovery of 100% of prudently incurred fixed costs of pipeline capacity and storage costs, including costs of any new capacity added since the last general rate case; (3) the notice period for requesting PGA rate changes was reduced to 14 days from 30 days; (4) the establishment of a tariff provision which allows the Company to recover margin losses from negotiated rates to non-IST large commercial and industrial customers; (5) a true-up of fixed gas costs recovered from the Company's customers; (6) a true-up of the Company's lost, unaccounted for and company use volumes compared to such volumes included in the last general rate case; and (7) an annual review of the Company's gas costs, including the prudence thereof, by the Public Staff of the NCUC and a hearing before the NCUC. The Company's second annual review of its gas costs was held in April 1994 for the 12 months ended November 30, 1993. The NCUC found the Company's gas costs and gas purchasing practices to be prudent, as it had for the first annual review in 1993.
In July 1994 the NCUC issued another rulemaking order in which it required that all natural gas utilities flow through to customers 90% of the net compensation received for capacity release and similar transactions while retaining 10% of such compensation. The Company had been accounting for such transactions in accordance with the 90/10 sharing mechanism pursuant to a previous Commission Order issued in 1993. In August 1994 the Company filed with the NCUC its second annual true-up of lost, unaccounted for and company use volumes for the 12 months ended June 30, 1994. Because such volumes exceeded the base period amounts included in the last general rate case, the Company charged $1,292,000 in 1994 from the true-up to the deferred gas cost account for future recovery in rates from customers.
3. INCOME TAXES:
The components of income tax expense are as follows (in thousands):
For the years ended September 30, ------------------------------------------------ 1994 1993 1992 -------------- -------------- --------------- Federal State Federal State Federal State ------- ----- ------- ----- ------- ----- Income taxes ...............(In Thousands)................... charged to operations- Payable currently... $3,937 $ 937 $4,016 $1,000 $4,473 $1,189 Deferred to subsequent years..... 1,256 386 1,124 360 (285) (10) Investment tax credits, net........ (198) -- (198) -- (198) -- ----- ----- ----- ----- ----- ----- $4,995 $1,323 $4,942 $1,360 $3,990 $1,179 ===== ===== ===== ===== ===== =====
Income taxes charged to other income $ 429 $ 106 $ 165 $ 42 $ 149 $ 136 ===== ===== ===== ===== ===== =====
The effective income tax rate, computed by dividing total income tax expense by the sum of certain income tax expense and net income, is 38.1% in 1994, 37.2% in 1993, and 36.0% in 1992.
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense is as follows (in thousands):
1994 1993 1992 ---- ---- ---- Federal taxes at 35% for 1994, 34.75% for 1993 and 34% for 1992 .... $6,301 $6,076 $5,152 State income taxes, net of federal benefit ..................... 929 915 868 Amortization of investment tax credits.. (203) (203) (198) Amortization of excess deferred income taxes returned to customers... (222) (222) (222) Tax credit - supplier refunds........... ( 17) (133) -- Tax effect of allowance for funds used during construction - equity portion. ( 97) ( 40) (107) Other................................... 162 116 ( 39) ----- ----- ----- Total income tax expense................ $6,853 $6,509 $5,454 ===== ===== =====
Effective October 1, 1993, the Company adopted FASB Statement No. 109, "Accounting for Income Taxes". The adoption of Statement No. 109 resulted in cumulative adjustments to the balance sheet and had no effect on consolidated net income. As a result of Statement No. 109, the Company reduced accumulated deferred income taxes and recorded related regulatory assets and liabilities. The regulatory net liability is due primarily to deferred income taxes recognized in years prior to 1987 at rates higher than currently enacted.
The major timing differences for 1992 and 1993 were accelerated tax depreciation and producer settlement payments. The tax effects of temporary differences in the carrying amounts of assets and liabilities in the Financial Statements and their respective tax bases that give rise to deferred tax assets and liabilities are as follows:
---- Deferred Tax Liabilities: Accelerated Depreciation $19,903 Property Basis Differences 3,435 ------ 	 Total Deferred Tax Liabilities $23,338 ------ Deferred Tax Assets: Unamortized Investment Tax Credits $ 1,245 Regulatory Liability Related to 	Income Taxes, Net 1,571 Other 2,243 ------ 	 Total Deferred Tax Assets $ 5,059 ------ Net Deferred Tax Liabilities $18,279 ======
4. SUBSIDIARY OPERATIONS: NCNGE and Cape Fear participated in oil and gas exploration and development programs for several years. Under a program approved by the NCUC, the Company's customers participated in several NCNGE exploration and development programs by providing through rates approximately 75% of the net costs of those programs and receiving approximately 75% of net program revenues in return.
Effective June 7, 1994, the Company and the other three natural gas distribution utilities in North Carolina sold their combined interests in all of the exploration and development programs in which NCNGE was involved. NCNGE's share of the net proceeds was $615,000, of which $144,500 was deposited in an escrow account to remain until December 31, 1995 to cover any potential claims presented by the buyers. NCNGE recognized a pretax gain of $58,000 (shareholders' portion) on the sale, excluding the amount held in escrow. Approximately 75% of the net proceeds from the sale, along with net revenues and expenses of the programs prior to the sale, will be considered in the final amounts due to or from customers under these programs.
Cape Fear also purchases natural gas for transportation for the Company's system supply and for certain of the Company's customers who have requested Cape Fear's services.
5. SHORT-TERM BORROWING ARRANGEMENTS: The Company has lines of credit with North Carolina banks for an aggregate amount of $35,500,000. Under these lines, the Company borrows funds on a short-term basis in connection with its construction program and also for seasonal financing of storage gas, usually on a demand basis for a period of 90 days. The Company also uses bankers' acceptances to finance the cost of gas in storage for periods up to 180 days. The maximum amount of such bankers' acceptances is dependent upon the market value of gas in storage and these loans are made at rates below the prime rate. At September 30, 1994, $26,000,000 was outstanding at interest rates ranging from 5.065% to 5.35% and $9,500,000 was available under these arrangements.
In connection with the lines of credit, the Company is expected to maintain certain annual average nonrestricted cash balances in the banks ranging from 5% to 10% of the loans outstanding. In addition, there are nominal commitment fees on the unused lines of credit. To the extent that bankers' acceptances are outstanding, no commitment fees are payable.
6. PENSION AND OTHER POSTRETIREMENT BENEFITS: The Company has a pension plan which provides retirement benefits for its employees within specified age limits and periods of service. Plan benefits are based on years of service and the employee's compensation during the last five years of employment. The Company's funding policy is to contribute annually an amount equal to the maximum allowable tax deductible amount.
The total pension cost was $222,000 in 1994, $131,000 in 1993, and $63,000 in 1992, of which approximately 20% was capitalized in each year.
The plan's funded status as of September 30, 1994 and 1993 and pension costs for 1994, 1993 and 1992 were as follows (in thousands):
Funded Status: 1994 1993 -------------- ---- ---- Actuarial present value of accumulated plan benefits: Vested $14,355 $12,883 Nonvested 97 97 ------ ------ Subtotal 14,452 12,980 Effect of salary progression 3,989 3,776 ------ ------ Projected benefit obligation 18,441 16,756 Plan assets at market value 18,920 20,003 ------ ------ Plan assets in excess of projected benefit obligation 479 3,247 Unrecognized prior service cost being amortized over twelve years 707 298 Unrecognized net(gain)loss being amortized over ten years 721 (1,189) Unrecognized net asset existing at the date of transition, being amortized over approximately ten years (729) (987) ------ ------ Prepaid pension cost $ 1,178 $ 1,369 ====== ======
Pension Cost 1994 1993 1992 ------------ ---- ---- ---- Net pension cost was comprised of the following items: Service Cost $ 633 $ 610 $ 536 Interest cost on projected 	 benefit obligation 1,346 1,225 1,108 Actual return on plan assets 299 (1,908) (2,024) Amortization of unrecognized prior service cost 66 32 32 Amortization of transition net asset (258) (258) (258) Deferred gain (loss) on net assets (1,864) 430 669 ------ ----- ----- Net pension cost $ 222 $ 131 $ 63 ====== ===== =====
The expected long-term rate of return on plan assets was 8%. At September 30, 1994, plan assets were invested approximately 63% in fixed income securities and 37% in equity securities, including 2% in the common stock of the Company.
The Company also provides certain health care and life insurance benefits for retired employees, and substantially all employees may remain eligible for these benefits when they retire. Effective October 1, 1993 the Company adopted FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," on a prospective basis. This statement requires accounting for these benefits on an accrual basis using a single actuarial method which spreads the expected cost of such benefits to each year of an employee's service until the employee becomes fully eligible to receive the benefits. Prior to October 1, 1993, the Company accounted for these benefits on a cash basis consistent with current ratemaking treatment. The costs of such benefits charged to expense amounted to $501,000 in 1993 and $568,000 in 1992. The NCUC, in rate cases where Statement No. 106 accounting has been presented, has expressed its preference for the accrual basis of accounting and, accordingly, the Company expects that the regulatory treatment of these costs under Statement No. 106 in the Company's next general rate case will be the same prospectively as the accrual method that has been adopted. The Company is not currently funding this plan.
The following tables show the funded status of the plan and the components of the plan's net costs (in thousands) for fiscal year 1994:
Funded Status Medical Life ------------- ------- ---- Actuarial present value of benefit obligation: Retirees and dependents $ 2,112 $ 335 Employees eligible to retire 818 106 Other Employees 1,966 197 ------ ------ Accumulated benefit obligation 4,896 638 Unrecognized net gain 112 38 Unrecognized transition obligation (4,446) (604) ------ ------ Postretirement benefit liability $ 562 $ 72 ====== ====== Components of Net Cost ---------------------- Service cost during the year $ 128 $ 12 Interest cost on accumulated benefit obligation 363 49 Amortization of unrecognized transition obligation over 20 years 234 32 ------ ------ Net periodic postretirement benefit cost $ 725 $ 93 ====== ======
Of the net postretirement medical and life insurance costs recorded in 1994, $670,000 was charged to operating expenses and the remainder was charged to construction and other accounts.
The discount rate and rate of increase in future compensation levels used in determining the actuarial present value of the projected benefit obligations (pension, health care and life insurance) previously shown were 8% and 6%, respectively.
An additional assumption used in measuring the accumulated postretirement medical benefit obligation was a medical care cost trend rate of 12.5% for 1994, decreasing gradually to 5.5% through the year 2005 and remaining at that level thereafter. An annual increase in the assumed medical care cost trend rate by 1% would increase the accumulated medical benefit obligation at September 30, 1994, by $965,000 and the aggregate of the service and interest cost components of the net retiree medical cost by $108,000.
The Financial Accounting Standards Board (FASB) issued Statement No. 112, "Employers' Accounting for Postemployment Benefits", which requires that all types of benefits provided to former or inactive employees and their families prior to reitrement be accounted for on an accrual basis. The Company plans to adopt this standard in Fiscal 1995 and it is not expected to have a material impact on the financial statements.
7. STOCKHOLDERS' INVESTMENT: The changes in common stock and capital in excess of par value for the three years ended September 30, 1994, were as follows: 				 Common Stock $2.50 Par, Authorized 12,000,000 Shares --------------------- Capital In Shares Excess of Outstanding Amount Par Value ----------- ---------- ---------- Balance at September 30, 1991 3,591,905 $8,979,763 $6,300,543 Issuance through Dividend Reinvestment Plan (DRP) 35,350 88,375 881,117 Issuance through Employee Stock Purchase Plan (ESPP) 5,002 12,505 89,911 Issuance through stock split effected in the form of a dividend 1,816,129 4,540,322 -- --------- ---------- --------- Balance at September 30, 1992 5,448,386 13,620,965 7,271,571 Issuance through DRP. . . 44,946 112,365 1,010,901 Issuance through ESPP . . 15,992 39,980 188,866 Issuance through exercise of stock options . . . 5,175 12,938 118,462 Issuance through public offering of common stock . . . . . 786,500 1,966,250 15,552,056 --------- ---------- ---------- Balance at September 30, 1993 . 6,300,999 15,752,498 24,141,856 Issuance through DRP. . . 52,868 132,170 1,123,814 Issuance through ESPP . . 12,677 31,692 232,750 --------- ---------- ---------- Balance at September 30, 1994 . 6,366,544 $15,916,360 $25,498,420 ========= ========== ========== In February 1993, the Company issued common stock through a public offering at a price of $23.50 per share with net proceeds of $17.5 million after expenses of the offering.
The Company's common stock was split three-for-two effective October 30, 1992, in the form of a stock dividend. All earnings and dividends per share amounts in the accompanying consolidated financial statements and notes thereto reflect the stock split.
At September 30, 1994, there are 893,818 shares of common stock reserved for issuance under the Company's Dividend Reinvestment Plan and for other reasons. Under the most restrictive covenants of the Company's long-term debt agreements, approximately $17,838,000 of the Company's retained earnings at September 30, 1994, is unrestricted.
8. LONG-TERM DEBT MATURITIES: Maturities of existing long-term debt during each of the next five years will be as follows: 1995, $2,000,000; 1996, $2,000,000; 1997, $2,000,000; 1998, $2,000,000 and 1999, $3,250,000.
9. STOCK PURCHASE AND OPTION PLANS: In 1990, the Company instituted a stock purchase plan and a key employee nonqualified stock option plan. The stock purchase plan enables employees to contribute up to 6% of their wages toward purchase of the Company's common stock at 90% of the lower of current or prior year-end market value. Shares have been purchased by employees each year since 1991. Under the terms of the nonqualified stock option plan, 300,000 of authorized but unissued shares were available for purchase under the plan.
Under the terms of the nonqualified stock option plan, a maximum of 150,000 shares are reserved for issuance. The option price is equal to 90% of the market value of the stock at the grant date. The period during which these options are exercisable begins five years after, but may not exceed seven years after, the date of grant. In addition, the plan provides that an amount equal to 50% of the dividends that would have been paid on the stock from the date of grant shall be paid in cash at the exercise date. The plan provides that retired officers may exercise a pro rata number of options based on the number of months' service after the date of grant.
Transactions for 1994 and 1993 respectively, are as follows: 					 Shares Subject Average Option To Option Price Per Share -------------- --------------- Balance at September 30, 1992 86,400 $13.82 Exercised upon retirement 	of two officers.... ( 5,175) 13.80 Canceled...... ( 8,475) 13.80 ------ ----- Balance at September 30, 1993 72,750 $13.83 Granted.. 2,600 24.98 ------ ----- Balance at September 30, 1994 75,350 $14.21 ====== =====
1994 1993 1992 ---- ---- ---- Options Exercisable at Year End........ -- -- -- Options Available for Grant at Year End.. 69,475 72,075 63,600
10. COMMITMENTS AND CONTINGENCIES:
During fiscal year 1991, the North Carolina Department of Environment, Health and Natural Resources advised the Company of possible environmental contamination arising from Company-owned property in Kinston, North Carolina, which is the former site of a manufactured gas plant. The Company retained an environmental services consulting firm which has evaluated the site. Based on that firm's investigation to date and actual expenditures for sites of similar scope and complexity, the cost for investigation and remediation of this site is estimated to be between $1.4 million and $2.8 million over a four-to-six-year period. As of September 30, 1994, the Company had incurred no significant expenditures which were not covered by reimbursements from third parties, and none of these costs or reimbursements were included in the Company's natural gas rates. The Company owns another site of a former manufactured gas plant in New Bern, North Carolina, and was the former owner of three other similar sites on which no environmental problems have arisen. Management believes that any appreciable investigation or remediation costs not previously provided for will be recovered from third parties, including insurance carriers, or in natural gas rates. Based on the anticipated recovery from these sources, the Company does not believe that the cost of any evaluation and remediation work will have a material adverse effect on the Company's financial condition or results of operations.
The Company is subject to claims and lawsuits arising in the ordinary course of business. Management does not expect any litigation from such claims or lawsuits to have a material effect on the Company's business, financial condition, or results of operations.
Supplementary data -
The following table presents certain financial information for each quarter during the fiscal years ended September 30, 1994 and 1993 (amounts in thousands, except per share data). Amounts have been restated to reflect a 3-for-2 common stock split in the form of a common stock dividend effective October 30, 1992.
-------------------------------------- Fourth Third Second First ------ ----- ------ ----- Operating revenues $26,117 $29,523 $62,615 $42,082 Gross margin 9,617 9,264 21,080 15,136 Operating income 1,148 1,148 7,676 4,431 Net income 28 127 7,301 3,693 Earnings per share .004 .02 1.15 .59
-------------------------------------- Fourth Third Second First ------ ----- ------ ----- Operating revenues $29,195 $38,638 $53,916 $51,396 Gross margin 9,872 10,103 19,855 14,215 Operating income 1,756 1,852 7,391 4,093 Net income 424 700 6,652 3,201 Earnings per share(1) .07 .11 1.12 .59
1) The sum of the quarterly earnings per share amounts for 1993 does not 	equal the annual earnings per share amount reflected in the 	consolidated statement of income due to the effect of changes in average common shares outstanding during the fiscal year.
Item 9.
Item 9. Changes in and Disagreements on 	 Accounting and Financial Disclosures - --------------------------------------------- None.
Item 10.
Item 10. Management's Responsibility for Financial Statements - ---------------------------------------------------------------
Management is responsible for the preparation, presentation and integrity of the financial statements and other financial information in this report. The accompanying financial statements have been prepared in accordance with generally accepted accounting principles applicable to rate-regulated public utilities, including estimates and judgments made by management that were necessary to prepare the statements in accordance with such accounting principles, and are not misstated due to material fraud or error. To assure the integrity of the underlying financial records supporting the financial statements, management maintains a system of internal accounting controls sufficient to provide reasonable assurances that NCNG assets are properly accounted for, safeguarded and are utilized only in accordance with management's authorization. The concept of reasonable assurance recognizes that the costs of a system of internal controls should not exceed the related benefits derived from it.
The system of internal accounting controls is augmented by NCNG's internal audit department, which has unrestricted access to all levels of NCNG management. The internal audit department meets periodically, with and without the presence of management, with the Audit Committee of the Board of Directors to discuss, among other things, NCNG's system of internal accounting controls and the adequacy of the internal audit program. The Audit Committee is comprised of four directors who are not officers or employees of NCNG.
The Audit Committee also meets periodically with Arthur Andersen LLP, NCNG's independent public accountants, with and without the presence of management, to discuss the results of the annual audit of NCNG's financial statements and related data. The Audit Committee and Arthur Andersen LLP also discuss internal accounting control matters that come to the attention of Arthur Andersen LLP during the course of the audit.
s/Calvin B. Wells s/Gerald A. Teele --------------------------- ---------------------- Calvin B. Wells Gerald A. Teele Chairman, President and Senior Vice President and Chief Executive Officer Chief Financial Officer
PART III --------
Item 11.
Item 11. Directors and Executive Officers of the Registrant - ------------------------------------------------------------ Directors -
The information for this item covering directors of the Company is set forth in the section entitled "Election of Directors and Information as to Members" on Pages 1, 2 and 3 in the Company's Proxy Statement dated December 5, 1994 relating to the January 10, 1995 Annual Meeting of Stockholders, which section is hereby incorporated by reference.
Executive officers -
The information for this item concerning executive officers of the Company is set forth on Page 14 of this annual report.
Item 12.
Item 12. Executive Compensation - -------------------------------- The information for this item is set forth in the sections entitled "Executive Compensation", "Key Employee Stock Option Plan", "Employee Stock Purchase Plan", "Employee Retirement Plan" and "Executive Employment Agreements in the Event of Change in Control" and "Report of Personnel Committee on Executive Compensation" on Pages 4, 5, 6, 7, 8, and 9 in the Company's Proxy Statement dated December 5, 1994 relating to the January 10, 1995 Annual Meeting of Stockholders, which sections are hereby incorporated by reference.
Item 13.
Item 13. Security Ownership of Certain Beneficial Owners 	 and Management - ---------------------------------------------------------- Security ownership of certain beneficial owners -
There is no person who is known to the Company to be the beneficial owner of more than five percent of the Company's common stock as of September 30, 1994.
Security ownership of management -
The information for this item is set forth in the section entitled "Election of Directors and Information as to Members" on Pages 1, 2 and 3 in the Company's Proxy Statement dated December 5, 1994 relating to the January 10, 1995 Annual Meeting of Stockholders, which section is hereby incorporated by reference.
Changes in control -
The Company knows of no contractual arrangements which may at a subsequent date result in a change in control of the Company.
Item 14.
Item 14. Certain Relationships and Related Transactions - ---------------------------------------------------------- The information for this item is set forth in the sections entitled "Directors Transactions" and "Compensation Interlocks and Insider Participation" on Pages 1 and 9 in the Company's Proxy Statement dated December 5, 1994 relating to the January 10, 1995 Annual Meeting of Stockholders, which section is hereby incorporated by reference.
PART IV ------- 	 Item 15.
Item 15. Exhibits, Financial Statement Schedules, and 	 Reports on Form 8-K - ------------------------------------------------------- (a) 1. Financial Statements Page ---- 	 Consolidated Balance Sheets as of September 30, 1994 and 	 1993. 24 	 Consolidated Statements of Income for the Years Ended 	 September 30, 1994, 1993 and 1992. 26 	 Consolidated Statements of Cash Flows for the Years Ended 	 September 30, 1994, 1993, and 1992. 27 	 Consolidated Statements of Capitalization as of September 30, 	 1994 and 1993. 28 	 Consolidated Statements of Retained Earnings for the Years 	 Ended September 30, 1994, 1993 and 1992. 29 	 Notes to Consolidated Financial Statements for years ended 	 September 1994, 1993 and 1992. 30 	 Management's Responsibility for Financial Statements. 44
No separate financial statements are presented for the Company's consolidated subsidiaries because the Company and its subsidiaries meet the requirements for omission set forth in Regulation S-X, Rule 3-O9.
(a) 2. Financial Statement Schedules -------------------------------------- 	 The following data and financial statement schedules are included herein: Page ---- 	 Report of Independent Public Accountants 58 	 Schedule V - Gas Utility Plant (Including 	 Intangibles) and Nonutility Property for 	 Years Ended September 30, 1994, 1993 and 1992. 49-51 	 Schedule VI - Reserves for Depreciation and 	 Amortization for the Years Ended September 30, 	 1994, 1993 and 1992. 52-54 	 Schedule VIII - Valuation and Qualifying Accounts 	 for the Years Ended September 30, 1994, 1993 	 and 1992. 55 	 Schedule IX - Short-term Borrowings for the 	 Years Ended September 30, 1994, 1993 and 1992. 56 	 Schedule X - Supplementary Income Statement 	 Information for the Years Ended September 30, 	 1994, 1993 and 1992. 57
Item 15. (Continued) - ---------------------
	 All other financial statement schedules are omitted as not 	 applicable, or nor required, or because the required information 	 is given in the Consolidated Financial Statements or Notes thereto.
	 (a) 3. Exhibits 	 ----------------
	 See Index of Exhibits on Page 60 of this report.
	 (b) Reports on Form 8-K 	 ------------------------
	 There were no reports on Form 8-K filed during the three months 	 ended September 30, 1994.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------
To the Stockholders and the Board of Directors of North Carolina Natural Gas Corporation:
We have audited the accompanying consolidated balance sheets and statements of capitalization of North Carolina Natural Gas Corporation (a Delaware corporation) and subsidiaries as of September 30, 1994 and 1993, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years ended September 30, 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of North Carolina Natural Gas Corporation and subsidiaries as of September 30, 1994 and 1993, and the results of their operations and their cash flows for each of the three years ended September 30, 1994, in conformity with generally accepted accounting principles.
As explained in Notes 3 and 6 to the consolidated financial statements, effective October 1, 1993, the Company changed its methods of accounting for income taxes and postretirement benefits other than pensions.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole period. The schedules listed in the index of financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
					 ARTHUR ANDERSEN LLP Atlanta, Georgia November 9, 1994
SIGNATURES
	Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES (Registrant)
By: s/Calvin B. Wells ------------------ Calvin B. Wells Chairman, President and Chief Executive Officer 						 				 December 13, 1994:
	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 date indicated.
	 Signature Title 	 --------- -------
						 s/Calvin B. Wells Chairman, President, Chief Executive - ----------------------------- (Principal Executive Officer) Calvin B. Wells
s/Gerald A. Teele Senior Vice President and Chief - ----------------------------- Financial Officer Gerald A. Teele (Principal Financial Officer)
s/Charles W. Siska, Jr. Controller - ----------------------------- (Principal Accounting Officer) Charles W. Siska, Jr.
s/ George T. Clark, Jr. s/William H. Prestage - ----------------------------- ---------------------------- George T. Clark, Jr.-Director William H. Prestage-Director
s/C. Felix Harvey s/Paul A. DelaCourt - ----------------------------- ---------------------------- C. Felix Harvey-Director Paul A. DelaCourt-Director
s/Richard F. Waid s/Hector MacLean - ----------------------------- ---------------------------- Richard F. Waid-Director Hector MacLean-Director
NORTH CAROLINA NATURAL GAS CORPORATION INDEX OF EXHIBITS
The following exhibits are filed as part of this 1994 Form 10-K report. Those exhibits previously filed and incorporated herein by reference are identified below by a note reference to the previous filing.
Exhibit Number
3-1 - Certificate of Incorporation and By-Laws. (1)
3-2 - Amendments of Certificate of Incorporation and By-Laws. (4)
3-3 - Amendment of Certificate of Incorporation. (10)
4-1 - Indenture dated as of September 1, 1984, covering 12 7/8% Debentures Series A due September 1, 1996. (3)
4-2 - First Supplemental Indenture dated as of June 15, 1986, supplementing Indenture dated as of September 1, 1984, and creating 8.75% Debentures, Series B due June 15, 2001. 	 (6)
4-3 - Second Supplemental Indenture dated as of November 1, 1991, supplementing Indenture dated as of September 1, 1984, and creating 9.21% Debentures, Series C due November 15, 2011. (10)
10-1 - Service Agreement dated August 31, 1967, with Transcontinental Gas Pipe Line Corporation covering storage service under Rate Schedule GSS. (1)
10-2 - Service Agreement dated August 2, 1974, with 	 Transcontinental Gas Pipe Line Corporation covering 		 storage service under Rate Schedule LG-A. (1)
10-3 - Precedent Agreement to provide Contract Demand Service of 25,000 Dt/day dated December 19, 1988, with Columbia Gas Transmission Corporation. (7)
10-4 - Contract Demand Service Agreement dated November 1, 1989, with Columbia Gas Transmission Corporation.(8)
10-5 - Firm Seasonal Transportation Agreement dated July 2, 1990, with Transcontinental Gas Pipe Line Corporation.(8)
10-6 - Service Agreement dated August 1, 1991, with Transcontinental Gas Pipeline Corporation covering storage service under Rate Schedule WSS (9)
10-7 - Firm Sales Agreement with Transcontinental Gas Pipe Line Corporation dated August 1, 1991 covering 54,043 Mcf per day.(9)
Index of Exhibits (Continued)
10-8 - Firm Transportation Agreement with Transcontinental Gas Pipe Line Corporation dated February 1, 1991 for 141,000 Mcf per day. (10)
10-9 - Supplemental Retirement Benefit Agreement dated January 13, 1981. (2)
10-10 - Employment Agreements executed in 1985 with certain Executive Officers. (5)
10-11 - Employment Agreements executed in 1986 with certain Executive Officers. (6)
10-15 - Natural Gas Service Agreement dated January 9, 1992 with the City of Wilson. (10)
10-16 - Natural Gas Service Agreement dated January 13, 1992 with the City of Rocky Mount. (10)
10-17 - Service Area Territory Agreement dated January 13, 1992 with the City of Rocky Mount. (10)
10-18 - Natural Gas Service Agreement dated March 12, 1992 with the Greenville Utilities Commission. (10)
10-19 - Natural Gas Service Agreement dated March 27, 1992 with the City of Monroe. (10)
10-20 - Amendment to Natural Gas Service Agreement dated March 27, 	 1992 with the City of Greenville Utilities Commission.
10-21 - Amendment to Natural Gas Service Agreement dated January 13, 1992 with the City of Rocky Mount.
24 - Consent of Experts
27 - Financial Data Schedule
NOTES:
(1) Filed as exhibits to Form 10-K report for fiscal year ended 	September 30, 1980.
(2) Filed as exhibits to Form 10-K report for fiscal year 	ended September 30, 1981.
(3) Filed as exhibit to Form 10-K report for fiscal year 	ended September 30, 1984.
(4) Filed as exhibits to Form 8-K report dated February 6, 1985.
Index of Exhibits (Continued)
(5) Filed as exhibit to Form 10-K report for fiscal year ended 	 September 30, 1985.
(6) Filed as exhibit to Form 10-K report for fiscal year ended 	 September 30, 1986.
(7) Filed as exhibit to Form 10-K report for fiscal year ended 	 September 30, 1989.
(8) Filed as exhibit to Form 10-K report for fiscal year ended 	 September 30, 1990.
(9) Filed as exhibit to Form 10-K report for fiscal year ended September 30, 1991.
(10) Filed as exhibit to Form 10-K report for fiscal year ended 	 September 30, 1992.
SECOND AMENDMENT TO Exhibit 10-20 NATURAL GAS SERVICE AGREEMENT BETWEEN Page 1 of 2 GREENVILLE UTILITIES COMMISSION, GREENVILLE, N.C. AND NORTH CAROLINA NATURAL GAS CORPORATION
	This Second Amendment entered into to be effective on the 1st day of 	January, 1994, between Greenville Utilities Commission, Greenville, 	N.C., (as "Customer") and North Carolina Natural Gas Corporation, a 	Delaware corporation (as "Company"), 	 W I T N E S S E T H:
	WHEREAS, Customer and Company are parties to a certain "Natural Gas 	Service Agreement By and Between Greenville Utilities Commission, 	Greenville, N.C. and North Carolina Natural Gas Corporation" dated 	March 12, 1992 ("the Agreement"); and 	 	WHEREAS, Company and Customer wish to amend that contract as more 	fully set forth herein;
	NOW, THEREFORE, in consideration of the premises and mutual covenants 	herein and in the Agreement, Company and Customer agree as follows: 	 	1. Section 2.01 is deleted in its entirety and the following is 	 substituted therefor: 	 	 2.01 Subject to the terms and provisions of this Agreement, 		 Company agrees to sell and deliver to Customer and 		 Customer agrees to purchase and receive from Company, 		 Customer's natural gas requirements, excluding that 		 portion of Customer's requirements which are transported 		 pursuant to Article III below. Customer agrees that the 		 maximum quantity of gas that Company is required to 		 deliver, either by sale or transportation, shall be 		 11,000 dekatherms ("Dth") per day and 550 Dth per hour. 		 For purposes of computing the Demand Charge under Rate 		 Schedules RE-2 and T-6, the foregoing maximum daily 		 quantity, subject to adjustments as provided herein, 		 shall constitute the Contract Demand, during the 		 respective periods to which each maximum is applicable, 		 and Customer agrees to pay Company therefor as provided 		 in the applicable rate schedule.
	2. This Second Amendment shall become effective on January 1, 1994.
	3. Except as specifically provided herein, the Agreement shall 	 continue in force and affect as previously written.
										Exhibit 10-20 									Page 2 of 2
	IN WITNESS WHEREOF, this instrument is executed effective as of the 	day and year first written above.
GREENVILLE UTILITIES COMMISSION GREENVILLE, N.C. 						 s/Malcolm A. Greene -------------------------------- Malcolm A. Greene Title: General Manager
NORTH CAROLINA NATURAL GAS COPRORATION
s/Calvin B. Wells -------------------------------- Calvin B. Wells Title: President
					 					
FIRST AMENDMENT TO Exhibit 10-21 NATURAL GAS SERVICE AGREEMENT BETWEEN Page 1 of 2 THE CITY OF ROCKY MOUNT, NC AND NORTH CAROLINA NATURAL GAS CORPORATION
	This First Amendment entered into to be effective on the 1st day 	of January, 1994, between The City of Rocky Mount, North Carolina, 	(as "Customer") and North Carolina Natural Gas Corporation, a 	Delaware corporation (as "Company"), 	 WITNESSETH:
	WHEREAS, Customer and Company are parties to a certain "Natural Gas 	Service Agreement By and Between The City of Rocky Mount, North 	Carolina and North Carolina Natural Gas Corporation" dated January 	13, 1992 ("the Agreement"); and
	WHEREAS, Company and Customer wish to amend that contract as more 	fully set forth herein; 	 	NOW, THEREFORE, in consideration of the premises and mutual covenants herein and in the Agreement, Company and Customer agree as follows: 	 	1. Section 2.01 is deleted in its entirety and the following 	 	is substituted therefor: 		 		2.01 Subject to the terms and provisions of this Agreement, 		 Company agrees to sell and deliver to Customer and 		 Customer agrees to purchase and receive from Company, 		 Customer's natural gas requirements, excluding that 		 portion of Customer's requirements which are 		 transported pursuant to Article III below. Customer 		 agrees that the maximum quantity of gas that Company 		 is required to deliver, either by sale or 		 transportation, shall be 18,000 dekatherms ("Dth") per 		 day and 1200 Dth per hour. For purposes of computing 		 the Demand Charge under Rate Schedules RE-2 and T-6, 		 the foregoing maximum daily quantity, subject to 		 adjustments as provided herein, shall constitute the 		 Contract Demand, during the respective periods to 		 which each maximum is applicable, and Customer agrees 		 to pay Company therefor as provided in the applicable 		 rate schedule.
	2. This First Amendment shall become effective on January 1, 1994. 	 	3. Except as specifically provided herein, the Agreement shall 		continue in force and affect as previously written.
Exhibit 10-21 Page 2 of 2 	 	IN WITNESS WHEREOF, this instrument is executed effective as of the 	day and year first written above.
CITY OF ROCKY MOUNT, N.C.
				 ATTEST: s/Jean M. Bailey s/Frederick E. Turnage 	 City Clerk ---------------------------- Title: Mayor
NORTH CAROLINA NATURAL GAS CORPORATION
s/Calvin B. Wells ---------------------------- Title: President
Exhibit 24 						 	 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS 		 As independent public accountants, we hereby consent to the incorporation of our reports included in this Form 10-K, into the Company's previously filed Registration Statement File No. 33-34779.
ARTHUR ANDERSEN LLP
Atlanta, Georgia December 13, 1994