UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the Transition period from to
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PIEDMONT NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
North Carolina 56-0556998
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1915 Rexford Road, Charlotte, North Carolina 28211
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (704) 364-3120
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange on
Title of each class which registered
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Common Stock, no par value New York Stock Exchange
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of January 12, 1996.
Common Stock, no par value - $614,259,271
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class Outstanding at January 12, 1996
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Common Stock, no par value 28,898,955
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Shareholders on February 23, 1996, are incorporated by reference into Part III.
PIEDMONT NATURAL GAS COMPANY, INC.
1995 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Part I. Page
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Item 1. Business 1
Item 2. Properties 5
Item 3. Legal Proceedings 6
Item 4. Submission of Matters to a Vote of Security Holders 6
Part II.
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 7
Item 6. Selected Financial Data 8
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 8
Item 8. Financial Statements and Supplementary Data 16
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 36
Part III.
Item 10. Directors and Executive Officers of the Registrant 37
Item 11. Executive Compensation 39
Item 12. Security Ownership of Certain Beneficial Owners
and Management 40
Item 13. Certain Relationships and Related Transactions 40
Part IV.
Item 14. Exhibits, Financial Statement Schedule, and
Reports on Form 8-K 41
Signatures 47
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PART I
Item 1. Business
Piedmont Natural Gas Company, Inc. (the Company), originally incorporated in 1950, is an energy and services company primarily engaged in the transportation and sale of natural gas and the sale of propane to over 588,500 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee.
The Company's utility operations serve over 540,000 natural gas customers. The Company and its non-utility subsidiaries and divisions are also engaged in acquiring, marketing and arranging for the transportation and storage of natural gas for large-volume purchasers, in retailing residential and commercial gas appliances and in the sale of propane to over 48,500 customers in the Company's three-state service area.
In the Carolinas, the service area is comprised of numerous cities, towns and communities including Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington and the Hickory area in North Carolina. In Tennessee, the service area is the metropolitan area of Nashville, including portions of eight adjoining counties. The Company's propane market is in and adjacent to its natural gas market in all three states.
Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. Such revenues totaled $505.2 million for the year ended October 31, 1995, of which 45% was from residential customers, 27% from commercial customers, 26% from industrial customers and 2% from various sources. Revenues from non-utility operations, less related costs and income taxes, are shown in the consolidated financial statements in other income. Non-utility revenues as a percentage of total revenues, including utility operations, were 8% in 1995. No single non-utility activity accounted for greater than 6% of total revenues. Income from non-utility activities as a percentage of total net income was 9% in 1995. No single non-utility activity accounted for more than 8% of net income.
The Company is principally engaged in the gas distribution industry and has no other reportable industry segments.
The Company's utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC) and the Tennessee Public Service Commission (TPSC) as to the issuance of securities, and by those commissions and by the Public Service Commission of South Carolina (PSCSC) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The Company is also subject to or affected by various federal regulations.
The Company holds non-exclusive franchises for natural gas service in all communities where required, with expiration dates from 1996 to 2044. The earliest date at which a franchise for a major service area expires is 1999. In the Company's opinion, the franchises are adequate for the operation of its gas distribution business and do not contain restrictions which are of a materially burdensome nature. In most cases, the loss of a franchise would not have a material effect on operations. The Company has never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action.
The Company's utility business and its non-utility propane activities are seasonal in nature as variations in weather conditions generally result in greater earnings during the winter months. The Company normally injects natural gas into storage during periods of warm weather (principally April 1 through October 31) for withdrawal from storage during periods of cold weather (principally November 1 through March 31) when sufficient quantities of flowing pipeline gas are not available to meet customer demand. During 1995, the amount of natural gas in storage varied from 7 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 18.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $14.1 million to $33.9 million.
The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1991 through 1995:
1995 1994 1993 1992 1991
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OPERATING REVENUES (in thousands):
Sales and Transportation:
Residential $226,071 $236,232 $217,545 $180,479 $154,945
Commercial 135,933 165,805 154,894 126,417 117,764
Industrial 133,205 165,989 173,943 146,964 133,367
Public Housing 3,475 4,082 4,087 3,963 3,736
For Resale 3,323 815 1 - -
Miscellaneous 3,216 2,431 2,290 2,079 1,736
-------- -------- -------- -------- --------
Total $505,223 $575,354 $552,760 $459,902 $411,548
======== ======== ======== ======== ========
GAS DELIVERED - DEKATHERMS (in thousands):
Residential 32,890 35,380 33,554 29,685 25,991
Commercial 22,867 28,931 28,179 25,876 23,869
Industrial 67,735 60,966 57,505 58,740 54,255
Public Housing 623 713 723 765 748
For Resale 1,478 140 192 - -
-------- ------- ------- ------- -------
Total 125,593 126,130 120,153 115,066 104,863
======== ======= ======= ======= =======
NUMBER OF CUSTOMERS BILLED (12 month average):
Residential 437,333 411,027 387,126 365,717 341,808
Commercial 57,803 56,147 54,451 52,603 50,561
Industrial 2,711 2,010 1,822 1,783 1,809
Public Housing (units) 8,785 9,834 9,268 9,964 10,403
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Total 506,632 479,018 452,667 430,067 404,581
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1995 1994 1993 1992 1991
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AVERAGE PER RESIDENTIAL CUSTOMER:
Gas Used - Dekatherms 75.21 86.08 86.67 81.17 76.04
Revenue $ 516.93 $ 574.74 $ 561.95 $ 493.49 $453.31
Revenue Per Dekatherm $6.87 $6.68 $6.48 $6.08 $5.96
COST OF GAS (in thousands):
Natural Gas Purchased $155,683 $242,609 $267,217 $211,492 $173,451
Liquefied Petroleum Gas (LPG) 60 204 - 138 55
Transportation Gas Received (Not
Delivered) (181) (616) (216) 627 187
Natural Gas Withdrawn from
(Injected into) Storage, net 6,094 4,106 (894) (10,344) 1,141
Other Storage 860 1,058 316 901 620
Other Adjustments 85,051 93,214 62,465 50,955 65,847
-------- -------- -------- -------- --------
Total $247,567 $340,575 $328,888 $253,769 $241,301
======== ======== ======== ======== ========
COST OF GAS PER DEKATHERM OF GAS SOLD $ 2.95 $ 3.29 $ 3.11 $ 2.64 $ 2.90
SUPPLY AVAILABLE FOR DISTRIBUTION - DEKATHERMS (in thousands):
Natural Gas Purchased 86,372 106,556 106,507 101,539 85,286
LPG 13 52 - 49 34
Transportation Gas 41,589 22,299 14,281 19,181 21,631
Natural Gas Withdrawn from (Injected
into) Storage, net (750) (1,646) (41) (4,072) (1,340)
Other Storage (15) 25 33 221 54
Company Use (118) (159) (171) (148) (128)
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Total 127,091 127,127 120,609 116,770 105,537
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UTILITY CAPITAL EXPENDITURES (in thousands) $100,825 $105,787 $84,242 $73,776 $68,803
GAS MAINS - MILES OF 3" EQUIVALENT 16,700 16,300 15,900 15,620 15,300
DEGREE DAYS - SYSTEM AVERAGE:
Normal 3,617 3,630 3,637 3,648 3,669
Actual 3,144 3,567 3,659 3,369 2,934
Percentage of Actual to Normal 87% 98% 101% 92% 80%
PROPANE OPERATIONS:
Revenues (in thousands) $33,414 $34,972 $32,120 $29,689 $25,226
Volumes Sold (gallons in millions) 38.4 41.3 37.2 34.1 27.8
Customers (at year end) 48,500 46,900 42,600 40,200 36,800
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During 1995, the Company delivered 125.6 million dekatherms of natural gas to its customers, of which 41.5 million dekatherms were transported for the Company's largest industrial customers. This compares with 126.1 million dekatherms delivered in 1994, of which 22.5 million dekatherms were transported.
Sales to temperature-sensitive customers, whose consumption varies with the weather, were 56.4 million dekatherms in 1995, compared with 65 million dekatherms in 1994. Weather which was 13% warmer than normal was experienced in 1995, compared with 2% warmer-than-normal weather in 1994. The Company sold or transported 67.7 million dekatherms to industrial users in 1995, compared with 61 million dekatherms in 1994. Industrial sales are the most price-sensitive of the Company's markets and are largely a function of the Company's ability to obtain reliable supplies of natural gas competitively priced with other industrial fuels.
Except as set forth below, all natural gas distributed by the Company is transported to the Company by one of five interstate pipelines, Transcontinental Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company (Tennessee Pipeline), Texas Eastern Transmission Corporation (Texas Eastern), Columbia
Gas Transmission Company (Columbia Gas) and Columbia Gulf Transmission Corporation (Columbia Gulf).
As of November 1, 1995, suppliers have contracted to provide the following daily pipeline capacity in dekatherms of natural gas:
Transco 423,200
Tennessee Pipeline 74,100
Texas Eastern 1,700
Columbia Gas (through arrangements with Transco and Columbia Gulf) 23,000
Columbia Gulf 5,000
Conoco, Inc. (limited term) (transported through Transco) 11,100
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Total 538,100
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The Company has the following additional daily peaking capacity in dekatherms of natural gas to meet the firm demands of its markets. This availability varies from 10 days to 365 days.
Liquefied natural gas 220,000
Liquefied petroleum gas 6,000
Transco 86,000
Columbia Gas 42,000
Tennessee Pipeline 55,900
Other 25,000
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Total 434,900
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The Company utilizes a "best cost" gas purchasing philosophy that seeks to purchase gas on a short- or long-term basis by weighing cost against supply security and reliability factors. Of the 86.4 million dekatherms of natural gas purchased by the Company in 1995, approximately 6% was purchased under short-term contracts of less than one year, 11% under contracts of from one to three years and 83% under contracts of over three years. The majority of these purchases was from non-pipeline sources.
The Company owns or has under contract 19.6 million dekatherms of storage capability, either in the form of underground storage or liquefied natural gas. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.
For further information on gas supply and regulation, see "Gas Supply and Rate Proceedings" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report.
Currently, approximately 36% of the Company's annual gas deliveries are being made to industrial or large commercial customers who have the capability to burn a fuel other than natural gas. The alternate fuels are primarily fuel oil or propane and, to a much lesser extent, coal or wood. The ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including governmental regulations, the availability of gas from suppliers and the price of gas as compared with alternate fuels.
Filed tariffs with the NCUC, the PSCSC and the TPSC permit the Company to reduce its filed rates to meet competition. During 1995, the Company negotiated $4.6 million of rates to industrial and large commercial customers in North Carolina and
South Carolina. The Company was able to recover these negotiated rates by purchasing and arranging interstate pipeline transportation for gas purchased at lower costs than that included in the Company's filed tariffs under procedures approved by the Federal Energy Regulatory Commission and state regulatory agencies. The ability to continue to offset revenue losses if prices of competitive fuels fall below the price of natural gas in the Company's tariffs depends on a number of factors, including the ability to obtain competitively priced gas from suppliers, the ability to obtain transportation for gas purchased from suppliers other than regulated pipelines, the ability of customers to obtain pipeline transportation for customer-owned gas and continued regulatory approval of these procedures.
Although local distribution companies, such as the Company, are generally concerned about the impact of the ability of a large commercial or industrial customer to bypass their systems, the Company does not view bypass from existing commercial and industrial customers as a major issue.
In the residential and small commercial markets, natural gas competes primarily with electricity for such uses as cooking and water heating and with electricity and fuel oil for space heating.
During 1995, the Company's largest customer contributed $11 million, or 2%, to revenues.
The amount of research and development costs incurred in connection with Company-sponsored research is immaterial. The Company contributes to gas industry-sponsored research projects; however, the amounts contributed to such projects are minimal.
Compliance with federal, state and local environmental protection laws had no material effect on capital expenditures, earnings or competitive position during 1995. For further information on environmental issues, see "Environmental Matters" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report.
As of October 31, 1995, the Company had 1,983 employees, compared with 1,968 employees as of October 31, 1994.
Item 2. Properties
The Company's properties consist primarily of distribution systems and related facilities to serve its utility customers. The Company has constructed and owns approximately 488 miles of lateral pipelines up to 16 inches in diameter which connect the distribution systems of the Company with the transmission systems of its pipeline suppliers. Natural gas is distributed through approximately 16,700 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or private property with the permission of the individual owners.
The Company either owns or leases for varying periods district and regional offices for its utility and non-utility operations.
Item 3. Legal Proceedings
There are a number of lawsuits pending against the Company for damages alleged to have been caused by negligence of the Company's employees. The Company has liability insurance which it believes is adequate to cover any material judgments which may result from these lawsuits.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters
(a) The Company's Common Stock is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices on the NYSE (symbol PNY) for each quarterly period for the years ended October 31, 1995 and 1994.
1995 High Low 1994 High Low - ---------- ---- --- ---------- ---- --- January 31 20 1/8 18 January 31 25 1/2 19 3/8 April 30 21 3/8 18 3/4 April 30 23 3/8 19 5/8 July 31 21 3/4 19 5/8 July 31 21 7/8 19 3/8 October 31 23 19 1/2 October 31 21 3/4 19 1/2 |
(b) As of January 12, 1996, the Company's Common Stock was owned by 12,442 shareholders of record.
(c) Information with respect to quarterly dividends paid on the Company's Common Stock for the years ended October 31, 1995 and 1994, is as follows:
Dividends Paid Dividends Paid
1995 Per Share 1994 Per Share
- -------- -------------- ------ --------------
January 31 26 c. January 31 24.5c.
April 30 27.5c. April 30 26 c.
July 31 27.5c. July 31 26 c.
October 31 27.5c. October 31 26 c.
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The Company's charter and note agreements under which long-term debt was issued contain provisions which restrict the amount of cash dividends that may be paid on Common Stock. As of October 31, 1995, all of the Company's retained earnings was free of such restrictions.
Item 6. Selected Financial Data
Selected financial data for the years ended October 31, 1991 through 1995, is as follows:
1995 1994 1993 1992 1991
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(in thousands except per share amounts)
Margin $257,656 $234,779 $223,872 $206,133 $170,247
Operating Revenues $505,223 $575,354 $552,760 $459,902 $411,548
Net Income $ 40,310 $ 35,506 $ 37,534 $ 35,310 $ 20,552
Earnings per Share of Common Stock $ 1.45 $ 1.35 $ 1.45 $ 1.39 $ .88
Cash Dividends Declared Per Share of
Common Stock $ 1.085 $ 1.025 $ .965 $ .91 $ .87
Average Shares of Common Stock Outstanding 27,890 26,346 25,960 25,345 23,282
Total Assets $964,895 $889,233 $797,748 $724,865 $666,490
Long-Term Debt (less current maturities) $361,000 $313,000 $278,000 $231,300 $220,525
Rate of Return on Average Common Equity 12.27% 12.10% 13.65% 14.02% 9.45%
Long-Term Debt to Capitalization Ratio 50.42% 50.89% 49.38% 46.62% 48.02%
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Liquidity and Capital Resources
The Company has committed bank lines of credit totaling $57 million to finance current cash requirements. Additional uncommitted lines are also available on an as needed, if available, basis. Borrowings under the lines include bankers' acceptances, transactional borrowings and overnight cost-plus loans based on the lending bank's cost of money, with a maximum rate of the lending bank's commercial prime interest rate. The gas distribution business is highly seasonal and requires the use of short-term debt at times to meet working capital requirements and to temporarily finance construction pending the issuance of long-term debt or equity. Borrowings against the lines of credit during 1995 ranged from zero to a high of $78 million in January.
The Company had $368 million of long-term debt outstanding at October 31, 1995. Annual sinking fund requirements and maturities of this debt are $7 million in 1996, $10 million in each of the next four years and $321 million thereafter. Long-term debt retired in 1995 totaled $5 million.
On March 28, 1995, the Company sold 1,725,000 shares of Common Stock in a public offering which resulted in net proceeds of $33.2 million. The proceeds were used for general corporate purposes, including construction of additional facilities, the repayment of short-term debt and working capital needs.
On May 16, 1995, the Company filed a shelf registration statement with the Securities and Exchange Commission for $150 million of debt securities, including $20 million from a previously filed shelf registration. On September 28, 1995, the Company sold $55 million of 7.40% Medium-Term Notes due 2025 under the shelf registration. Proceeds from the sale were used to reduce short-term debt. The notes are to be redeemed in a single payment at maturity.
At October 31, 1995, the Company's capitalization ratio consisted of 50% long-term debt and 50% common equity. The embedded cost of long-term debt at October 31, 1995, was 8.52%. The return on average common equity in 1995 was 12.27%.
Cash provided from operations and from financing was sufficient to fund investing activities, largely utility and non-utility construction, payments of debt principal and interest and dividend payments to shareholders.
Although local gas distribution companies (LDCs), such as the Company, are generally concerned about the impact of the ability of a large commercial or industrial customer to bypass their systems, the Company does not presently view bypass from existing commercial and industrial customers as a major liquidity issue.
In order to sustain its approximately 6% annual growth in customer base, the Company's capital expansion program is very important in meeting the growth in the demand for natural gas. Capital expenditures for 1995 totaled $100.8 million for utility operations and $3 million for non-utility activities. Capital expenditures totaling $98.1 million for utility operations and $3.5 million for non-utility activities are budgeted for 1996. Cash requirements to fund these expenditures and to fund interest and sinking fund payments and dividends are expected to be provided by internally generated cash, issuance of Common Stock through dividend reinvestment and stock purchase plans, short-term bank borrowings and issuance of long-term debt.
Gas Supply and Rate Proceedings
Except as set forth below, all natural gas distributed by the Company is transported to the Company by one of five interstate pipelines, Transcontinental Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company (Tennessee Pipeline), Texas Eastern Transmission Corporation (Texas Eastern), Columbia Gas Transmission Corporation (Columbia Gas) and Columbia Gulf Transmission Corporation, under tariffs regulated by the Federal Energy Regulatory Commission (FERC).
The majority of the Company's natural gas supply is purchased from sources in non-regulated transactions. The regulations under which the Company purchases and transports gas
are in various stages of litigation or appeal to the courts. The final resolution of these matters could affect the rates paid by the Company to these interstate pipelines for past and future purchases and transportation of gas, the amount of refunds to which the Company may be entitled with respect to past amounts paid and the terms under which the Company may purchase and transport gas in the future. Based on past rate recovery decisions of the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Public Service Commission (TPSC), the Company expects to recover all such gas and transportation costs in its rates.
The Company has been operating in an unbundled environment with all of its interstate pipelines for several years under FERC Order 636. This order required the interstate pipelines to price separately the gas sales, transportation and storage services provided by them and to transport gas to their customers. The Company has not experienced any major operating problems due to Order 636. In the Company's opinion, present rules and regulations of the NCUC, the PSCSC and the TPSC permit the Company to pass through to its customers any interstate pipeline capacity and storage service costs and any other costs that may be incurred under Order 636. Through 1995, the Company has recovered such costs through purchased gas adjustment procedures.
The Company is permitted to recover 100% of its prudently incurred gas costs, subject to annual prudence reviews covering an historical twelve-month period, in all three states in which the Company operates. For the latest applicable twelve-month period, the NCUC, the TPSC and the PSCSC found the Company to be prudent in its gas purchasing practices and allowed 100% recovery of its gas costs.
Certain supplier refunds attributable to North Carolina operations are being held by the Company for possible inclusion in an expansion fund as legislated by the General Assembly of North Carolina to extend natural gas service to unserved areas of the state. As ordered by the NCUC, these refunds are invested in short-term U.S. Treasury securities pending the establishment of an expansion fund. Additionally, other supplier refunds are being held by the Company for possible inclusion in an expansion fund. Such refunds, including interest earned to date, are included in restricted cash.
In September 1994, the Company filed a petition with the NCUC for a certificate of public convenience and necessity to serve four counties in North Carolina which are not presently receiving natural gas service. The Company estimated that the expansion would require capital expenditures of $57.7 million over a period of five years and would result in the addition of approximately 10,000 customers. The Company also filed an application to establish an expansion fund and place $14.8 million of supplier refunds into this fund. The Company
requested permission to use the fund to offset a portion of the cost of the construction in the four counties. Another company, not currently providing natural gas service in North Carolina or elsewhere, also filed an application to serve the four counties; however, this company did not request permission to use expansion funds.
On June 19, 1995, the NCUC granted a conditional certificate to the Company to serve the four-county area but prohibited the Company from utilizing available expansion funds. On July 10, the Company filed its exceptions to the order declining the conditional certificate and requesting that a final order be granted which would not prohibit the Company from using expansion funds. On July 20, the NCUC granted a conditional certificate to the competing applicant. On August 17, the Company gave notice of appeal and filed its exceptions to the July 20 order. Following further motions and responses by all parties involved, a hearing was held on December 12 to determine whether the conditions of the certificate were met and whether an unconditional certificate should be granted to the competing applicant. The outcome of these proceedings cannot be determined at this time.
In October 1994, the NCUC issued an order permitting the Company to increase its rates in North Carolina, effective November 1, 1994, by $5.2 million annually. In February 1995, the NCUC approved an annual increase in rates of $1.8 million to cover the Company's investment and operating costs associated with Cardinal Pipeline Company, L.L.C. See Other Matters.
In October 1994, the TPSC issued an order permitting the Company to increase its rates in Tennessee, effective October 28, 1994, by $6.8 million annually.
In November 1995, the PSCSC issued an order permitting the Company to increase its rates in South Carolina, effective November 7, 1995, by $7.8 million annually. A petition filed by the Consumer Advocate for the State of South Carolina for rehearing and reconsideration of the order was denied by the PSCSC.
Impact of Inflation
Inflation impacts the Company primarily in the prices it pays for labor, materials and services. Since the Company can adjust its rates to recover these costs only through the regulatory process, increased costs can have a significant impact on the results of operations. Under present regulatory commission orders, the Company passes on to its customers substantially all changes in the cost of gas through purchased gas adjustment procedures.
Results of Operations
Net income for 1995 was $40.3 million, compared with $35.5 million in 1994 and $37.5 million in 1993. The increase in net income in 1995, compared with 1994, was primarily due to regulatory rate changes which increased rates and updated gas cost components, partially offset by increases in operating expenses and utility interest charges. The decrease in net income in 1994, compared with 1993, was primarily due to increases in operations and maintenance expenses, general taxes and utility interest charges, partially offset by higher rates billed, increased delivered volumes to residential and industrial customers and increased earnings from propane operations. Volumes of gas delivered to customers decreased slightly to 125.6 million dekatherms in 1995, compared with 126.1 million dekatherms in 1994 and 120.2 million dekatherms in 1993. Compared with the prior year, weather in the Company's service area was 12% and 3% warmer in 1995 and 1994, respectively, and 9% colder in 1993.
Operating revenues were $505.2 million in 1995, $575.4 million in 1994 and $552.8 million in 1993. The decrease in 1995 from 1994 was primarily due to the shift from sales of gas to transportation on which there is no commodity cost included in revenues and to a net decrease in rates charged to customers. Even though general rate increases were in effect in two states for 1995, such increases were offset by decreases in the gas cost components. The average number of customers billed increased 6% in 1995 over 1994. The increase in operating revenues in 1994 over 1993 was primarily due to higher rates billed, increased delivered volumes, particularly increased sales to weather-sensitive residential and commercial customers on which a higher margin is earned, and a 6% increase in the average number of customers billed. The weather normalization adjustment mechanism (WNA) in effect in all three states is designed to offset the impact that unusually cold or warm weather has on customer billings and operating margin. The WNA has been in effect in North Carolina and Tennessee for the past four years and in South Carolina since December 1993. Weather which was 13% warmer than normal was experienced in 1995, compared with 2% warmer-than-normal weather in 1994 and 1% colder-than-normal weather in 1993.
For competitive reasons, the Company has for several years negotiated rates to industrial customers in North Carolina and South Carolina with alternate fuel capabilities. The Company has been able to offset such lower negotiated rates through decreases in the cost of gas paid to suppliers. Therefore, negotiation has resulted in reduced revenues but has not reduced margin. The Company negotiated $4.6 million of rates in 1995. The ability to offset negotiated margin reductions through savings in the cost of gas is subject to continuing regulatory approval.
Cost of gas was $247.6 million in 1995, $340.6 million in 1994 and $328.9 million in 1993. The decrease in 1995 from 1994 was primarily due to lower prices from suppliers and the shift from sales to transportation as noted above. The increase in 1994, compared with 1993, was primarily due to the increase in delivered volumes. Increases or decreases in purchased gas costs from suppliers had no significant impact on margin as they were passed on to customers or used to offset negotiated margin reductions as noted above.
Margin was $257.7 million in 1995, $234.8 million in 1994 and $223.9 million in 1993. The increase in 1995, compared with 1994, was primarily due to rate increases as well as the effect of the WNA which resulted in a surcharge of $10.4 million in 1995, compared with $100,000 in 1994. The increase in margin in 1994, compared with 1993, was primarily due to growth in the customer base and industrial customer usage as well as increased sales to weather-sensitive residential and commercial customers on which a higher margin is earned. The margin earned per dekatherm of gas delivered increased by $.19 in 1995 over 1994, and remained unchanged in 1994 from 1993.
Other operations and maintenance expenses increased from $99.5 million to $110.5 million over the three-year period 1993 to 1995. The increases were primarily due to increases in the cost of maintenance and repair of mains, rents, payroll and employee benefits.
Depreciation expense increased from $22.2 million to $31.9 million over the three-year period 1993 to 1995 due to the growth in plant in service and to increases in depreciation rates for North Carolina operations effective November 1, 1994.
General taxes increased from $24.1 million to $27.4 million over the three-year period 1993 to 1995 primarily due to increases in property taxes resulting from property tax rate increases and additions to taxable property, partially offset in 1995 by a decrease in gross receipts taxes resulting from decreased revenues.
Other income, net of income taxes, was $4.5 million in 1995, $4.2 million in 1994 and $2.9 million in 1993. The increases were primarily due to increases from year to year in the allowance for equity funds used during construction, interest earned on temporary cash investments and, for 1995, earnings from energy marketing services.
Utility interest charges were $29.5 million in 1995, $24.5 million in 1994 and $21.9 million in 1993. The increase in 1995, compared with 1994, was primarily due to increases in the balances outstanding during the year on long-term and short-term debt, higher interest rates charged on short-term debt and higher interest charged on refunds due customers. The increase in 1994,
compared with 1993, was primarily due to increases in the balances of long-term debt outstanding even though at lower overall interest rates, amortization of debt expenses due to the issuance of debt in the last two years and interest charged on refunds due customers due to greater amounts outstanding.
Environmental Matters
The Company has owned, leased or operated manufactured gas plant (MGP) facilities at 11 sites in its three-state service area. Four of these sites and a portion of two other sites are still owned by the Company and the remainder are owned by other individuals or companies. Eight of the 11 sites involve other parties who either owned the property or operated the facilities. Currently, five of the eight sites in North Carolina are on the Comprehensive Environmental Response, Compensation and Liability Act Information System target list of the Environmental Protection Agency on the recommendation of the North Carolina Department of Environment, Health, and Natural Resources (the Department). This list identifies these sites for a preliminary assessment as to the danger posed to health and the environment. The North Carolina Superfund Section is in various stages of analyses on these five sites. In June 1995, the Department placed on hold the investigation of a site in which the Company is involved which the Department had earlier placed on a priority list for investigation. The Company has not received any notification from the Department nor does it have other information which indicates significant remedial measures with respect to any of these sites. The Company has not been notified by any governmental agency in South Carolina or Tennessee with respect to MGPs in those states.
Further evaluations of the MGP sites will determine any remediation requirements and associated costs and the involvement of the Company in the sharing of these costs. The Company cannot presently determine the liability with respect to individual MGP sites since site specific evaluations have not been performed and cost-sharing arrangements with other responsible parties have not been finalized.
The Company is in the process of evaluating and remediating sites with respect to its present or former ownership of underground tanks. As of October 31, 1995, comprehensive evaluations of underground tank sites were substantially complete. Of the 11 sites in North Carolina and South Carolina, six require corrective action and varying degrees of remediation. The Department has established a trust fund which reimburses the owner or operator for the costs of evaluating and remediating the underground tank sites in North Carolina in excess of a designated variable dollar amount per site.
Based on a generic MGP site study and estimates determined in the underground storage tank comprehensive site evaluations,
the Company has increased its liability and associated regulatory asset from $1.7 million to $3.1 million for potential future environmental costs. The ultimate cost to the Company, however, will depend on the extent of contamination found as the sites are evaluated and remediated, the time period to complete the evaluation and remediation, which could be ten years or more, and the contribution to the total evaluation and remediation costs by others.
The three state regulatory commissions regulating the Company have authorized deferral accounting, or the creation of a regulatory asset, for expenditures made in connection with environmental matters. A determination as to whether or not environmental expenditures, net of recoveries from other responsible parties, will be recovered from ratepayers will be made at the appropriate time in general rate case proceedings. In North Carolina and South Carolina, current procedures permit the Company to recover 100% of its prudently incurred MGP costs but do not permit the recovery of any carrying costs on such amounts from the time the amounts are expended until the time they are collected. Based on regulatory accounting directives and the trend in the industry for regulators to permit substantial recovery of such costs, the Company believes that the resolution of these matters will not have a material adverse effect on the Company's financial position or results of operations.
Accounting Pronouncements
Effective November 1, 1994, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112). FAS 112 requires, among other things, the accrual for benefits provided to former or inactive employees after employment but before retirement and to their beneficiaries and covered dependents. Adoption of FAS 112 did not have a material impact on the Company's financial position or results of operations.
In its fiscal year beginning November 1, 1996, the Company will adopt SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (FAS 121). FAS 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Adoption of FAS 121 is not expected to have a material impact on the Company's financial position or results of operations based on the current regulatory structure in which the Company operates.
Other Matters
Piedmont Intrastate Pipeline Company, a wholly-owned subsidiary, is a 36% member of Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal
was formed in cooperation with another North Carolina utility to construct, own and operate a natural gas pipeline from a connection with an interstate pipeline to facilities owned by the Company and facilities owned by the other utility company. The pipeline began operations in January 1995. In December 1995, the two members of Cardinal, the interstate pipeline and another North Carolina utility formed a new limited liability company, Cardinal Extension Company, LLC, to purchase and extend the existing pipeline. It is anticipated that the purchase and extension, which is subject to regulatory approvals, will be project financed on a non-recourse basis with estimated costs of $97 million. It is anticipated that Piedmont Intrastate's ownership in the new limited liability company will be 17% and will not require any capital contributions beyond its current investment in Cardinal.
Piedmont Interstate Pipeline Company, a wholly-owned subsidiary, is a 35% member of Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle was formed in 1995 to construct, own and operate a liquified natural gas (LNG) peak demand facility in North Carolina. Pending FERC approval, construction of the LNG facility will begin in early 1997, to be completed in mid-1999 in time for withdrawal service in the 1999 winter heating season. The facility, estimated to cost $107 million, will be located near an interstate pipeline and will have storage capacity of four billion cubic feet with vaporization capability of 400 million cubic feet per day. The facility will provide peak demand and storage service to the Company and other customers on the interstate pipeline's system, primarily in the southeast market area. In August 1995, Pine Needle concluded an open season for subscriptions from potential customers of the facility, at which time subscriptions were received for 361 million cubic feet per day, including a subscription from the Company for 200 million cubic feet per day. Pine Needle plans to seek non-recourse project financing for the facility investment. The interstate pipeline will serve as operator and dispatch agent.
Item 8. Financial Statements and Supplementary Data
The Company's consolidated financial statements and schedules required by this Item are listed in Item 14(a)1 and 2 in Part IV of this report.
CONSOLIDATED BALANCE SHEETS
October 31, 1995 and 1994
ASSETS
1995 1994
---- ----
(in thousands)
Utility Plant:
Utility plant in service $1,045,011 $939,717
Less accumulated depreciation 273,350 243,325
---------- --------
Utility plant in service, net 771,661 696,392
Construction work in progress 29,655 38,501
---------- --------
Total utility plant, net 801,316 734,893
---------- --------
Other Physical Property, at cost (net of
accumulated depreciation of $12,869,000
in 1995 and $11,753,000 in 1994) 26,299 25,188
---------- --------
Current Assets:
Cash and cash equivalents 5,811 6,523
Restricted cash 17,948 14,961
Receivables (less allowance for doubtful
accounts of $972,000 in 1995 and
$947,000 in 1994) 21,118 22,597
Inventories:
Gas in storage 39,992 44,725
Materials, supplies and merchandise 7,463 7,401
Deferred cost of gas 3,352 5,162
Refundable income taxes 15,265 10,194
Other 6,336 5,830
---------- --------
Total current assets 117,285 117,393
---------- --------
Deferred Charges and Other Assets:
Unamortized debt expense (amortized
over life of related debt on a
straight-line basis) 3,071 2,758
Other 16,924 9,001
---------- --------
Total deferred charges and other assets 19,995 11,759
---------- --------
Total $ 964,895 $889,233
========== ========
|
See notes to consolidated financial statements.
CAPITALIZATION AND LIABILITIES 1995 1994
---- ----
(in thousands)
Capitalization:
Stockholders' equity:
Cumulative preferred stock - no par
value - 175,000 shares authorized $ - $ -
Common stock - no par value - 50,000,000
shares authorized; outstanding, 28,835,004
shares in 1995 and 26,576,543 shares in 1994 230,964 187,592
Retained earnings 124,015 114,400
-------- --------
Total stockholders' equity 354,979 301,992
Long-term debt 361,000 313,000
-------- --------
Total capitalization 715,979 614,992
-------- --------
Current Liabilities:
Current maturities of long-term debt and sinking
fund requirements 7,000 5,000
Notes payable 13,500 63,500
Accounts payable 38,303 35,903
Customers' deposits 9,589 8,496
Deferred income taxes 14,166 11,314
Taxes accrued 9,008 8,019
Refunds due customers 22,289 22,124
Other 9,803 9,687
-------- --------
Total current liabilities 123,658 164,043
-------- --------
Deferred Credits and Other Liabilities:
Unamortized federal investment tax credits 9,497 10,055
Accumulated deferred income taxes 84,320 72,158
Other 31,441 27,985
-------- --------
Total deferred credits and other liabilities 125,258 110,198
-------- --------
Total $964,895 $889,233
======== ========
|
See notes to consolidated financial statements.
STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended October 31, 1995, 1994 and 1993
1995 1994 1993
---- ---- ----
(in thousands except per share amounts)
Operating Revenues $505,223 $575,354 $552,760
Cost of Gas 247,567 340,575 328,888
-------- -------- -------
Margin 257,656 234,779 223,872
-------- -------- --------
Other Operating Expenses:
Operations 94,088 92,686 84,527
Maintenance 16,409 15,526 14,969
Depreciation 31,944 24,571 22,161
Income taxes 22,511 19,561 21,572
General taxes 27,392 26,565 24,068
-------- -------- --------
Total other operating expenses 192,344 178,909 167,297
-------- -------- --------
Operating Income 65,312 55,870 56,575
-------- -------- --------
Other Income:
Non-utility activities, net of
income taxes 3,785 3,997 2,679
Other income, net of income taxes 691 180 187
-------- -------- --------
Total other income 4,476 4,177 2,866
-------- -------- --------
Income Before Utility Interest Charges 69,788 60,047 59,441
-------- -------- --------
Utility Interest Charges:
Interest on long-term debt 26,354 23,816 21,230
Allowance for borrowed funds used
during construction (credit) (1,095) (1,272) (1,080)
Other interest 4,219 1,997 1,757
-------- -------- --------
Total utility interest charges 29,478 24,541 21,907
-------- -------- --------
Net Income $ 40,310 $ 35,506 $ 37,534
======== ======== ========
Average Shares of Common 27,890 26,346 25,960
Stock Outstanding
Earnings Per Share of Common Stock $ 1.45 $ 1.35 $ 1.45
|
See notes to consolidated financial statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended October 31, 1995, 1994 and 1993
1995 1994 1993
---- ---- ----
(in thousands)
Cash Flows from Operating Activities:
Net income $40,310 $35,506 $37,534
------- ------- -------
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation and amortization 35,712 28,366 25,313
Deferred income taxes 15,014 (4,529) 10,416
Amortization of investment
tax credits (558) (559) (577)
Allowance for funds used during
construction (1,690) (2,272) (1,738)
Other, net - - 117
Changes in assets and liabilities:
Restricted cash (2,987) (7,973) 3,842
Receivables 1,479 1,176 7,274
Inventories 4,671 (4,898) (1,705)
Deferred cost of gas 1,810 2,430 (3,714)
Other assets, net (13,651) 2,585 (16,422)
Refunds due customers 165 20,247 (6,160)
Other liabilities, net 10,610 2,324 (1,757)
-------- ------- -------
Total adjustments 50,575 36,897 14,889
-------- ------- -------
Net cash provided by operating activities 90,885 72,403 52,423
-------- ------- -------
Cash Flows from Investing Activities:
Utility construction expenditures (99,180) (103,534) (82,652)
Other (3,311) (3,867) (2,308)
-------- ------- -------
Net cash used in investing activities (102,491) (107,401) (84,960)
-------- ------- -------
Cash Flows from Financing Activities:
Increase (Decrease) in bank loans, net (50,000) 21,500 9,000
Proceeds from issuance of
long-term debt 55,000 40,000 90,000
Retirement of long-term debt (5,000) (5,000) (49,025)
Sale of common stock, net of expenses 33,023 - -
Issuance of common stock through
dividend reinvestment and
employee stock plans 8,435 8,462 7,652
Dividends paid (30,564) (26,996) (25,043)
-------- ------- -------
Net cash provided by financing
activities 10,894 37,966 32,584
-------- ------- -------
Net Increase (Decrease) in Cash and
Cash Equivalents (712) 2,968 47
Cash and Cash Equivalents at
Beginning of Year 6,523 3,555 3,508
-------- ------- -------
Cash and Cash Equivalents at End of Year $ 5,811 $ 6,523 $ 3,555
======== ======= =======
Cash Paid During the Year for:
Interest $ 27,310 $24,327 $23,833
Income taxes $ 30,087 $27,114 $22,143
|
See notes to consolidated financial statements.
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
For the Years Ended October 31, 1995, 1994 and 1993
1995 1994 1993
-------- ------- --------
(in thousands)
Balance at Beginning of Year $114,400 $105,890 $ 96,637
Net Income 40,310 35,506 37,534
-------- -------- --------
Total 154,710 141,396 134,171
-------- -------- --------
Deduct:
Dividends declared on common
stock ($1.085 a share in 1995,
$1.025 in 1994 and $.965 in 1993) 30,564 26,996 25,043
Stock split - - 3,238
Capital stock expense 131 - -
-------- -------- --------
Total 30,695 26,996 28,281
-------- -------- --------
Balance at End of Year $124,015 $114,400 $105,890
======== ======== ========
|
See notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation.
Piedmont Natural Gas Company, Inc. (the Company), an investor-owned
public utility, distributes gas to residential, commercial and industrial
customers in the Piedmont region of North Carolina and South Carolina and the
metropolitan Nashville, Tennessee, area. The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries,
Piedmont Energy Company, Piedmont Intrastate Pipeline Company, Piedmont
Interstate Pipeline Company and PNG Energy Company and its wholly-owned
subsidiary, Piedmont Propane Company. Significant intercompany transactions
have been eliminated in consolidation where appropriate.
B. Utility Plant and Depreciation.
Utility plant is stated at original cost. The cost of additions to
utility plant includes direct labor and materials, allocable overheads and an
allowance for funds used during construction (AFUDC). As prescribed in the
applicable regulatory system of accounts, AFUDC is the allowance for borrowed
and equity funds used to finance construction. The weighted average accrual
rate was 9.47% for 1995, 9.30% for 1994 and 10.52% for 1993. The portion of
AFUDC attributable to equity funds is included in other income, and the portion
attributable to borrowed funds is shown as a reduction of utility interest
charges. The costs of units of property retired are removed from utility plant
and such costs, plus removal costs, less salvage, are charged to accumulated
depreciation.
Depreciation expense is computed using the straight-line method applied to average depreciable costs. The ratio of depreciation provisions to average depreciable property balances was 3.29% for 1995, 2.79% for 1994 and 2.77% for 1993.
C. Inventories.
Inventories are maintained on the basis of the average cost charged
thereto.
D. Deferred Purchased Gas Adjustment.
The Company's rate schedules include purchased gas adjustment
provisions that permit the recovery of purchased gas costs. The purchased gas
adjustment factor is revised periodically without formal rate proceedings to
reflect changes in the cost of purchased gas. Charges to cost of gas are
based on the amount recoverable under approved rate schedules. The net of any
over or under recovered amounts is included in refunds due customers.
E. Income Taxes.
Deferred income taxes are provided for differences between book and
tax income, principally attributable to accelerated tax depreciation, the
recording of revenues and cost of gas and accrued long-term incentive
compensation. Investment tax credits allowed on certain qualified property
were deferred and are being amortized to income over the estimated useful life
of the related property.
F. Operating Revenues.
The Company recognizes revenues from meters read on a monthly cycle
basis which results in unrecognized revenue from the cycle date through month
end. The cost of gas delivered to customers but not yet billed under the cycle
billing method is deferred.
G. Earnings Per Share.
Earnings per share are computed based on the weighted average number
of shares of Common Stock outstanding during each year.
H. Regulation.
Certain income, expense and capital items may be treated differently
for ratemaking purposes by the state regulatory commissions which establish
rates charged to customers.
I. Statement of Cash Flows.
For purposes of reporting cash flows, the Company considers all highly
liquid debt instruments purchased with an original maturity of three months or
less to be cash equivalents.
J. Segment Reporting.
The Company is principally engaged in the gas distribution industry
and has no other reportable industry segments.
K. Reclassifications.
Certain financial statement items for 1994 and 1993 have been
reclassified to conform with the 1995 presentation.
2. Regulatory Matters
The Company's utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC) and the Tennessee Public Service Commission (TPSC) as to the issuance of securities, and by those commissions and by the Public Service Commission of South Carolina (PSCSC) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation.
The Company has been operating in an unbundled environment with all of its interstate pipelines for several years under Federal Energy Regulatory Commission (FERC) Order 636. This order required the interstate pipelines to price separately the gas sales, transportation and storage services provided by them and to transport gas to their customers. The Company has not experienced any major operating problems due to Order 636. In the Company's opinion, present rules and regulations of the NCUC, the PSCSC and the TPSC permit the Company to pass through to its customers any interstate pipeline capacity and storage service costs and any other costs that may be incurred under Order 636. Through 1995, the Company has recovered such costs through purchased gas adjustment procedures.
Certain supplier refunds attributable to North Carolina operations are being held by the Company for possible inclusion in an expansion fund as legislated by the General Assembly of
North Carolina to extend natural gas service to unserved areas of the state. As ordered by the NCUC, these refunds are invested in short-term U.S. Treasury securities pending the establishment of an expansion fund. Additionally, other supplier refunds are being held by the Company for possible inclusion in an expansion fund. Such refunds, including interest earned to date, are included in restricted cash.
In 1994, the Company filed a petition with the NCUC for a certificate of public convenience and necessity to serve four counties in North Carolina which are not presently receiving natural gas service and an application to establish an expansion fund and place $14,800,000 of supplier refunds into the fund for such expansion. The Company estimated capital requirements totaling $57,700,000 over a five-year period and the addition of approximately 10,000 customers. A similar application to serve these counties was filed by a company not currently operating in North Carolina; however, this company did not request permission to use expansion funds. In June 1995, the NCUC granted a conditional certificate to the Company to serve the four-county area but prohibited the Company from utilizing available expansion funds. In July, the Company refused to accept the condition and the NCUC granted a conditional certificate to the competing applicant. Following further motions and responses by all parties involved, a hearing was held on December 12 to determine whether the conditions of the certificate were met and whether an unconditional certificate should be granted to the competing applicant. The outcome of these proceedings cannot be determined at this time.
In October 1994, the NCUC issued an order permitting the Company to increase its rates in North Carolina, effective November 1, 1994, by $5,200,000 annually. In February 1995, the NCUC approved an annual increase in rates of $1,800,000 to cover the Company's investment and operating costs in Cardinal Pipeline Company, L.L.C. See Note 8.
In October 1994, the TPSC issued an order permitting the Company to increase its rates in Tennessee, effective October 28, 1994, by $6,800,000 annually.
In November 1995, the PSCSC issued an order permitting the Company to increase its rates in South Carolina, effective November 7, 1995, by $7,800,000 annually. A petition filed by the Consumer Advocate for the State of South Carolina for rehearing and reconsideration of the order was denied by the PSCSC.
In its fiscal year beginning November 1, 1996, the Company will adopt Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (FAS 121). FAS 121 imposes stricter criteria for regulatory assets by requiring that such
assets be probable of future recovery at each balance sheet date. Adoption of FAS 121 is not expected to have a material impact on the Company's financial position or results of operations based on the current regulatory structure in which the Company operates.
3. Long-Term Debt
Long-term debt at October 31, 1995 and 1994, is summarized as follows:
1995 1994
---- ----
(in thousands)
Senior Notes:
9.19%, due 2001 $30,000 $30,000
10.02%, due 2003 32,000 34,000
10.06%, due 2004 17,000 18,000
10.11%, due 2004 34,000 36,000
9.44%, due 2006 35,000 35,000
8.51%, due 2017 35,000 35,000
Medium-Term Notes:
6.23%, due 2003 45,000 45,000
6.87%, due 2023 45,000 45,000
8.45%, due 2024 40,000 40,000
7.40%, due 2025 55,000 -
-------- --------
Total 368,000 318,000
Less current maturities 7,000 5,000
-------- --------
Total $361,000 $313,000
======== ========
|
Annual sinking fund requirements and maturities through 2000 are $7,000,000 in 1996 and $10,000,000 in 1997 through 2000.
On September 28, 1995, the Company sold $55,000,000 of 7.40% Medium-Term Notes due 2025 under a shelf registration. Proceeds from the sale were used to reduce short-term debt. The notes are to be redeemed in a single payment at maturity.
The Company's charter and note agreements under which the Company's long-term debt was issued contain provisions which restrict the amount of cash dividends that may be paid on Common Stock. At October 31, 1995, all of the Company's retained earnings was free of such restrictions.
4. Capital Stock
The changes in Common Stock for the years ended October 31, 1993, 1994 and 1995, are summarized as follows:
Shares Amount
-------- --------
(in thousands except shares data)
Balance, October 31, 1992 25,795,924 $168,253
Issue to Employee Stock Purchase
Plan (SPP) 24,862 474
Issue to Dividend Reinvestment and
Stock Purchase Plan (DRIP) 331,568 7,178
Stock Split (excluding $13,000
applicable to SPP and DRIP prior
to the split) - 3,225
---------- --------
Balance, October 31, 1993 26,152,354 179,130
Issue to SPP 28,630 524
Issue to DRIP 395,559 7,938
---------- --------
Balance, October 31, 1994 26,576,543 187,592
Issue to SPP 29,133 523
Issue to DRIP 409,860 7,912
Public Offering 1,725,000 33,154
Issue to Participants in the
Long-Term Incentive Plan 94,468 1,783
---------- --------
Balance, October 31, 1995 28,835,004 $230,964
========== ========
|
At October 31, 1995, 1,729,812 shares of Common Stock were reserved for issuance as follows:
SPP 298,289
DRIP 275,441
Long-Term Incentive Plan 1,156,082
---------
Total 1,729,812
=========
|
5. Financial Instruments and Related Fair Value
The Company has committed bank lines of credit totaling $57,000,000 to finance current cash requirements. Additional uncommitted lines are also available on an as needed, if available, basis. Borrowings under the lines, with maturity dates of less than 90 days, include bankers' acceptances, transactional borrowings and overnight cost-plus loans based on the lending bank's cost of money, with a maximum rate of the lending bank's commercial prime interest rate. At October 31, 1995, the lines of credit were on either a fee basis or compensating balance basis, with average annual balance requirements of $600,000.
At October 31, 1995, outstanding notes payable consisted of $10,000,000 in bankers' acceptances and $3,500,000 in overnight cost-plus loans. The weighted average interest rate on such borrowings was 5.94%.
The Company's principal business activity is the sale and transportation of natural gas to customers located in North Carolina, South Carolina and Tennessee. At October 31, 1995, gas receivables totaled $12,986,000 and other receivables totaled $9,104,000. The uncollected balance of installment receivables transferred with recourse in 1992 was $22,147,000 and $22,138,000 at October 31, 1995 and 1994, respectively. The Company has provided an adequate allowance for any receivables which may not be ultimately collected, including the receivables transferred with recourse.
In October 1995, the Company transferred an additional $5,000,000 of its installment receivables from merchandise activities to a major financial institution in a transaction that was accounted for as a sale under SFAS No. 77, "Reporting by Transferors for Transfers of Receivables with Recourse."
The following estimated fair values of financial instruments have been determined using available market information and commonly accepted valuation methodologies. Judgment is necessary in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions or estimation methodologies may have a material effect on the estimated fair values. The estimated fair values of the Company's financial instruments at October 31, 1995 and 1994, are as follows:
1995 1994
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- ------
(in thousands)
Cash and cash
equivalents (1) $ 5,811 $ 5,811 $ 6,523 $ 6,523
Restricted cash (1) 17,948 17,948 14,961 14,961
Receivables (1) 21,118 21,118 22,597 22,597
Long-term debt (2) 368,000 426,529 318,000 310,479
Notes payable (1) 13,500 13,500 63,500 63,500
Accounts payable (1) 38,303 38,303 35,903 35,903
|
(1) The carrying amount in the consolidated balance sheets approximates fair value because of the short maturity of these instruments.
(2) The fair value is estimated by discounting the future cash flows using the current rates at which similar loans would be made to borrowers with similar credit ratings and for the same remaining maturities.
6. Employee Benefit Plans
The Company has a defined-benefit pension plan for the benefit of substantially all full-time regular employees of the
Company and its subsidiaries. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement during which the participant received his or her highest compensation. It is the Company's policy to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes under applicable federal regulations. Plan assets consist primarily of marketable securities with a minor investment in commercial real estate and cash equivalents.
The plan is amended from time to time in accordance with changes in tax law. The unrecognized prior service costs, if any, resulting from such amendments are amortized over the average remaining service life of active employees.
A reconciliation of the funded status of the plan to the amounts recognized in the consolidated financial statements at October 31, 1995 and 1994, is presented below:
1995 1994
---- ----
(in thousands)
Actuarial present value of benefit obligations:
Vested benefit obligation $ 64,217 $ 50,765
========= ========
Accumulated benefit obligation $ 70,840 $ 57,548
========= ========
Projected benefit obligation for services
rendered to date $(103,867) $(86,004)
Plan assets at fair value 104,520 91,796
--------- --------
Plan assets in excess of projected
benefit obligation 653 5,792
Unrecognized net gain from past experience
different from that assumed and effects
of changes in assumptions (10,157) (15,239)
Prior service cost not recognized in
net periodic pension cost 4,639 5,055
Remaining unrecognized net obligation at date
of initial adoption 120 136
--------- -------
Accrued pension cost $ (4,745) $(4,256)
========= =======
|
Net periodic pension cost, excluding trustee fees and other expenses, for the years ended October 31, 1995, 1994 and 1993, includes the following components:
1995 1994 1993
---- ---- ----
(in thousands)
Service cost $4,212 $4,475 $3,974
Interest cost 6,704 6,359 6,599
Return on plan assets (19,009) (161) (11,666)
Net asset gain (loss) deferred 10,544 (7,105) 4,659
Other 358 432 454
------ ------ ------
Net periodic pension cost $2,809 $4,000 $4,020
====== ====== ======
|
Actuarial assumptions used were:
Weighted average discount rate 6.75% 7.75% 6.75%
Rate of increase in future compensation
levels 5.0 % 5.5 % 5.0 %
Expected long-term rate of return 9.5 % 8.5 % 8.5 %
|
The Company provides certain postretirement health care and life insurance benefits to substantially all full-time regular employees of the Company and its subsidiaries. Effective November 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (FAS 106). Prior to adoption, the costs of such benefits, which were $946,000 in 1993, were currently expensed as health care claims and premiums for health and life insurance were paid. As of October 31, 1995, the liability associated with such benefits was funded in irrevocable trust funds which can only be used to pay the benefits.
A reconciliation of the funded status of the plan to the amount recognized in the consolidated financial statements at October 31, 1995 and 1994, is presented below:
1995 1994
---- ----
(in thousands)
Accumulated postretirement benefit obligation:
Retirees $(9,043) $(7,510)
Fully eligible active plan participants (6,094) (6,570)
Other active plan participants (4,271) (3,343)
------ ------
Total (19,408) (17,423)
Plan assets at fair value 2,763 2,027
------ ------
Accumulated postretirement benefit obligation
in excess of plan assets (16,645) (15,396)
Unrecognized net gain from past experience
different from that assumed and from changes
in assumptions (995) (2,272)
Unrecognized transition obligation 16,738 17,668
------ ------
Prepaid postretirement benefit cost $ (902) $ -
====== ======
|
Net periodic postretirement benefit cost for the years ended October 31, 1995 and 1994, includes the following components:
1995 1994
---- ----
(in thousands)
Service cost $ 578 $ 600
Interest cost 1,405 1,335
Return on plan assets (226) -
Amortization of transition obligation 930 975
Other (24) -
------ ------
Net periodic postretirement benefit cost $2,663 $2,910
====== ======
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The weighted average discount rate used in determining the accumulated postretirement benefit obligation at October 31, 1995 and 1994, was 7.25% and 8%, respectively. The weighted average rate of return on plan assets at October 31, 1995 and 1994, was 8% and 8.5%, respectively. The average assumed annual rate of salary increase for the applicable life insurance plans at October 31, 1995 and 1994, was 5% and 5.5%, respectively. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation for the medical plans is 10.25% for 1996, declining gradually to 5.25% in 2005 and remaining at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage point increase in the assumed health care cost trend rate would increase the accumulated postretirement benefit obligation at October 31, 1995, by $1,888,000 and the aggregate of the service and interest cost components of net periodic postretirement benefit cost by $133,000.
The Company is recovering FAS 106 costs, including amounts previously deferred, from ratepayers in North Carolina and Tennessee, effective in November 1994, and in South Carolina, effective November 7, 1995, pursuant to rate orders in general rate proceedings.
The Company maintains salary investment plans which are profit sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), and which include qualified cash or deferred arrangements under Tax Code Section 401(k). Employees of the Company and its affiliated companies who have completed six months of service are eligible to participate. Participants are permitted to defer a portion of their base salary to the plans, with the Company matching a portion of the participants' contributions. All contributions vest immediately. For the years ended October 31, 1995, 1994 and 1993, the Company contributed $1,932,000, $1,824,000 and $1,674,000, respectively, to the plans.
Effective November 1, 1994, the Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112). FAS 112 requires, among other things, the accrual for benefits provided to former or inactive employees after employment but before retirement and to their beneficiaries and covered dependents. Adoption of FAS 112 did not have a material impact on the Company's financial position or results of operations.
7. Income Taxes
The components of income tax expense for the years ended October 31, 1995, 1994 and 1993, are as follows:
1995 1994 1993
---- ---- ----
Federal State Federal State Federal State
------- ----- ------- ----- ------- -----
(in thousands)
Income taxes charged
to operations:
Current $ 6,809 $1,886 $14,224 $3,213 $10,131 $2,017
Deferred 12,176 2,198 2,334 349 8,080 1,921
Amortization of
investment tax
credits (558) - (559) - (577) -
------- ----- ------- ------ ------- -----
Total 18,427 4,084 15,999 3,562 17,634 3,938
------- ----- ------- ------ ------- -----
Income taxes charged
to other income:
Current 1,937 353 1,765 446 1,108 332
Deferred 485 155 (524) 159 354 61
------- ----- ------- ------ ------- ------
Total 2,422 508 1,241 605 1,462 393
------- ----- ------- ------ ------- ------
Total income tax
expense $20,849 $4,592 $17,240 $4,167 $19,096 $4,331
======= ====== ======= ====== ======= ======
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A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 1995, 1994 and 1993, is as follows:
1995 1994 1993
---- ---- ----
(in thousands)
Federal taxes at 35% for 1995
and 1994 and 34.83% for 1993 $23,013 $19,920 $21,233
State income taxes, net of
federal benefit 2,987 2,709 2,823
Amortization of investment tax credits (558) (559) (577)
Implementation of FAS 109 for
non-regulated subsidiaries - (723) -
Other, net (1) 60 (52)
------- ------- ------
Total income tax expense $25,441 $21,407 $23,427
======= ======= =======
|
Effective November 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes" (FAS 109), on a prospective basis. FAS 109 requires a liability approach for financial accounting and reporting of income taxes. While classification of certain items in the consolidated balance sheets has changed, principally due to deferred taxes recorded at higher historical tax rates, there was no material effect on the Company's results of operations.
At October 31, 1995 and 1994, deferred income tax balances consisted of the following temporary differences:
1995 1994
---- ----
(in thousands)
Excess of tax over book depreciation and tax and
book asset basis differences $93,820 $83,748
Revenues and cost of gas 14,498 11,876
Long-term incentive plan (2,962) (3,885)
Alternative minimum tax (2,469) (3,637)
Regulatory asset related to FAS 109 tax gross-up (4,861) (5,122)
Other, net 460 492
------ -------
Net deferred income taxes $98,486 $83,472
======= =======
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Total deferred income tax liabilities were $116,022,000 and $95,972,000 and total deferred income tax assets were $17,536,000 and $12,500,000 at October 31, 1995 and 1994, respectively.
Although realization is not assured, management believes it more likely than not that all of the deferred tax assets will be realized. As such, a valuation allowance is not considered necessary.
The components of the deferred income tax provision for the year ended October 31, 1993, are summarized as follows (in thousands):
Excess of tax over book depreciation $ 7,635
Revenues and cost of gas 2,693
Long-term incentive plan (1,498)
Alternative minimum tax 459
Other, net 1,127
-------
Total deferred provisions $10,416
=======
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8. Subsidiary and Non-Utility Activities
Piedmont Energy Company is a 51% member of Resource Energy Services Company, L.L.C. (Resource Energy), a North Carolina limited liability company. Resource Energy offers natural gas acquisition, transportation and storage services to industrial users and other utilities. For several years, PNG Energy Company acquired and marketed natural gas for the Company's system supply and other natural gas distribution companies. PNG Energy also acted as an agent for several of the Company's large industrial customers to arrange for the purchase and transportation of natural gas. Such activities are now being conducted primarily by Resource Energy. Revenues earned by the Company for transporting this gas for its utility customers are included in utility operating revenues.
Piedmont Intrastate Pipeline Company is a 36% member of Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal was formed in cooperation with another North Carolina utility to construct, own and operate a natural gas pipeline from a connection with an interstate pipeline to facilities owned by the Company and facilities owned by the other utility company. The pipeline began operations in January 1995. In December 1995, the two members of Cardinal, the interstate pipeline and another North Carolina utility formed a new limited liability company, Cardinal Extension Company, LLC,
to purchase and extend the existing pipeline. It is anticipated that the purchase and extension, which is subject to regulatory approvals, will be project financed on a non-recourse basis with estimated costs of $97,000,000. It is anticipated that Piedmont Intrastate's ownership in the new limited liability company will be 17% and will not require any capital contributions beyond its current investment in Cardinal. Because the Company's investment in Cardinal is treated as utility assets for ratemaking purposes, the Company includes its share of the assets and operations of Cardinal in utility operations.
Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle was formed in 1995 to construct, own and operate a liquified natural gas (LNG) peak demand facility in North Carolina. Pending FERC approval, construction of the LNG facility will begin in early 1997, to be completed in mid-1999 in time for withdrawal service in the 1999 winter heating season. The facility, estimated to cost $107,000,000, will be located near an interstate pipeline and will have storage capacity of four billion cubic feet with vaporization capability of 400 million cubic feet per day. The facility will provide peak demand and storage service to the Company and other customers on the interstate pipeline's system, primarily in the southeast market area. In August 1995, Pine Needle concluded an open season for subscriptions from potential customers of the facility, at which time subscriptions were received for 361 million cubic feet per day, including a subscription from the Company for 200 million cubic feet per day. Pine Needle plans to seek non-recourse project financing for the facility investment. The interstate pipeline will serve as operator and dispatch agent.
Piedmont Propane Company, through various operating divisions, markets propane and propane appliances to residential, commercial and industrial customers within and adjacent to the Company's three-state natural gas service area.
The Company is also engaged in various other non-utility activities, including the sale and financing of gas appliances and jobbing work performed on customer-owned property.
Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. Non-utility revenues as a percentage of total revenues, including utility operations, were 8% in 1995, 1994 and 1993. No single non-utility activity accounted for greater than 6% of total revenues in any year. Income from non-utility activities as a percentage of total net income was 9% in 1995, 12% in 1994 and 7% in 1993. No single non-utility activity accounted for more than 8% of net income in any year.
9. Environmental Matters
The Company has owned, leased or operated manufactured gas plant (MGP) facilities at 11 sites in its three-state service area. Four
of these sites and a portion of two other sites are still owned by the Company and the remainder are owned by other individuals or companies. Eight of the 11 sites involve other parties who either owned the property or operated the facilities. Currently, five of the eight sites in North Carolina are on the Comprehensive Environmental Response, Compensation and Liability Act Information System target list of the Environmental Protection Agency on the recommendation of the North Carolina Department of Environment, Health, and Natural Resources (the Department). This list identifies these sites for a preliminary assessment as to the danger posed to health and the environment. The North Carolina Superfund Section is in various stages of analyses on these five sites. In June 1995, the Department placed on hold the investigation of a site in which the Company is involved which the Department had earlier placed on a priority list for investigation. The Company has not received any notification from the Department nor does it have other information which indicates significant remedial measures with respect to any of the other sites. The Company has not been notified by any governmental agency in South Carolina or Tennessee with respect to MGP sites in those states.
Further evaluations of the MGP sites will determine any remediation requirements and associated costs and the involvement of the Company in the sharing of these costs. The Company cannot presently determine the liability with respect to individual MGP sites since site specific evaluations have not been performed and cost-sharing arrangements with other responsible parties have not been finalized.
The Company is in the process of evaluating and remediating sites with respect to its present or former ownership of underground tanks. As of October 31, 1995, comprehensive evaluations of underground tank sites were substantially complete. Of the 11 sites in North Carolina and South Carolina, six require corrective action and varying degrees of remediation. The Department has established a trust fund which reimburses the owner or operator for the costs of evaluating and remediating the underground tank sites in North Carolina in excess of a designated variable dollar amount per site.
Based on a generic MGP site study and estimates determined in the underground storage tank comprehensive site evaluations, the Company has increased its liability and associated regulatory asset from $1,670,000 to $3,120,000 for potential future environmental costs. The ultimate cost to the Company, however, will depend on the extent of contamination found as the sites are evaluated and remediated, the time period to complete the evaluation and remediation, which could be ten years or more, and the contribution to the total evaluation and remediation costs by others.
The three state regulatory commissions regulating the Company have authorized deferral accounting, or the creation of a regulatory asset, for expenditures made in connection with environmental matters. A determination as to whether or not environmental expenditures, net of recoveries from other responsible parties, will be recovered from ratepayers will be made at the appropriate time in general rate case proceedings. In North Carolina and South Carolina,
current procedures permit the Company to recover 100% of its prudently incurred MGP costs but do not permit the recovery of any carrying costs on such amounts from the time the amounts are expended until the time they are collected. Based on regulatory accounting directives and the trend in the industry for regulators to permit substantial recovery of such costs, the Company believes that the resolution of these matters will not have a material adverse effect on the Company's financial position or results of operations.
INDEPENDENT AUDITORS' REPORT
Piedmont Natural Gas Company, Inc.
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the Company) as of October 31, 1995 and 1994, and the related statements of consolidated income, retained earnings and cash flows for each of the three years in the period ended October 31, 1995. Our audits also included the supplemental consolidated financial statement schedule listed in Item 14. These financial statements and consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at October 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 1995 in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP Charlotte, North Carolina December 15, 1995 |
QUARTERLY FINANCIAL DATA
Quarterly financial data for the years ended October 31, 1995 and 1994, is summarized as follows:
Earnings
Operating Operating Net Per Share of
Revenues Margin Income Income Common Stock
- -----------------------------------------------------------------------
(in thousands except per share amounts)
1995
- ----
January 31 $202,476 $97,769 $35,370 $30,233 $1.13
April 30 $179,391 $87,840 $30,280 $24,026 $ .87
July 31 $ 61,649 $35,202 $ (703) $(8,825) $(.31)
October 31 $ 61,707 $36,845 $ 365 $(5,124) $(.18)
1994
- ----
January 31 $233,108 $87,489 $30,630 $27,743 $1.06
April 30 $204,810 $81,987 $27,975 $22,988 $ .87
July 31 $ 70,641 $32,472 $ (468) $(7,239) $(.27)
October 31 $ 66,795 $32,831 $(2,267) $(7,986) $(.30)
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The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions generally result in greater earnings during the winter months. Earnings per share are calculated based on the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information required under this item with respect to directors is contained in the Company's proxy statement filed with the Securities and Exchange Commission (SEC) on or about January 23, 1996, and is incorporated herein by reference.
The names, ages and positions of all of the executive officers of the Company as of October 31, 1995, are listed below along with their business experience during the past five years.
So far as practicable, all elected officers are elected at the first meeting of the Board of Directors held following the annual meeting of shareholders in each year and hold office until the meeting of the Board of Directors following the annual meeting of shareholders in the next subsequent year and until their respective successors are elected and qualify. All other officers hold office during the pleasure of the Board of Directors. There are no family relationships among these officers. There are no arrangements or understandings between any officer and any other person pursuant to which the officer was selected except for employment agreements with Messrs. Maxheim and Denny.
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
John H. Maxheim, 61 Elected in 1984.
Chairman of the Board, President
and Chief Executive Officer
Ware F. Schiefer, 57 Elected February 1995.
Executive Vice President Prior to his election, he was Senior Vice President-
Marketing and Gas Supply.
David J. Dzuricky, 44 Elected in June 1995.
Senior Vice President-Finance From 1993 until his election, he was Vice President
and Treasurer of Consolidated Natural Gas Company,
Pittsburgh, Pennsylvania. From 1992 to 1993, he was
Vice President and Treasurer of Virginia Natural Gas
Company, Norfolk, Virginia. Prior to 1992,
|
he was Vice President, Treasurer and Controller of
that company.
Ray B. Killough, 47 Elected in 1993. Prior to his election,
Senior Vice President-Operations he was Vice President-Engineering.
Thomas E. Skains, 39 Elected in February 1995, effective April 1995.
Senior Vice President-Gas Supply Prior to his election, he was Senior Vice President,
Transportation and Customer Services, for
Transcontinental Gas Pipe Line Corporation, Houston, Texas.
Ted C. Coble, 52 Elected in 1982.
Vice President and Treasurer, and
Assistant Secretary
Stephen D. Conner, 47 Elected in 1990.
Vice President-Corporate
Communications
J. William Denny, 60 Elected in 1985.
Vice President-Nashville Division;
President of the Nashville
Gas Company Division
Charles W. Fleenor, 45 Elected in 1987.
Vice President-Gas Supply
Paul C. Gibson, 56 Elected in 1986.
Vice President-Rates
Barry L. Guy, 51 Elected in 1986.
Vice President and Controller
Donald F. Harrow, 40 Elected in 1992. Prior to his election,
Vice President-Governmental Relations he was Director-Governmental Relations.
Dale C. Hewitt, 50 Elected in 1993. Prior to his election,
Vice President-North Carolina he was District Manager of the Company's
Operations Greensboro, North Carolina, operations.
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William L. Lindner, 64 Elected in 1973.
Vice President-Technology
Kevin M. O'Hara, 37 Elected in 1993. Prior to
Vice President-Corporate Planning his election, he was Director-Information Services
Plans and Controls.
William R. Pritchard, Jr., 52 Elected in 1986.
Vice President-Information
Services
Ralph P. Stewart, 55 Elected in 1986.
Vice President-Employee Relations
Bartlett C. Winkler, 59 Elected in 1992. Prior to
Vice President-Marketing his election, he was Vice President-Residential and
Commercial Sales.
William D. Workman, III, 55 Elected in December 1993,
Vice President-South Carolina effective January 1994.
Operations Prior to his election, he was Senior Director for
Facilities and Civic Affairs for Fluor Daniel, Inc.,
Greenville, South Carolina.
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Item 11. Executive Compensation
Information required under this item is contained in the Company's proxy statement filed with the SEC on or about January 23, 1996, and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
(a) Security Ownership of Certain Beneficial Owners
Information with respect to security ownership of certain beneficial owners is contained in the Company's proxy statement filed with the SEC on or about January 23, 1996, and is incorporated herein by reference.
(b) Security Ownership of Management
Information with respect to security ownership of directors and officers is contained in the Company's proxy statement filed with the SEC on or about January 23, 1996, and is incorporated herein by reference.
(c) Changes in Control
The Company knows of no arrangements or pledges which may result in a change in control.
Item 13. Certain Relationships and Related Transactions
Information with respect to certain transactions with directors is contained in the Company's proxy statement filed with the SEC on or about January 23, 1996, and is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) 1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company and its subsidiaries and the related independent auditors' report for the year ended October 31, 1995, are included in Item 8 of this report as follows:
Page
----
Consolidated Balance Sheets - October 31, 1995 and 1994 17
Statements of Consolidated Income - Years Ended
October 31, 1995, 1994 and 1993 19
Statements of Consolidated Cash Flows - Years Ended
October 31, 1995, 1994 and 1993 20
Statements of Consolidated Retained Earnings - Years
Ended October 31, 1995, 1994 and 1993 21
Notes to Consolidated Financial Statements 22
Independent Auditors' Report 35
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(a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
Page
----
II Valuation and Qualifying Accounts 49
|
Schedules other than those listed above and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.
(a) 3. EXHIBITS
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, the Company will provide a copy of the exhibit at a nominal charge.
3.1 Copy of Articles of Incorporation of the Company, filed in the Department of State of the State of North Carolina on December 13, 1993 (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994).
3.2 Copy of By-Laws of the Company as amended (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994).
4.1 Copy of Note Agreement, dated as of August 30, 1988, between the Company and Jefferson-Pilot Life Insurance Company, et al (Exhibit 4.26, Form 10-K for the fiscal year ended October 31, 1988).
4.2 Copy of Note Agreement, dated as of June 15, 1989, between the Company and The Mutual Life Insurance Company of New York (Exhibit 4.27, Form 10-K for the fiscal year ended October 31, 1989).
4.3 Copy of Note Agreement, dated as of August 31, 1989, between the Company and Teachers Insurance and Annuity Association of America (Exhibit 4.28, Form 10-K for the fiscal year ended October 31, 1989).
4.4 Copy of Note Agreement, dated as of July 30, 1991, between the Company and The Prudential Insurance Company of America (Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 1991).
4.5 Copy of Note Agreement, dated as of September 21, 1992, between the Company and Provident Life and Accident Insurance Company (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).
4.6 Copy of Indenture, dated as of April 1, 1993, between the Company and Citibank, N.A., Trustee (Exhibit 4.1, Registration Statement No. 33-60108).
4.7 Copy of Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7, Form 10-K for the fiscal year ended October 31, 1993).
4.8 Copy of Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
4.9 Copy of Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.10 Copy of Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995.
10.1 Copy of Employment Agreement between Tennessee Natural
Resources, Inc., and J. William Denny, dated April 27, 1984
(Exhibit 10.17, Registration Statement No. 33-4767).
10.2 Copy of the Company's Executive Long-Term Incentive Plan, as
amended through December 2, 1994 (Exhibit 10.3, Form 10-K
for the fiscal year ended October 31, 1994).
10.3 Copy of Employment Agreement between the Company and John H.
Maxheim, dated February 26, 1993 (Exhibit 10.4, Form 10-K
for the fiscal year ended October 31, 1993).
10.4 Copy of Articles of Organization of Cardinal Pipeline
Company, L.L.C., dated April 5, 1994 (Exhibit 10.1, Form
10-Q for the quarterly period ended April 30, 1994).
10.5 Copy of Operating Agreement of Cardinal Pipeline Company,
L.L.C., dated March 23, 1994 (Exhibit 10.2, Form 10-Q for
the quarterly period ended April 30, 1994).
10.6 Copy of Construction, Operating and Management Agreement by
and between Public Service Company of North Carolina, Inc.
and Cardinal Pipeline Company, L.L.C., dated March 23, 1994
(Exhibit 10.3, Form 10-Q for the quarterly period ended
April 30, 1994).
10.7 Copy of Service Agreement under Rate Schedule LG-A, dated
January 15, 1971, between the Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 67, Registration
Statement No. 2-59631).
10.8 Copy of Firm Seasonal Gas Transportation Agreement (Southern
Expansion, FT 53,000 mcf), dated June 29, 1990, between the
Company and Transcontinental Gas Pipe Line Corporation
(Exhibit 10.25, Form 10-K for the fiscal year ended October
31, 1990).
10.9 Copy of Service Agreement (5,900 Mcf per day), dated August
1, 1991, between the Company and Transcontinental Gas Pipe
Line Corporation (Exhibit 10.20, Form 10-K for the fiscal
year ended October 31, 1991).
10.10 Copy of Service Agreement under Rate Schedule WSS, dated
August 1, 1991, between the Company and Transcontinental Gas
Pipe Line Corporation.
10.11 Copy of Service Agreement (6,222 Mcf per day), dated August
1, 1991, between the Company and Transcontinental Gas Pipe
Line Corporation (Exhibit 10.16, Form 10-K for the fiscal
year ended October 31, 1992).
|
10.12 Copy of Service Agreement Rate Schedule FS (20,000 Mcf per
day), dated August 1, 1991, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.17,
Form 10-K for the fiscal year ended October 31, 1992)
10.13 Copy of Service Agreement Rate Schedule FS (43,640 Mcf per
day), dated August 1, 1991, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.18,
Form 10-K for the fiscal year ended October 31, 1992).
10.14 Copy of Gas Transportation Agreement (FT, 24,505 Mcf per
day, NIPPS), dated January 30, 1992, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.19,
Form 10-K for the fiscal year ended October 31, 1992).
10.15 Copy of Service Agreement (FT, 205,200 Mcf per day), dated
February 1, 1992, between the Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10.20, Form 10-K for the
fiscal year ended October 31, 1992).
10.16 Copy of Service Agreement (FT-NT, 12,785 Mcf/day, Texas
Gas/CNG), dated July 20, 1992, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.25,
Form 10-K for the fiscal year ended October 31, 1993).
10.17 Copy of Amendment to Service Agreement (Southern Expansion,
FT 53,000 mcf), dated February 1, 1993, between the Company
and Transcontinental Gas Pipe Line Corporation (Exhibit
10.27, Form 10-K for the fiscal year ended October 31,
1993).
10.18 Copy of Service Agreement (Contract #800059) (SCT, 1,677
Dt/day), dated June 1, 1993, between the Company and Texas
Eastern Transmission Corporation (Exhibit 10.28, Form 10-K
for the fiscal year ended October 31, 1993).
10.19 Copy of Gas Storage Contract (for Use Under Rate Schedule
FS) (Contract No. 2399) (FS, 2,901,943 Dt), dated September
1, 1993, between the Company and Tennessee Gas Pipeline
Company (Exhibit 10.29, Form 10-K for the fiscal year ended
October 31, 1993).
10.20 Copy of Gas Transportation Agreement (for Use Under FT-A
Rate Schedule) (Contract No. 237) (FTA, 130,000 Dt/day),
dated September 1, 1993, between the Company and Tennessee
Gas Pipeline Company (Exhibit 10.30, Form 10-K for the
fiscal year ended October 31, 1993).
|
10.21 Copy of Gas Storage Contract (for Use Under Rate Schedule
FS) (Contract No. 2400) (FS, 672,091 Dt total capacity),
dated September 1, 1993, between the Company and Tennessee
Gas Pipeline Company (Exhibit 10.31, Form 10-K for the
fiscal year ended October 31, 1993).
10.22 Copy of Service Agreement under Rate Schedule GSS, dated
October 1, 1993, between the Company and Transcontinental
Gas Pipe Line Corporation.
10.23 Copy of FTS Service Agreement (23,000 Dt/day), dated
November 1, 1993, between the Company and Columbia Gas
Transmission Corporation (Exhibit 10.24, Form 10-K for the
fiscal year ended October 31, 1994).
10.24 Copy of Service Agreement under Rate Schedule FSS (2,263,920
Dt total capacity), dated November 1, 1993, between the
Company and Columbia Gas Transmission Corporation (Exhibit
10.25, Form 10-K for the fiscal year ended October 31,
1994).
10.25 Copy of Service Agreement under Rate Schedule SST (Winter:
10,000 Dt/day; Summer: 5,000 Dt/day), dated November 1,
1993, between the Company and Columbia Gas Transmission
Corporation (Exhibit 10.26, Form 10-K for the fiscal year
ended October 31, 1994).
10.26 Copy of FSS Service Agreement (10,000 dekatherms per day
daily storage quantity), dated November 1, 1993, between the
Company and Columbia Gas Transmission Corporation.
10.27 Copy of SST Service Agreement (37,000 dekatherms per day),
dated November 1, 1993, between the Company and Columbia Gas
Transmission Corporation.
10.28 Copy of Form of Assignment Agreement (23,455 dekatherms per
day), dated November 1, 1993, between the Company and
Columbia Gulf Transmission Company.
10.29 Copy of Service Agreement (20,504 Mcf per day), dated June
6, 1994, between the Company and Transcontinental Gas Pipe
Line Corporation.
10.30 Copy of FTS-1 Service Agreement (5,000 dekatherms per day),
dated September 14, 1994, between the Company and Columbia
Gulf Transmission Company.
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12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule (for Securities and Exchange
Commission use only).
99 Annual Report on Form 11-K.
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(b) Reports on Form 8-K
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date January 24, 1996 By: /s/ John H. Maxheim
---------------- --------------------------------
John H. Maxheim
Chairman of the Board, President
and Chief Executive Officer
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ John H. Maxheim Chairman of the Board, January 24, 1996
- --------------------- President and Chief
John H. Maxheim Executive Officer, and
Director
/s/ David J. Dzuricky Senior Vice President- January 24, 1996
- ---------------------- Finance
David J. Dzuricky (Principal Financial
Officer)
/s/ Barry L. Guy Vice President and January 24, 1996
- --------------------- Controller (Principal
Barry L. Guy Accounting Officer)
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Signature Title Date
--------- ----- ----
/s/ Jerry W. Amos Director January 24, 1996
- ------------------------------
Jerry W. Amos
/s/ C. M. Butler III Director January 24, 1996
- ------------------------------
C. M. Butler III
/s/ Sam J. DiGiovanni Director January 24, 1996
- ------------------------------
Sam J. DiGiovanni
/s/ Muriel W. Helms Director January 24, 1996
- ------------------------------
Muriel W. Helms
/s/ John F. McNair III Director January 24, 1996
- ------------------------------
John F. McNair III
/s/ Ned R. McWherter Director January 24, 1996
- ------------------------------
Ned R. McWherter
/s/ Walter S. Montgomery, Jr. Director January 24, 1996
- ------------------------------
Walter S. Montgomery, Jr.
/s/ Donald S. Russell, Jr. Director January 24, 1996
- ------------------------------
Donald S. Russell, Jr.
/s/ John E. Simkins, Jr. Director January 24, 1996
- ------------------------------
John E. Simkins, Jr.
|
Schedule II
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
For the Years Ended October 31, 1995, 1994 and 1993
- ----------------------------------------------------------------------
Balance at Additions Balance
Beginning Charged to Deductions at End
Description of Period Costs and Expenses (A) of Period
- ----------------------------------------------------------------------
(in thousands)
Allowance for doubtful accounts:
1995 $ 947 $1,805 $1,780 $972
1994 776 2,195 2,024 947
1993 1,120 1,849 2,193 776
|
(A) Uncollectible accounts written off, net of recoveries and adjustments.
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 1995
Exhibits
4.10 Copy of Pricing Supplement of Medium-Term Notes, Series B, dated
October 3, 1995.
10.10 Copy of Service Agreement under Rate Schedule WSS, dated August
1, 1991, between the Company and Transcontinental Gas Pipe Line
Corporation.
10.22 Copy of Service Agreement under Rate Schedule GSS, dated October
1, 1993, between the Company and Transcontinental Gas Pipe Line
Corporation.
10.26 Copy of FSS Service Agreement (10,000 dekatherms per day daily
storage quantity), dated November 1, 1993, between the Company
and Columbia Gas Transmission Corporation.
10.27 Copy of SST Service Agreement (37,000 dekatherms per day), dated
November 1, 1993, between the Company and Columbia Gas
Transmission Corporation.
10.28 Copy of Form of Assignment Agreement (23,455 dekatherms per day),
dated November 1, 1993, between the Company and Columbia Gulf
Transmission Company.
10.29 Copy of Service Agreement (20,504 Mcf per day), dated June 6,
1994, between the Company and Transcontinental Gas Pipe Line
Corporation.
10.30 Copy of FTS-1 Service Agreement (5,000 dekatherms per day), dated
September 14, 1994, between the Company and Columbia Gulf
Transmission Company.
12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule (for Securities and Exchange use only).
99 Annual Report on Form 11-K.
|
Exhibit 4.10 Rule 424(b)(3) File Nos.33-60108 and 33-59369
PRICING SUPPLEMENT NO. 1 TO REGISTRATION STATEMENT NO. 33-59369
AND PRICING SUPPLEMENT NO. 4 TO REGISTRATION STATEMENT NO. 33-60108
Dated September 28, 1995
(Prospectus dated August 9, 1995, as supplemented
by the Prospectus Supplement dated September 20, 1995)
$150,000,000 Piedmont Natural Gas Company, Inc. Medium-Term Notes, Series B Due Nine Months or More from Date of Issue
Principal Amount: $55,000,000 [ ] Floating Rate Notes [x] Book Entry Notes
Issue Price: 100% [x] Fixed Rate Notes [ ] Certificated Notes
Original Issue Date: October 3, 1995 Maturity Date: October 3, 2025
Original Issue Discount Notes: [ ] Yes Total Amount of OID:
[x] No
Yield to Maturity:
Initial Accrual Period:
|
Interest Payments Dates: January 1 and Record Dates: December 16 and June 15 July 1 of each year and at maturity next preceding the Interest Payment Dates |
[x] The Notes cannot be redeemed prior to maturity. [x] The Notes cannot be repaid
prior to maturity.
[ ] The Notes may be redeemed prior to maturity. [ ] The Notes may be repaid prior
to maturity at the option of
the holders thereof.
|
Optional Optional
Redemption Redemption Repayment Repayment
Date(s) Percentage(s) Date(s) Percentage(s)
- --------- ------------- -------- -------------
Applicable Only to Fixed Rate Notes:
Interest Rate: 7.40%
Applicable Only to Floating Notes:
Interest Rate Basis: Maximum Interest Rate:
[ ] Commercial Paper Rate Minimum Interest Rate:
[ ] CD Rate Spread (plus or minus):
[ ] Prime Rate Spread Multiplier:
[ ] Federal Funds Effective Rate Interest Reset Date(s):
[ ] Treasury Rate Interest Reset Month(s):
[ ] LIBOR Interest Reset Period:
Initial Interest Rate: Interest Payment Month(s):
Index Maturity: Interest Payment Period:
Calculation Date(s): Calculation Agent:
|
Exhibit 10.10
Service Agreement Under Rate Schedule WSS
THIS AGREEMENT entered into this 1st day of August, 1991 by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller", first party, and PIEDMONT NATURAL GAS COMPANY, a New York corporation, hereinafter referred to as "Buyer", second party,
W I T N E S S E T H:
WHEREAS, Buyer is purchasing natural gas storage service from Seller under Seller's Rate Schedule WSS as set forth herein:
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
SERVICE TO BE RENDERED
Subject to the terms and provisions of this agreement and of Seller's Rate Schedule WSS, Seller agrees to receive from Buyer, quantities of natural gas for the Base Gas and for storage, inject into storage for Buyer's account, store, withdraw from storage (or cause to be injected into storage for Buyer's account, stored, and withdrawn from storage) and deliver to Buyer, quantities of natural gas as follows:
To withdraw from storage or cause to be withdrawn from storage, the gas stored for Buyer's account up to a maximum quantity in any day of 69,701 Mcf, which quantity shall be Buyer's Storage Demand Quantity, or such greater or lesser daily quantity, as applicable from time to time, pursuant to the terms and conditions of Seller's Rate Schedule WSS.
To receive and store or cause to be stored up to a total quantity at any one time of 5,924,550 Mcf, which quantity shall be Buyer's Storage Capacity Quantity.
ARTICLE II
POINT OF DELIVERY
The Point or Points of Delivery for all natural gas delivered by Seller to Buyer under this agreement shall be at or near:
Station 54
ARTICLE III
DELIVERY PRESSURE
Seller shall deliver natural gas to Buyer at the Point(s) of Delivery at a pressure(s) of:
Not applicable.
Service Agreement Under Rate Schedule WSS
(Continued)
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective August 1, 1991 and shall remain in force and effect for a period ending March 31, 1998.
ARTICLE V
RATE SCHEDULE AND PRICE
Buyer Shall pay Seller for natural gas service rendered hereunder in accordance with Seller's Rate Schedule WSS, and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be amended or superseded from time to time at the initiative of either party. Such rate schedule and General Terms and Conditions are by this reference made a part hereof.
ARTICLE VI
MISCELLANEOUS
1. The subject headings of the Articles of this agreement are inserted for the purpose of convenient reference and are not intended to be a part of this agreement or to be considered in any interpretation of the same.
2. This agreement supersedes and cancels as of the effective date hereof the following contracts between the parties hereto: WSS Service Agreement dated August 6, 1981.
3. No waiver by either part of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
4. This agreement shall be interpreted, performed and enforced in accordance with the laws of the State of Texas.
5. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective Presidents or Vice Presidents thereunto duly authorized and have caused their respective corporate seals to be hereunto affixed and attested by their respective Secretaries or Assistant Secretaries the day and year above written.
Service Agreement Under Rate Schedule WSS
(Continued)
TRANSCONTINENTAL GAS PIPE LINE
ATTEST: CORPORATION
/s/ Grace L. Bellinger By:/s/ Thomas E. Skains
- ---------------------- ---------------------------
Assistant Secretary (Seller)
ATTEST: PIEDMONT NATURAL GAS COMPANY
/s/ T. C. Coble By:/s/ Ware F. Schiefer
- ---------------------- ---------------------------
Assistant Secretary (Buyer)
|
Exhibit 10.22
SERVICE AGREEMENT UNDER RATE SCHEDULE GSS
THIS AGREEMENT entered into this first day of October, 1993, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller", first party, and, PIEDMONT NATURAL GAS COMPANY, INC., a(n) North Carolina corporation, hereinafter referred to as "Buyer", second party,
W I T N E S S E T H:
WHEREAS, Buyer desires to purchase and Seller desires to sell natural gas storage service under Seller's Rate Schedule GSS as set forth herein; and
WHEREAS, Seller and Consolidated Natural Gas Transmission Corporation ("CNG") have entered into an agreement providing for underground natural gas storage service by CNG for Seller; and
WHEREAS, pursuant to the terms of the Joint Stipulation approved by the Commission's Order dated July 16, 1993 in Docket Nos. RS92-86-003, RP92-108-000, and RP92-137-000 which amended Seller's Certificate in Docket No. CP61-194, Seller and Buyer agree to a twenty year contract term for the Storage Demand Quantity and Storage Capacity Quantity set forth in Article I hereof;
NOW THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
SERVICE TO BE RENDERED
Subject to the terms and provisions of this agreement and of Seller's Rate Schedule GSS, Seller agrees to receive from Buyer for storage, inject into storage for Buyer's account, store, withdraw from storage (or cause to be injected into storage for Buyer's account, stored, and withdrawn from storage) and deliver to Buyer, quantities of natural gas as follows:
To withdraw from storage or cause to be withdrawn from storage, the gas stored for Buyer's account up to a maximum quantity in any day of 37,486 Mcf, which quantity shall be Buyer's Storage Demand.
To receive and store or cause to be stored up to a total quantity at any one time of 2,l97,887 Mcf, which quantity shall be Buyer's Storage Capacity Quantity.
ARTICLE II
POINT OF DELIVERY
The Point or Points of Delivery for all natural gas delivered
SERVICE AGREEMENT UNDER RATE SCHEDULE GSS
(Continued)
ARTICLE II
POINT OF DELIVERY
(Continued)
by Seller to Buyer under this agreement shall be at or near:
(1) Anderson Meter Station, located at milepost 1162.72 on
Seller's main transmission line in Anderson County, South
Carolina, approximately 3.5 miles southeasterly from Anderson,
South Carolina, on County Road near Broadway Lake.
(2) Charlotte Meter Station, located at milepost 1287.10 on
Seller's main transmission line in Iredell County, North
Carolina, adjoining Seller's Compressor Station No. 150 site
near Davidson, North Carolina.
(3) Greensboro Meter Station, located at milepost 1355.06 on
Seller's main transmission line in Guilford County, North
Carolina, approximately 12 miles southwesterly from
Greensboro, North Carolina, near the intersection of State
Highway #150 and State Highway #68.
(4) Greenville Meter Station, located at milepost 1183.96 on
Seller's main transmission line in Greenville County, South
Carolina, approximately 17 miles southeasterly from
Greenville, South Carolina, on County Road near Woodville,
South Carolina.
(5) Iva-Starr Meter Station, located at milepost 1159.01 on
Seller's main transmission line, approximately 4 miles south
of Anderson, Anderson County, South Carolina.
(6) Owens-Corning Meter Station, located at milepost 1159-01 on
Seller's main transmission line approximately 4 miles south of
Anderson, South Carolina, near the juncture of South Carolina
Highway #82 and #811.
(7) Salisbury Meter Station, located at milepost 1308.45 on
Seller's main transmission line in Rowan County, North
Carolina, approximately 6 miles northwesterly from Salisbury,
North Carolina, near U.S. Highway #70.
(8) Simpsonville Meter Station, located at milepost 1190.00 on
Seller's main transmission line on U.S. Highway No. 276,
approximately 1.75 miles northwesterly from Fountain Inn,
Greenville County, South Carolina.
(9) Spartanburg Meter Station, located at milepost 1214.34 on
Seller's main transmission line in Spartanburg County,
|
South Carolina, approximately 3.5 miles southeasterly from
Spartanburg, South Carolina on State Highway #56.
(10) Startex Meter Station, located in Spartanburg County, South
Carolina, approximately 7.5 miles south of Spartanburg, South
Carolina, on Compressor Station No. 140 Site.
(11) Winston-Salem Meter Station, located at milepost 1340.48 on
Seller's main transmission line in Davidson County, North
Carolina, approximately 8 miles southeasterly from
Winston-Salem, North Carolina, near Wallburg, North Carolina.
(12) Woodruff Meter Station, located at milepost 1198.97 on
Seller's main transmission line on State Highway No. 101,
approximately 5.5 miles northwesterly from Woodruff,
Spartanburg County, South Carolina.
(13) Belton Meter Station, located at milepost 1171.30 on Seller's
main transmission line in Anderson County, South Carolina,
near the city of Belton, South Carolina.
(14) Greenwood Meter Station, located at the point of connection of
Seller's facilities and those of the City of Greenwood, South
Carolina on Seller's main transmission line approximately 2
miles northeast of the City of Belton, Anderson County, South
Carolina.
(15) Stokesdale Meter Station, located at milepost 1359.63 on
Seller's main transmission line in Guilford County, North
Carolina, near the city of Stokesdale, North Carolina.
(16) Kernersville Meter station, located at milepost 1348.86 on
Seller's main transmission line near Kernersville, Forsyth
County, North Carolina.
(17) Cowpens Meter Station, located at milepost 1222.66 on Seller's
main transmission line near Cowpens, Cherokee County, South
Carolina.
(18) Inman Meter Station located on Seller's Mill Spring Extension
at approximately milepost 15.16 in Spartanburg County, South
Carolina.
(19) Landrum Meter Station, located on Seller's Mill Spring
Extension at approximately milepost 23.81 in Spartanburg
County, South Carolina.
(20) Hickory Meter Station, located at milepost 1269.23 on Seller's
main transmission line near Stanley, North Carolina.
(21) Lowesville Meter Station, located on Seller's Maiden
|
Extension at approximately milepost 0.18 at the intersection
of State Highway Nos. 1394 and 73 in Lincoln County, North
Carolina.
(22) Maiden Meter Station, located on Seller's Maiden Extension at
approximately milepost 17.76 near the intersection of State
Highway Nos. 1882 and 1883 in Catawba County, North Carolina.
(23) Moore Meter Station, located at milepost 1205.89 on Seller's
main transmission line on the side of Seller's Compressor
Station No. 140, Spartanburg County, South Carolina.
(24) Spencer-Buck Meter Station, located at milepost 1312.72 on
Seller's main transmission line in Rowan County, North
Carolina, near the intersection of State Highway 601 and Young
Road.
(25) West Startex Meter Station, located adjacent to Seller's Mill
Spring Extension in Spartanburg County, South Carolina
approximately 6.0 miles from Seller's Compressor Station No.
140.
|
OTHER
The point of connection of Seller's facilities and those of Duke Power Company adjacent to Seller's main transmission line at milepost 1175.55, in Anderson County, South Carolina, for delivery of gas to the Duke Lee Meter Station.
ARTICLE III
DELIVERY PRESSURE
Seller shall deliver natural gas to Buyer at the Point(s) of Delivery at a pressure(s) of: not less than fifty (50) pounds per square inch gauge, or as such other pressures as may be agreed upon in the day-to-day operations of Buyer and Seller.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective October 1, 1993 and shall remain in force and effect through March 31, 2013.
ARTICLE V
RATE SCHEDULE AND PRICE
Buyer shall pay Seller for natural gas service rendered hereunder in accordance with Seller's Rate Schedule GSS and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy
Regulatory Commission, and as the same may be amended or superseded from time to time at the initiative of either party. Such rate schedule and General Terms and Conditions are by this reference made a part hereof.
ARTICLE VI
MISCELLANEOUS
1. The subject headings of the Articles of this agreement are inserted for the purpose of convenient reference and are not intended to be a part of this agreement nor to be considered in any interpretation of the same.
2. This agreement supersedes and cancels as of the effective date hereof the following contract:
None. Service Agreement dated April 13, 1972 expired on April 1, 1992.
3. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
4. This agreement shall be interpreted, performed and enforced in accordance with the laws of the State of North Carolina.
5. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective Presidents or Vice Presidents thereunto duly authorized and have caused their respective corporate seals to be hereunto affixed and attested by their respective Secretaries or Assistant Secretaries the day and year above written.
ATTEST: TRANSCONTINENTAL GAS PIPE LINE CORPORATION
/s/ Grace L. Hughes By: /s/ Thomas E. Skains
- -------------------- --------------------------
Ast. Secretary Thomas E. Skains
Senior Vice President
Transportation and Customer Services
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Secretary Title Vice President
Exhibit 10.26
Agreement No. 38017
Control No. 930905-0241
FSS SERVICE AGREEMENT
(10,000 Dth per Day Daily Storage Quantity)
THIS AGREEMENT, made and entered into this lst day of November, 1993, by
and between COLUMBIA GAS TRANSMISSION CORPORATION ("Seller") and NASHVILLE GAS
COMPANY ("Buyer").
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Seller shall perform and Buyer shall receive the service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Seller shall store quantities of gas for Buyer up to but not exceeding Buyer's Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Buyer and Seller, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284.223 of Subpart G of the Commission's regulations. Buyer warrants that service hereunder is being provided on behalf of Buyer.
Section 2. Term. Service under this Agreement shall commence as of November 1, 1993 and shall continue in full force and effect until October 31, 2010 and from year to year thereafter unless terminated by either party upon six months written notice to the other party prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Buyer may have under the Commission's regulations and Seller' s Tariff.
Section 3. Rates. Buyer shall pay the charges and furnish the Retainage percentage set forth in the above-referenced Rate Schedule and specified in Seller's currently effective Tariff, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement.
Section 4. Notices. Notices to Seller under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Director, Transportation and Exchange, and notices to Buyer shall be
Agreement No. 38017 Control No. 930905-0241
addressed to it at Post Office Box 33068, Charlotte, North Carolina 28233, Attention: Chuck Fleenor, until changed by either party by written notice.
Section 5. Prior Service Agreements. This Agreement is being entered into by the parties hereto pursuant to the Commission's Order No. 636 and its orders dated July 14, 1993 and September 29, 1993, with respect to Seller's Order No. 636 compliance filing and relates to the following existing Service Agreements:
CDS Service Agreement No. 36081, effective November 1, 1989, as it may have been amended, providing for a bundled sales, transportation and storage service under the CDS Rate Schedule.
WS Service Agreement No. 36082, effective November 1, 1989, as it may have been amended, providing for a bundled storage and delivery service under the WS Rate Schedule.
The terms of Service Agreement No. 38017 shall become effective as of the effective date hereof, however, the parties agree that neither the execution nor the performance of Service Agreement No. 38017 shall prejudice any recoupment or other rights that Buyer may have under or with respect to the above-referenced Service Agreements.
NASHVILLE GAS COMPANY COLUMBIA GAS TRANSMISSION CORPORATION
By /s/ C. W. Fleenor By /s/ George E. Shriver
-------------------- ------------------------
Title Vice President Title Director T & E
|
Revision No.
Control No. 1993-09-05-0241
|
Appendix A to Service Agreement No. 38017
Under Rate Schedule FSS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (Buyer) PIEDMONT NATURAL GAS CO
Storage Contract Quantity 611,870 Dth
Maximum Daily Storage Quantity 10,000 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A shall become effective as of NOVEMBER 01, 1993. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A , to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
PIEDMONT NATURAL GAS CO
By /s/ C. W. Fleenor ----------------------------------- Its Vice President Date December 8, 1993 |
COLUMBIA GAS TRANSMISSION CORPORATION
By /s/ George E. Shriver ----------------------------------- Its Dir T & E Date December 19, 1993 |
Exhibit 10.27
Service Agreement No. 38054
Control No. 930905-075
SST SERVICE AGREEMENT
(Winter 37,000 Dth/day; Summer 18,500 Dth/day)
THIS AGREEMENT, made and entered into this lst day of November, 1993, by and between COLUMBIA GAS TRANSMISSION CORPORATION ("Seller") and PIEDMONT NATURAL GAS COMPANY ("Buyer").
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Seller shall perform and Buyer shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Seller to deliver gas hereunder to or for Buyer, the designation of the points of delivery at which Seller shall deliver or cause gas to be delivered to or for Buyer, and the points of receipt at which Buyer shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Buyer and Seller, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284.223 of Subpart G of the Commission's regulations. Buyer warrants that service hereunder is being provided on behalf of Buyer.
Section 2. Term. Service under this Agreement shall commence as of November 1, 1993, and shall continue in full force and effect until October 31, 2011 and from year-to-year thereafter unless terminated by either party upon six (6) months' written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Buyer may have under the Commission's regulations and Seller's Tariff.
Section 3. Rates. Buyer shall pay Seller the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement.
Service Agreement No. 38054 Control No. 930905-075
SST SERVICE AGREEMENT
Section 4. Notices. Notices to Seller under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Director, Transportation and Exchange and notices to Buyer shall be addressed to it at P. 0. Box 33068, Charlotte, NC 28233 Attention: Mr. Chuck Fleenor, until changed by either party by written notice.
Section 5. Prior Service Agreements. This Agreement is being entered into by the parties hereto pursuant to the Commission's Order No. 636 and its order dated July 14, 1993 and September 29, 1993, with respect to Seller's Order No. 636 compliance filing and relates to the following existing Service Agreements:
CDS Service Agreement No. 37016, effective November 1, 1989, as it may have been amended, providing for a bundled sales, transportation and storage service under the CDS Rate Schedule.
WS Service Agreement No. 37122, effective November 1, 1989 as it may have been amended, providing for a bundled storage and delivery service under the WS Rate Schedule.
The terms of Service Agreement No. 38054 shall become effective as of the effective date hereof, however, the parties agree that neither the execution nor the performance of Service Agreement 38054 shall prejudice any recoupment or other rights that Buyer may have under or with respect to the above-referenced Service Agreements.
PIEDMONT NATURAL GAS COMPANY
By: /s/ C. W. Fleenor
-------------------------------
Title: Vice President
|
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ George E. Shriver
-------------------------------
Title: Dir T & E
|
Revision No.
Control No. 1993-09-05-0075
Appendix A to Service Agreement No. 38054
Under Rate Schedule SST
Between (Seller) Columbia Gas Transmission Corporation and (Buyer) Piedmont Natural Gas Company
October through March Transportation Demand 37,000 Dth/day April through September Transportation Demand 18,500 Dth/day
Primary Receipt Points
Scheduling Scheduling Maximum Daily
Point No. Point Name Quantity (Dth/Day)
- -----------------------------------------------------------------------------------------------
STOW Storage Withdrawals 37,000
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Revision No.
Control No. 1993-09-05-07
Appendix A to Service Agreement No. 38054
Under Rate Schedule SST
Between (Seller) Columbia Gas Transmission Corporation and (Buyer) Piedmont Natural Gas Company
Primary Delivery Points
F
o
o
t Maximum S1/
n Delivery
o Maximum Daily Pressure
Scheduling Scheduling Measuring t Measuring Delivery Obligation Obligation
Point No. Point Name Point No. e Point Name (Dth/Day) (PSIG)
- --------------------------------------------------------------------------------------------------------------------------------
124 Piedmont Natural Gas 833097 Boswells Tavern 37,000 750
|
Revision No Control No. 1993-09-05-0075
Appendix A to Service Agreement No. 38054
Under Rate Schedule SST
Between (Seller) Columbia Gas Transmission Corporation
and (Buyer) Piedmont Natural Gas Co.
S1 / If a maximum pressure is not specifically stated, then Seller's
obligation shall be as stated in Section 13 (delivery pressure) of the
General Terms and Conditions.
GFNT/ Unless station specific MDDOS are specified in a separate firm service
agreement between Seller and Buyer, Seller's aggregate maximum daily
delivery obligation, under this and any other service agreement
between Seller and Buyer, at the stations listed above shall not
exceed the MDDO quantities set forth above for each station. Any
station specific MDDOS in a separate firm service agreement between
Seller and Buyer shall be additive to the individual station MDDOS set
forth above.
|
Revision No.
Control No. 1993-09-05-0075
|
Appendix A to Service Agreement No. 38054 Under Rate Schedule SST
Between (Seller) Columbia Gas Transmission Corporation and (Buyer) Piedmont Natural Gas Company
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Seller's Tariff is incorporated herein by reference for the purpose of listing valid secondary receipt and delivery points.
Service changes pursuant to this Appendix A shall become effective as of November 01, 1993. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A , to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
Piedmont Natural Gas Company
By: /s/ Chuck Fleenor
------------------
Its: Vice President
Date: December 8, 1993
|
Columbia Gas Transmission Corporation
By: /s/ George E. Shriver
----------------------
Its: Director T & E
Date: December 19, 1993
|
Exhibit 10.28
Assignment Agreement No. 37929
Control No. 930905-142
FORM OF ASSIGNMENT AGREEMENT
(23,455 Dth/day)
This Assignment Agreement (Agreement) made and entered into this 1st of November, 1993, is by and among PIEDMONT NATURAL GAS COMPANY - NORTH CAROLINA (Assignee), and COLUMBIA GULF TRANSMISSION COMPANY (Transporter).
W I T N E S S E T H:
WHEREAS, pursuant to a Release Notice complying with Section 14 of the General Terms and Conditions of Transporter's FERC Gas Tariff, Second Revised Volume No. 1 (Tariff ), Columbia Gas Transmission Corporation (Releasor) released capacity and service rights under its Service Agreement with Transporter or under a prior Assignment Agreement, subject to the requirements set forth in said Section 14; and
WHEREAS, Assignee is to be awarded all or part of such capacity and service rights in accordance with Section 14 of the Transporter's Tariff.
NOW, THEREFORE, in consideration of the mutual covenants herein contained, the parties agree as follows:
1. Assignment. Transporter hereby assigns to Assignee the capacity and service rights hereinafter specified in Releasor's Agreement under the T-1 Rate Schedule with Transporter dated November 1, 1966, having Agreement Number 90500, to the extent described in Appendix A attached hereto and incorporated herein by reference.
2. Obligations of Assignee.
(a) Assignee shall be responsible for nominating and scheduling with Transporter all service be rendered by Transporter for the benefit of Assignee under this Agreement.
(b) Assignee shall comply with (i) the terms and conditions of Transporter's FTS-1 Rate Schedule, (ii) Appendix A attached hereto, and (iii) the General Terms and Conditions of Transporter's Tariff, under which Assignee shall be deemed to be a "Shipper".
(c) Assignee shall pay Transporter a reservation charge equal to the maximum reservation charge for service under Transporter's FTS-1 Rate Schedule per Dth/day per month, plus any demand surcharges, and (ii) all commodity charges, plus any commodity surcharges, and (iii) any penalties or imbalance correction costs associated with the capacity and service rights
Assignment Agreement No. 37929 Control No. 930905-142
FORM OF ASSIGNMENT AGREEMENT (Cont'd)
assigned under this Agreement, as set forth in Transporter's currently-effective Tariff, as any of these charges may be adjusted from time to time upon approval of the Federal Energy Regulatory Commission.
3. Obligations of Transporter. Transporter shall provide service to Assignee and shall bill Releasor and Assignee in accordance with (i) the assigned Service Agreement or Assignment Agreement described in Section 1 above, (ii) Transporter's FTS-1 Rate Schedule, (iii) Appendix A attached hereto, and (iv) the General Terms and Conditions of Transporter's Tariff.
4. Term. Service under this Agreement shall commence as of November 1, 1993, and shall continue in full force and effect until Releasor permanently assigns to Assignee the capacity on Transporter described herein in accordance with Releasor's Order No. 636 restructuring proposal as approved by the Federal Energy Regulatory Commission in Docket No. RS92-5-000, et al, or upon the further order of the Commission.
5. Releasor's Recall Rights. N/A
6. Notices. Notices given under this Agreement shall be provided in accordance with Section 29 of the General Terms and Conditions of Transporter's Tariff as follows:
If to Transporter: Columbia Gulf Transmission Company
P.0. Box 1273
Charleston, West Virginia 25325-1273
ATTN: Transportation & Exchange
If to Assignee: Piedmont Natural Gas Company
P.0. Box 33068
Charlotte, NC 28233
ATTN: Mr. Chuck Fleenor
|
7. Successors and Assigns. Consistent with Section 14 of the General Terms and Conditions of Transporter's Tariff, this Agreement shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns; provided that if this Agreement is subject to recall rights as set forth in Section 5 above, the capacity and service rights assigned herein shall not vary the recall provisions contained in the original assignment.
8. Other Provisions. All applicable provisions of Transporter's Tariff are incorporated herein and made a part hereof by reference.
Assignment Agreement No. 37929 Control No. 930905-242
FORM OF ASSIGNMENT AGREEMENT (Cont'd)
9. Applicable Law. This Agreement shall be construed and interpreted under the laws of the State of Texas.
COLUMBIA GULF TRANSMISSION COMPANY
By: /s/ H. M. Melton, Jr.
----------------------
Name: H. M. Melton, Jr.
Title: Vice President
Date: 12-8-93
|
PIEDMONT NATURAL GAS COMPANY - TENNESSEE
BY: /s/ C. W. Fleenor
----------------------
Name: C. W. Fleenor
Title: Vice President
Date: Oct 12, 1993
|
Note: Appendix A, attached hereto and incorporated herein by reference, shall be Transporter's form of Appendix A set forth in Transporter's Tariff pertaining to Transporter's Rate Schedule under which the service assigned in this Assignment Agreement is released by Transporter, completed to describe the capacity and service rights assigned to Assignee under this Assignment Agreement.
Revision No. N/A Control No. 930905-142
Appendix A to Service Agreement No. 37929 Under Rate Schedule FTS-1 Between Columbia Gulf Transmission Company (Transporter) and Piedmont Natural Gas Company - North Carolina (Shipper)
Transportation Demand 23,455 Dth/day
Primary Receipt Points
Measuring Measuring Maximum Daily
Point No. Point Name Quantity (Dth/Day)
- ---------- ----------- --------------------
2700010 CGT-Rayne 1/ 23,455
---
|
Primary Delivery Points
Measuring Measuring Maximum Daily
Point No. Point Name Quantity (Dth/Day)
- ---------- ----------- --------------------
801 Leach 1/ 23,455
---
|
1/ The Transportation Demand and the firm capacity rights will fluctuate seasonally for this measuring point. During the winter season (11-01 through 03-31) the Transportation Demand rights will be 23,455 Dth/d and during the summer season (04-01 through 10-31) the Transportation Demand will be 21,583 Dth/d.
Revision No. N/A Control No. 930905-242
Appendix A to Service Agreement No.
Under Rate Schedule FTS-1
Between Columbia Gulf Transmission Company (Transporter) and Piedmont Natural Gas Company - Tennessee (Shipper)
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for purposes of listing valid secondary interruptible receipt points and delivery points.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A shall become effective as of November 1, 1993. This Appendix A shall cancel and supersede the previous Appendix A effective NA , to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
COLUMBIA GULF TRANSMISSION COMPANY
By /s/ H. M. Melton, Jr.
----------------------
Its Vice President
Date 12-8-93
|
PIEDMONT NATURAL GAS COMPANY - TENNESSEE
BY /s/ C. W. Fleenor
---------------------
Its Vice President
Date Oct. 12, 1993
|
Exhibit 10.29
SERVICE AGREEMENT
(20,504 Mcf per day)
THIS AGREEMENT entered into this 6th day of June, 1994, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and PIEDMONT NATURAL GAS COMPANY, INC. hereinafter referred to as "Buyer," second party,
W I T N E S S E T H
WHEREAS, Seller has filed with the Federal Energy Regulatory Commission in Docket No. CP94-68 for approval of Seller's 1994 Southeast Expansion Project (referred to as "SE94"); and
WHEREAS, Buyer has requested firm transportation service under SE94 and has executed with Seller a Precedent Agreement, dated October 26, 1993, for such service; and
WHEREAS, Seller is willing to provide the requested firm transportation for Buyer under SE94 pursuant to the terms of this Service Agreement and the Precedent Agreement.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of 20,504 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) of Seller's pipeline system at such point(s) of receipt. In the event the maximum operating pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder,
SERVICE AGREEMENT
(Continued)
is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of the later of November 1, 1994 or the date that the necessary regulatory approvals have been received and accepted by Seller and Seller's facilities necessary to provide service to Buyer under SE94 have been constructed and are ready for service, and shall remain in force and effect for a primary term of twenty (20) years from and after such effective date and year to year thereafter until terminated after such primary term by Seller or Buyer upon at least two (2) years written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable judgment fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Seller's Rate Schedule FT.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.
SERVICE AGREEMENT
(Continued)
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Seller's Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto: None
2. No waiver by either party of any one or more defaults by the other in the performance of any provision of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
SERVICE AGREEMENT
(Continued)
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P.O. Box 1396
Houston, Texas 77251
Attention: Tom Skains - Senior Vice President
Transportation and Customer Services
(b) If to Buyer: Attention:
Piedmont Natural Gas Company, Inc. Ware F. Schiefer
1915 Rexford Road Senior Vice President
Charlotte, North Carolina 28211 Marketing and Gas Supply
|
such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller)
By /s/ Thomas E. Skains
-----------------------------------------
Thomas E. Skains
Senior Vice President
Transportation and Customer Services
|
PIEDMONT NATURAL GAS COMPANY, INC.
(Buyer)
By /s/ Ware F. Schiefer ----------------------------------------- |
SERVICE AGREEMENT
(Continued)
EXHIBIT A
TRANSPORTATION CONTRACT QUANTITY (TCQ): 20,504 MCF/D
POINT(S) OF RECEIPT MAXIMUM DAILY QUANTITY AT EACH
RECEIPT POINT (MCF/D)(1):
The interconnection between the 20,504
facilities of Seller and Seller's
Mobile Bay Lateral near Butler in
Choctaw County, Alabama.
|
(1) These quantities do not include the additional quantities of gas to be retained by Seller for compressor fuel and line loss make-up. Therefore, Buyer shall also deliver or cause to be delivered at the receipt points such additional quantities of gas to be retained by Seller for compressor fuel and line loss make-up.
SERVICE AGREEMENT
(Continued)
EXHIBIT B
POINT(S) OF DELIVERY PRESSURE
The point(s) of delivery between Seller's available pipeline
Seller and Buyer, subject to the pressure.
limits of Buyer's Delivery Point
Entitlements (DPEs) as set forth
in the General Terms and Conditions
of Seller's FERC Gas Tariff, as
such DPEs may be amended from time
to time.(2)
|
(2) 2,978 Mcf/d of Buyer's firm transportation capacity hereunder extends
to the suction side of Seller's Station No. 165.
Exhibit 10.30
SERVICE AGREEMENT NO. 43462
CONTROL NO.1994-07-02-0004
FTS1 SERVICE AGREEMENT
(Transportation Demand 5,000 Dth/day)
THIS AGREEMENT, made and entered into this 14th day of September, 1994, by and between:
COLUMBIA GULF TRANSMISSION COMPANY
("TRANSPORTER")
AND
NASHVILLE GAS COMPANY
("SHIPPER")
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Transporter shall perform and Shipper shall receive the service in accordance with the provisions of the effective FTS 1 Rate Schedule and applicable General Terms and Conditions of Transporter's FERC Gas Tariff, First Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission herein contained. The maximum obligations of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which the Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284.222 of Subpart G of the Commission's regulations. Shipper warrants that service hereunder is being provided on behalf of AN INTERSTATE PIPELINE COMPANY, COLUMBIA GAS TRANSMISSION CORPORATION.
Section 2. Term. Service under this Agreement shall commence as of NOVEMBER 01, 1994, and shall continue in full force and effect until OCTOBER 31, 2010, and from YEAR -to- YEAR thereafter unless terminated by either party upon 6 MONTHS' written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Shipper and Transporter agree to avail themselves of the Commission's pre-granted abandonment authority upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commission's regulations and Transporter's Tariff.
Section 3. Rates. Shipper shall pay the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement
Section 4. Notices. Notices to Transporter under this Agreement shall be
addressed to it at Post Office Box 683, Houston, Texas 77001, Attention:
Director, Planning, Transportation and Exchange and notices to Shipper shall be
addressed to it at:
SERVICE AGREEMENT NO. 43462
CONTROL NO. 1994-07-02-0004
FTS1 SERVICE AGREEMENT
NASHVILLE GAS COMPANY
665 MAINSTREAM DRIVE
NASHVILLE, TN 37228
ATTN: DOUG FORD;
until changed by either party by written notice.
Section 5. Superseded Agreements. This Service Agreement supersedes and
cancels, as of the effective date hereof, the following Service Agreements:
FTS1 37928
NASHVILLE GAS COMPANY
By: /s/ C. W. Fleenor
------------------
Name: C. W. Fleenor
Title: Vice President
Date: September 19, 1994
|
COLUMBIA GULF TRANSMISSION
By: /s/ S. M. Warnick
-------------------
Name: S. M. Warnick
Title: Vice President
Date: 9-19-94
|
Revision No.
Control No. 1994-07-02-0004
Appendix A to Service Agreement No. 43462
Under Rate Schedule FTS1
Between (Transporter) COLUMBIA GULF TRANSMISSION COMPANY
and (Shipper) NASHVILLE GAS COMPANY
Transportation Demand 5,000 Dth/day
F
o Primary Receipt Points
o ----------------------
t
n
o
Measuring t Measuring Maximum Daily
Point No. e Point Name Quantity (Dth/Day)
--------- - ---------- ------------------
2700010 01 CGT-RAYNE 5,000
|
Revision No.
Control No. 1994-07-02-0004
Appendix A to Service Agreement No. 43462
Under Rate Schedule FTS1
|
Between (Transporter) Columbia Gulf Transmission Company and (Shipper) Nashville Gas Company
F
o Primary Receipt Points
o ----------------------
t
n
o
Measuring t Measuring Maximum Daily
Point No. e Point Name Quantity (Dth/Day)
--------- - ---------- ------------------
801 01 TCO-LEACH 5,000
|
Revision No.
Control No. 1994-07-02-0004
Appendix A to Service Agreement No. 43462
Under Rate Schedule FTS1
Between (Transporter) Columbia Gulf Transmission Company
and (Shipper) Nashville Gas Company
FN01/ The transportation demand and the firm capacity rights will fluctuate
seasonally for this measuring point. During the winter season (11-01
through 03-31) the transportation demand rights will be 5,000 dth/d
and during the summer season (04-01 through 10-31) the transportation
demand will be 4,601 dth/d.
|
Revision No.
Control No. 1994-07-02-0004
|
Appendix A to Service Agreement No. 43462
Under Rate Schedule FTS1
Between (Transporter) Columbia Gulf Transmission Company
and (Shipper) Nashville Gas Company
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for purposes of listing valid secondary interruptible receipt points and delivery points.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A shall become effective as of November 01, 1994. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A , to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
NASHVILLE GAS COMPANY
By: /s/ C. W. Fleenor
------------------
Name: C. W. Fleenor
Title: Vice President
Date: September 19, 1994
|
COLUMBIA GULF TRANSMISSION COMPANY
By: /s/ S. M. Warnick
------------------
Name: S. M. Warnick
Title: Vice President
Date: 9-19-94
|
Exhibit 12
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges For the Years Ended October 31, 1991 through 1995
(in thousands except ratio amounts)
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Earnings:
Net income from
continuing operations $40,310 $35,506 $37,534 $35,310 $20,552
Income taxes 25,442 21,407 23,427 21,259 11,408
Fixed charges 35,651 29,736 26,715 26,246 26,823
------ ------- ------- ------- -------
Total Adjusted Earnings $101,403 $86,649 $87,676 $82,815 $58,783
======== ======= ======= ======= =======
Fixed Charges:
Interest $33,224 $27,671 $24,870 $24,570 $25,253
Amortization of debt
expense 336 334 192 180 259
One-third of rental expense 2,091 1,731 1,653 1,496 1,311
------ ------ ------ ------- -------
Total Fixed Charges $35,651 $29,736 $26,715 $26,246 $26,823
======= ======= ======= ======= =======
Ratio of Earnings to Fixed
Charges 2.84 2.91 3.28 3.16 2.19
======= ======= ======= ======= =======
|
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
Piedmont Natural Gas Company, Inc.:
We consent to the incorporation by reference in Post-Effective Amendment No. 3 to Registration Statement No. 2-67478 of Piedmont Natural Gas Company, Inc., on Form S-8; in Post-Effective Amendment No. 2 to Registration Statement No. 33-3815 of Piedmont Natural Gas Company, Inc., on Form S-8; in Post-Effective Amendment No. 1 to Registration Statement No. 33-52639 of Piedmont Natural Gas Company, Inc., on Form S-3; in Amendment No. 1 to Registration Statement No. 33-59369 of Piedmont Natural Gas Company, Inc., on Form S-3; and in Registration Statement No. 33-61093 of Piedmont Natural Gas Company, Inc., on Form S-8 of our report dated December 15, 1995, appearing in this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc., for the year ended October 31, 1995.
/s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Charlotte, North Carolina January 24, 1996 |
| ARTICLE UT |
| THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FINANCIAL STATEMENTS OF PIEDMONT NATURAL GAS FOR THE YEAR ENDED OCTOBER 31, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. |
| MULTIPLIER: 1,000 |
| PERIOD TYPE | YEAR |
| FISCAL YEAR END | OCT 31 1995 |
| PERIOD START | NOV 01 1994 |
| PERIOD END | OCT 31 1995 |
| BOOK VALUE | PER BOOK |
| TOTAL NET UTILITY PLANT | 801,316 |
| OTHER PROPERTY AND INVEST | 26,299 |
| TOTAL CURRENT ASSETS | 117,285 |
| TOTAL DEFERRED CHARGES | 19,995 |
| OTHER ASSETS | 0 |
| TOTAL ASSETS | 964,895 |
| COMMON | 230,964 |
| CAPITAL SURPLUS PAID IN | 0 |
| RETAINED EARNINGS | 124,015 |
| TOTAL COMMON STOCKHOLDERS EQ | 354,979 |
| PREFERRED MANDATORY | 0 |
| PREFERRED | 0 |
| LONG TERM DEBT NET | 361,000 |
| SHORT TERM NOTES | 13,500 |
| LONG TERM NOTES PAYABLE | 0 |
| COMMERCIAL PAPER OBLIGATIONS | 0 |
| LONG TERM DEBT CURRENT PORT | 7,000 |
| PREFERRED STOCK CURRENT | 0 |
| CAPITAL LEASE OBLIGATIONS | 0 |
| LEASES CURRENT | 0 |
| OTHER ITEMS CAPITAL AND LIAB | 228,416 |
| TOT CAPITALIZATION AND LIAB | 964,895 |
| GROSS OPERATING REVENUE | 505,223 |
| INCOME TAX EXPENSE | 22,511 |
| OTHER OPERATING EXPENSES | 417,400 |
| TOTAL OPERATING EXPENSES | 439,911 |
| OPERATING INCOME LOSS | 65,312 |
| OTHER INCOME NET | 4,476 |
| INCOME BEFORE INTEREST EXPEN | 69,788 |
| TOTAL INTEREST EXPENSE | 29,478 |
| NET INCOME | 40,310 |
| PREFERRED STOCK DIVIDENDS | 0 |
| EARNINGS AVAILABLE FOR COMM | 40,310 |
| COMMON STOCK DIVIDENDS | 30,564 |
| TOTAL INTEREST ON BONDS | 0 |
| CASH FLOW OPERATIONS | 90,885 |
| EPS PRIMARY | 1.45 |
| EPS DILUTED | 0 |
Exhibit 99
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 11-K
For Annual Reports of Employee Stock Purchase, Savings and Similar Plans Pursuant to Section 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended October 31, 1995
Commission file number 1-6196
A. Full title of the plans and address of the plans, if different from that of the issuer named below:
Piedmont Natural Gas Company Employee Stock Purchase Plan Piedmont Natural Gas Company Employee Stock Ownership Plan
B. Name of issuer of the securities held pursuant to the plans and the address of its principal executive office:
PIEDMONT NATURAL GAS COMPANY, INC.
1915 Rexford Road
Charlotte, North Carolina 28211
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK PURCHASE PLAN
There were no material changes in the provisions of the Piedmont Natural Gas Company Employee Stock Purchase Plan (ESPP) during the year ended October 31, 1995. Financial statements are not required under Article 6A of Regulation S-X since the shares purchased by employees under the ESPP are not held by a trustee. Participating employees are furnished a statement after each stock purchase date (June 30 and December 31) showing the number of shares and the purchase price of any stock purchased for them and the balance remaining to their credit. At October 31, 1995, 641 employees participated in the ESPP.
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
October 31, 1995 and 1994
Assets:
1995 1994
---- ----
Assets held by Wachovia Bank of North Carolina,
N.A., as trustee and custodian:
Common Stock of Piedmont Natural Gas
Company, Inc., at market value - 233,053
and 243,786 shares (cost $2,428,677 and
$2,370,714) at 1995 and 1994,
respectively (Note 3) $5,127,166 $4,906,193
Receivable on sale of stock 65,603 17,987
Short-term demand notes, at cost which
approximates market 182 265
Other 1 35
---------- ----------
Total Assets 5,192,952 4,924,480
Liabilities - -
---------- ----------
Net Assets Available for Plan Benefits $5,192,952 $4,924,480
========== ==========
|
See notes to financial statements.
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
STATEMENTS OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
For the Years Ended October 31, 1995, 1994 and 1993
1995 1994 1993
---- ---- ----
Dividend and interest income $ 256,811 $ 252,624 $ 246,701
Gain on sale of assets (Note 3) 65,663 9,611 56,502
Net appreciation (depreciation)
on Common Stock 361,882 (1,322,886) 1,377,667
Withdrawals by participants (Note 1) (397,697) (323,052) (345,791)
Withdrawals by participants due to
diversification (Note 1) (18,187) (86,093) (18,029)
---------- ---------- ----------
Net increase (decrease) 268,472 (1,469,796) 1,317,050
Net assets available for benefits:
Beginning of year 4,924,480 6,394,276 5,077,226
---------- ---------- ----------
End of year $5,192,952 $4,924,480 $6,394,276
========== ========== ==========
|
See notes to financial statements.
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
NOTES TO FINANCIAL STATEMENTS
1. DESCRIPTION OF THE PLAN
The Piedmont Natural Gas Company Employee Stock Ownership Plan (ESOP) was established to enable employees of the Company and its subsidiaries to acquire Common Stock of the Company. Through 1986, the basis for the Company's contributions to the ESOP was a tax credit on the amount of aggregate compensation paid or accrued to all employees under the ESOP. The Tax Reform Act of 1986 eliminated the tax credit allowance, and no Company contributions have been made since 1987.
Separate accounts are maintained for each participant to reflect the allocation of Company contributions and subsequent dividend and investment income. Any income credited to participants is reinvested in the Company's Common Stock.
A participant is defined as an active eligible employee with a balance in his or her ESOP account. An employee is eligible to participate in the ESOP following the later of the date on which he or she completes at least 1,000 hours of service during a period of 12 consecutive months or attains age 21. Employees who reached eligibility subsequent to the termination of Company contributions to the ESOP are not considered participants.
The ESOP provides for immediate vesting. Distributions are made either at early retirement (age 55 and 10 years of service), at normal retirement (age 65), at actual retirement for a participant who remains employed after attaining normal retirement age, at permanent disability or at death of the participant. The Administration Committee of the ESOP may, in its sole discretion, direct an earlier distribution following a participant's termination of employment.
A qualified participant, defined as any employee who has reached age 55 and completed ten years of participation, has the right to diversify a portion of his or her account balance each year during the qualified election period.
The Company may terminate the ESOP at any time and may either cause the ESOP to continue operations until the ESOP trustee has distributed all benefits or cause the assets of the ESOP to be liquidated and distributed.
2. BASIS OF ACCOUNTING
The financial statements are presented on the accrual basis of accounting.
3. GAIN ON SALE OF ASSETS
The gain on sale of assets for the years ended October 31, 1995, 1994 and 1993, is computed as follows:
1995 1994 1993
---- ---- ----
Gross proceeds $195,724 $271,116 $334,820
Historical cost 130,061 261,505 278,318
-------- -------- --------
Gain on sale of assets $ 65,663 $ 9,611 $ 56,502
======== ======== ========
|
4. NET ASSETS AVAILABLE FOR BENEFITS
Net assets available for benefits adjusted for the payable to participants for withdrawal for the years ended October 31, 1995, 1994 and 1993, are as follows:
1995 1994 1993
---- ---- ----
Net assets available for
benefits at end of year $5,192,952 $4,924,480 $6,394,276
Payable to participants
for withdrawals 70,795 20,363 164,818
---------- ---------- ----------
Net assets available for
benefits adjusted for
payable to participants
for withdrawals $5,122,157 $4,904,117 $6,229,458
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5. TAX STATUS
The ESOP is qualified under Sections 401 and 409 of the Internal Revenue Code of 1986, as amended (the Tax Code). The trust which is part of the ESOP is exempt from income taxes under Section 501(a) of the Tax Code.
The amount of the distribution under the ESOP is taxed to the recipient as ordinary income, with the taxable amount attributed to Common Stock distributed to a participant being the lesser of the cost to the trust or its fair market value on the date of distribution. Any increase in the value of the Common Stock is not taxed during the period that the stock is held by the trust nor upon its distribution to the participant. If stock is sold by a participant after distribution, the sale is subject to capital gain or loss treatment, depending on the sales price of the stock.
INDEPENDENT AUDITORS' REPORT
Piedmont Natural Gas Company
Employee Stock Ownership Plan:
We have audited the accompanying statements of net assets available for benefits of the Piedmont Natural Gas Company Employee Stock Ownership Plan (the Plan) as of October 31, 1995 and 1994, and the related statements of changes in net assets available for benefits for each of the three years in the period ended October 31, 1995. These financial statements are the responsibility of the Plan's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the net assets available for benefits of the Plan at October 31, 1995 and 1994, and the Plan's changes in net assets available for benefits for each of the three years in the period ended October 31, 1995 in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Charlotte, North Carolina January 3, 1996 |
INDEPENDENT AUDITORS' CONSENT
Piedmont Natural Gas Company, Inc.:
We consent to the incorporation by reference in Post-Effective Amendment No. 3 to Registration Statement No. 2-67478 of Piedmont Natural Gas Company, Inc., on Form S-8, and in Registration Statement No. 33-61093 of Piedmont Natural Gas Company, Inc., on Form S-8 of our report dated January 3, 1996, appearing in this Annual Report on Form 11-K of the Piedmont Natural Gas Company Employee Stock Purchase Plan and the Piedmont Natural Gas Company Employee Stock Ownership Plan for the year ended October 31, 1995.
/s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Charlotte, North Carolina January 3, 1996 |