SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999 Commission file number 000-26591
RGC RESOURCES, INC.
(successor to Roanoke Gas Company)
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(Exact name of registrant as specified in its charter)
Virginia 54-1909697
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
519 Kimball Avenue, N.E., Roanoke, VA 24016
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (540) 777-4427
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Securities registered pursuant to Section 12(b) of the Act: None.
Securities registered pursuant to Section 12(g) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
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OTC (Nasdaq
Common Stock, $5 Par Value National Market)
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
<PAGE>
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ ]
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant as of November 29, 1999. $ 37,872,140.63
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the last practicable date.
Class Outstanding at November 29, 1999
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COMMON STOCK, $5 PAR VALUE 1,836,225 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. 1999 Annual Report to Shareholders are
incorporated by reference into Parts II and IV hereof.
Portions of the RGC Resources, Inc. Proxy Statement for the 2000 Annual Meeting
of Shareholders are incorporated by reference into Part III hereof.
<PAGE>
PART I
Item 1. Business.
Historical Development
RGC Resources, Inc. (the "Company" or "Resources") was initially
incorporated in Virginia on July 31, 1998 for the primary purpose
of becoming the holding company for Roanoke Gas Company ("Roanoke
Gas") and its former subsidiaries Bluefield Gas Company
("Bluefield" or "Bluefield Gas") and Diversified Energy Company
("Diversified"). Effective July 1, 1999, Roanoke Gas and its
subsidiaries were reorganized into a holding company structure
("Reorganization"). As a result of the Reorganization: (i)
Resources became a holding company owned by the former
shareholders of Roanoke Gas; (ii) Resources became the sole owner
of the stock of Roanoke Gas, Bluefield and Diversified; (iii)
Commonwealth Public Service Corporation, a former subsidiary of
Bluefield, merged its natural gas distribution business into
Roanoke Gas; (iv) Roanoke Gas and Bluefield continue to operate
in the natural gas distribution business as subsidiaries of
Resources; and (v) Diversified continues to carry on its
nonutility propane business as a subsidiary of Resources.
Roanoke Gas was organized as a public service corporation under
the laws of the Commonwealth of Virginia in 1912. The principal
service of Roanoke Gas was, and continues to be, the distribution
and sale of natural gas. Commencing in 1972, the distribution and
sale of propane gas was added to Roanoke Gas' line of business.
The propane business was transferred to Diversified in January
1979. Diversified, which is not a public utility, distributes and
sells propane in Southwestern Virginia and Southern West Virginia.
On May 15, 1987, Roanoke Gas, through a series of merger
transactions, acquired 100 percent of the outstanding stock of
Bluefield, a public service corporation, organized in 1944 under
the laws of the State of West Virginia and principally engaged in
the distribution of natural gas in Bluefield, West Virginia and
surrounding areas, and Gas Service, Inc. ("Gas Service"), a
nonpublic utility affiliate (through common directors and
shareholders) of Bluefield, which was engaged in the sale of
propane in southwestern Virginia and southern West Virginia. After
obtaining requisite shareholder approval and the approvals of the
Virginia State Corporation Commission ("Virginia Commission") and
the West Virginia Public Service Commission ("West Virginia
Commission"), Gas Service was merged into Diversified, and
Bluefield became a wholly-owned subsidiary of Roanoke Gas. Prior
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to the Reorganization, Bluefield owned all of the issued and
outstanding stock of Commonwealth, a small Virginia public service
corporation organized in 1930 as the subsidiary of a predecessor
corporation to Bluefield.
In March 1994, the Highland Gas Marketing division of Diversified
was established to broker natural gas to several industrial
transportation customers of Roanoke Gas and Bluefield Gas.
Services
Resources maintains an integrated natural gas distribution system.
Natural gas is purchased from suppliers and distributed to
residential, commercial and large industrial users through
underground mains and services. Approximately 90.2 percent of the
Company's customers are residential, approximately 9.7 percent are
small commercial users, and the remaining percentage is made up of
large industrial customers, who received approximately 29 percent
of the Company's total annual delivered volume in 1999 under the
Company's interruptible tariff and transportation gas services.
Resources' natural gas distribution business accounted for
approximately 85 percent of the total revenues generated by the
Company in fiscal 1999, and approximately 87 percent and
approximately 89 percent of the Company's total revenues in
fiscals 1998 and 1997, respectively. The Company's revenues are
affected by the cost of natural gas, economic conditions in the
areas that the Company serves, and weather conditions. Higher gas
costs, which the Company is generally able to pass through to
customers, may cause customers to conserve, or in the case of
industrial customers, to use alternative energy sources. In recent
years, regulatory changes at the federal level and ample supply in
the natural gas industry have led to a national spot market for
natural gas and an increase in the number of suppliers of natural
gas.
The Company's retail sales are seasonal and temperature-sensitive
as the majority of the gas sold by Resources is used for heating.
For the fiscal year ended September 30, 1999, more than 54
percent of the Company's total MCF of natural gas sales were made
in the four-month period of December through March. Retail gas
deliveries for fiscal 1999 were 10,318,043 MCF, as compared to
10,875,481 MCF and 10,804,045 MCF in fiscal years 1998 and 1997,
respectively. The Company's actual heating degree days in fiscal
1999 were approximately 88 percent of normal, as compared with
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approximately 96 percent of normal in fiscal 1998, and
approximately 102 percent of normal in fiscal 1997.
Suppliers
Effective November 1, 1993, the natural gas transportation
pipelines supplying the Company, including Columbia Gas
Transmission Corporation and Columbia Gulf Transmission
Corporation (together "Columbia"), and East Tennessee Natural Gas
Company and Tennessee Gas Pipeline (together "East Tennessee"),
have operated under Federal Energy Regulatory Commission ("FERC")
Order 636. Order 636 was the start of a new era in the natural gas
industry when the responsibility of gas supply procurement and
management was shifted from the pipeline companies to the local
distribution companies and to other "shippers" of natural gas.
The cornerstone of Order 636 was the "unbundling" of pipeline
services to provide a number of choices to shippers. The pipelines
retained the responsibility of transporting contracted firm
volumes for their shippers but are no longer responsible for
obtaining the natural gas supplies. The Company now chooses who it
buys its gas from, how much storage gas to purchase, how much
transportation capacity to keep and how much to release. The
Company constantly monitors its gas requirements to minimize
exposure to pipeline penalties for insufficient supplies or
excessive gas injections. The Company's "shipper" responsibilities
bring increased scrutiny from the state commissions as they
monitor the Company's gas purchasing practices to assure that a
"least cost with adequate reliability" policy is followed.
Accordingly, the Company has worked diligently to ensure that its
customers will have an economical and reliable gas supply.
Management believes the relationships the Company has built with
its suppliers as it constructed a supply portfolio will allow it
to continue to attain this goal.
The post Order 636 function of the pipelines is simply to
transport natural gas volumes for their shippers in a safe and
efficient manner. The pipelines issue restrictions on secondary
receipt and delivery points during periods of heavy demand that
may affect the gas supply economics. The pipelines retained the
responsibilities for transportation, title tracking, and
measurement of natural gas deliveries.
The Company currently uses long-term (multi-year), mid-term
(seasonal) and short-term (spot) gas purchases to meet its system
requirements. The Company has entered into, or is in the process
of entering into, long-term and mid-term firm supply agreements to
cover the majority of its firm demand. Long-term and mid-term
suppliers currently include Columbia Energy Services, Cabot Oil
and Gas, Coral
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Energy, Engage Energy, PG&E Energy Trading and Southern Company
Energy Marketing.
The Company's firm supply agreements will supply the total system
requirements at varying prices during the period October 1, 1999
through September 30, 2000. Both Roanoke Gas and Bluefield
participate in pilot gas hedging programs approved by their
respective public utility commissions which are intended to help
protect against supply related price volatility adversely
impacting customer billing rates. Under the pilot programs, gas
cost hedges may be employed for up to 50% of normal winter demand
not supplied from storage. Under the pilot programs, the Company
has entered into options to purchase approximately 690,000
dekatherms of natural gas during fiscal 2000. All costs and
benefits of the Company's natural gas hedging programs are
reflected in cost of gas and recovered through customer billing
rates.
With the growth of the spot gas market, gas prices have developed
a pronounced seasonal pattern, with summer to winter price swings
of 100 percent or more. The Company tries to take advantage of
this opportunity by injecting lower-priced summer gas into its
liquefied natural gas storage facility, which is capable of
storing up to 220,000 DTH for use during peak winter periods. In
addition, the Company has contracted for storage reserves from
Columbia, Tennessee Gas pipeline and Virginia Gas Storage Company,
with a combined total of 2,738,631 DTH of underground storage
capacity for Roanoke and Bluefield. These reserves were available
for summer 1999 storage injections using spot market supply. This
storage capacity provides supply security with reduced exposure to
potential supply interruptions. It also offers the Company the
flexibility to balance supply with its highly variable,
weather-sensitive customer consumption patterns. In addition, the
Company has entered into an asset management agreement with PG&E
Energy Trading to further minimize the cost of firm service to its
customers by reselling pipeline capacity not needed during the
warmer months.
Columbia continues to be the Company's primary transporter of
natural gas. Columbia historically has delivered approximately
two-thirds of Roanoke Gas' gas supply and 100 percent of
Bluefield's gas supply. The Company has completed construction on
a pipeline which delivers Bluefield approximatley 25% of its
annual gas supply. Columbia presently delivers approximately 75%
of Bluefield's annual supply. East Tennessee continues to be the
Company's other major source of transportation services.
Historically, East Tennessee has delivered approximately
one-third of the Company's natural gas supply to the Roanoke
location. The rates paid for natural gas transportation and
storage services purchased from Columbia and East Tennessee are
established by tariffs approved by FERC. These tariffs contain
flexible pricing provisions, which, in some instances, authorize
these suppliers to reduce rates and charges to meet price
competition.
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Having two major pipeline transporters, a shaving facility and a
number of underground storage options, the Company believes that
it is well positioned to provide adequate gas supply for future
customer growth. As a means to more fully utilize pipeline
capacity and further lower costs to its customers, Roanoke Gas
and Bluefield Gas have entered into asset management agreements.
Effective November 1, 1999, PG&E Energy Trading, the asset
manager, will manage nomination, confirmation and scheduling of
all existing supply and storage contracts as well as supply any
additional natural gas requirements.
The Company believes that Order 636 provides regulatory
stability. Additionally, the increased opportunities available in
a deregulated natural gas supply environment may result in
additional market forces that establish gas prices and help keep
them more consistent and competitive.
Diversified has entered into storage and purchase contracts for a
substantial portion of its winter supply of propane. At September
30, 1999, Diversified has contracts with eight propane suppliers
for the purchase of up to 7,957,225 gallons of propane at varying
prices per gallon during the period October 1, 1999 through
September 30, 2000. Management believes these storage and purchase
contracts will help alleviate the effects of wholesale price
swings during peak sales months and provide added supply security.
Diversified has also entered into options to purchase
approximately 1.2 million gallons of propane during fiscal 2000.
In addition to storage contracts, Diversified has 12 storage
facilities, providing a combined total storage of 504,000 gallons.
Management believes its propane supply strategies have positioned
Diversified to provide an adequate propane supply to current
customers and allow for future customer growth.
Competition
Resources competes with other energy sources such as fuel oil,
electricity and coal. Competition is intense among the competing
energy sources and is based primarily on price. This is
particularly true for industrial applications where sales are at
risk to price competition in markets which may swing to residual
and other fuel oils.
Roanoke Gas currently holds the only franchises and/or
certificates of public convenience and necessity to distribute
natural gas in it's Virginia service areas. The franchises
generally extend for multi-year periods and are renewable by the
municipalities. Certificates of public convenience and necessity,
which are issued by the Virginia Commission, are of perpetual
duration, subject to compliance with regulatory standards.
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Bluefield Gas holds the only franchise to distribute natural gas
in its West Virginia service area. Its franchise extends for a
period of 30 years from August 23, 1979.
Management anticipates that the Company will be able to renew all
of its franchises when they expire. There can be no assurance,
however, that a given jurisdiction will not refuse to renew a
franchise or will not, in connection with the renewal of a
franchise, impose certain restrictions or conditions that could
adversely affect the Company's business operations or financial
condition.
Regulation
Roanoke Gas and Bluefield are subject to regulation at federal
and state levels. Federally, the interstate gas transmission
between Bluefield and Roanoke Gas in Bluefield, Virginia is
regulated by FERC. At the state level, the Virginia and West
Virginia Commissions regulate Roanoke Gas and Bluefield,
respectively. Such regulation includes the prescription of rates
and charges at which natural gas is sold to customers, the
approval of agreements between or among affiliated companies
involving the provision of goods and services, pipeline safety,
and certain corporate activities of the Company, including
mergers, acquisitions and the issuance of securities. Both state
Commissions also grant certificates of public convenience and
necessity to distribute natural gas in their respective states.
Roanoke Gas and Bluefield are further regulated by the
municipalities and localities which grant franchises for the
placement of gas distribution pipelines and the operation of a gas
distribution network.
Both Roanoke Gas and Bluefield Gas operated manufactured gas
plants (MGPs) as a source of fuel for lighting and heating until
the early 1950's. A by-product of operating MGPs was coal tar, and
the potential exists for on-site tar waste contaminants at former
plant sites. The extent of contaminants at these sites, if any, is
unknown at this time. An analysis at the Bluefield site indicates
some soil contamination. The Company, with concurrence of legal
counsel, does not believe any events have occurred requiring
regulatory reporting. Further, the Company has not received any
notices of violation or liabilities associated with environmental
regulations related to the MGP sites and is not aware of any
off-site contamination or pollution as a result of prior
operations. Therefore, the Company has no plans for subsurface
remediation at the MGP sites. Should the Company eventually be
required to remediate either site, the Company will pursue all
prudent and reasonable means to recover any related costs,
including insurance claims and regulatory approval for rate
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case recognition of expenses associated with any work required. A
stipulated rate case agreement between the Company and the West
Virginia Public Service Commission recognized the Company's right
to defer MGP clean-up costs at the Bluefield site, should any be
incurred, and to seek rate relief for such costs. If the Company
eventually incurs costs associated with a required clean-up of
either MGP site, the Company anticipates recording a regulatory
asset for such clean-up costs to be recovered in future rates.
Based on anticipated regulatory actions and current practices,
management believes that any costs incurred related to this matter
will not have a material effect on the Company's consolidated
financial condition or results of operations.
Employees
At September 30, 1999, Resources had 163 full-time employees. As
of that date, approximately 28 percent of the Company's full-time
employees belonged to the Oil, Chemical and Atomic Workers
International Union, AFL-CIO Local No. 3-515, which has entered
into a collective bargaining agreement with Resources. The union
has been in place at the Company since 1952. A new collective
bargaining agreement became effective on August 1, 1998. That
agreement will expire on July 31, 2000. Resources considers its
employee relations to be satisfactory.
Forward-Looking Statements
From time to time, Resources may publish forward-looking
statements relating to such matters as anticipated financial
performance, business prospects, technological developments, new
products, research and development activities and similar matters.
The Private Securities Litigation Reform Act of 1995 provides a
safe harbor for forward-looking statements. In order to comply
with the terms of the safe harbor, the Company notes that a
variety of factors could cause the Company's actual results and
experience to differ materially from the anticipated results or
other expectations expressed in the Company's forward-looking
statements. The risks and uncertainties that may affect the
operations, performance, development and results of the Company's
business include the following: (i) frozen rates in both regulated
jurisdictions; (ii) earning on a consistent basis an adequate
return on invested capital; (iii) increasing expenses and labor
costs and availability; (iv) price competition from alternate
fuels; (v) volatility in the price of natural gas and propane;
(vi) uncertainty in the projected rate of growth of natural gas
and propane requirements in the Company's service area; (vii)
general economic conditions both locally and nationally; and
(viii) developments in electricity and natural gas deregulation
and associated industry restructuring. In addition, the Company's
business is seasonal in character and strongly influenced by
weather conditions. Extreme changes in winter heating
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degree days from the normal or mean can have significant
short-term impacts on revenues and gross margin.
Item 2. Properties.
Roanoke Gas owns and operates five metering stations through which
it measures and regulates the gas being delivered by its
suppliers. The location and physical description of the properties
are as follows:
Plantation Station - Parcel on Virginia Highway #601 near point
of intersection of Hershberger Road (Rt. 623) and Rt. 601 - 1.590
acres.
J. M. Mason Station - S/E corner of Lakeside Circle and east of
Lot #4 of Mill Road subdivision just east of Kessler Mill Road -
.842 acres.
Sugarloaf Station - Parcel fronting on S/L of Rt. 686 and W/L of
Lynnson Drive - 111 acres.
Clearbrook Station - Parcel 356' west of Rt. 675 and 0.2 mile
south of Rt. 220 - 255 acres.
Cave Spring Station - N/L Route 221 just west of Route 688 - 3.93
acres.
The network of distribution lines includes the cities of Roanoke
and Salem, the Town of Vinton, and the counties of Roanoke,
Montgomery, Botetourt and Bedford. These distribution lines are
used to interconnect metering stations and supply and storage
facilities with customers.
Located in Botetourt County is a liquefied natural gas storage
facility which has the capacity to hold 220,000 DTH of natural
gas. The County issued Industrial Revenue Bonds to finance this
facility. Roanoke Gas had a twenty-year lease on the facility with
the option to purchase for a nominal amount. The lease expired May
1, 1991, and the facility was purchased by Roanoke Gas.
Roanoke Gas' general and business offices and the maintenance and
service departments are located in Roanoke, Virginia on an
irregularly shaped parcel of land running from H. L. Lawson and
Son, Inc. south to Norfolk Southern Computer Center fronting on
Kimball Avenue to the west to the Norfolk Southern Railway yard.
The land area is 8.3 acres.
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Bluefield's main corporate office and warehouse is located on
2.175 acres at 4699 East Cumberland Road and consists of a
one-story metal building with brick front. Bluefield owns a lot at
800 Pulaski Street, Bluefield, West Virginia. In addition,
Bluefield owns two lots in the City of Bluefield, West Virginia,
comprising approximately 1.23 acres, upon which its high pressure
regulator stations are located.
In West Virginia, Diversified owns an office, loading platform,
garage and storage tank facility in Rainelle. The storage facility
consists of two 18,000-gallon tanks, pumps and related equipment.
A 30,000 gallon storage facility is also located in Ansted.
Another storage facility, comprising two 30,000 gallon tanks, one
18,000-gallon tank, pumps and related equipment, is located on
Bluefield Gas Company's property at 800 Pulaski Street, Bluefield,
West Virginia. A storage facility in Beckley, West Virginia,
comprising one 30,000 gallon tank, is expected to be completed
during the first quarter of fiscal 2000.
In Virginia, Diversified owns and operates nine storage
facilities. The location and storage capacities at each facility
is as follows:
Thirlane Road, N.W., Roanoke--two 30,000 gallon tanks.
Fort Chiswell, Virginia--two 30,000 gallon tanks.
Consolidated Glass in Galax, Virginia--one 30,000 gallon tank.
Craig County, Virginia, near the town of New Castle--one 30,000
gallon tank.
Floyd County, Virginia--one 30,000 gallon tank.
Virginia Forging in Botetourt County, near the town of
Buchanan--one 30,000 gallon tank.
Golden West Foods in the City of Bedford--one 30,000 gallon tank.
City of Buena Vista--two 30,000 gallon tanks.
Alleghany County, near the town of Low Moor--one 30,000 gallon
tank.
A 30,000 gallon tank storage facility in Weyers Cave is expected
to be completed during the first quarter of fiscal 2000.
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Resources considers present properties adequate. The Company
intends to construct additional distribution lines as communities
develop.
Item 3. Legal Proceedings.
Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders
during the fourth quarter of the year ended September 30, 1999.
Executive Officers of the Registrant
Pursuant to General Instruction G(3) of Form 10-K, the following
list is included as an unnumbered Item in Part I of this report in
lieu of being included in the Proxy Statement for the Annual
Meeting of Stockholders to be held on January 24, 2000.
The names, ages and positions of all of the executive officers of
RGC Resources, Inc. as of September 30, 1999, are listed below
with their business experience for the past five years. Officers
are appointed annually by the Board of Directors at the meeting of
directors immediately following the Annual Meeting of
Stockholders. There are no family relationships among these
officers, nor any agreement or understanding between any officer
and any other person pursuant to which the officer was selected.
Previous and present duties and responsibilities:
<TABLE>
<CAPTION>
Position and Business
Name and Age Experience for Past Five Years
<S> <C> <C> <C> <C> <C> <C>
John B. Williamson, III, 45 July 1999 to present President and CEO
February 1998 to July 1999 President & CEO -
Roanoke Gas
January 1993 to January 1998 Vice President- Rates
and Finance - Roanoke Gas
April 1992 to January 1993 Director of Rates and Finance
- Roanoke Gas
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Roger L. Baumgardner, 57 July 1999 to present Vice President, Secretary &
Treasurer
January 1986 to July 1999 Vice President, Secretary and
Treasurer - Roanoke Gas
Howard T. Lyon, 38 July 1999 to present Controller and Assistant
Treasurer
January 1994 to July 1999 Controller - Roanoke Gas
Dale P. Moore, 44 July 1999 to present Assistant Vice President and
Assistant Secretary
May 1998 to July 1999 Director of Rates, Regulatory
Affairs and Financial Planning
- Roanoke Gas
May 1994 to May 1998 Senior Rate Analyst-
American Electric Power/VA
</TABLE>
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PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters.
The information set forth under the caption "Market Price and
Dividend Information" in the 1999 Annual Report to
Shareholders is incorporated herein by reference.
Item 6. Selected Financial Data.
The information set forth under the caption "Selected
Financial Data" in the 1999 Annual Report to Shareholders is
incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
The information set forth under the caption "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" in the 1999 Annual Report to Shareholders is
incorporated herein by reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
Item 8. Financial Statements and Supplementary Data.
The following consolidated financial statements of the
registrant and the Independent Auditors' Report set forth in
the 1999 Annual Report to Shareholders are incorporated herein
by reference:
1. Independent Auditors' Reports
2. Consolidated Balance Sheets as of September 30, 1999
and 1998
3. Consolidated Statements of Earnings for the Years Ended
September 30, 1999, 1998 and 1997
4. Consolidated Statements of Stockholders' Equity for the
Years Ended September 30, 1999, 1998 and 1997
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5. Consolidated Statements of Cash Flows for the years
ended September 30, 1999, 1998 and 1997
6. Notes to Consolidated Financial Statements for the
years ended September 30, 1999, 1998 and 1997
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.
Not applicable.
PART III
Item 10. Directors and Executive Officers of the Registrant.
For information with respect to the executive officers of
the registrant, see "Executive Officers of the Registrant"
at the end of Part I of this report. For information with
respect to the Directors of the registrant, see "Election of
Directors of Resources" in the Proxy Statement for the 2000
Annual Meeting of Shareholders of Resources, which
information is incorporated herein by reference. The
information with respect to compliance with Section 16(a) of
the Exchange Act, which is set forth under the caption
"Section 16(a) Beneficial Ownership Reporting Compliance" in
the Proxy Statement for the 2000 Annual Meeting of
Shareholders of Resources, is incorporated herein by
reference.
Item 11. Executive Compensation.
The information set forth under the captions "Executive
Compensation," "Report of the Compensation Committee of the
Board of Directors," "Compensation Committee Interlocks and
Insider Participation" and "Performance Graph" in the Proxy
Statement for the 2000 Annual Meeting of Shareholders of
Resources, is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information pertaining to shareholders beneficially owning
more than five percent of the registrant's common stock and
the security ownership of management, which is set forth under
the captions "The Annual Shareholders Meeting" and "Security
Ownership of Management" in the Proxy Statement for
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the 2000 Annual Meeting of Shareholders of Resources, is
incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
The information with respect to certain transactions with
management of the registrant, which is set forth under the
caption "Transactions with Management" in the Proxy Statement
for the 2000 Annual Meeting of Shareholders of Resources, is
incorporated herein by reference.
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PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) List of documents filed as part of this report:
1. Financial statements:
All financial statements of the registrant as set
forth under Item 8 of this Report on Form 10-K.
2. Financial statement schedules:
All schedules are omitted, as the required
information is inapplicable or the information is
presented in the consolidated financial statements or
related notes thereto.
3. Exhibits to this Form 10-K are as follows:
Exhibit No. Description
2 Amended and Restated Agreement and Plan of Merger and
Reorganization (incorporated by reference to Exhibit 2
to Form 8-K filed on July 2, 1999)
3(a) Articles of Incorporation of RGC Resources, Inc.
(incorporated herein by reference to Exhibit 3(a) of
Registration Statement No. 33-67311, on Form S-4, filed
with the Commission on November 13, 1998, and amended
by Amendment No. 5, filed with the Commission on
January 28, 1999.)
3(b) Bylaws of RGC Resources, Inc. (incorporated herein
by reference to Exhibit 3(b) of Registration Statement
No. 33-67311, on Form S-4, filed with the Commission on
November 13, 1998, and amended by Amendment No. 5,
filed with the Commission on January 28, 1999.)
4(a) Specimen copy of certificate for RGC Resources,
Inc. common stock, $5.00 par value (incorporated herein
by reference to Exhibit 3(b) of Registration Statement
No. 33-67311, on Form S-4, filed with the Commission on
November 13, 1998, and
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amended by Amendment No. 5, filed with the Commission
on January 28, 1999.)
4(b) Article I of the Bylaws of RGC Resources (included
in Exhibit 3(b) hereto)
4(c) Instruments defining the rights of holders of
long-term debt (incorporated herein by reference to
Exhibit 4(c) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1991)
10(a) Firm Transportation Agreement between East
Tennessee Natural Gas Company and Roanoke Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(a) of the Annual Report on Form
10-K for the fiscal year ended September 30, 1994)
10(b) Interruptible Transportation Agreement between East
Tennessee Natural Gas Company and Roanoke Gas Company
dated July 1, 1991 (incorporated herein by reference to
Exhibit 10(b) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(c) NTS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
October 25, 1994 (incorporated herein by reference to
Exhibit 10(c) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(d) SIT Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 30, 1993 (incorporated herein by reference to
Exhibit 10(d) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(e) FSS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(e) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
18
<PAGE>
10(f) FTS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(f) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(g) SST Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(g) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(h) ITS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(h) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(i) FTS-1 Service Agreement between Columbia Gulf
Transmission Company and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(i) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(j) ITS-1 Service Agreement between Columbia Gulf
Transmission Company and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(j) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(k) Gas Transportation Agreement, for use under FT-A
rate schedule, between Tennessee Gas Pipeline Company
and Roanoke Gas Company dated November 1, 1993
(incorporated herein by reference to Exhibit 10(k) of
the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
10(l) Gas Transportation Agreement, for use under IT rate
schedule, between Tennessee Gas Pipeline Company and
Roanoke Gas Company dated September 1, 1993
(incorporated herein by reference to Exhibit 10(l) of
the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
19
<PAGE>
10(m) Gas Storage Contract under rate schedule FS
(Production Area) Bear Creek II between Tennessee Gas
Pipeline Company and Roanoke Gas Company dated November
1, 1993 (incorporated herein by reference to Exhibit
10(m) of the Annual Report on Form 10-K for the fiscal
year ended September 30, 1994)
10(n) Gas Storage Contract under rate schedule FS
(Production Area) Bear Creek I between Tennessee Gas
Pipeline Company and Roanoke Gas Company dated
September 1, 1993 (incorporated herein by reference to
Exhibit 10(n) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(o) Certificate of Public Convenience and Necessity for
Bedford County dated February 21, 1966 (incorporated
herein by reference to Exhibit 10(o) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(p) Certificate of Public Convenience and Necessity for
Roanoke County dated October 19, 1965 (incorporated
herein by reference to Exhibit 10(p) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(q) Certificate of Public Convenience and Necessity for
Botetourt County dated August 30, 1966 (incorporated
herein by reference to Exhibit 10(q) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(r) Certificate of Public Convenience and Necessity for
Montgomery County dated July 8, 1985 (incorporated
herein by reference to Exhibit 10(r) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
20
<PAGE>
10(s) Certificate of Public Convenience and Necessity for
Tazewell County dated March 25, 1968 (incorporated
herein by reference to Exhibit 10(s) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(t) Certificate of Public Convenience and Necessity for
Franklin County dated September 8, 1964 (incorporated
herein by reference to Exhibit 10(t) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(u) Ordinance of the Town of Bluefield, Virginia dated
August 25, 1986 (incorporated herein by reference to
Exhibit 10(u) of Registration Statement No. 33-36605,
on Form S-2, filed with the Commission on August 29,
1990, and amended by Amendment No. 1, filed with the
Commission on September 19, 1990)
10(v) Ordinance of the City of Bluefield, West Virginia
dated as of August 23, 1979 (incorporated herein by
reference to Exhibit 10(v) of Registration Statement
No. 33-36605, on Form S-2, filed with the Commission on
August 29, 1990, and amended by Amendment No. 1, filed
with the Commission on September 19, 1990)
10(w) Resolution of the Council for the Town of
Fincastle, Virginia dated June 8, 1970 (incorporated
herein by reference to Exhibit 10(f) of Registration
Statement No. 33-11383, on Form S-4, filed with the
Commission on January 16, 1987)
10(x) Resolution of the Council for the Town of
Troutville, Virginia dated November 4, 1968
(incorporated herein by reference to Exhibit 10(g) of
Registration Statement No. 33-11383, on Form S-4, filed
with the Commission on January 16, 1987)
10(y)* Consulting Agreement between Albert W. Buckley and
Roanoke Gas Company dated February 20, 1992
(incorporated herein by
21
<PAGE>
reference to Exhibit 10(b)(b) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1992)
10(z)* Consulting Contract between A. Anson Jamison and
Roanoke Gas Company dated March 27, 1990 (incorporated
herein by reference to Exhibit 10(c)(c) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(a)(a) Contract between Roanoke Gas Company and
Diversified Energy Services, Inc. dated December 18,
1978 (incorporated herein by reference to Exhibit
10(e)(e) of Registration Statement No. 33-36605, on
Form S-2, filed with the Commission on August 29, 1990,
and amended by Amendment No. 1, filed with the
Commission on September 19, 1990)
10(b)(b) Service Agreement between Bluefield Gas Company
and Commonwealth Public Service Corporation dated
January 1, 1981 (incorporated herein by reference to
Exhibit 10(f)(f) of Registration Statement No.
33-36605, on Form S-2, filed with the Commission on
August 29, 1990, and amended by Amendment No. 1, filed
with the Commission on September 19, 1990)
10(c)(c)* Retirement Payment Agreement between Arthur T.
Ellett and Roanoke Gas Company dated April 6, 1972
(incorporated herein by reference to Exhibit 10(g)(g)
of Registration Statement No. 33-36605, on Form S-2,
filed with the Commission on August 29, 1990, and
amended by Amendment No. 1, filed with the Commission
on September 19, 1990)
10(d)(d)* Consulting Services Agreement between Edward C.
Dunbar and Roanoke Gas Company dated February 25, 1991
(incorporated herein by reference to Exhibit 10(h)(h)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1991)
10(e)(e)* Consultation Contract between Gordon C. Willis
and Roanoke Gas Company dated April 29, 1991
(incorporated herein by reference to Exhibit 10(I)(I)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1991)
22
<PAGE>
10(f)(f) Gas Storage Contract under rate schedule FS
(Market Area) Portland between Tennessee Gas Pipeline
Company and Roanoke Gas Company dated November 1, 1993
(incorporated herein by reference to Exhibit 10(k)(k)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
10(g)(g) FTS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(l)(l) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(h)(h) ITS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(m)(m) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(i)(i) FSS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(n)(n) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(j)(j) SST Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(o)(o) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(k)(k) FTS-1 Service Agreement between Columbia Gulf
Transmission Company and Bluefield Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(p)(p) of the Annual Report on Form 10-K for
the fiscal year ended September 30, 1994)
10(l)(l)* RGC Resources Key Employee Stock Option Plan
(incorporated herein by reference to Exhibit 4(c) of
Registration Statement No. 333-02455, Post Effective
Amendment on Form S-8, filed with the Commission on
July 2, 1999.)
23
<PAGE>
10(m)(m)* RGC Resources, Inc. Stock Bonus Plan
10(n)(n) Gas Franchise Agreement between the Town of
Vinton, Virginia, and Roanoke Gas Company dated July 2,
1996 (incorporated herein by reference to Exhibit
10(n)(n) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(o)(o) Gas Franchise Agreement between the City of
Salem, Virginia, and Roanoke Gas Company dated July 9,
1996 (incorporated herein by reference to Exhibit
10(o)(o) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(p)(p) Gas Franchise Agreement between the City of
Roanoke, Virginia, and Roanoke Gas Company dated July
12, 1996 (incorporated herein by reference to Exhibit
10(p)(p) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(q)(q)* Consulting Agreement between W. Bolling Izard
and Roanoke Gas Company dated January 27, 1997
10(r)(r)* RGC Resources, Inc. Restricted Stock Plan for
Outside Directors
10(s)(s) FTA Gas Transportation Agreement effective
November 1, 1998, between East Tennessee Natural Gas
Company and Roanoke Gas Company
10(t)(t) SST Service Agreement effective November 1,
1997, between Columbia Gas Transmission Corporation and
Roanoke Gas Company
10(u)(u) FSS Service Agreement effective April 1, 1997,
between Columbia Gas Transmission Corporation and
Roanoke Gas Company
10(v)(v) FTS Precedent Agreement effective August 7,
1997, between Columbia Gas Transmission Corporation and
Roanoke Gas Company
24
<PAGE>
10(w)(w) Firm Storage Service Agreement effective March
19, 1997, between Virginia Gas Storage Company and
Roanoke Gas Company
10(x)(x) FTS-2 Service Agreement effective February 1,
1994, between Columbia Gulf Transmission Company and
Bluefield Gas Company
10(y)(y) Firm Transportation Agreement effective
December 31, 1998, between Phoenix Energy Sales Company
and Bluefield Gas Company
10(z)(z)* Agreement for Consulting Services effective
January 26, 1998, between Frank A. Farmer, Jr. and
Roanoke Gas Company
10(a)(a)(a)* Agreement for Consulting Services effective
January 26, 1998, between John H. Parrott and Roanoke
Gas Company
10(b)(b)(b) Master Firm Purchase/Sale Agreement effective
November 1, 1999, between PG&E Energy Trading - Gas
Corporation and Bluefield Gas Company
10(c)(c)(c) First Amendment to the Master Firm
Purchase/Sale Agreement effective November 1, 1999, by
and between Bluefield Gas Company and PG&E Energy
Trading - Gas Corporation
10(d)(d)(d) Master Firm Purchase/Sale Agreement effective
March 1, 1999, between PG&E Energy Trading - Gas
Corporation and Roanoke Gas Company
10(e)(e)(e) First Amendment to the Master Firm
Purchase/Sale Agreement effective October 20, 1999 by
and between Roanoke Gas Company and PG&E Energy Trading
- Gas Corporation
13 1999 Annual Report to Shareholders (such report, except
to the extent incorporated herein by reference, is
being furnished for the information of the Commission
only and is not to be deemed filed as part of this
Annual Report on Form 10-K)
21 Subsidiaries of the Company
25
<PAGE>
23(a) Consent of Deloitte & Touche LLP
23(b) Consent of KPMG LLP
27 Financial Data Schedule
* Management contract or compensatory plan or agreement
required to be filed as an Exhibit to this Form 10-K
pursuant to Item 14(c).
(b) Reports on Form 8-K:
None.
26
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to
be signed on its behalf by the undersigned, thereunto duly authorized.
RGC RESOURCES, INC.
By: s/Roger L. Baumgardner December 15, 1999
Roger L. Baumgardner Date
Vice President, Secretary and
Treasurer
27
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual
Report on Form 10-K has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
s/John B. Williamson, III December 15, 1999 President, Chief Executive Officer
John B. Williamson, III Date and Director
s/Roger L. Baumgardner December 15, 1999 Vice President, Secretary and
Roger L. Baumgardner Date Treasurer (Principal Accounting
Officer)
s/Lynn D. Avis December 15, 1999 Director
Lynn D. Avis Date
s/Abney S. Boxley, III December 15, 1999 Director
Abney S. Boxley, III Date
s/Frank T. Ellett December 15, 1999 Director
Frank T. Ellett Date
s/Frank A. Farmer, Jr. December 15, 1999 Chairman of the Board, Director
Frank A. Farmer, Jr. Date
s/Wilbur L. Hazlegrove December 15, 1999 Director
Wilbur L. Hazlegrove Date
s/J. Allen Layman December 15, 1999 Director
J. Allen Layman Date
s/Thomas L. Robertson December 15, 1999 Director
Thomas L. Robertson Date
s/S. Frank Smith December 15, 1999 Director
S. Frank Smith Date
28
<PAGE>
EXHIBIT INDEX
Exhibit No. Description
2 Amended and Restated Agreement and Plan of Merger and
Reorganization (incorporated by reference to Exhibit 2
to Form 8-K filed on July 2, 1999)
3(a) Articles of Incorporation of RGC Resources, Inc.
(incorporated herein by reference to Exhibit 3(a) of
Registration Statement No. 33-67311, on Form S-4, filed
with the Commission on November 13, 1998, and amended
by Amendment No. 5, filed with the Commission on
January 28, 1999.)
3(b) Bylaws of RGC Resources, Inc. (incorporated herein
by reference to Exhibit 3(b) of Registration Statement
No. 33-67311, on Form S-4, filed with the Commission on
November 13, 1998, and amended by Amendment No. 5,
filed with the Commission on January 28, 1999.)
4(a) Specimen copy of certificate for RGC Resources, Inc.
common stock, $5.00 par value (incorporated herein by
reference to Exhibit 3(b) of Registration Statement No.
33-67311, on Form S-4, filed with the Commission on
November 13, 1998, and amended by Amendment No. 5,
filed with the Commission on January 28, 1999.)
4(b) Article I of the Bylaws of RGC Resources (included
in Exhibit 3(b) hereto)
4(c) Instruments defining the rights of holders of
long-term debt (incorporated herein by reference to
Exhibit 4(c) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1991)
10(a) Firm Transportation Agreement between East
Tennessee Natural Gas Company and Roanoke Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(a) of the Annual Report on Form
10-K for the fiscal year ended September 30, 1994)
10(b) Interruptible Transportation Agreement between East
Tennessee Natural Gas Company and Roanoke Gas Company
dated July 1, 1991 (incorporated herein by reference to
Exhibit 10(b) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(c) NTS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
October 25, 1994 (incorporated herein by reference to
Exhibit 10(c) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(d) SIT Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 30, 1993 (incorporated herein by reference to
Exhibit 10(d) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
<PAGE>
10(e) FSS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(e) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(f) FTS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(f) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(g) SST Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(g) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(h) ITS Service Agreement between Columbia Gas
Transmission Corporation and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(h) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(i) FTS-1 Service Agreement between Columbia Gulf
Transmission Company and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(i) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(j) ITS-1 Service Agreement between Columbia Gulf
Transmission Company and Roanoke Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(j) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(k) Gas Transportation Agreement, for use under FT-A
rate schedule, between Tennessee Gas Pipeline Company
and Roanoke Gas Company dated November 1, 1993
(incorporated herein by reference to Exhibit 10(k) of
the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
10(l) Gas Transportation Agreement, for use under IT rate
schedule, between Tennessee Gas Pipeline Company and
Roanoke Gas Company dated September 1, 1993
(incorporated herein by reference to Exhibit 10(l) of
the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
10(m) Gas Storage Contract under rate schedule FS
(Production Area) Bear Creek II between Tennessee Gas
Pipeline Company and Roanoke Gas Company dated November
1, 1993 (incorporated herein by reference to Exhibit
10(m) of the Annual Report on Form 10-K for the fiscal
year ended September 30, 1994)
<PAGE>
10(n) Gas Storage Contract under rate schedule FS
(Production Area) Bear Creek I between Tennessee Gas
Pipeline Company and Roanoke Gas Company dated
September 1, 1993 (incorporated herein by reference to
Exhibit 10(n) of the Annual Report on Form 10-K for the
fiscal year ended September 30, 1994)
10(o) Certificate of Public Convenience and Necessity for
Bedford County dated February 21, 1966 (incorporated
herein by reference to Exhibit 10(o) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(p) Certificate of Public Convenience and Necessity for
Roanoke County dated October 19, 1965 (incorporated
herein by reference to Exhibit 10(p) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(q) Certificate of Public Convenience and Necessity for
Botetourt County dated August 30, 1966 (incorporated
herein by reference to Exhibit 10(q) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(r) Certificate of Public Convenience and Necessity for
Montgomery County dated July 8, 1985 (incorporated
herein by reference to Exhibit 10(r) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(s) Certificate of Public Convenience and Necessity for
Tazewell County dated March 25, 1968 (incorporated
herein by reference to Exhibit 10(s) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(t) Certificate of Public Convenience and Necessity for
Franklin County dated September 8, 1964 (incorporated
herein by reference to Exhibit 10(t) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(u) Ordinance of the Town of Bluefield, Virginia dated
August 25, 1986 (incorporated herein by reference to
Exhibit 10(u) of Registration Statement No. 33-36605,
on Form S-2, filed with the Commission on August 29,
1990, and amended by Amendment No. 1, filed with the
Commission on September 19, 1990)
10(v) Ordinance of the City of Bluefield, West Virginia
dated as of August 23, 1979 (incorporated herein by
reference to Exhibit 10(v) of Registration Statement
No. 33-36605, on Form S-2, filed with the Commission on
August 29, 1990, and amended by Amendment No. 1, filed
with the Commission on September 19, 1990)
<PAGE>
10(w) Resolution of the Council for the Town of
Fincastle, Virginia dated June 8, 1970 (incorporated
herein by reference to Exhibit 10(f) of Registration
Statement No. 33-11383, on Form S-4, filed with the
Commission on January 16, 1987)
10(x) Resolution of the Council for the Town of
Troutville, Virginia dated November 4, 1968
(incorporated herein by reference to Exhibit 10(g) of
Registration Statement No. 33-11383, on Form S-4, filed
with the Commission on January 16, 1987)
10(y)* Consulting Agreement between Albert W. Buckley and
Roanoke Gas Company dated February 20, 1992
(incorporated herein by reference to Exhibit 10(b)(b)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1992)
10(z)* Consulting Contract between A. Anson Jamison and
Roanoke Gas Company dated March 27, 1990 (incorporated
herein by reference to Exhibit 10(c)(c) of Registration
Statement No. 33-36605, on Form S-2, filed with the
Commission on August 29, 1990, and amended by Amendment
No. 1, filed with the Commission on September 19, 1990)
10(a)(a) Contract between Roanoke Gas Company and
Diversified Energy Services, Inc. dated December 18,
1978 (incorporated herein by reference to Exhibit
10(e)(e) of Registration Statement No. 33-36605, on
Form S-2, filed with the Commission on August 29, 1990,
and amended by Amendment No. 1, filed with the
Commission on September 19, 1990)
10(b)(b) Service Agreement between Bluefield Gas Company
and Commonwealth Public Service Corporation dated
January 1, 1981 (incorporated herein by reference to
Exhibit 10(f)(f) of Registration Statement No.
33-36605, on Form S-2, filed with the Commission on
August 29, 1990, and amended by Amendment No. 1, filed
with the Commission on September 19, 1990)
10(c)(c)* Retirement Payment Agreement between Arthur T.
Ellett and Roanoke Gas Company dated April 6, 1972
(incorporated herein by reference to Exhibit 10(g)(g)
of Registration Statement No. 33-36605, on Form S-2,
filed with the Commission on August 29, 1990, and
amended by Amendment No. 1, filed with the Commission
on September 19, 1990)
10(d)(d)* Consulting Services Agreement between Edward C.
Dunbar and Roanoke Gas Company dated February 25, 1991
(incorporated herein by reference to Exhibit 10(h)(h)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1991)
10(e)(e)* Consultation Contract between Gordon C. Willis
and Roanoke Gas Company dated April 29, 1991
(incorporated herein by reference to Exhibit 10(I)(I)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1991)
<PAGE>
10(f)(f) Gas Storage Contract under rate schedule FS
(Market Area) Portland between Tennessee Gas Pipeline
Company and Roanoke Gas Company dated November 1, 1993
(incorporated herein by reference to Exhibit 10(k)(k)
of the Annual Report on Form 10-K for the fiscal year
ended September 30, 1994)
10(g)(g) FTS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(l)(l) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(h)(h) ITS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(m)(m) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(i)(i) FSS Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(n)(n) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(j)(j) SST Service Agreement between Columbia Gas
Transmission Corporation and Bluefield Gas Company
dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(o)(o) of the Annual Report on
Form 10-K for the fiscal year ended September 30, 1994)
10(k)(k) FTS-1 Service Agreement between Columbia Gulf
Transmission Company and Bluefield Gas Company dated
November 1, 1993 (incorporated herein by reference to
Exhibit 10(p)(p) of the Annual Report on Form 10-K for
the fiscal year ended September 30, 1994)
10(l)(l)* RGC Resources Key Employee Stock Option Plan
(incorporated herein by reference to Exhibit 4(c) of
Registration Statement No. 333-02455, Post Effective
Amendment on Form S-8, filed with the Commission on
July 2, 1999.)
<PAGE>
10(m)(m)* RGC Resources, Inc. Stock Bonus Plan
10(n)(n) Gas Franchise Agreement between the Town of
Vinton, Virginia, and Roanoke Gas Company dated July 2,
1996 (incorporated herein by reference to Exhibit
10(n)(n) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(o)(o) Gas Franchise Agreement between the City of
Salem, Virginia, and Roanoke Gas Company dated July 9,
1996 (incorporated herein by reference to Exhibit
10(o)(o) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(p)(p) Gas Franchise Agreement between the City of
Roanoke, Virginia, and Roanoke Gas Company dated July
12, 1996 (incorporated herein by reference to Exhibit
10(p)(p) of Annual Report on Form 10-K for the fiscal
year ended September 30, 1996)
10(q)(q)* Consulting Agreement between W. Bolling Izard
and Roanoke Gas Company dated January 27, 1997
10(r)(r)* RGC Resources, Inc. Restricted Stock Plan for
Outside Directors
10(s)(s) FTA Gas Transportation Agreement effective
November 1, 1998, between East Tennessee Natural Gas
Company and Roanoke Gas Company
10(t)(t) SST Service Agreement effective November 1,
1997, between Columbia Gas Transmission Corporation and
Roanoke Gas Company
10(u)(u) FSS Service Agreement effective April 1, 1997,
between Columbia Gas Transmission Corporation and
Roanoke Gas Company
10(v)(v) FTS Precedent Agreement effective August 7,
1997, between Columbia Gas Transmission Corporation and
Roanoke Gas Company
10(w)(w) Firm Storage Service Agreement effective March
19, 1997, between Virginia Gas Storage Company and
Roanoke Gas Company
10(x)(x) FTS-2 Service Agreement effective February 1,
1994, between Columbia Gulf Transmission Company and
Bluefield Gas Company
10(y)(y) Firm Transportation Agreement effective
December 31, 1998, between Phoenix Energy Sales Company
and Bluefield Gas Company
10(z)(z)* Agreement for Consulting Services effective
January 26, 1998, between Frank A. Farmer, Jr. and
Roanoke Gas Company
<PAGE>
10(a)(a)(a)* Agreement for Consulting Services effective
January 26, 1998, between John H. Parrott and Roanoke
Gas Company
10(b)(b)(b) Master Firm Purchase/Sale Agreement effective
November 1, 1999, between PG&E Energy Trading - Gas
Corporation and Bluefield Gas Company
10(c)(c)(c) First Amendment to the Master Firm
Purchase/Sale Agreement effective November 1, 1999, by
and between Bluefield Gas Company and PG&E Energy
Trading - Gas Corporation
10(d)(d)(d) Master Firm Purchase/Sale Agreement effective
March 1, 1999, between PG&E Energy Trading - Gas
Corporation and Roanoke Gas Company
10(e)(e)(e) First Amendment to the Master Firm
Purchase/Sale Agreement effective October 20, 1999 by
and between Roanoke Gas Company and PG&E Energy Trading
- Gas Corporation
13 1999 Annual Report to Shareholders (such report, except
to the extent incorporated herein by reference, is
being furnished for the information of the Commission
only and is not to be deemed filed as part of this
Annual Report on Form 10-K)
21 Subsidiaries of the Company
23(a) Consent of Deloitte & Touche LLP
23(b) Consent of KPMG LLP
27 Financial Data Schedule
* Management contract or compensatory plan or agreement
required to be filed as an Exhibit to this Form 10-K
pursuant to Item 14(c).
Exhibit 10(m)(m)
RGC RESOURCES, INC.
STOCK BONUS
PLAN
Policy Statement: The purpose of RGC Resources, Inc.'s (the "Company") Stock
Bonus Plan ("Stock Bonus Plan") is to allow the Board of Directors to reward
individual or collective superior performance that has resulted in enhanced
stockholder value or returns, and to encourage increased ownership of Company
stock by officers and management.
Administration: The Stock Bonus Plan shall be administered by the Board of
Directors Compensation Committee. The Committee shall consider recommendations
from the Company President before making its bonus award proposal to the Board
of Directors. The President shall consider recommendations from the other
officers of the Company when making recommendations to the Compensation
Committee. The Committee bonus award proposals shall be subject to approval by
the Board of Directors.
Timetable: The Compensation Committee shall present its stock bonus award
proposal to the Board of Directors at the Boards' annual meeting in January of
each year. The Compensation Committee may, for exceptional employee performance,
recommend stock bonus awards at times other than and in addition to the normal
January proposal.
Financial Operating Impact: The Committee shall consider the potential income
statement impact of its stock bonus award proposals and include a statement on
the anticipated impact in its proposal to the Board of Directors.
Plan Revision: The Stock Bonus Plan may be revised, temporarily suspended, or
revoked by the Board of Directors upon recommendation of the Compensation
Committee.
Non Discrimination: The Officers, President and Compensation Committee of the
Company will make their recommendations and proposals for stock bonus awards
without respect to race, color, age, sex or religious preference. The final
decision of the Board of Directors will likewise be non discriminating.
Eligibility: The Stock Bonus Plan is intended as a reward for superior
performance of the officers and managers of the Company. However, individual non
management employees of the Company may be considered for stock bonus awards
when circumstances do not allow adequate recognition of performance through
existing compensation sources or plans. For example, stock certificates as
perfect attendance recognition may be given to all employees of the Company.
<PAGE>
Officer Ownership Policy: Officers of the Company are encouraged to own a
position in the Company's Stock of at least 50 percent of the value of their
annual salary. To promote this policy all bonuses for officers with stock
ownership positions below the 50 percent ownership level should receive no less
than 50 percent of any performance bonuses in the form of Company stock or stock
options unless otherwise approved by the Compensation Committee.
Stock Options: The Compensation Committee and Board of Directors may use stock
options in the place of or in conjunction with stock bonuses once the Company
has in place an SEC approved non qualified stock option plan.
Adoption: This plan was originally adopted on January 23, 1994 at a meeting of
the Board of Directors of Roanoke Gas Company held at its Corporate Offices at
519 Kimball Avenue, N.E., Roanoke, Virginia 24016. RGC Resources, Inc. adopted
this amended and restated plan on August 23, 1999 at a meeting held at its
corporate offices at 519 Kimball Avenue, N.E., Virginia 24016.
s/Roger L. Baumgardner
Corporate Secretary
2
Exhibit 10(r)(r)
AMENDED AND RESTATED
RESTRICTED STOCK PLAN
FOR OUTSIDE DIRECTORS
OF RGC RESOURCES, INC.
1. Assumption of Plan by RGC Resources, Inc.; Purpose
This Amended and Restated Restricted Stock Plan for Outside Directors of
RGC Resources, Inc. (as successor to Roanoke Gas Company) (the "Plan") amends
and restates the Roanoke Gas Company Restricted Stock Plan for Outside Directors
(the "Original Plan"), which was adopted by the Board of Directors of Roanoke
Gas Company ("Roanoke Gas") on September 23, 1996, and became effective as of
such date upon approval of the Original Plan by the shareholders of Roanoke Gas
Company on Juanuary 27th, 1997. The amendment and restatement of the Original
Plan and the assumption of liabilities hereunder are undertaken by RGC
Resources, Inc. (the "Company"), as successor to Roanoke Gas, in connection with
the reorganization of Roanoke Gas into a holding company structure (the
"Reorganization") as part of which Roanoke Gas became a wholly-owned subsidiary
of RGC Resources as of July 1, 1999. The Reorganization is being effected
pursuant to an Agreement and Plan of Merger dated as of September 28, 1998 (the
"Merger Agreement"), which was approved by the stockholders of Roanoke Gas on
March 31, 1999, and pursuant to which Roanoke Gas and RGC Resources agreed that
from and after the effective date of the Merger provided for therein, this Plan
would utilize RGC Resources common stock instead of Roanoke Gas common stock.
Accordingly, as of the effective date hereof, RGC Resources assumes the
obligations of Roanoke Gas under the Original Plan and undertakes to carry out
all responsibilities of the Company specified herein. Roanoke Gas consents and
agrees to the assumption by RGC Resources of the Roanoke Gas' responsibilities
under this Plan.
The Amended and Restated Restricted Stock Plan for Outside Directors of
RGC Resources, Inc. is intended to advance the interests of RGC Resources, Inc.,
its shareholders, and its affiliates by encouraging and enabling outside
directors upon whose judgment, initiative and effort the Company relies for the
successful conduct of its business, to acquire and retain a proprietary interest
in the Company by ownership of its stock.
2. Definitions
The following definitions apply to this Plan and to the Election Forms:
(a) Beneficiary or Beneficiaries means a person or persons or other
entity designated on a Beneficiary Designation Form by a
Participant to receive Company Stock under this Plan if the
Participant dies. If there is no valid designation by the
Participant, or if the designated Beneficiary or Beneficiaries
fail to survive the Participant, the Participant's Beneficiary is
the first of the following who survives
<PAGE>
the Participant: the Participant's spouse (the person legally
married to the Participant when the Participant dies); the
Participant's children in equal shares; the Participant's other
surviving issue, per stirpes; the Participant's parents; and the
Participant's estate.
(b) Beneficiary Designation Form means a form acceptable to the
Chairman of the Committee or his designee used by a Participant
according to this Plan to name the Beneficiary or Beneficiaries
who will receive all the Company Stock under this Plan if the
Participant dies.
(c) Board means the Board of Directors of the Company.
(d) Change in Control means a change in control of a nature that
would be required to be reported (assuming such event has not
been "previously reported") in response to Item 1(a) of the
Current Report on Form 8-K, as in effect on the date hereof,
pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934, as amended ("Exchange Act"); provided that, notwithstanding
the foregoing and without limitation, such a change in control
shall be deemed to have occurred at such time as (i) any Person
is or becomes the "beneficial owner" (as defined in Rule 13d-3 or
Rule 13d-5 under the Exchange Act as in effect on the date
hereof), directly or indirectly, of 20% or more of the combined
voting power of the Company's voting securities; (ii) the
incumbent Board ceases for any reason to constitute at least the
majority of the Board, provided that any person becoming a
director subsequent to the date hereof whose election, or
nomination for election by the Company's shareholders, was
approved by a vote of at least 75% of the directors comprising
the incumbent Board (either by a specific vote or by approval of
the proxy statement of the Company in which such person is named
as a nominee for director, without objection to such nomination)
shall be, for purposes of this clause (ii), considered as though
such person were a member of the incumbent Board; (iii) all or
substantially all of the assets of the Company are sold,
transferred or conveyed by any means, including, but not limited
to, direct purchase or merger, if the transferee is not
controlled by the Company, control meaning the ownership of more
than 50% of the combined voting power of such entity's voting
securities; or (iv) the Company is merged or consolidated with
another corporation or entity and as a result of such merger or
consolidation less than 75% of the outstanding voting securities
of the surviving or resulting corporation or entity shall be
owned in the aggregate by the former shareholders of the Company.
Notwithstanding anything in the foregoing to the contrary, no
Change in Control shall be deemed to have occurred for purposes
of the Plan by virtue of any transaction (i) which results in a
Participant or a group of Persons which includes the Participant,
acquiring, directly or indirectly, 20% or more of the combined
voting power of the Company's voting securities; or (ii) which
2
<PAGE>
results in the Company, any affiliate of the Company or any
profit-sharing plan, employee stock ownership plan or employee
benefit plan of the Company or any of its affiliates (or any
trustee of or fiduciary with respect to any such plan acting in
such capacity) acquiring, directly or indirectly, 20% or more of
the combined voting power of the Company's voting securities.
(e) Committee means the Compensation Committee of the Board.
(f) Company means RGC Resources, Inc.
(g) Company Stock means the common stock, $5 par value of the
Company.
(h) Compensation means a Member's Retainer Fee for the Deferral Year.
(i) Election Form means a document governed by the provisions of
Section 4 of this Plan, including the portion that is the related
Beneficiary Designation Form, that applies to all of that
Participant's shares of Restricted Stock under the Plan.
(j) Directors means those duly named members of the Board.
(k) Election Date means the date established by this Plan as the date
before which a Member must submit a valid Election Form to the
Committee. For each Plan Year, the Election Date is July 31.
However, for an individual who becomes a Member during a Plan
Year, the Election Date is the thirtieth day following the date
that he becomes a Member. Despite the two preceding sentences,
the Committee may set an earlier date as the Election Date for
any Plan Year.
(l) Employee means an individual with whom either the Company or its
affiliates has an employer-employee relationship as determined
for Federal Insurance Contribution Act purposes and Federal
Unemployment Tax Act purposes, including subsection 3401(c) of
the Internal Revenue Code and regulations promulgated under that
subsection.
(m) Members means Directors who are not simultaneously Employees.
(n) Participant means a Member during the Plan Year.
(o) Plan means the Company's Restricted Stock Plan for Outside
Directors.
(p) Plan Year means a fiscal year ending September 30 during which
the Plan is in effect and during which a Member receives a
portion or all of his Compensation in Restricted Stock hereunder.
3
<PAGE>
(q) Person means person within the meaning of Sections 3(a)(9) and
13(d)(3) of the Securities Exchange Act of 1934.
(r) Restricted Stock means Company Stock issued to Participants under
the Plan and subject to the vesting and nontransferability
provision of the Plan.
(s) Retainer Fee means that portion of a Director's Compensation that
is fixed and paid without regard to his attendance at meetings.
3. Restricted Stock Payments
On the first day of each month during each Plan Year, forty percent
(40%) of a Participant's Compensation for the month shall be paid in shares of
Restricted Stock of the Company. In determining the number of shares to be
issued pursuant to the preceding sentence, the Fair Market Value of the
Restricted Stock under the Plan shall, for each calendar month, be calculated
based on the closing sales price of the Company's common stock on the Nasdaq-NMS
on the first day of the month, if the first day of the month is a trading day,
or if not, the first trading day prior to the first day of the month.
4. Additional Restricted Stock Election
(a) Before each Plan Year's Election Date, each Member will be
provided with an Election Form and a Beneficiary Designation
Form. Subject to approval of the Board or the Committee, a Member
may elect to receive up to 100% of his Compensation for the Plan
Year in Restricted Stock.
(b) An additional Restricted Stock election is valid when an Election
Form is completed, signed by the electing Member, received by the
Committee Chairman and approved by the Board or the Committee on
or before the Election Date.
(c) A Member may not revoke or amend an Election Form after the
Election Date for the Plan Year. Any revocation before an
Election Date is the same as a failure to submit an Election
Form. Any writing signed by a Member expressing an intention to
revoke his Election Form and delivered to a member of the
Committee before the close of business on the relevant Election
Date is a revocation.
5. Vesting
The shares of Restricted Stock of the Company issued under Section 3 and
Section 4 of this Plan shall vest only in the case of a Participant's death,
disability, retirement (including not standing for reelection to the Board), or
in the event of a Change in Control of the Company. There shall be no option to
take cash in lieu of stock upon vesting of shares under this Plan.
4
<PAGE>
6. Nontransferability
No share of Restricted Stock issued hereunder may be sold, transferred,
assigned, or pledged by the Participant until such share has vested in
accordance of the terms of this Plan. At the time the Restricted Stock vests,
and, if the Participant has been issued legended certificates of Restricted
Stock, upon the return of such certificates to the Company, a certificate for
such vested shares shall be delivered to the Participant (or the Beneficiary
designated by the Participant in the event of death), free of restrictive legend
(other than any required by applicable securities laws). Notwithstanding the
foregoing, no vested shares may be sold, transferred, assigned or pledged by the
Participant (or the Beneficiary) unless six months have elapsed between the date
of grant of the shares of Restricted Stock which have vested and the date of the
sale, transfer, assignment or pledge of such vested shares.
7. Forfeiture
The shares of Restricted Stock issued under Section 3 and Section 4 of
this Plan shall be forfeited to the Company upon a Member's voluntary
resignation during his term on the Board, or removal for cause as a Director.
8. Stock Certificates
Stock certificates representing the Restricted Stock, together with
stock powers or other instruments of assignment, each endorsed in blank, which
will permit transfer to the Company of all or any portion of the Restricted
Stock evidenced by such certificate in the event it is forfeited, shall be
deposited by the recipient with the Company.
9. Rights as Shareholder
Subject to the terms of this Plan, the Participant, as the owner of the
Restricted Stock, shall have all rights of a shareholder including, but not
limited to, voting rights, the right to receive cash or stock dividends thereon,
and the right to participate in any capital adjustment of the Company. Any
distribution with the respect to shares of Restricted Stock other than in the
form of cash shall be held by the Company, and shall be subject to the same
restrictions as the shares with respect to which such distributions were made.
The Committee may require that any or all dividends or other distributions paid
on shares of Restricted Stock shall be automatically sequestered and may be
reinvested on an immediate or deferred basis in additional shares of Company
stock, which may be subject to the same restrictions as the Restricted Stock or
such other restrictions as the Committee may determine.
10. Claims against Participant's Restricted Stock
The shares of Restricted Stock issued pursuant to this Plan are not
subject in any manner to anticipation, alienation, sale, transfer, assignment,
pledge, encumbrance, or charge, and any attempt to do so is void. Moreover, the
shares are not subject to attachment or legal process for a
5
<PAGE>
Participant's debts or other obligations. Nothing contained in this Plan gives
any Participant any interest, lien, or claim against any specific asset of the
Company.
11. Amendment or Termination
The Board may at any time suspend or terminate the Plan or may amend it
from time to time in such respects as the Board may deem advisable in order that
the Restricted Stock issued hereunder may conform to any changes in the law or
any other respect with which the Board may deem to be in the best interests of
the Company. No such suspension, termination or amendment of the Plan shall
require approval of the shareholders unless shareholder approval is required by
applicable law or stock exchange requirements.
12. Notices
Notices and elections under this Plan must be in writing. A notice or
election is deemed delivered if it is delivered personally or if it is mailed by
registered or certified mail to the person at his last known business address.
13. Waiver
The waiver of a breach of any provision in this Plan does not operate as
and may not be construed as a waiver of any later breach.
14. Construction
This Plan is created, adopted, and maintained according to the laws of
the Commonwealth of Virginia (except its choice-of-law rules). It is governed by
those laws in all respects. Headings and captions are only for convenience; they
do not have substantive meaning. If a provision of this Plan is not valid or not
enforceable, that fact in no way affects the validity or enforceability of any
other provision. Use of the one gender includes all, and the singular and plural
include each other.
15. Adjustments For Changes in Capitalization
In the event of a reorganization, recapitalization, stock split, stock
dividend, combination of shares, rights offer, liquidation, dissolution, merger,
consolidation, spin off, sale of assets, payment of an extraordinary cash
dividend, or any other change in or affecting the corporate structure or
capitalization of the Company, the Committee shall make appropriate adjustments
in the number, price or kind of shares of Restricted Stock authorized to be
issued under this Plan, and in any outstanding shares of Restricted Stock issued
hereunder.
6
<PAGE>
16. Withholding Taxes
Whenever the Company is required to issue or transfer shares of
Restricted Stock under this Plan, the Company shall have the right to require
the recipient of such Restricted Stock to remit to the Company an amount
sufficient to satisfy any federal, state or local withholding tax liability
prior to the delivery of any certificate for such shares. Whenever under the
Plan payments are to be made in cash, such payments shall be net of an amount
sufficient to satisfy any federal, state or local withholding tax liability.
17. Indemnification
The Company shall indemnify and hold harmless each person who is or has
been a member of the Committee, or of the Board of Directors, against and from
any and all loss, expense, liability, or costs (including reasonable attorneys'
fees) that may be imposed upon or reasonably incurred by him in connection with
or resulting from any claim, action, suit or proceedings to which he may be a
party or in which he may be involved by reason of any action taken or failure to
act under the Plan, and against and from any and all amounts paid by him in
settlement thereof with the Company's approval or paid by him in satisfaction of
a final judgment against him in such action, suit, or proceedings, provided he
shall give the Company an opportunity, at its own expense to handle and defend
the same before he undertakes to handle defense on his own behalf. The right of
indemnification herein set forth shall not be exclusive of any other rights of
indemnification to which such person may be entitled under the Company's
Articles of Incorporation, or code or regulations, as a matter of law, or
otherwise, or any power that the Company may have to indemnify him or to hold
him harmless. It is the Company's intention that all expenses incurred in
connection with the administration of the Plan shall be borne by the Company
rather than by any member of the Committee or the Board of Directors.
18. Effective Date of the Plan
The Plan is subject to approval by the shareholders of the Company. The
Plan will become effective on the date so approved.
19. Shares Subject to the Plan
The aggregate number of shares of Company Stock which may be issued in
respect to Restricted Stock shall not exceed 50,000 shares. All shares
distributed pursuant to the Plan shall consist of authorized but unissued shares
of the Company.
20. Power of the Committee
The Committee shall have authority to interpret conclusively the
provisions of the Plan, to adopt such rules and regulations for carrying out the
Plan as it may deem advisable, to decide conclusively all questions of fact
arising in the application of the Plan, and to make all other
7
<PAGE>
determinations necessary or advisable for the administration of the Plan. All
decisions and acts of the Committee shall be final and binding upon all affected
Plan Participants.
21. Miscellaneous
Transactions under this Plan are intended to comply with Rule 16b-3 (or
its successor), as amended from time to time, promulgated pursuant to the
Securities Exchange Act of 1934. Therefore, to the extent any provision of the
Plan or action by a person administering the Plan fails to so comply, it shall
be deemed null and void ab initio to the extent permitted by law and deemed
advisable by the Committee.
As evidence of its adoption and approval of this Plan and approval of
the terms and conditions of each Participant transaction hereunder, the Board
has caused this document to be executed on its behalf, and on behalf of the
Company, this 2nd day of July, 1999.
By s/John B. Williamson, III
President and CEO of RGC
Resources, Inc.
8
Exhibit 10(b)(b)(b)
PG&E Energy Trading-Gas Corporation is not the same company as Pacific
Gas and Electric Company, the utility. PG&E Energy Trading-Gas
Corporation is not regulated by the California Public Utilities
Commission, and you do not have to buy PG&E Energy Trading-Gas
Corporation's products in order to continue to receive quality
regulated services from the utility.
MASTER FIRM PURCHASE/SALE AGREEMENT
between
PG&E ENERGY TRADING-GAS CORPORATION
("Company")
and
BLUEFIELD GAS COMPANY
("Customer")
Gas
dated
November 1, 1999
<PAGE>
PG&E ENERGY TRADING-GAS CORPORATION
MASTER FIRM PURCHASE/SALE AGREEMENT
PG&E ENERGY TRADING-GAS CORPORATION, a California corporation ("Company"), and
BLUEFIELD GAS COMPANY, a __________________________________ ("Customer"),
referred to collectively as the 'Parties,' enter into this Master Firm
Purchase/Sale Agreement (together with all Transactions, collectively, this
'Agreement') effective as of the 1st day of November, 1999 (the 'Effective
Date'). The PG&E Energy Trading-Gas Corporation General Provisions set forth in
Appendix "1" shall apply to this Agreement.
ARTICLE 1. TERM This Agreement shall govern all Transactions for the firm
purchase or sale of gas and be in effect for a term of one year from the
Effective Date. It shall then continue in effect from Month to Month, unless
terminated by either Party upon 30 Days prior written notice to the other Party;
provided, this Agreement shall continue to apply to all Transactions then in
effect until all Transactions are completed. Termination of this Agreement in
all instances shall be subject to Section 8.4.
ARTICLE 2. SCOPE OF AGREEMENT 2.1. Scope of Agreement. Company and Customer from
time to time during the term hereof may, but are not obligated to, enter into
Transactions for the firm purchase and sale of Gas to which this Agreement shall
apply. Each Transaction shall be effectuated and evidenced as set forth in this
Article 2 and shall constitute a part of this Agreement and all Transactions,
together with this Agreement, shall constitute a single integrated agreement. It
is acknowledged that the Parties are relying upon the fact that all
Transactions, together with this Agreement, will form a single integrated
agreement and that the Parties would not otherwise enter into any Transactions.
Each Transaction shall be construed as one with this Agreement and any
discrepancy between this Agreement and a Transaction shall be resolved in favor
of the Transaction. Each Transaction shall provide whether the Transaction is
based upon DCQ quantity obligations or MinMQ or MinDQ and MaxDQ quantity
obligations, in which case the applicable alternative definitions and provisions
set forth in this Agreement shall apply.
2.2. Transaction Procedures. It is the intent of the Parties to facilitate
Transactions in accordance with the agreed procedures in this Article 2 and
assure that such Transactions are valid and enforceable as a result of the use
of these procedures for the mutual benefit of the Parties. Any Transaction may
be formed and effectuated (i) by a written paper-based Transaction Agreement in
the form of a Confirmation as set out on Exhibit B-1 executed by the Parties
(including by facsimile and/or counterparts) or (ii) in a recorded telephone
conversation between the Parties occurring on any Business Day during the
Pricing Hours whereby an offer and acceptance shall constitute the agreement of
the Parties to a Transaction as evidenced by the Transaction Tape; provided,
each Party may stipulate by prior notice to the other Party that any particular
contemplated Transaction may be effectuated and formed only by means of
procedure (i) above. The Parties shall be legally bound by each Transaction from
the time they agree to its terms in accordance with this Article 2 and
acknowledge that each Party will rely thereon in doing business related to the
Transaction. The Transaction Tape is adopted by the Parties as a means by which
a Transaction is reduced to tangible form, and the Parties to a Transaction are
identified and authenticate a Transaction. Any Transaction formed and
effectuated pursuant to the foregoing shall be considered to be a .writing' or
'in writing' and to have been 'signed' and any Transaction Tape shall be
considered to constitute an 'original' document evidencing the Transaction. Each
Party consents to and has obtained any necessary consent of its employees to the
recording of its employees' telephone conversations without any further notice.
2.3. Equipment and Transaction Tape. Company shall at its expense maintain
equipment necessary to regularly record Transactions on Transaction Tapes and
retain Transaction Tapes in such manner as to protect its business records from
improper access; provided, Company shall not be liable for any malfunction of
equipment or the operation thereof in respect of any Transaction WITHOUT REGARD
TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING, WITHOUT LIMITATION, THE
NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT,
OR ACTIVE OR PASSIVE. No Transaction shall be vitiated should a malfunction
occur in equipment regularly utilized for recording Transactions or retaining
Transaction Tapes or the operation thereof, and in such event, the Transaction
shall be evidenced by the written and computer records of the Parties concerning
the Transaction made contemporaneously with the telephone conversation.
2.4. Confirmations. In addition to, but not in lieu of, the foregoing, the
Parties agree that Company may confirm a recorded telephonic Transaction by
forwarding to Customer a facsimile Confirmation in the form set out on Exhibit B
and that a reasonable time for the receipt by Customer of a Confirmation is
within 24 hours of the Transaction formation. Company does hereby adopt its
letterhead, including its address, as its signature on any Confirmation as the
identification of Company and authentication by Company of the Confirmation, and
such letterhead shall be sufficient to verify that Company originated the
Confirmation. The Parties agree that any objections to the contents of the
Confirmation shall be made in writing on or before the Confirm Deadline for all
purposes hereunder and at law. Upon issuance of a Confirmation and the passage
of the Confirm Deadline, if no objection to the Confirmation has been then
received, the Confirmation shall be conclusive evidence of the Transaction made
the subject matter thereof and the final expression of all of its terms.
2.5. Enforcement of Transactions. The Parties agree not to contest or assert a
defense to the validity or enforceability of telephonic Transactions entered
into in accordance with this Agreement under laws relating to (I) whether
certain agreements are to be in writing or signed by the Party to be thereby
bound or (ii) the authority of any employee of the Party if the employee name is
stated in the Transaction Tape.
ARTICLE 3. QUANTITY OBLIGATIONS 3.1. Seller's Sales Obligation. Seller shall
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Gas Day a quantity of Gas equal to the quantity property requested by Buyer
up to the DCQ or MaxDQ, if applicable (" Requested Quantity"). Unless otherwise
agreed nothing in this Agreement, and in particular this Article 3, shall
require or permit either Party to Schedule Gas at a point other than a Delivery
Point or in excess of the DCO, Maximum Daily Delivery Point Quantity or MaxDQ,
as applicable.
3.2. Seller's Failure to Schedule. If on any Gas Day Seller fails to Schedule
Buyer's Requested Quantity, then such occurrence shall constitute a "Deficiency
Default" and "Seller's Deficiency Quantity" shall be the numerical difference
between Buyer's Requested Quantity and the amount of Gas Scheduled for such Gas
Day. In the event of a Seller's Deficiency Default, Seller shall pay Buyer the
sum of the following: (1) an amount equal to the product of the Seller's
Deficiency Quantity multiplied by the Replacement Price Differential, plus (ii)
liquidated damages equal to $0.15 per MMBtu multiplied by Seller's Deficiency
Quantity to cover Buyer's administrative and operational costs. During any Month
in which Settees nonperformance continues for a period of five consecutive Gas
Days Buyer may elect upon notice to Seller, without liability, not to recommence
Scheduling Gas hereunder for the remainder of such Month, but for no longer
period. Subject to offset pursuant to Section 3.5, payment to Buyer shall be
made on the later of the 25th Day of the Month or ten days after Seller receives
Buyer's statement for same.
3.3. Buyer's Purchase Obligation. Buyer shall Schedule, or cause to be
Scheduled, at the Delivery Point(s) on a firm basis each Gas Day a quantity of
Gas equal to the DCQ; provided, (I) if the MinMQ is applicable to a Transaction,
Buyer shall Schedule, or cause to be Scheduled, at the Delivery Point(s) on a
firm basis each Month a minimum quantity of Gas equal to the MinMQ and (ii) if
the MinDQ is applicable to a Transaction, Buyer shall
<PAGE>
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Day a minimum quantity of Gas equal to the MinDQ.
3.4. Buyer's Failure to Schedule. If on any Gas Day Buyer fails to Schedule the
DCQ or MinDQ, if applicable, then such occurrence shall constitute a "Buyer's
Deficiency Default" and "Buyer's Deficiency Quantity" shall be the numerical
difference between the DCQ or MinDQ, if applicable, and the quantity of Gas
Scheduled for such Gas Day; provided, if the MinMQ is applicable to a
Transaction, (i) the Buyers Deficiency Default shall occur if Buyer fails to
Schedule the MinMQ for any Month and (ii) the Buyer's Deficiency Quantity shall
be the numerical difference between the MinMQ and the quantity of Gas Scheduled
for such Month. In the event of a Buyers Deficiency Default, Buyer shall pay
Seller the sum of the following: (i) an amount equal to the product of Buyer's
Deficiency Quantity multiplied by the Replacement Price Differential, plus (ii)
liquidated damages equal to $0.15 per MMBtu multiplied by Buyer's Deficiency
Quantity to cover Seller's administrative and operational costs. With respect to
DCQ and MinDQ obligations, during any Month in which Buyer's nonperformance
continues for a period of five consecutive Gas Days Seller may elect upon notice
to Buyer, without liability, not to recommence Scheduling Gas for the remainder
of such Month, but for no longer period. Subject to offset pursuant to Section
3.5 payment to Seller shall be made in accordance with the Financial Matters
provisions set forth in Appendix "l".
3.5. Netting. In the event that Buyer and Seller are each required under this
Agreement to pay an amount in the same Month hereunder, then such amounts with
respect to each Party may be aggregated and the Parties may discharge their
obligations to pay through netting, in which case the Party, if any, owing the
greater aggregate amount may pay to the other Party the difference between the
amounts owed.
ARTICLE 4. DEFAULTS AND REMEDIES 4.1. Early Termination. If a Triggering Event
(defined in Section 4.2) occurs with respect to either Party at any time during
the term of this Agreement, the other Party (the "'Notifying Party") may (i)
upon two Business Days written notice to the first Party, which notice shall be
given no later than 60 Days after the discovery of the occurrence of the
Triggering Event, establish a date on which any or all Transactions selected by
it and this Agreement in respect thereof will terminate ("Early Termination
Date") except as provided in Section 8.4, and (ii) withhold any payments due in
respect of such Transactions; provided, upon the occurrence of any Triggering
Event listed in item (iv) of Section 4.2 as it may apply to any party, all
Transactions and this Agreement in respect thereof shall automatically
terminate, without notice, as if an Early Termination Date had been immediately
declared except as provided in Section 8.4. If an Early Termination Date occurs,
the Notifying Party shall in good faith calculate its damages, including its
associated costs and attorneys' fees, resulting from the termination of the
terminated Transactions (the 'Termination Payment"). The Termination Payment
will be determined by (i) comparing the value of (a) the remaining term,
quantities and prices under each such Transaction had it not been terminated to
(b) the equivalent quantities and relevant market prices for the remaining term
either quoted by a bona fide third party offer or which are reasonably expected
to be available in the market under a replacement contract for each such
Transaction and (ii) ascertaining the associated costs and attorneys' fees. To
ascertain the market prices of a replacement contract the Notifying Party may
consider, among other valuations, any or all of the settlement prices of NYMEX
Gas futures contracts, quotations from leading dealers in Gas swap contracts and
other bona fide third party offers, all adjusted for the length of the remaining
term and the basis differential. All terminated Transactions shall be netted
against each other and upon the netting of all terminated Transactions, if the
calculation of the Termination Payment does not result in damages to the
Notifying Party, the Termination Payment shall be zero. The Notifying Party
shall give the Affected Party (defined in Section 4.2) written notice of the
amount of the Termination Payment, inclusive of a statement showing its
determination. The Affected Party shall pay the Termination Payment to the
Notifying Party within 10 Days of receipt of such notice. At the time for
payment of any amount due under this Article 4, each Party shall pay to the
other Party all additional amounts payable by it pursuant to this Agreement, but
all such amounts shall be netted and aggregated with any Termination Payment
payable hereunder. If the Affected Party disagrees with the calculation of the
Termination Payment, the issue shall be submitted to arbitration pursuant to
this Agreement and the resulting Termination Payment shall be due and payable
within three Days after the award.
4.2. Triggering Event shall mean, with respect to a Party (the "Affected Party")
(i) the failure by the Affected-Party to make, when due, any payment required
under this Agreement ff such failure is not remedied within five Business Days
after written notice of such failure is given to the Affected Party; provided,
the payment is not the subject of a good faith dispute as described in the
Billing and Payment provisions or (ii) any representation or warranty made by
the Affected Party in this Agreement shall prove to have been false or
misleading in any material respect when made or deemed to be repeated or (iii)
the failure by the Affected Party to perform any covenant set forth in this
Agreement (other than its obligations to make any payment or obligations which
are otherwise specifically covered in this Section 4.2 as a separate Triggering
Event), and such failure is not excused by Force Majeure or cured within five
Business Days after written notice thereof to the Affected Party or (iv) the
Affected Party shall (a) make an assignment or any general arrangement for the
benefit of creditors, (b) file a petition or otherwise commence, authorize or
acquiesce in the commencement of a proceeding or cause under any bankruptcy or
similar law for the protection of creditors, or have such petition filed against
it and such proceeding remains undismissed for 30 Days, (c) otherwise become
bankrupt or insolvent (however evidenced) or (d) be unable to pay its debts as
they fall due or (v) Sellers unexcused failure to Schedule the Buyer's Requested
Quantity requested by Buyer for a cumulative period of 30 or more Gas Days in a
12 Month period in any one Transaction or (vi) Buyers unexcused failure to
Schedule the DCQ or MinDQ for a cumulative period of 30 or more Gas Days in a 12
Month period in any one Transaction, or, if applicable, the MinMQ for a
cumulative period of three Months in a 12 Month period in any one Transaction,
or (vii) the occurrence of a Material Adverse Change of the Affected Party;
provided, such Material Adverse Change shall not be considered ff the Affected
Party establishes, and maintains throughout the term hereof, a Letter of Credit
(naming the Notifying Party as the beneficiary) in an amount equal to the sum of
(in each case rounding upwards for any fractional-amount to the next $100,000)
(a) the Notifying Party's Termination Payment plus (b) if the Notifying Party is
Seller, the aggregate of the amounts Seller is entitled to receive under each
Transaction for Gas Scheduled during the 60 Day period preceding the Material
Adverse Change (the amount of said Letter of Credit to be adjusted quarterly to
reflect amounts owing at that point in time) or (viii) the Affected Party fails
to establish, maintain, extend or increase a Letter of Credit when required
pursuant to this Agreement, or after reasonable notice fails to replace the
issuing bank with another bank acceptable to the beneficiary or (ix) with
respect to Company, at any time, Company shall have defaulted on its
indebtedness to third parties resulting in an acceleration of obligations of
Company in excess of $20,000,000 or with respect to Customer, at any time,
Customer shall have defaulted on its indebtedness to third parties, resulting in
an acceleration of obligations of Customer in excess of $500,000.
4.3. Other Events. In the event Buyer under a Transaction is regulated by a
federal, state or local regulatory body, and such body shall disallow all or any
portion of any costs incurred or yet to be incurred by Buyer under any provision
of this Agreement, such action shall not operate to excuse Buyer from
performance of any obligation nor shall such action give rise to any right of
Buyer to any refund or retroactive adjustment of the Contract Price provided in
any Transaction. Notwithstanding the foregoing, if the Affected Party's
activities hereunder become subject to regulation of any kind whatsoever under
any law (other than with respect to New Taxes) to a greater or different extent
than that existing on the Effective Date and such regulation either (i) renders
this Agreement illegal or unenforceable or (ii) materially adversely affects the
business of the Affected Party, with respect to its financial position or
<PAGE>
otherwise, then in the case of (i) above, either Party, and in the case of (ii)
above, only the Affected Party, shall at such time have the right to declare an
Early Termination Date in accordance with the provisions hereof; provided,
notwithstanding the rights of the Parties to declare an Early Termination Date
as above stated, the Affected Party shall be liable for payment of the
Termination Payment calculated by the non-Affected Party as provided in Section
4.l.
4.4. Offset. Each Party reserves to itself all rights, set-offs, counterclaims
and other remedies and defenses consistent with Section 8.3 (to the extent not
expressly herein waived or denied) which such Party has or may be entitled to
arising from or out of this Agreement. All outstanding Transactions and the
obligations to make payment in connection therewith or under this Agreement may
be offset against each other, set off or recouped therefrom.
4.5. Collateral Requirements/General. It is understood and agreed by the Parties
that either Party may request a Letter of Credit or other collateral prior to
consummating any Transaction hereunder; provided, nothing herein shall obligate
any Party to provide such a Letter of Credit or other collateral without having
made an agreement so to do in respect of such Transaction.
ARTICLE 5. FORCE MAJEURE This Article 5 is the sole and exclusive excuse of
performance permitted under this Agreement and all other excuses at law or in
equity are WAIVED to the extent permitted by law. Except with respect to payment
obligations, in the event either Party is rendered unable, wholly or in part, by
Force Majeure to carry out its obligations hereunder, it is agreed that upon
such Party's giving notice and full particulars of such Force Majeure to the
other Party as soon as reasonably possible (such notice to be confirmed in
writing), the obligations of the Party giving such notice, to the extent they
are affected by such event, shall be suspended from the inception and during the
continuance of the Force Majeure for a period of up to 60 Days in the aggregate
during any 12 Month period, but for no longer period. The Party receiving notice
of Force Majeure may immediately take such action as it deems necessary at its
expense for the entire 60 Day period or any part thereof. The Parties expressly
agree that upon the expiration of the 60 Day period Force Majeure shall no
longer apply to the obligations hereunder and both Buyer and Seller shall be
obligated to perform. The cause of the Force shall be remedied with all
reasonable diligence and dispatch; provided, unless otherwise agreed no
provision herein shall require or permit Seller or Buyer to Schedule quantities
of Gas (i) in excess of the DCQ, Maximum Daily Delivery Point Quantity or MaxDQ,
as applicable, or (ii) at points other than the Delivery Point(s).
ARTICLE 6. TAXES 6.1. Allocation of Taxes. The Contract Price includes, and
Seller is liable for and shall pay, cause to be paid, or reimburse Buyer if
Buyer has paid, all Taxes applicable to the Gas upstream of the Delivery
Point(s). In the event Buyer is required to remit such Taxes, the amount thereof
shall be deducted from any sums becoming due to Seller hereunder. The Contract
Price does not include, and Buyer is liable for and shall pay, cause to be paid,
reimburse Seller if Seller has paid or pay to Seller if Seller is required by
law to pay to a taxing authority, all Taxes applicable to the Gas downstream of
or at the Delivery Point(s), including, but not limited to, any Taxes imposed or
collected by a taxing authority with jurisdiction over Buyer and any Taxes
imposed on the sale of Gas to Buyer, on Buyer's purchase, possession,
transportation, consumption, use, sale or other disposition of Gas, or on any
payment by Buyer to Seller.
6.2. New Taxes. A. If (i) New Tax occurs and (ii) Buyer or Seller would be
responsible for such New Tax if it were a Tax under Section 6.1 and (iii) such
New Tax is, due to and on the basis of laws, regulations and applicable
contracts of Buyer in effect as of the effective date of the Now Tax, of the
type which Buyer can pass directly through to, or be reimbursed by, another
person or entity in the chain of Gas supply, such Buyer shall pay or cause to be
paid, or reimburse Seller if Seller has paid, all such New Taxes; provided, if
Buyer does not identify its contracts for long-term fixed sourcing in the
ordinary course of its business and cannot identify applicable contracts, this
Paragraph A shall not apply. B. If (i) a New Tax occurs and (ii) either Buyer or
Seller would be responsible for such New Tax if it were a Tax under Section 6.1,
and (iii) Paragraph A does not apply, such responsible Buyer or Seller (the
"Taxed Party") shall be entitled to declare an Early Termination Date in
accordance with the provisions of this Agreement subject to the following
conditions; provided, prior to and including the initial Agreement Period (below
defined) invoked under this Section 6.2, New -Taxes shall be allocated as if
they were Taxes as provided in Section 6.1: (a) the Taxed Party must give the
nonTaxed Party at least 30 Days prior written notice (the "Agreement Period") of
its intent to declare an Early Termination Date (and which notice shall be given
no later than 90 Days after the later of the enactment or effective date of the
relevant New Tax), and prior to the proposed Early Termination Date Buyer and
Seller shall attempt to reach a mutual agreement as to the sharing of the New
Tax, (b) ff a mutual sharing agreement is not reached, the non-Taxed Party shall
have the right, but not the obligation, upon written notice to the Taxed Party
within the Agreement Period, to pay the New Tax for any continuous period it so
elects on a Month to Month basis, and in such case the Taxed Party shall not
have the right during such continuous period to declare the Early Termination
Date on the basis of the New Taxes, (c) should the nonTaxed Party at its
election agree to pay the New Tax on a Month to Month basis, then upon 30 Days
prior written notice to the Taxed Party of its election to cease payment of such
New Tax, the Taxed Party shall then be liable for the payment of the New Tax and
the Parties shall again be subject to this Section 6.2 as if the New Tax had an
effective date as of the date the non-Taxed Party ceases payment of such New
Tax, (d) if a mutual sharing agreement is not reached and the non-Taxed Party
does not elect to pay the New Tax for any period of time within the Agreement
Period, the Early Termination Date shall take effect and all Transactions must
be terminated and be subject to the same Early Termination Date, (e) the Early
Termination Date shall be effected as if a Triggering Event had occurred and the
Termination Payment calculated as set forth in Section 4.1 shall be payable;
provided, both Seller and Buyer pursuant to Section 4.1 shall calculate their
respective Termination Payments resulting from the termination of all
Transactions as if they each were a Notifying Party; provided further, if the
calculation of the Termination Payments results in either the non-Taxed Party's
or the Taxed Party's having either a gain or loss (after netting its gains
against its losses), the Parties shall share equally such net gain due, or be
responsible to pay to the Party having the net loss, one-half of the Termination
Payment and (f) such Termination Payment shall be payable as provided in Section
4.1 and its calculation shall be subject to arbitration as provided in the PG&E
Energy Trading-Gas Corporation General Provisions.
6.3. Documentation Supporting Exemptions or Deductions. If Buyer asserts that an
exemption or deduction from Taxes applies, or if Seller requests in writing that
Buyer provide documentation in support of the application of an exemption or
deduction, Seller shall claim the exemption or deduction only after Buyer has
timely provided to Seller all documents required by law in order for the
exemption or-deduction to apply; provided, however, Seller shall have no duty or
obligation: (i) to request such documentation; or (ii) to file a claim for
refund for any Taxes paid for any prior period. Seller's failure to request such
documentation shall not alter the rights and obligations of the Parties under
this Article 6.
6.4. Billing and Payment of Taxes and Governmental Fees. All Taxes and/or
Governmental Fees which a Party is obligated to pay hereunder shall be billed
and paid in accordance with the Financial Matters provisions set forth in
Appendix "l".
ARTICLE 7.-- TITLE, RISK OF LOSS, INDEMNITY AND BALANCING 7.1. Title, Risk of
Loss and Indemnity. As between the Parties, Seller shall be deemed to be in
exclusive control and possession of Gas Scheduled hereunder and responsible for
any damage or injury caused thereby prior to the time the same shall have been
delivered to Buyer at the Delivery Point(s). After delivery of Gas to Buyer at
the Delivery Point(s), Buyer shall be deemed
<PAGE>
to be in exclusive control and possession thereof and responsible for any injury
or damage caused thereby. Title to Gas Scheduled hereunder and risk of loss
therefor shall pass from Seller to Buyer at the Delivery Point(s). Seller and
Buyer each assumes all liability for and shall indemnify, defend and hold
harmless the other Party from any Claims, including injury to and death of
persons, arising from any act or incident occurring when title to the Gas is
vested in the Indemnifying Party; provided, however, no Party shall have any
obligation under this Article 7.1 with regard to Taxes, the entire obligation of
any Party regarding Taxes being fully set forth under Article 6; and provided
further, however, Company shall have no obligation under this Article 7.1 with
regard to Governmental Fees, the entire obligation of Customer regarding
Governmental Fees being fully set forth in the Section entitled "Transportation"
in Appendix "1" IT IS THE INTENT OF THE PARTIES THAT THIS INDEMNITY AND THE
LIABILITY ASSUMED UNDER IT BE WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF,
INCLUDING, WITHOUT LIMITATION, THE NEGLIGENCE OF ANY INDEMNIFIED PARTY, WHETHER
SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE; PROVIDED,
NEITHER PARTY SHALL BE LIABLE IN RESPECT OF ANY CLAIM TO THE EXTENT SAME
RESULTED FROM THE GROSS NEGLIGENCE, WILLFUL MISCONDUCT OR BAD FAITH OF THE
INDEMNIFIED PARTY.
7.2. Correction of Imbalances, Cashouts and Penalties. Differences between
Scheduled quantities and actual quantities delivered and received hereunder
("Imbalances") will be corrected or settled in cash or Gas or by offset as the
Parties agree. Additionally, in the event of (i) an Imbalance on Buyer's
Transporters system caused by Seller or Seller's Transporter's delivery of less
or more than the Scheduled quantity for any Gas Day (in which case Seller shall
be the "Responsible Party") or (ii) an Imbalance on Settees Transporter's system
caused by Buyer or Buyer's Transporter's receipt of more or less than the
Scheduled quantity for any Gas Day (in which case Buyer shall be the
"Responsible Party"), the Responsible Party shall be liable for and reimburse to
the other Party any associated Transporter penalties or cashout costs and losses
incurred by such other Party. In the event the tariff of either Buyer's or
Seller's Transporter provides for cashouts on the basis of the aggregation of
all overdeliveries and underdeliveries between such Transporter and Buyer or
Seller, respectively (the "Aggregate Transporter Imbalance"'), and the nature of
the Imbalance (overdelivery or underdelivery) attributable to the Responsible
Party is the same as the Aggregate Transporter Imbalance (overdelivery or
underdelivery), the Responsible Party shall participate in the other Party's
cashout settlement of the Aggregate Transporter Imbalance on the basis of only
the Responsible Party's pro-rata share thereof.
ARTICLE 8. MISCELLANEOUS 8.1. Notices. All notices, including, without
limitation, consents, and communications made pursuant to this Agreement shall
be made as specified in Exhibit "A" Notices required to be in writing shall be
delivered in written form by letter, facsimile or other documentary form. Notice
by facsimile or hand delivery shall be deemed to have been received by the close
of the Business Day on which it was transmitted or hand delivered (unless
transmitted or hand delivered after close in which case it shall be deemed
received at the close of the next Business Day) or such earlier time confirmed
by the receiving Party. Notice by overnight mail or courier shall be deemed to
have been received two Business Days after it was sent or such earlier time
confirmed by the receiving Party. Any notices given hereunder in respect of the
declaration of an Early Termination Date shall be also sent to the address or
facsimile number so specified in Exhibit "A." Any Party may change its addresses
by providing notice of same in accordance herewith.
8.2. Transfer. This Agreement, including, without limitation, each
indemnification, shall inure to and bind the permitted successors and assigns of
the Parties; provided, neither Party shall transfer this Agreement without the
prior written approval of the other Party which may be withheld entirely at the
option of such Party; provided further, either Party may transfer its interest
to any parent or affiliate by assignment, merger or otherwise or transfer, sell,
pledge encumber or assign this Agreement or the accounts, revenues or proceeds
hereof in connection with any financing or other financial arrangements without
the prior approval of the other Party, but no such transfer shall operate to
relieve the transferor Party of its obligations hereunder or the obligations of
the transferor Party's assignee. Any Party's transfer in violation of this
Section 8.2 shall be void.
8.3. Limitation of Remedies, Liability and Damages and Mitigation. THE PARTIES
DO HEREBY CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN
THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY
PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS HEREIN PROVIDED,
SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY
HEREUNDER, THE OBLIGORS LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH
PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF
NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, THE OBLIGOR'S
LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL
DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY HEREUNDER AND ALL OTHER REMEDIES
OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED,
NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY
OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, IN
TORT, CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. NOTWITHSTANDING ANY
OTHER PROVISION IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY BE LIABLE FOR
ANY PENALTIES OR CHARGES ASSESSED BY ANY TRANSPORTER OR OTHER ENTITY FOR THE
UNAUTHORIZED RECEIPT OF GAS BY THE OTHER PARTY. IT IS THE INTENT OF THE PARTIES
THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE
WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING, WITHOUT
LIMITATION, THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT
OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE
PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE
DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS
INCONVENIENT AND THE LIQUIDATED DAMAGES CONSTITUTE A REASONABLE APPROXIMATION OF
THE HARM OR LOSS. BUYER ACKNOWLEDGES THAT IT HAS ENTERED INTO THIS AGREEMENT AND
IS CONTRACTING FOR THE GOODS TO BE SUPPLIED BY SELLER BASED SOLELY UPON THE
EXPRESS REPRESENTATIONS AND WARRANTIES HEREIN SET FORTH AND SUBJECT TO SUCH
REPRESENTATIONS AND WARRANTIES, ACCEPTS SUCH GOODS "AS-IS" AND "WITH ALL FAULTS"
SELLER EXPRESSLY NEGATES ANY OTHER REPRESENTATION OR WARRANTY, WRITTEN OR ORAL,
EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR
WARRANTY WITH RESPECT TO CONFORMITY - TO MODELS OR SAMPLES, MERCHANTABILITY, OR
FITNESS FOR ANY PARTICULAR PURPOSE. EACH PARTY HEREBY WAIVES ALL RIGHTS UNDER,
ARISING OUT OF OR ASSOCIATED WITH TEXAS & BUSINESS COMMERCE CODE SECTIONS 17.41
THROUGH 17.63 KNOWN AS THE DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT TO
THE EXTENT ALLOWED BY LAW. The Parties acknowledge the duty to mitigate damages
hereunder. In this connection, the Parties recognize that the ability to
effectuate arrangements for the sale or purchase of Gas is conditioned upon the
volatility of Gas markets, the creditworthiness and reliability of potential
customers, the complexity and size of the portfolios of contracts managed by
each Party and the need to conduct market business in an orderly manner.
Therefore, the Parties agree that (i) three Business Days is a commercially
reasonable period to purchase or sell Gas in respect of a Seller's or Buyer's
Deficiency Default and (ii) three Business Days after the end of the Month in
which the Early Termination Date occurs is a commercially reasonable period
after the establishment of an Early Termination Date to determine the
Termination Payment; provided, notwithstanding the foregoing, if Gas volumes
made the
<PAGE>
basis of a Sellers or Buyers Deficiency Default or a Party's determination of
the Termination Payment are in excess of 20,000 MMBtu/Gas Day, the Parties
recognize that a longer period may ordinarily be required to effectuate cover or
determine the Termination Payment in an orderly manner so as not to adversely
affect the Gas market. Each Party may utilize its discretion, with commercially
reasonable foresight, to adjust the timing and staggering of the purchases or
sales of Gas volumes in its efforts to mitigate damages. No claim that a Party
failed to mitigate damages shall be grounded solely on the basis of counter Gas
market movement.
8.4. Winding Up Arrangements. Upon the expiration of the Parties' sale and
purchase obligations under this Agreement, any monies, penalties or other
charges due and owing shall be paid, any corrections or adjustments to payments
previously made shall be determined, and any refunds due shall be made within 60
Days. Any Imbalances in receipts or deliveries shall be corrected to zero
balance within 60 Days. Notwithstanding the preceding provisions of this Article
8.4, all indemnity and confidentiality obligations, audit rights, and any rights
and obligations with regard to Taxes pursuant to Article 6 and to Governmental
Fees described in the Section entitled 'Transportation' in Appendix "1" shall
survive the termination of this Agreement. The Parties' obligations provided in
this Agreement shall remain in effect for the purpose of complying herewith.
8.5. Applicable Law. THIS AGREEMENT AND EACH TRANSACTION AND THE RIGHTS AND
DUTIES OF THE PARTIES ARISING OUT OF THIS AGREEMENT SHALL BE GOVERNED BY AND
CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF
TEXAS, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. THE PARTIES AGREE THAT
THIS AGREEMENT AND ALL TRANSACTIONS SHALL BE ACCEPTED AND FORMED IN THE STATE OF
TEXAS ACCORDING TO THE PROCEDURES HEREIN SET FORTH.
8.6. Document Record Retention and Evidence. This Agreement, the Exhibits and
Appendices hereto, if any, and each Transaction, constitute the entire agreement
between the Parties relating to the subject matter contemplated by this
Agreement. There are no prior or contemporaneous agreements or representations
(whether oral or written) affecting the subject matter other than those herein
expressed. Other than with respect to Transactions entered into in accordance
with the procedures set forth in this Agreement and as otherwise herein
expressly stated (the 'Transaction Procedures'), no amendment or modification to
this Agreement shall be enforceable, unless reduced to writing and executed by
both Parties. The conduct of the Parties in accordance with the Transaction
Procedures shall evidence a course of dealing and a course of performance
accepted by the Parties in furtherance of this Agreement and all Transactions
entered into by the Parties. The provisions of this Agreement shall not impart
rights enforceable by any person, firm or organization not a Party or not bound
as a Party, or not a permitted successor or assignee of a Party bound to this
Agreement. Except as otherwise herein stated, any provision, article or section
declared or rendered unlawful by a court of law or regulatory agency with
jurisdiction over the Parties or deemed unlawful because of a statutory change
will not otherwise affect the lawful obligations that arise under this
Agreement. The headings used for the Articles herein are for convenience and
reference purposes only. All Exhibits and Appendices referenced in this
Agreement, if any, are incorporated. Any original executed Agreement or
Transaction Agreement may be photocopied and stored on computer tapes and disks
(the 'Imaged Agreement.). The Imaged Agreement, if introduced as evidence on
paper, the Confirmation, if introduced as evidence in automated facsimile form,
and the Transaction Tape, if introduced as evidence in its original form and as
transcribed onto paper, and all computer records of the foregoing, if introduced
as evidence in printed format, in any judicial, arbitration, mediation or
administrative proceedings, will be admissible as between the Parties to the
same extent and under the same conditions as other business records originated
and maintained in documentary form. Neither Party shall object to the
admissibility of the Transaction Tape, the Confirmation or the Imaged Agreement
(or photocopies of the transcription of the Transaction Tape, the Confirmation
or the Imaged Agreement) on the basis that such were not originated or
maintained in documentary form under either the hearsay rule, the best evidence
rule or other rule of evidence.
8.7. Confidentiality. Each Party shall not disclose the terms of any Transaction
to a third party (other than the Party's and its affiliates' employees, lenders,
counsel, accountants or prospective purchasers of any rights under any
Transactions who have agreed to keep such terms confidential) except in order to
comply with any applicable law, order, regulation or exchange rule; provided,
each Party shall notify the other Party of any proceeding of which it is aware
which may result in disclosure and use reasonable efforts to prevent or limit
the disclosure. The provisions of the Agreement other than the terms of any
Transaction are not subject to this confidentiality obligation. The Parties
shall be entitled to all remedies available at law or in equity to enforce, or
seek relief in connection with, this confidentiality obligation; provided, all
monetary damages shall be limited in accordance with Section 8.3.
The Parties have executed this Agreement in multiple counterparts to be
construed as one effective as of the Effective Date.
PG&E ENERGY TRADING-GAS CORPORATION
By: s/Tony Chovanec
Title: Vice President
BLUEFIELD GAS COMPANY
By: s/Arthur L. Pendleton
Title: President & COO
<PAGE>
APPENDIX "1"
PG&E ENERGY TRADING-GAS CORPORATION GENERAL PROVISIONS Usage and Definitions.
All references to Articles and Sections are to those set forth in this
Agreement. Reference to any document means such document as amended from time to
time and reference to any Party includes any permitted successor or assignee
thereof. The following definitions and any terms defined internally in this
Agreement shall apply to this Agreement and all notices and communications made
pursuant to this Agreement.
"Btu" means the amount of energy required to raise the temperature of
one pound of pure water one degree Fahrenheit from 59 degrees
Fahrenheit to 60 degrees Fahrenheit. The term "MMBtu" means one
million Btus.
"Buyer" means the Party to a Transaction who is obligated to purchase
Gas during a Period of Delivery.
"C.T." means Central Time.
"Claims" means all claims or actions, threatened or filed and whether
groundless, false or fraudulent, that directly or indirectly relate to
the subject matters of the indemnity, and the resulting losses,
damages, expenses, attorneys' fees and court costs, whether incurred
by settlement or otherwise, and whether such claims or actions are
threatened or filed prior to or after the termination of this
Agreement.
"Confirmation" means a written notice confirming the specific terms of
a Transaction which may be in any form adequate at law; an example of
a Confirmation which may be utilized hereunder is shown in Exhibit B.
"Confirm Deadline" means two (2) business days after a Party receives
a 'Confirmation; provided, if the Confirmation is not received during
a Business Day it shall be deemed received at the open of the next
Business Day.
"Contract Price" means the price for the purchase or sale of Gas
pursuant to a Transaction.
"Daily Contract Quantity" ("DCQ") means the quantity of Gas to be
Scheduled each Gas Day pursuant to a Transaction.
"Day" means a period of 24 consecutive hours, beginning at midnight
C.T. on any calendar Day. "Business Day" means a Day on which Federal
Reserve member banks in New York City are open for business and a
Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local
time. "Gas Day" means a period of 24 consecutive hours beginning at
the time of the applicable Transporter's gas day.
"Delivery Point(s)" means the agreed point(s) of delivery pursuant to
a Transaction.
"Force Majeure" means an event not anticipated as of the Effective
Date, which is not within the reasonable control of the Party, or in
the case of third party obligations or facilities, the third party,
claiming suspension, and which by the exercise of due diligence such
Party, or third party, is unable to overcome or obtain or cause to be
obtained a commercially reasonable substitute performance therefor;
provided, neither (i) the loss of Buyer's markets nor Buyer's
inability economically to use or resell Gas purchased hereunder nor
(ii) the loss or failure of Seller's Gas supply, including, without
limitation, depletion of reserves or other failure of production, nor
Seller's ability to sell Gas to a market at a more advantageous price,
shall constitute an event of Force Majeure. "Force Majeure" shall
include an event of Force Majeure occurring with respect to the
facilities or services of Buyer's or Settees Transporter.
"GAAP" means generally accepted accounting principles, consistently
applied.
"Gas" means methane and other gaseous hydrocarbons meeting the quality
standards and specifications of Buyer's Transporter.
"Governmental Fees". means any and all privilege, franchise fees,
charges, user fees or rentals levied by governmental entities in
exchange for the grant of privileges relating to use of land or
improvements thereon.
"Indemnified Party" and "Indemnifying Party" means the Party receiving
and providing an indemnity, respectively.
"Interest Rate" means, for any date, two percent over the per annum
rate of interest announced as the "Prime Rate" from time to time for
commercial loans by Citibank, N. A. as established by the
administrative body of such bank charged with the responsibility of
establishing such rate, as same may change from time to time;
provided, the Interest Rate shall never exceed the maximum lawful rate
permitted by applicable law.
"Letter of Credit" means an irrevocable standby letter of credit
established by a Party (the "Account Party") and issued or confirmed
in a form and by a commercial bank acceptable to the Party in whose
favor it is issued (the "Beneficiary Party").
"Material Adverse Change" means (i) with respect to Customer, in the
reasonable opinion of Company, a material change in the
creditworthiness, financial condition or ongoing business of Customer
that may adversely affect Customer's ability to perform hereunder, or
(ii) with respect to Company, in the reasonable opinion of Customer, a
material change in the creditworthiness, financial condition or
ongoing business of Company that may adversely affect Company's
ability to perform hereunder.
"MaxDQ" means the maximum quantity of Gas that Seller is required to
Schedule per Gas Day pursuant to a Transaction, if applicable.
"Maximum Daily Delivery Point Quantity" means the maximum quantity of
Gas which may be Scheduled per Gas Day at each Delivery Point where
there are multiple Delivery Points applicable to a Transaction.
"MinDQ" means the minimum quantity of Gas that Buyer is required to
Schedule per Gas Day pursuant to a Transaction, ff applicable.
"MinMQ" means for any Month the minimum quantity of Gas per Gas Day
that Buyer is obligated to Schedule times the number of Days in the
Month pursuant to a Transaction, if applicable.
"Month" means a period of time beginning at midnight C.T. on the first
Day of any calendar Month and ending at midnight C.T. on the first Day
of the following calendar Month.
"New Taxes" means (i) any Taxes enacted and effective after the
Effective Date, including, without limitation, that portion of any
Taxes or New Taxes that constitutes an increase, or (ii) any law,
order, rule or regulation, or interpretation thereof, enacted and
effective after the Effective Date resulting in the application of any
Taxes to a new or different class of parties."
"Period of Delivery" means -the period from the date Scheduling
obligations are to commence to the date same are to terminate under a
Transaction.
"Pipeline" means a company authorized to ship Gas on behalf of itself
or others on physical Gas transmission facilities.
"Pricing Hours" means the hours C.T. from 8:00 a.m. to 5:00 p.m. of
each Business Day.
"Replacement Price Differential" means (i) in the event of a Seller's
Deficiency Default, the positive difference, if any, obtained by
subtracting the Contract Price from the of (a) the cost to Buyer,
including incremental transportation costs and other basis
adjustments, to replace Settees Deficiency Quantity for such Gas Day
(but excluding penalties or charges for unauthorized receipts of Gas
by Buyer) or (b) the Spot Price for the Gas Day in which Sellers
Deficiency Default occurred, and (if) in the event of a Buyer's
Deficiency Default, the positive difference, ff any, obtained by
subtracting the of (a) the price obtained by Seller in an incremental,
arms-length sale(s) to a third party of a quantity equal to Buyer's
Deficiency Quantity for such Gas Day, less incremental transportation
charges to Seller, and including other basis adjustments, or (b) the
Spot Price for the Gas Day in which Buyer's Deficiency Default
occurred (or if the MinMQ is applicable, the Spot Price for the middle
Gas Day of the Month in which Buyer's Deficiency Default occurred),
from the Contract Price.
"Scheduling" or "Schedules" when used in reference to Seller, means to
make Gas available, or cause Gas to be made available, at the Delivery
Point(s) for delivery to or for the account of Buyer, including making
all Pipeline nominations, and when used in reference to Buyer, means
to cause Buyer's Transporter to make available at the Delivery
Point(s) transportation capacity sufficient to permit Buyer's
Transporter to receive on a firm basis the quantities Seller has
available at such Delivery Point(s), including making all Pipeline
nominations. Gas shall be deemed to have been Scheduled when confirmed
by Transporter.
"Seller" means the Party to a Transaction who is obligated to sell Gas
during a Period of Delivery.
<PAGE>
"Spot Price" means the price set forth in as Gas Daily (Pasha
Publications, Inc.), or successor publication, in the column 'Daily
Price Survey' under the listing applicable to the geographic location
agreed pursuant to a Transaction for the relevant Gas Day. If there is
no single price published for that particular Gas Day, but there is
published a range of prices under the above column and listing, then
the Spot Price shall be the average of such high and low prices. In
the event that no price or range of prices is published for that
particular Gas Day, then the Spot Price shall be the average of the
following: the price (determined as stated above) for each of the
first Gas Day immediately preceding and following the Gas Day in which
the default occurred for which a Spot Price can be determined.
"Taxes" means any or all ad valorem, property, occupation, severance,
production, extraction, first use, conservation, Btu or energy,
gathering, transport, Pipeline, utility, gross receipts, gas or oil
revenue, gas or oil import, privilege, sales, use, consumption,
excise, transaction, and other taxes or New Taxes, governmental
charges or fees, licenses, fees, permits and assessments, or increases
therein, and any interest or penalties on such taxes, charges,
licenses, fees, permits, New Taxes and assessments, other than taxes
based on net income or net worth, and Governmental Fees.
"Transaction" means an agreement and any amendment or modification
thereof made in accordance herewith for the purchase or sale of Gas to
be performed hereunder.
"Transaction Agreement" means a written paper-based agreement executed
by the Parties to form and effectuate a Transaction which may be
substantially in the form set forth in Exhibit B-1.
"Transaction Tape" means the tape recording of a recorded Transaction
effectuated in accordance with Article 2.
"Transporter" means either the Pipeline delivering or receiving Gas at
a delivery Point in a Transaction.
* Representations and Warranties As a material inducement to entering into
this Agreement, including each Transaction, each Party, with respect to
itself, hereby represents and warrants to the other Party continuing
throughout the term of this Agreement as follows: (i) there are no suits,
proceedings, judgments, rulings or orders by or before any court or any
governmental authority that materially adversely affect its ability to
perform this Agreement or the rights of the other Party under this
Agreement, (ii) it is duly organized, validly existing and in good standing
under the laws of the jurisdiction of its formation, and it has the legal
right, power and authority and is qualified to conduct its business, and to
execute and deliver this Agreement and perform its obligations under the
same and each Transaction, and all regulatory authorizations have been
maintained as necessary for it to legally perform its obligations
hereunder, (iii) the making and performance by it of this Agreement is
within its powers, has been duly authorized by all necessary action on its
part, and does not and will not violate any provision of law or any rule,
regulation, order, writ, judgment, decree or other determination presently
in effect applicable to it or its governing documents, (iv) each of this
Agreement and each Transaction when entered into constitutes a legal, valid
and binding act and obligation of it, enforceable against it in accordance
with its terms, subject to bankruptcy, insolvency, reorganization and other
laws affecting creditors rights generally, and with regard to equitable
remedies, to the discretion of the court before which proceedings to obtain
same may be pending, (v) there are no bankruptcy, insolvency,
reorganization, receivership or other arrangement proceedings pending or
being contemplated by it, or to its knowledge threatened against it, (vi)
it has assets of $5,000,000 or more according to its most recent financial
statements prepared in accordance with GAAP and knowledge and experience in
financial matters that enable it to evaluate the merits and risks of this
Agreement, and (vii) it is not in a disparate bargaining position with the
other Party.
* Operations and Delivery Scheduling Requests. Not later than two Business
Days prior to the earlier of Buyer's or Settees Transporters nomination
deadline for the first Gas Day of each Month during a Period of Delivery,
Buyer agrees to provide to Seller facsimile notice of the quantities Buyer
requests Seller to Schedule for each Gas Day of such Month. Should Buyer
desire to change the requested quantities Scheduled, Buyer shall provide to
Seller facsimile notice thereof not later than one Business Day prior to
the earlier of Buyer's or Sellers Transporter's nomination deadline for the
applicable Gas Day. In the event the nomination or Scheduling deadline of a
Transporter conflicts with these notification dates, Buyer and Seller agree
to modify the notification dates accordingly. Scheduling requests to Seller
will be accepted at the telephone number and shall be confirmed by
facsimile as set forth in Exhibit "A."
Transportation. Seller shall obtain, or cause to be obtained,
transportation to the Delivery Point, and Buyer shall obtain, or cause to
be obtained, transportation from the Delivery Point. Customer shall pay,
cause to be paid, or reimburse Company if Company has-Paid, all
Governmental Fees which are imposed on Company or Company's Transporter.
Gas Specifications. Seller represents that all Gas delivered hereunder
shall meet or exceed the specifications of Buyer's Transporter.
Multiple Delivery Point Utilization. In the event a Transaction shall
contain more than one Delivery Point, the Parties shall specify a Maximum
Daily Delivery Point Quantity for each Delivery Point. The Delivery Points
which shall be utilized for delivery of Gas and the quantities of Gas to be
Scheduled for delivery at such Delivery Points shall be determined by
Seller in its sole discretion within each applicable Maximum Daily Delivery
Point Quantity. Seller shall provide to Buyer a list of Delivery Points and
quantities determined by it within a period of time necessary to permit
Buyer to make nominations.
Operational Flow Orders. Should either Party receive an operational flow
order or other order or notice from a Transporter requiring action to be
taken in connection with this Agreement or Gas flowing under this Agreement
("OFO"), such Party shall immediately notify the other Party of the OFO and
provide the other Party a copy of same by facsimile. The Parties shall take
all actions required by the OFO within the time prescribed. Each Party
shall indemnify, defend and hold harmless the other Party from any Claims,
including, without limitation, all non-compliance penalties and attorneys'
fees, associated with an CFO (i) of which the Indemnifying Party failed to
give the Indemnified Party the notice required hereunder or (ii) under
which the Indemnifying Party failed to take the action required by the OFO
within the time prescribed.
* Financial Matters Billing, Invoice Date, Charges and Payment. By the 10th
Day of each calendar Month following the Month in which Gas was Scheduled
under a Transaction, Seller shall provide Buyer with a written statement
setting forth Gas Scheduled during the preceding Month, and other charges
due Seller, including, without limitation, deficiency charges under Article
3, and any Taxes for which Buyer has an obligation to pay Seller pursuant
to Article 6. If Seller becomes aware, at a later time, of any Taxes for
which Buyer has an obligation to pay Seller pursuant to Article 6. Seller
shall render to Buyer a written statement setting forth such Taxes, and
Buyer shall render payment of such statement in accordance with this
Financial Matters provision. Billing and payment will be based on Scheduled
quantities. If Company pays, or becomes aware at a later time of any
Governmental Fees for which Customer has an obligation to pay Company
pursuant to the Section entitled 'Transportation' in this Appendix "1",
Company shall render to Customer a written statement setting forth such
Governmental Fees, and Customer shall render payment of such statement in
accordance with this Financial Matters provision, Within five Business Days
of the request of either Party, the other Party shall provide, to the
extent it has a legal right of access thereto and/or such statement is then
available, a copy of the Transporter's allocation or imbalance statement
applicable to Gas sold hereunder for the requested period. The difference,
ff any, between Scheduled and actual quantities delivered or accepted shall
be treated as Imbalances under Article 7. Buyer shall remit any amounts due
on the later of the 25th Day of the Month in which Sellers statement was
received or ten days after receipt of Seller's invoice. If the due date for
any payment to be made under this Agreement is not a Business Day, the due
date for such payment shall be the following Business Day. Payment of all
funds shall be made in U. S. currency and as indicated in Exhibit "A" in
such manner that funds are immediately available to the payee on the
applicable due date. Each Party shall take all actions necessary to effect
payments in accordance with the process stated in "A." If Buyer or Seller
should fail to remit any amounts in full when due hereunder, interest on
the unpaid portion shall accrue from the date due at a
<PAGE>
rate equal to the Interest Rate. Billings, payments and statements shall be
made to the accounts or the addresses / facsimiles specified in Exhibit
"A."
Suspension of Performance. If either Party fails to make a timely payment
and such failure is not remedied within two Business Days after such Party
receives written notice of default, the nondefaulting Party, in addition to
other remedies, may suspend the Scheduling of Gas until such amount,
including interest, is paid; provided, if the defaulting Party, in good
faith, shall dispute the amount of any such billing or part thereof and
shall pay such amounts as it concedes to be correct, no suspension shall be
permitted.
Audit Rights. During the term of this Agreement and for a period of two
years from the date of termination of a Transaction, Buyer or Seller or any
third party representative thereof shall have the right, upon reasonable
notice and at reasonable times, to examine the books and records of the
other to the extent reasonably necessary to verify the accuracy of any
billing statement, payment demand, charge, payment or computation made
under this Agreement. The records of the Parties shall be retained in
accordance with Section 8.6 for a like period to facilitate the audit
rights of the Parties.
Financial Information. If requested by Customer, Company shall deliver (i)
within 120 Days following the end of each fiscal year, a copy of the annual
report of PG&E Corporation containing consolidated financial statements for
such fiscal year certified by independent certified public accountants and
(ii) within 60 Days after the end of each of its first three fiscal
quarters of each fiscal year, a copy of the quarterly report of PG&E
Corporation containing unaudited consolidated financial statements for such
fiscal quarter. If requested by Company, Customer shall deliver (i) within
120 Days following the end of each fiscal year, a copy of its annual report
containing consolidated financial statements for such fiscal year certified
by independent certified public accountants and (ii) within 60 Days after
the end of each of its first three fiscal quarters of each fiscal year, a
copy of its quarterly report containing unaudited consolidated financial
statements for such fiscal quarter. In all cases the statements shall be
for the most recent accounting period and prepared in accordance with GAAP;
provided, should any such statements not be timely due to a delay in
preparation or certification, such delay shall not be considered a default
so long as such Party diligently pursues the preparation, certification and
delivery of the statements.
* Warranty of Title to Gas Seller in any Transaction warrants that title to
Gas to be Scheduled by Seller is free from all production burdens, liens
and adverse claims and warrants its right to sell the same. Seller agrees
to indemnify, defend and hold harmless Buyer against all Claims to or
against the title of said Gas. In the event any Claim is asserted to said
Gas, Buyer, in addition to other remedies, may suspend its obligation to
pay for said Gas up to the amount of such Claim.
* Alternate Price Redetermination If any or all of the indices used to
determine the Spot Price or the Contract Price are not available in the
future. the Parties agree to promptly negotiate a mutually satisfactory
alternate index for the Spot Price or Contract Price (each an "Alternate
Price"). If the Parties cannot agree by the end of the first Month for
which the Spot Price or Contract Price could not be determined, then Seller
and Buyer shall each prepare a prioritized list of up to five alternative
published reference postings or prices representative of spot prices for
Gas delivered in the same geographic area. Each Party shall submit its list
to the other within 10 Days after the end of the first Month for which the
price could not be determined. The first listed index appearing in Settees
list that also appears in Buyer's list shall constitute the replacement
index. If no common indices appear on the lists, each Party shall submit a
new list adding two indices within 10 Days. If either Party fails to
provide timely a list, such Party's list shall not be considered. From and
after the "Renegotiation Date," which shall be the date the Spot Price or
Contract Price is no longer available, until the Alternate Price is
determined, the Alternate Price shall be the average of the Spot Price(s)
or Contract Price(s) in effect during the 12 Months preceding the Month in
which the Renegotiation Date occurred, which price shall be effective until
the Alternate Price is determined. Upon determination of a new Alternate
Price, the Spot Price or Contract Price, as applicable, will be adjusted
retroactively to the Renegotiation Date.
* Effect of Waiver or Consent No waiver or consent by either Party, express
or implied, of any one or more defaults by the other Party in the
performance of any provision of this Agreement shall operate or be
construed as a waiver or consent of any other default or defaults whether
of a like or different nature. Failure by a Party to complain of any act of
the other Party or to declare the other Party in default with respect to
this Agreement, regardless of how long that failure continues, shall not
constitute a waiver by that Party of its rights with respect to that
default until the applicable statute of limitations period has run.
* Indemnifications With respect to each indemnification included in this
Agreement the indemnity is given to the extent authorized by law and the
following provisions shall be considered applicable. The Indemnified Party
shall promptly notify the Indemnifying Party in writing of any Claim and
the Indemnifying Party shall have the right to assume the investigation and
defense thereof, including the employment of counsel, and shall be
obligated to pay the related attorneys' fees; provided, the Indemnified
Party shall have the right to employ separate counsel and participate in
the defense of any Claim, however, the attorneys' fees of such counsel
shall be paid by the Indemnified Party unless the employment of such
counsel has been consented to in writing by the Indemnifying Party or the
Indemnifying Party has failed to assume the defense and employ counsel in a
timely manner; provided further, if the named parties to any Claim include
both Parties, and the Indemnified Party shall have been advised by counsel
that there may be a legal defense available to it which is different from
those available to the Indemnifying Party, the Indemnified Party may elect
to employ separate counsel at the expense of the Indemnifying Party, in
which case the Indemnifying Party shall pay all attorneys' fees of such
counsel and shall not have the right to assume the defense of the Claim on
behalf of the Indemnified Party. The Parties shall use reasonable efforts
to cooperate in the defense of any Claim. The Indemnifying Party shall not
be liable for any settlement of a Claim without its express written consent
thereto. The Indemnified Party shall reimburse the Indemnifying Party for
payments made or costs incurred in respect of-an indemnity with the
proceeds of any judgment, insurance, bond, surety or other recovery made
with respect to an event covered by the indemnity.
* Arbitration Disputes to be Arbitrated. Any and all claims, demands, causes
of action, disputes, controversies, and other matters in question arising
out of or relating to this Agreement, any of its provisions, or the
relationship between the Parties created by this Agreement, whether
sounding in contract, tort, or otherwise, whether provided by statute or
the common law, for damages or any other relief, including, without
limitation, all Claims (all of which are referred to herein as "Disputes"),
shall be resolved by binding arbitration pursuant to the Federal
Arbitration Act. The arbitration may be initiated by either Party by
providing to the other a written notice of arbitration specifying the
Disputes to be arbitrated. If a Party refuses to honor its obligations to
arbitrate, the other Party may seek to compel arbitration in either federal
or state court. The arbitration proceeding shall be conducted in Houston,
Texas, or other location mutually agreed upon by the Parties. Within 30
Days of the notice initiating the arbitration procedure, each Party shall
designate one arbitrator, who need not be impartial. If a Party fails to
designate an arbitrator, the other Party may have an arbitrator appointed
by applying to the senior active United States District Judge for the
Southern District of Texas. The two arbitrators shall select a third
arbitrator. If the two arbitrators chosen by the Parties fail to agree upon
the third arbitrator, both or either of the Parties may apply to the senior
active United States District Judge for the Southern District of Texas for
the appointment of a third arbitrator. The third arbitrator shall take an
oath of neutrality.
* Arbitration Procedures. The three arbitrators shall make all of their
decisions by majority vote. The enforcement of this Agreement to arbitrate,
the validity, construction, and interpretation of this Agreement to
arbitrate, and all procedural aspects of the proceeding pursuant to this
Agreement to arbitrate, including, without limitation, the issues subject
to arbitration, the scope of the arbitrable issues, allegations of 'fraud
in the inducement' to enter into this entire Agreement or to enter into
this Agreement to arbitrate, allegations of waiver, delay or defenses to
arbitrability, and the rules governing the conduct of the arbitration,
shall be governed by and construed pursuant to the Federal Arbitration Act.
In deciding the substance of the parties' Disputes, the arbitrators shall
apply the substantive laws of the State of Texas (excluding Texas choice-of
law principles that might call for the application of some other
<PAGE>
State's law). The arbitration shall be conducted in accordance with the
Commercial Arbitration Rules of the American Arbitration Association,
except as modified in this Agreement. It is contemplated that although the
arbitration shall be conducted in accordance with the Commercial
Arbitration Rules of the American Arbitration Association, the arbitration
proceeding will be selfadministered by the Parties; provided, if a Party
believes the process will be enhanced if it is administered by the American
Arbitration Association, such Party shall have the right to cause the
process to become administered by the American Arbitration Association by
applying to the American Arbitration Association and, thereafter, the
arbitration shall be conducted pursuant to the administration of the
American Arbitration Association. In determining the extent of discovery,
the number and length of depositions, and all other prehearing matters, the
arbitrators shall endeavor to the extent possible to streamline the
proceedings and minimize the time and cost of the proceedings. There shall
be no transcript of the hearing. The final hearing shall be conducted
within 120 days of the selection of the third arbitrator. The final hearing
shall not exceed 10 Business Days, with each Party to be granted onehalf of
the allocated time to present its case to the arbitrators. All proceedings
conducted hereunder and the decision of the arbitrators shall be kept
confidential by the Parties.
Arbitration Award. Only damages allowed pursuant to this Agreement may be
awarded. IT IS EXPRESSLY AGREED THAT THE ARBITRATORS SHALL HAVE NO
AUTHORITY TO AWARD TREBLE, EXEMPLARY OR PUNITIVE DAMAGES OF ANY TYPE UNDER
ANY CIRCUMSTANCES REGARDLESS OF WHETHER SUCH DAMAGES MAY BE AVAILABLE UNDER
TEXAS LAW. THE PARTIES HEREBY WAIVE THEIR RIGHT, IF ANY, TO RECOVER TREBLE,
EXEMPLARY OR PUNITIVE DAMAGES IN CONNECTION WITH ANY DISPUTE, EITHER IN
ARBITRATION OR IN LITIGATION. The arbitrators shall render their final
decision within 20 Days of the completion of the final hearing fully
resolving all of the Disputes that are the subject of the arbitration
proceeding. The arbitrators' ultimate decision after final hearing shall be
in writing. The arbitrators shall certify in their decision that no part of
their award includes any amount for treble, exemplary or punitive damages
not allowed hereunder. The arbitrators' decision shall be final and
non-appealable to the maximum extent permitted by law. Any and all of the
arbitrators' orders and decisions may be enforceable in, and judgment upon
any award rendered in the arbitration proceeding may be confirmed and
entered by, any federal or state court having jurisdiction.
* Authority for Transactions Each Party represents to the other Party that
each of its employees has authority to enter into Transactions pursuant to
this Agreement on its behalf. Identification and authority of a Party's
employee engaging in a recorded telephonic Transaction shall be
conclusively established for all purposes by a statement on the Transaction
Tape by the employee of the employee's name; provided, failure to state the
employee name shall not evidence any lack of authority of the employee to
effectuate and form a Transaction.
* Trigger Pricing During the Period of Delivery for a Transaction expressly
providing for "Trigger Pricing" in the Confirmation, either Party may
request a price other than the original Contract Price, being a Fixed
Price, Fixed Basis Price or Floating Basis Price (each below defined) by
contacting the other Party during Pricing Hours requesting any such price
for a specified quantity of Gas to be Scheduled during selected Months
within the Period of Delivery; provided, such request must be made prior to
12:00 CT on the last trading day of the applicable exchange (NYMEX Gas
futures contract for the selected Month or KCBT Gas futures contract for
the selected month). The terms of this Agreement, including, without
limitation, Article 2. shall apply to Trigger Pricing in respect of any
Transaction hereunder. A Confirmation may be sent by Company to Customer
confirming the Trigger Pricing agreement in accordance with Section 2.4.
"Fixed Price" means a fixed dollar amount agreed to by the Parties. "Fixed
Basis Price" means a price agreed to by the Parties on the basis of the Gas
futures contract for the applicable exchange then trading for the
applicable Month, or (unless otherwise indicated in the Confirmation) if no
such price is agreed prior to the Trigger Deadline as set out on the
Confirmation, the price shall be the last posted price by the applicable
exchange for any contract month for Gas futures contracts then trading on
the applicable exchange plus a fixed dollar amount basis adjustment agreed
to by the Parties. 'Floating Basis Price' means a price equal to the sum of
a fixed dollar amount agreed to by the Parties plus the difference between
the selected reference price for the Delivery Point(s) and the Average
Settlement Price for the applicable Month. The price for all Gas for which
a Flexible Price has not been agreed by the Parties shall be the original
Contract Price applicable to the Transaction.
<PAGE>
EXHIBIT"A"
PG&E ENERGY TRADING-GAS CORPORATION
MASTER FIRM PURCHASE/SALE AGREEMENT
NOTICE / COMMUNICATION / PAYMENT
TO COMPANY:
Notices/Correspondence:
Post Office Box 4791
Houston, Texas 77210-4791
Attn: Contract Administration
Telephone No.: 713-371-6000
Facsimile No.: 713-371-6309
Termination Notice Facsimile No.: 713-371-6309
Duns No.: 83-469-2394
Fed. Tax I.D. No.: 94-3115649
Invoices:
Post Office Box 4791
Houston, Texas 77210-4791
Attn: Accounting
Facsimile No.: 713-371-6821
Payments:
Boston Safe Deposit & Trust
Medford, MA
For the account of PG&E Energy Trading-Gas Corporation
ABA No.: 011001234
Account No.: 101036
Confirmations:
Facsimile No.: 713-371-6899
Nominations:
Telephone No.: 713-371-6000
Facsimile No.: 713-371-6821
TO CUSTOMER:
Notices / Correspondence:
Nominations:
519 Kimball Avenue Telephone No.:
Roanoke, VA 24016 Facsimile No.:
Attn: Michael Gagnet
Telephone No.: 540-983-3838
Facsimile No.: 540-983-3957
Duns No.: 005849393
Fed. Tax I.D. No.:
Invoices:
519 Kimball Avenue
Roanoke, VA 24016
Attn: Accounting
Payments: -
Bank Name: First Union National Bank
City & State: Roanoke, VA
For the account of: Bluefield Gas Company
ABA No.: 051400549
Account No.: 2001008895748
Confirmations:
Facsimile No.:
<PAGE>
TRANSACTION CONFIRMATION
FOR IMMEDIATE DELIVERY
EXHIBIT B
Date:
PG&E Energy Trading - Gas Corporation Transaction Confirm No.:
This Transaction Confirmation is subject to the Master Contract between Seller
and Buyer dated __________________. The terms of this Transaction Confirmation
are binding unless disputed in writing on or before the "Confirm Deadline"
specified in the Master Contract. PG&E Energy Trading-Gas Corporation adopts the
confirming letterhead as its signature on this Transaction Confirmation.
Seller: Buyer:
Attn: Attn:
Phone: Phone:
Fax: Fax:
Contract No.: Contract No.:
Pricing Terms:
Delivery Period: Begin: Delivery Point:
End:
Performance Obligation and Contract Quantity:
Firm (Fixed Quantity):
____________ MMBtus/day (DCQ)
[ ] EFP
Special Conditions:
<PAGE>
TRANSACTION CONFIRMATION
EXHIBIT B-1
PG&E Energy Trading - Gas Corporation Date: October 25, 1999
PG&E Energy Trading is not the same company as
Pacific
Transaction Confirm No.:
Gas and Electric Company, the utility; see attached
PG&E Energy Trading is not regulated by the
California Public Utilities Commission; and
you do not have to buy PG&E Energy Trade Date: October 8, 1999
Trading's products in order to continue to
receive quality regulated
services from the utility.
Seller: Buyer:
PG&E Energy Trading-Gas Corporation ("PG&E ET") Bluefield Gas ("BG")
1100 Louisiana, Suite 1 000 519 Kimball Avenue, N.E
Houston, Texas 77002 Roanoke, VA 24030
Attn: Alan Ehlers Attn: Mike Gagnet
Phone: 502-895-9404 Phone: 540-777-3838
Fax: 502-896-0384 Fax: 540-777-3957
Pricing Terms:
Baseload Supply
BGC will be charged for the monthly baseload based upon an average of relevant
(points) published prices in Inside F.E.R.C.'s Gas Market Report. The relevant
points are based upon an average of BGC's current transportation entitlements.
In effect, PG&E ET will supply an "Index Basket" of baseload supply at IFERC
"Index Basket" flat.
Winter baseload deliveries will be priced according to the following rates:
Commodity Supply: Weighted average of the following Indices
50% Inside F.E.R.C. Gas Market Report's FOM Columbia Gulf
Transmission Co. - Louisiana index
50% Gas Daily Monthly Contract index for Columbia, Mainline
Variable Charges: $.04185 Commodity Charges
5.3209% Fuel Retainage
Summer baseload deliveries will be priced according to the following rates:
Commodity Supply: Same as Winter Commodity Supply (see above)
Variable Charges: Same as Winter Variable Charges (see above)
Deliveries TO Columbia Gas Storage will be priced according to the following
rates:
Commodity Supply: Weighted average of the following Indices
50% Inside F.E.R.C. Gas Market Report's FOM Columbia Gulf
Transmission Co. - Louisiana index
50% Gas Daily Monthly Contract index for Columbia, Mainline
Variable Charges: $.04185 Commodity Charges
5.3209% Fuel Retainage
Pricing Terms (continued):
Swing Supply
PG&E ET will supply additional swing supply at the Midpoint of Gas Daily's -
Daily Price Survey - Columbia, App. flat. The Gas Daily price billed to BGC will
be dependent upon the day in which the additional supply is actually purchased
by PG&E ET. In addition to the commodity price paid, BGC will also be
responsible for the variable transportation costs (commodity and fuel retainage
rates) associated with the Columbia, App. Supply.
PG&E ET will purchase excess baseload supply from BGC at the lower of the
Midpoint of Gas Daily's - Daily Price Survey - Louisiana, Onshore -Columbia flat
or IFERC Columbia Gulf Louisiana flat. The price paid to BGC will be based upon
the day in which the additional supply is actually re-sold in the market by PG&E
ET. PG&E ET will reimburse BGC for any variable transportation costs charged on
the monthly baseload quantity which is sold back to PG&E ET under the
aforementioned method.
Delivery Period: Begin: November 1, 1999 Delivery Point: Bluefield Gas citygate
End: October 31, 2000
<PAGE>
Performance Obligation and Contract Quantity:
Full Requirements, not to exceed 15,740 MMBtus/day (DCQ)
Baseload Deliveries (Fixed Quantity):
Nov99 - 1,647 MMBtus/day May00 - 3,596 MMBtus/day
Dec99 - 2,866 MMBtus/day Jun00 - 3,211 MMBtus/day
Jan00 - 2,847 MMBtus/day Jul00 - 3,079 MMBtus/day
Feb00 - 2,734 MMBtus/day Aug00 - 3,171 MMBtus/day
Mar00 - 2,154 MMBtus/day Sep00 - 3,019 MMBtus/day
Apr00 - 4,679 MMBtus/day Oct00 - 4,498 MMBtus/day
Swing Deliveries/Purchases:
On any day in which the net natural gas requirements of BGC exceed the monthly
baseload as determined by PG&E ET, PG&E ET will supply the necessary additional
supply up to the Contract Quantity of 15,740 MMBtus/day.
On any day in which the net natural gas requirements of BGC are less than the
monthly baseload established by PG&E ET, PG&E ET will purchase the excess
baseload supply from BGC.
Special Conditions:
Asset Release: BGC will (i) appoint PG&E ET as its agent for all
of its storage capacity (see Exhibit A, First Amendment)
and (ii) release its transportation contracts to PG&E ET
(see Exhibit C). To facilitate BGC's release of its
transportation contracts, PG&E ET will pay all pipeline
demand charges, but will be subsequently reimbursed by
BGC. At the expiration of the transaction, all storage
assets will be returned to the control of RGC with
inventory levels equal to those that existed on 10/31/99.
Supply Contracts: BGC will sell all existing supply contracts to
PG&E ET. PG&E ET will reimburse BGC for their costs
associated with this supply, exclusive of demand charges
(see Exhibit D). BGC will pay all supply invoices.
Demand Payment: Throughout the term of the deal, PG&E ET will pay a
monthly demand charge to BGC equal to $10.882.58.
Extension of Term PG&E ET will have the unilateral right to extend
the term of this transaction through October 31, 2001.
Should PG&E ET wish to exercise this right, BGC must be
notified prior to the close of business on February 29,
2000. Should the term of the transaction be extended and
BGC so desire, PG&E ET will work in good faith to develop
a plan which would provide for PG&E ET to take assignment
of BGC's storage capacity and own BGC's storage gas until
delivery of aforementioned storage gas to the BGC
city-gate.
Storage Billing BGC will be billed monthly for a ratable storage
withdrawal/injection. During the winter, the total daily
withdrawals billed will be equal to a citygate delivery of
2,951/dth (TCO). During the summer, the total daily
injections billed will be equal to 2,145 (TCO).
Storage Costs: In addition to the variable cost charged to BGC for
deliveries to storage, BGC will be responsible for any
variable charges associated with delivery into storage.
BGC will not pay for the commodity when it is withdrawn
from storage but will be responsible for the variable
transportation costs associated with delivering the
storage commodity to their citygate. It is the intent of
the parties to keep PG&E ET whole with respect to variable
transportation costs incurred as a result of daily
balancing activity in storage.
Variable Charges All variable charges associated with this
transaction are based upon the current commodity and fuel
rates as presented in the applicable pipeline tariff.
These rates will be adjusted to continuously reflect the
most up to date tariff rates.
Non-Performance Notwithstanding any other provisions in this Transaction
Confirmation, BGC shall have a unilateral right to
terminate the Agreement between the parties as evidenced
hereby, before March 31, 2000, upon 10 days' notice to
ENERGY TRADING, for inadequate performance. "Inadequate
performance" shall only mean ENERGY TRADING's failure to
supply the firm citygate natural gas volumes to BGC, as
contracted by the parties, unless ENERGY TRADING's
performance is excused under the Master Firm Agreement.
Seller: PG&E Energy v Trading-Gas Corporation Buyer: Bluefield Gas
By: By: Roger L. Baumgardner
Name/Title: Name/Title: VP, Sec & Treas.
Date: Date: 12/6/99
<PAGE>
The following are the Transaction Confirm No.'s for the attached Transaction
Confirmation Exhibit B-1 dated October 26,1999 between PG&E Energy Trading-Gas
Corporation as Seller and Bluefield Gas as Buyer.
BLUEFIELDGAS-P/S-01-RMS181531
BLUEFIELDGAS-P/S-01-RMS181538
BLUEFIELDGAS-P/S-01-RMS181545
BLUEFIELDGAS-P/S-0l-RMS181667
BLUEFIELDGAS-P/S-01-RMS181678
BLUEFIEIDGAS-P/S-01-RMS181680
BLUEFIELDGAS-P/S-01-RMS181682
BLUEFIELDGAS-P/S-01-RMS181767
BLUEFIELDGAS-P/S-01-RMS181781
BLUEFIELDGAS-P/S-01-RMS181968
BLUEFIELDGAS-P/S-01-RMS181970
BLUEFIELDGAS-P/S-01-RMS182017
BLUEFIELDGAS-P/S-01-RMS182482
BLUEFIELDGAS-P/S-01-RMS182487
BLUEFIELDGAS-P/S-01-RMS182488
BLUEFIELDGAS-P/S-01-RMS182489
BLUEFIELDGAS-P/S-01-RMS182491
BLUEFIELDGAS-P/S-01-RMS182493
BLUEFIELDGAS-P/S-01-RMS182731
BLUEFIELDGAS-P/S-01-RMS182732
BLUEFIELDGAS-P/S-01-RMS182811
BLUEFIELDGAS-P/S-01-RMS182812
<PAGE>
EXHIBIT C
EXHIBIT C TO MASTER AGREEMENT
Bluefield Gas Company - Commodity Pricing and Associated Variable Charges
*Winter baseload deliveries will be priced according to the following rates:
<TABLE>
<CAPTION>
Winter Fuel Winter Fuel Winter Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Winter Fuel pipeline 1 pipeline 2
- -------------- --------- ---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Columbia Gulf-La. 50% CGT FTS2 to FTS1 to TCO to RGC 0.590% 2.988% 2.116% 5.601% $0.0039 $0.0170
Columbia Mainline* 50% CGT FTS1 to TCO to RGC 2.988% 2.116% 5.041% $0.0170 $0.0229
(GD-Monthly Contract Index) Winter Index Basket - Variable Charges 5.3209% FUEL
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
$0.0229 $0.0438
$0.0399
$0.04185 Commodity
</TABLE>
- -----------------------------------------------------------------------------
*Summer baseload deliveries to the citygate will be priced according to the
following rates:
<TABLE>
<CAPTION>
Summer Fuel Summer Fuel Summer Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Summer Fuel pipeline 1 pipeline 2
- -------------- --------- ---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Columbia Gulf-La. 50% CGT FTS2 to FTS1 to TCO to RGC 0.590% 2.988% 2.116% 5.601% $0.0039 $0.0170
Columbia Mainline* 50% CGT FTSI to TCO to Roanoke 2.988% 2.116% 5.041% $0.0170 $0.0229
Summer Index Basket - Variable Charges 5.3209% FUEL
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0229 $0.0438
$0.0399
$0.04185 Commodity
</TABLE>
- ------------------------------------------------------------------------------
*The commodity price of storage injections will be based upon the following
rates:
1) Columbia Gas Storage
<TABLE>
<CAPTION>
Summer Fuel Summer Fuel Summer Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Summer Fuel pipeline 1 pipeline 2
- -------------- --------- ---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Columbia Gulf-La. 50% CGT FTS2 to FTS1 to TCO to RGC 0.590% 2.988% 2.116% 5.601% $0.0039 $0.0170
Columbia Mainline* 50% CGT FTS1 to TCO to Roanoke 2.988% 2.116% 5.041% $0.0170 $0.0229
(GO-Monthly Contract Index)*
Variable Charges to Storage 5.3209% FUEL
(Variable charges into Storage will be based on actual Storage Service injected to)
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0229 $0.0438
$0.0399
$0.04185 Commodity
</TABLE>
<PAGE>
EXHIBIT D
EXHIBIT D TO TRANSACTION CONFIRMATION
<TABLE>
<CAPTION>
Bluefield Gas
Capacity Detail
Pipeline Type Contract# Recpt. No Recpt Name Receipt Vol Delivery No Delivery Name Delivery Volume
- -------- ---- --------- ---------- ---------- ----------- ----------- ------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Columbia Gulf FTS-2 40432 434 Tennessee 345
433 CGT-Egan A 1000
624 Kelly 1000
2700010 CGT-Rayne 2345
Columbia Gulf FTS-1 38026 2700010 CGT-Rayne 2083
801 Tco-Leach 2083
Columbia FTS 38098 A02 Flat Top 27
A01 Kenova 3
801 Tco-Leach 2028
62 BGC 2058
Columbia SST 38085 STOW Storage With 8682
62 BGC 8682
BPC-intrastate n/a Gather&well *5000
(Phoenix) varies with pipeline operating conditions 62 BGC 5000
</TABLE>
<PAGE>
EXHIBIT E
EXHIBIT E TO MASTER AGREEMENT
Gas Supply Contracts
Bluefield, Natural Gas
<TABLE>
<CAPTION>
Supplier Receipt Term Max Volume Min Volume
Pipeline Point Start End Dth/day Dth/day Price
<S> <C> <C> <C> <C> <C> <C>
TNF Sales Phx Gathering/ 12/1/98 11/30/13 5,000 150 IFGMR FOM CNG Appl. GDA same 1=flat YES 10 calendar days before
Well eom. Bill Strazleka
412-854-5108
Coral Cgt On Pool 12/1/98 11/30/01 1,100 1,100 IFGMR FOM, CGT LA 1+0075
6,100 1,250 10 day notification is not
strictly enforced BGC
system may require takes
above min. BGC will
communicate with supplier
on our behalf.
</TABLE>
*** Special Note: Phoenix Pipeline supply. Supply comes into BGC system at a
strategic point (in terms of maintaining system pressure). Supply is
nominated monthly, any takes over the monthly nom are priced at the average
of GD for the month.
Exhibit 10(c)(c)(c)
FIRST AMENDMENT
TO
THE MASTER FIRM PURCHASE/SALE AGREEMENT
BY AND BETWEEN
BLUEFIELD GAS COMPANY
AND
PG & E ENERGY TRADING-GAS CORPORATION
DATED
NOVEMBER 1, 1999
This Amendment, (the "Amendment") to that certain Master Firm Purchase/Sale
Agreement between Bluefield Gas Company, a West Virginia corporation ("BGC"),
and PG & E Energy Trading-Gas Corporation, a California corporation ("Energy
Trading"), dated November 1, 1999 (the "Master Firm Agreement"), is entered into
by BGC and ENERGY TRADING, effective as of November 1, 1999.
WHEREAS, BGC and ENERGY TRADING have entered into a Letter of Intent,
dated October 18, 1999, pursuant to which ENERGY TRADING has agreed to manage
all of BGC's natural gas, transportation and storage assets, exclusive of LNG
facilities;
WHEREAS, ENERGY TRADING's asset management shall include its assumption
of 100% of BGC's natural gas requirements up to 15,740/dth per day, on a firm
uninterruptible basis;
WHEREAS, a portion of BGC's gas requirements will be pulled from storage
and on any given day the contract withdrawal plan may differ from physical
storage activities, and a portion of such requirements may be sold to BGC by
ENERGY TRADING under the terms of the Master Firm Agreement; and
WHEREAS, to further facilitate ENERGY TRADING's management of BGC's
assets, the parties desire to amend the Master Firm Agreement to (i) govern
ENERGY TRADING's asset management responsibilities, including management of
BGC's storage capacity located at the storage facilities listed on Exhibit A
hereto and (ii) .458271 Bcf of natural gas owned by BGC and stored at the
storage facilities (the "Storage Assets"), which Storage Assets shall then be
loaned back and forth between the parties during the term thereof.
NOW, THEREFORE, in consideration of the mutual covenants herein
contained, BGC and ENERGY TRADING agree as follows:
1. ARTICLE 1. TERM of the Master Firm Agreement is hereby deleted in
its entirety and replaced by the following:
<PAGE>
"ARTICLE 1. TERM. This Master Firm Agreement shall govern all
Transactions for (i) the firm purchase or sale of gas between the
parties, and (ii) ENERGY TRADING's management of BGC's Storage
Assets under Article 9 hereof, to be in effect until October 31,
2000. At ENERGY TRADING's sole election, the term of this Master
Firm Agreement may be extended through October 31, 2001. Should
ENERGY TRADING elect to extend this Master Finn Agreement, it
must give notice to BGC prior to the close of business on
February 29, 2000. Both parties agree that if the Master Firm
Agreement is extended, and BGC so desires, they will negotiate in
good faith to develop a plan for Energy Trading to take title to
BGC's storage capacity and stored gas until delivery to BGC's
citygate. Termination of this Master Firm Agreement shall in all
instances be subject to Section 8.4.
2. The Master Firm Agreement is hereby amended to add an ARTICLE 9.
ASSET MANAGEMENT. Article 9 shall read as follows:
"ARTICLE 9. ASSET MANAGEMENT. 9.1 Management Services. Beginning
on November 1, 1999, ENERGY TRADING agrees to assume full
responsibility for supplying 100% of BGC's natural gas
requirements up to 15,740/dth per day, on a firm uninterruptible
basis, and to provide asset management services to BGC, such
services to be provided for the remainder of the term of this
Master Firm Agreement.
9.2 Limited Agency Appointment. In order to facilitate ENERGY
TRADING's management services, BGC hereby appoints ENERGY TRADING
its limited agent for the purpose of nominating injections and
withdrawals from storage, buying and selling natural gas on its
behalf. As BGC's limited agent, ENERGY TRADING's role shall be
one of independent contractor, and in no event shall the
relationship between the parties be construed as a partnership,
joint venture or full agency relationship. At all times during
ENERGY TRADING's agency, title to all gas withdrawn from,
purchased, sold or injected into storage shall reside with BGC.
9.3 Management Fee Waiver. In lieu of any management fee payable
to ENERGY TRADING for its asset management services hereunder,
BGC waives all proceeds, if any, recognized by ENERGY TRADING in
the management of the Storage Assets, other than the demand
charge provided for in the Special Conditions section of the
Transaction Confirmation.
9.4 Inadequate Performance. Notwithstanding any other provisions
in this Master Firm Agreement, BGC shall have a unilateral right
to terminate this Master Firm Agreement before March 31, 2000,
upon 10 days' notice to ENERGY TRADING, for inadequate
performance. "Inadequate performance" shall only
<PAGE>
mean ENERGY TRADING's failure to supply the firm citygate natural
gas volumes to BGC, as contracted by the parties unless ENERGY
TRADING'S performance is excused under the Master Firm Agreement.
3. For purposes of incorporating this Amendment into the Master Finn
Agreement, as between the parties, the term "Seller" shall refer
to ENERGY TRADING, either in its own right or on behalf of BGC,
and the terms "Buyer" and "Customer" shall refer to BGC.
4. The commercial terms of the Letter of Intent between the parties
are incorporated herein by this reference and made a part hereof.
5. Except as set forth in this Amendment, the terms of the Master
Firm Agreement are ratified and confirmed in all respects by the
parties.
IN WITNESS WHEREOF, the parties have executed this Amendment effective as of the
1st day of November, 1999.
BLUEFIELD GAS COMPANY
By: s/John B. Williamson, III
Name: John B. Williamson, III
Title: Chairman & CEO
PG & E ENERGY TRADING-GAS CORPORATION
By:______________________
Name:____________________
Title:___________________
<PAGE>
EXHIBIT A
[Storage Asset details]
<PAGE>
EXHIBIT A TO THE FIRST AMENDMENT
Firm Storage Contracts
Bluefield Gas Company
<TABLE>
<CAPTION>
Storage Max Daily Max Daily
Pipeline Type SCQ Withdrawal Rights Injection Rights
<S> <C> <C> <C> <C> <C> <C>
Columbia Transmission FSS 480,915 8,682 3,847
</TABLE>
Exhibit 10 (d)(d)(d)
PG&E Energy Trading-Gas Corporation is not the same company as
Pacific Gas and Electric Company, the utility, PG&E
Energy Trading-Gas Corporation is not regulated by the
California Public Utilities Commission, and
you do not have to buy PG&E Energy Trading-Gas
Corporation's products in order to continue to
receive quality regulated services from the utility.
MASTER FIRM PURCHASE/SALE AGREEMENT
between
PG&E ENERGY TRADING-GAS CORPORATION
and
ROANOKE GAS COMPANY
dated
March 1, 1999
<PAGE>
PG&E ENERGY TRADING-GAS CORPORATION
MASTER FIRM PURCHASE/SALE AGREEMENT
II
PG&E ENERGY TRADING-GAS CORPORATION, a California corporation ("Company"), and
ROANOKE GAS COMPANY, a Virginia Corporation ('Customer), referred to
collectively as the "Parties," enter into this Master Firm Purchase/Sale
Agreement (together with all Transactions, collectively, this "Agreement")
effective as of the 1st day of March, 1999 (the"Effective Date"). The PG&E
Energy Trading-Gas Corporation General Provisions set forth in Appendix "1"
shall apply to this Agreement.
ARTICLE 1. TERM This Agreement shall govern all Transactions for the firm
purchase or sale of gas and be in effect for a term of one year from the
Effective Date. It shall then continue in effect from Month to Month, unless
terminated by either Party upon 30 Days prior written notice to the other Party;
provided, this Agreement shall continue to apply to all Transactions then in
effect until all Transactions are completed. Termination of this Agreement in
all instances shall be subject to Section 8.4.
ARTICLE 2. SCOPE OF AGREEMENT 2.1. Scope of Agreement. Company and Customer from
time to time during the term hereof may, but are not obligated to, enter into
Transactions for the firm purchase and sale of Gas to which this Agreement shall
apply. Each Transaction shall be effectuated and evidenced as set forth in this
Article 2 and shall constitute a part of this Agreement and all Transactions,
together with this Agreement, shall constitute a single integrated agreement. It
is acknowledged that the Parties are relying upon the fact that all
Transactions, together with this Agreement, will form a single integrated
agreement and that the Parties would not otherwise enter into any Transactions.
Each Transaction shall be construed as one with this Agreement and any
discrepancy between this Agreement and a Transaction shall be resolved in favor
of the Transaction. Each Transaction shall provide whether the Transaction is
based upon DCQ quantity obligations or MinMQ or MinDQ and MaxDQ quantity
obligations, in which case the applicable alternative definitions and provisions
set forth in this Agreement shall apply.
2.2. Transaction Procedures. It is the intent of the Parties to facilitate
Transactions in accordance with the agreed procedures in this Article 2 and
assure that such Transactions are valid and enforceable as a result of the use
of these procedures for the mutual benefit of the Parties. Any Transaction may
be formed and effectuated (i) by a written paper-based Transaction Agreement in
the form of a Confirmation as set out on Exhibit B-1 executed by the Parties
(including by facsimile and/or counterparts) or (ii) in a recorded telephone
conversation between the Parties occurring on any Business Day during the
Pricing Hours whereby an offer and acceptance shall constitute the agreement of
the Parties to a Transaction as evidenced by the Transaction Tape; provided,
each Party may stipulate by prior notice to the other Party that any particular
contemplated Transaction may be effectuated and formed only by means of
procedure (i) above. The Parties shall be legally bound by each Transaction from
the time they agree to its terms in accordance with this Article 2 and
acknowledge that each Party will rely thereon in doing business related to the
Transaction. The Transaction Tape is adopted by the Parties as a means by which
a Transaction is reduced to tangible form, and the Parties to a Transaction are
identified and authenticate a Transaction. Any Transaction formed and
effectuated pursuant to the foregoing shall be considered to be a "writing" or
in "writing" and to have been"'signed" and any Transaction Tape shall be
considered to constitute an "original" document evidencing the Transaction. Each
Party consents to and has obtained any necessary consent of its employees to the
recording of its employees' telephone conversations without any further notice.
2.3. Equipment and Transaction Tape. Company shall at its expense maintain
equipment necessary to regularly record Transactions on Transaction Tapes and
retain Transaction Tapes in such manner as to protect its business records from
improper access; provided, Company shall not be liable for any malfunction of
equipment or the operation thereof in respect of any Transaction WITHOUT REGARD
TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING, WITHOUT LIMITATION, THE
NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT,
OR ACTIVE OR PASSIVE. No Transaction shall be vitiated should a malfunction
occur in equipment regularly utilized for recording Transactions or retaining
Transaction Tapes or the operation thereof, and in such event, the Transaction
shall be evidenced by the written and computer records of the Parties concerning
the Transaction made contemporaneously with the telephone conversation.
2.4 Confirmations. In addition to, but not in lieu of, the foregoing, the
Parties agree that Company may confirm a recorded telephonic Transaction by
forwarding to Customer a facsimile Confirmation in the form set out on Exhibit B
and that a reasonable time for the receipt by Customer of a Confirmation is
within 24 hours of the Transaction formation. Company does hereby adopt its
letterhead, including its address, as its signature on any Confirmation as the
identification of Company and authentication by Company of the Confirmation, and
such letterhead shall be sufficient to verify that Company originated the
Confirmation. The Parties agree that any objections to the contents of the
Confirmation shall be made in writing on or before the Confirm Deadline for all
purposes hereunder and at law. Upon issuance of a Confirmation and the passage
of the Confirm Deadline, if no objection to the Confirmation has been then
received, the Confirmation shall be conclusive evidence of the Transaction made
the subject matter thereof and the final expression of all of its terms.
2.5 Enforcement of Transactions. The Parties agree not to contest or assert a
defense to the validity or enforceability of telephonic Transactions entered
into in accordance with this Agreement under laws relating to (i) whether
certain agreements are to be in writing or signed by the Party to be thereby
bound or (ii) the authority of any employee of the Party if the employee name is
stated in the Transaction Tape.
ARTICLE 3. QUANTITY OBLIGATIONS 3.1. Seller's Sales Obligation. Seller shall
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Gas Day a quantity of Gas equal to the quantity properly requested by Buyer
up to the DCQ or MaxDQ, if applicable ("Buyer's Requested Quantity"). Unless
otherwise agreed nothing in this Agreement, and in particular this Article 3,
shall require or permit either Party to Schedule Gas at a point other than a
Delivery Point or in excess of the DCO, Maximum Daily Delivery Point Quantity or
MaxDQ, as applicable.
3.2 Seller's Failure to Schedule. If on any Gas Day Seller fails to Schedule
Buyer's Requested Quantity, then such occurrence shall constitute a "Seller's
Deficiency Default" and "Seller's Deficiency Quantity" shall be the numerical
difference between Buyer's Requested Quantity and the amount of Gas Scheduled
for such Gas Day. In the event of a Sellers Deficiency Default, Seller shall pay
Buyer the sum of the following: (i) an amount equal to the product of the
Seller's Deficiency Quantity multiplied by the Replacement Price Differential,
plus (ii) liquidated damages equal to $0.15 per MMBtu multiplied by Sellers
Deficiency Quantity to cover Buyer's administrative and operational costs.
During any Month in which Settees nonperformance continues for a period of five
consecutive Gas Days Buyer may elect upon notice to Seller, without liability,
not to recommence Scheduling Gas hereunder for the remainder of such Month, but
for no longer period. Subject to offset pursuant to Section 3.5, payment to
Buyer shall be made on the later of the 25th Day of the Month or ten days after
Seller receives Buyers statement for same.
3.3. Buyers Purchase Obligation. Buyer shall Schedule, or cause to be Scheduled,
at the Delivery Point(s) on a firm basis each Gas Day a quantity of Gas equal to
the DCQ; provided, (I) if the MinMQ is applicable to a Transaction, Buyer shall
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Month a minimum quantity of Gas equal to the MinMO and (ii) if the MinDQ is
applicable to a Transaction, Buyer shall
<PAGE>
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Day a minimum quantity of Gas equal to the MinDQ.
3.4. Buyer's Failure to Schedule. If on any Gas Day Buyer fails to Schedule the
DCQ or MinDQ, if applicable, then such occurrence shall constitute a "Buyer's
Deficiency Default" and "Buyer's Deficiency Quantity" shall be the numerical
difference between the DCQ or MinDQ, if applicable, and the quantity of Gas
Scheduled for such Gas Day; provided, if the MinMQ is applicable to a
Transaction, (i) the Buyer's Deficiency Default shall occur if Buyer fails to
Schedule the MinMQ for any Month and (ii) the Buyer's Deficiency Quantity shall
be the numerical difference between the MinMQ and the quantity of Gas Scheduled
for such Month. In the event of a Buyer's Deficiency Default, Buyer shall pay
Seller the sum of the following: (i) an amount equal to the product of Buyers
Deficiency Quantity multiplied by the Replacement Price Differential, plus (ii)
liquidated damages equal to $0.15 per MMBtu multiplied by Buyer's Deficiency
Quantity to cover Settees administrative and operational costs. With respect to
DCQ and MinDQ obligations, during any Month in which Buyers nonperformance
continues for a period of five consecutive Gas Days Seller may elect upon notice
to Buyer, without liability, not to recommence Scheduling Gas for the remainder
of such Month, but for no longer period. Subject to offset pursuant to Section
3.5, payment to Seller shall be made in accordance with the Financial Matters
provisions set forth in Appendix "l."
3.5. Netting. In the event that Buyer and Seller are each required under this
Agreement to pay an amount in the same Month hereunder, then such amounts with
respect to each Party may be aggregated and the Parties may discharge their
obligations to pay through netting, in which case the Party, if any, owing the
greater aggregate amount may pay to the other Party the difference between the
amounts owed.
ARTICLE 4. DEFAULTS AND REMEDIES 4.1.Early Termination. If a Triggering Event
(defined in Section 4.2) occurs with respect to either Party at any time during
the term of this Agreement, the other Party (the "Notifying Party") may (i) upon
two Business Days written notice to the first Party, which notice shall be given
no later than 60 Days after the discovery of the occurrence of the Triggering
Event, establish a date on which any or all Transactions selected by it and this
Agreement in respect thereof will terminate ("Early Termination Date") except as
provided in Section 8.4, and (ii) withhold any payments due in respect of such
Transactions; provided, upon the occurrence of any Triggering Event listed in
item (iv) of Section 4.2 as it may apply to any party, all Transactions and this
Agreement in respect thereof shall automatically terminate, without notice, as
if an Early Termination Date had been immediately declared except as provided in
Section 8.4. If an Early Termination Date occurs, the Notifying Party shall in
good faith calculate its damages, including its associated costs and attorneys'
fees, resulting from the termination of the terminated Transactions (the
"Termination Payment."). The Termination Payment will be determined by (I)
comparing the value of (a) the remaining term, quantities and prices under each
such Transaction had it not been terminated to (b) the equivalent quantities and
relevant market prices for the remaining term either quoted by a bona fide third
party offer or which are reasonably expected to be available in the market under
a replacement contract for each such Transaction and (ii) ascertaining the
associated costs and attorneys' fees. To ascertain the market prices of a
replacement contract the Notifying Party may consider, among other valuations,
any or all of the settlement prices of NYMEX Gas futures contracts, quotations
from leading dealers in Gas swap contracts and other bona fide third party
offers, all adjusted for the length of the remaining term and the basis
differential. All terminated Transactions shall be netted against each other and
upon the netting of all terminated Transactions, if the calculation of the
Termination Payment does not result in damages to the Notifying Party, the
Termination Payment shall be zero. The Notifying Party shall give the Affected
Party (defined in Section 4.2) written notice of the amount of the Termination
Payment, inclusive of a statement showing its determination. The Affected Party
shall pay the Termination Payment to the Notifying Party within 10 Days of
receipt of such notice. At the time for payment of any amount due under this
Article 4, each Party shall pay to the other Party all additional amounts
payable by it pursuant to this Agreement, but all such amounts shall be netted
and aggregated with any Termination Payment payable hereunder. If the Affected
Party disagrees with the calculation of the Termination Payment, the issue shall
be submitted to arbitration pursuant to this Agreement and the resulting
Termination Payment shall be due and payable within three Days after the award.
4.2. Triggering Event. shall mean, with respect to a Party (the "Affected
Party"): (i) the failure by the Affected Party to make, when due, any payment
required under this Agreement ff such failure is not remedied within five
Business Days after written notice of such failure is given to the Affected
Party; provided, the payment is not the subject of a good faith dispute as
described in the Billing and Payment provisions or (ii) any representation or
warranty made by the Affected Party in this Agreement shall prove to have been
false or misleading in any material respect when made or deemed to be repeated
or (iii) the failure by the Affected Party to perform any covenant set forth in
this Agreement (other than its obligations to make any payment or obligations
which are otherwise specifically covered in this Section 4.2 as a separate
Triggering Event), and such failure is not excused by Force Majeure or cured
within five Business Days after written notice thereof to the Affected Party or
(iv) the Affected Party shall (a) make an assignment or any general arrangement
for the benefit of creditors, (b) file a petition or otherwise commence,
authorize or acquiesce in the commencement of a proceeding or cause under any
bankruptcy or similar law for the protection of creditors, or have such petition
filed against it and such proceeding remains undismissed for 30 Days, (c)
otherwise become bankrupt or insolvent (however evidenced) or (d) be unable to
pay its debts as they fall due or (v) Settees unexcused failure to Schedule the
Buyer's Requested Quantity requested by Buyer for a cumulative period of 30 or
more Gas Days in a 12 Month period in any one Transaction or (vi) Buyer's
unexcused failure to Schedule the DCQ or MinDQ for a cumulative period of 30 or
more Gas Days in a 12 Month period in any one Transaction, or, if applicable,
the MinMQ for a cumulative period of three Months in a 12 Month period in any
one Transaction, or (vii) the occurrence of a Material Adverse Change of the
Affected Party; provided, such Material Adverse Change shall not be considered
if the Affected Party establishes, and maintains throughout the term hereof, a
Letter of Credit (naming the Notifying Party as the beneficiary) in an amount
equal to the sum of (in each case rounding upwards for any fractional amount to
the next $100,000) (a) the Notifying Party's Termination Payment plus (b) if the
Notifying Party is Seller, the aggregate of the amounts Seller is entitled to
receive under each Transaction for Gas Scheduled during the 60 Day period
preceding the Material Adverse Change (the amount of said Letter of Credit to be
adjusted quarterly to reflect amounts owing at that point in time) or (viii) the
Affected Party fails to establish, maintain, extend or increase a Letter of
Credit when required pursuant to this Agreement, or after reasonable notice
fails to replace the issuing bank with another bank acceptable to the
beneficiary or (ix) with respect to Company, at any time, Company shall have
defaulted on its indebtedness to third parties resulting in an acceleration of
obligations of Company in excess of $20,000,000 or with respect to Customer, at
any time, Customer shall have defaulted on its indebtedness to third parties,
resulting in an acceleration of obligations of Customer in excess of $500,000.
4.3 Other Events. In the event Buyer under a Transaction is regulated by a
federal, state or local regulatory body, and such body shall disallow all or any
portion of any costs incurred or yet to be incurred by Buyer under any provision
of this Agreement, such action shall not operate to excuse Buyer from
performance of any obligation nor shall such action give rise to any right of
Buyer to any refund or retroactive adjustment of the Contract Price provided in
any Transaction. Notwithstanding the foregoing, if the Affected Party's
activities hereunder become subject to regulation of any kind whatsoever under
any law (other than with respect to New Taxes) to a greater or different extent
than that existing on the Effective Date and such regulation either (i) renders
this Agreement illegal or unenforceable or (ii) materially adversely affects the
business of the Affected Party, with respect to its financial position or
<PAGE>
otherwise, then in the case of (i) above, either Party, and in the case of (ii)
above, only the Affected Party, shall at such time have the right to declare an
Early Termination Date in accordance with the provisions hereof; provided,
notwithstanding the rights of the Parties to declare an Early Termination Date
as above stated, the Affected Party shall be liable for payment of the
Termination Payment calculated by the non-Affected Party as provided in Section
4.1.
4.4. Offset. Each Party reserves to itself all rights, set-offs, counterclaims
and other remedies and defenses consistent with Section 8.3 (to the extent not
expressly herein waived or denied) which such Party has or may be entitled to
arising from or out of this Agreement. All outstanding Transactions and the
obligations to make payment in connection therewith or under this Agreement may
be offset against each other, set off or recouped therefrom.
4.5. Collateral Requirement/General. It is understood and agreed by the Parties
that either Party may request a Letter of Credit or other collateral prior to
consummating any Transaction hereunder; provided, nothing herein shall obligate
any Party to provide such a Letter of Credit or other collateral without having
made an agreement so to do in respect of such Transaction.
ARTICLE 5. FORCE MAJEURE This Article 5 is the sole and exclusive excuse of
performance permitted under this Agreement and all other excuses at law or in
equity are WAIVED to the extent permitted by law. Except with respect to payment
obligations, in the event either Party is rendered unable, wholly or in part, by
Force Majeure to carry out its obligations hereunder, it is agreed that upon
such Party's giving notice and full particulars of such Force Majeure to the
other Party as soon as reasonably possible (such notice to be confirmed in
writing), the obligations of the Party giving such notice, to the extent they
are affected by such event, shall be suspended from the inception and during the
continuance of the Force Majeure for a period of up to 60 Days in the aggregate
during any 12 Month period, but for no longer period. The Party receiving notice
of Force Majeure may immediately take such action as it deems necessary at its
expense for the entire 60 Day period or any part thereof. The Parties expressly
agree that upon the expiration of the 60 Day period Force Majeure shall no
longer apply to the obligations hereunder and both Buyer and Seller shall be
obligated to perform. The cause of the Force Majeure shall be remedied with all
reasonable diligence and dispatch; provided, unless otherwise agreed no
provision herein shall require or permit Seller or Buyer to Schedule quantities
of Gas (i) in excess of the DCQ, Maximum Daily Delivery Point Quantity or MaxDQ,
as applicable, or (ii) at points other than the Delivery Point(s).
ARTICLE 6. TAXES 6.1. Allocation of Taxes. The Contract Price includes, and
Seller is liable for and shall pay, cause to be paid, or reimburse Buyer if
Buyer has paid, all Taxes applicable to the Gas upstream of the Delivery
Point(s). In the event Buyer is required to remit such Taxes, the amount thereof
shall be deducted from any sums becoming due to Seller hereunder. The Contract
Price does not include, and Buyer is liable for and shall pay, cause to be paid,
reimburse Seller if Seller has paid or pay to Seller if Seller is required by
law to pay to a taxing authority, all Taxes applicable to the Gas downstream of
or at the Delivery Point(s), including, but not limited to, any Taxes imposed or
collected by a taxing authority with jurisdiction over Buyer and any Taxes
imposed on the sale of Gas to Buyer, on Buyer's purchase, possession,
transportation, consumption, use, sale or other disposition of Gas, or on any
payment by Buyer to Seller.
6.2. New Taxes. A. If (i) a New Tax occurs and (ii) Buyer or Seller would be
responsible for such New Tax if it were a Tax under Section 6.1 and (iii) such
New Tax is, due to and on the basis of laws, regulations and applicable
contracts of Buyer in effect as of the effective date of the New Tax, of the
type which Buyer can pass directly through to, or be reimbursed by, another
person or entity in the chain of Gas supply, such Buyer shall pay or cause to be
paid, or reimburse Seller if Seller has paid, all such New Taxes; provided, if
Buyer does not identify its contracts for long-term fixed sourcing in the
ordinary course of its business and cannot identify applicable contracts, this
Paragraph A shall not apply. B. If (i) a New Tax occurs and (ii) either Buyer or
Seller would be responsible for such New Tax if it were a Tax under Section 6.1,
and (iii) Paragraph A does not apply, such responsible Buyer or Seller (the
"Taxed Party") shall be entitled to declare an Early Termination Date in
accordance with the provisions of this Agreement subject to the following
conditions; provided, prior to and including the initial Agreement Period (below
defined) invoked under this Section 6.2, New Taxes shall be allocated as if they
were Taxes as provided in Section 6.1: (a) the Taxed Party must give the
non-Taxed Party at least 30 Days prior written notice (the"'Agreement Period")
of its intent to declare an Early Termination Date (and which notice shall be
given no later than 90 Days after the later of the enactment or effective date
of the relevant New Tax), and prior to the proposed Early Termination Date Buyer
and Seller shall attempt to reach a mutual agreement as to the sharing of the
New Tax, (b) if a mutual sharing agreement is not reached, the non-Taxed Party
shall have the right, but not the obligation, upon written notice to the Taxed
Party within the Agreement Period, to pay the New Tax for any continuous period
it so elects on a Month to Month basis, and in such case the Taxed Party shall
not have the right during such continuous period to declare the Early
Termination Date on the basis of the New Taxes, (c) should the non-Taxed Party
at its election agree to pay the New Tax on a Month to Month basis, then upon 30
Days prior written notice to the Taxed Party of its election to cease payment of
such New Tax, the Taxed Party shall then be liable for the payment of the New
Tax and the Parties shall again be subject to this Section 6.2 as if the New Tax
had an effective date as of the date the non-Taxed Party ceases payment of such
New Tax, (d) if a mutual sharing agreement is not reached and the non-Taxed
Party does not elect to pay the New Tax for any period of time within the
Agreement Period, the Early Termination Date shall take effect and all
Transactions must be terminated and be subject to the same Early Termination
Date, (e) the Early Termination Date shall be effected as if a Triggering Event
had occurred and the Termination Payment calculated as set forth in Section 4.1
shall be payable; provided, both Seller and Buyer pursuant to Section 4.1 shall
calculate their respective Termination Payments resulting from the termination
of all Transactions as if they each were a Notifying Party; provided further, if
the calculation of the Termination Payments results in either the non-Taxed
Party's or the Taxed Party's having either a gain or loss (after netting its
gains against its losses), the Parties shall share equally such net gain due, or
be responsible to pay to the Party having the net loss, one-half of the
Termination Payment and (o such Termination Payment shall be payable as provided
in Section 4.1 and its calculation shall be subject to arbitration as provided
in the PG&E Energy Trading-Gas Corporation General Provisions.
6.3 Documentation Supporting Exemptions or Deductions. If Buyer asserts that an
exemption or deduction from Taxes applies, or if Seller requests in writing that
Buyer provide documentation in support of the application of an exemption or
deduction, Seller shall claim the exemption or deduction only after Buyer has
timely provided to Seller all documents required by law in order for the
exemption or deduction to apply; provided, however, Seller shall have no duty or
obligation: (i) to request such documentation; or (ii) to file a claim for
refund for any Taxes paid for any prior period. Seller's failure to request such
documentation shall not alter the rights and obligations of the Parties under
this Article 6.
6.4 Billing and Payment of Taxes Due Seller. Any Taxes for which Buyer has an
obligation to pay Seller pursuant to Article 6 shall be billed and paid in
accordance with the Financial Matters provision set forth in Appendix 1.
ARTICLE 7. TITLE, RISK OF LOSS, INDEMNITY AND BALANCING 7.1. Title, Risk of Loss
and lndemnity. As between the Parties, Seller shall be deemed to be in exclusive
control and possession of Gas Scheduled hereunder and responsible for any damage
or injury caused thereby prior to the time the same shall have been delivered to
Buyer at the Delivery Point(s). After delivery of Gas to Buyer at the Delivery
Point(s), Buyer shall be deemed to be in exclusive control and possession
thereof and responsible for any injury
<PAGE>
or damage caused thereby. Title to Gas Scheduled hereunder and risk of loss
therefor shall pass from Seller to Buyer at the Delivery Point(s). Seller and
Buyer each assumes all liability for and shall indemnify, defend and hold
harmless the other Party from any Claims, including injury to and death of
persons, arising from any act or incident occurring when title to the Gas is
vested in the Indemnifying Party; provided, however, no Party shall have any
obligation under this Article 7.1 with regard to Taxes, the entire obligation of
any Party regarding Taxes being fully set forth under Article 6. IT IS THE
INTENT OF THE PARTIES THAT THIS INDEMNITY AND THE LIABILITY ASSUMED UNDER IT BE
WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF, INCLUDING, WITHOUT LIMITATION,
THE NEGLIGENCE OF ANY INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT
OR CONCURRENT, OR ACTIVE OR PASSIVE; PROVIDED, NEITHER PARTY SHALL BE LIABLE IN
RESPECT OF ANY CLAIM TO THE EXTENT SAME RESULTED FROM THE GROSS NEGLIGENCE,
WILLFUL MISCONDUCT OR BAD FAITH OF THE INDEMNIFIED PARTY.
7.2. Correction of Imbalances, Cashouts and Penalties. Differences between
Scheduled quantities and actual quantities delivered and received hereunder
("Imbalances") will be corrected or settled in cash or Gas or by offset as the
Parties agree. Additionally, in the event of (i) an Imbalance on Buyer's
Transporters system caused by Seller or Sellers Transporter's delivery of less
or more than the Scheduled quantity for any Gas Day (in which case Seller shall
be the "Responsible Party" - ) or (ii) an Imbalance on Seller's Transporter's
system caused by Buyer or Buyer's Transporter's receipt of more or less than the
Scheduled quantity for any Gas Day (in which case Buyer shall be the
"Responsible Party"), the Responsible Party shall be liable for and reimburse to
the other Party any associated Transporter penalties or cashout costs and losses
incurred by such other Party. In the event the tariff of either Buyer's or
Seller's Transporter provides for cashouts on the basis of the aggregation of
all overdeliveries and underdeliveries between such Transporter and Buyer or
Seller, respectively (the "Aggregate Transporter Imbalance" ), and the nature of
the Imbalance (overdelivery or underdelivery) attributable to the Responsible
Party is the same as the Aggregate Transporter Imbalance (overdelivery or
underdelivery), the Responsible Party shall participate in the other Party's
cashout settlement of the Aggregate Transporter Imbalance on the basis of only
the Responsible Party's pro-rata share thereof.
ARTICLE 8. MISCELLANEOUS 8.1. Notices. All notices, including, without
limitation, consents, and communications made pursuant to this Agreement shall
be made as specified in Exhibit "A." Notices required to be in writing shall be
delivered in written form by letter, facsimile or other documentary form. Notice
by facsimile or hand delivery shall be deemed to have been received by the close
of the Business Day on which it was transmitted or hand delivered (unless
transmitted or hand delivered after close in which case it shall be deemed
received at the close of the next Business Day) or such earlier time confirmed
by the receiving Party. Notice by overnight mail or courier shall be deemed to
have been received two Business Days after it was sent or such earlier time
confirmed by the receiving Party. Any notices given hereunder in respect of the
declaration of an Early Termination Date shall be also sent to the address or
facsimile number so specified in Exhibit "A." Any Party may change its addresses
by providing notice of same in accordance herewith.
8.2. Transfer. This Agreement, including, without limitation, each
indemnification, shall inure to and bind the permitted successors and assigns of
the Parties; provided, neither Party shall transfer this Agreement without the
prior written approval of the other Party which may be withheld entirely at the
option of such Party; provided further, either Party may transfer its interest
to any parent or affiliate by assignment, merger or otherwise or transfer, sell,
pledge encumber or assign this Agreement or the accounts, revenues or proceeds
hereof in connection with any financing or other financial arrangements without
the prior approval of the other Party, but no such transfer shall operate to
relieve the transferor Party of its obligations hereunder. Any Party's transfer
in violation of this Section 8.2 shall be void.
8.3 Limitation of Remedies, Liability and Damages and Mitigation. THE PARTIES DO
HEREBY CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN
THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY
PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS HEREIN PROVIDED,
SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY
HEREUNDER, THE OBLIGOR'S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH
PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF
NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, THE OBLIGOR'S
LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL
DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY HEREUNDER AND ALL OTHER REMEDIES
OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED,
NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY
OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, IN
TORT, CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. NOTWITHSTANDING ANY
OTHER PROVISION IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY BE LIABLE FOR
ANY PENALTIES OR CHARGES ASSESSED BY ANY TRANSPORTER OR OTHER ENTITY FOR THE
UNAUTHORIZED RECEIPT OF GAS BY THE OTHER PARTY. IT IS THE INTENT OF THE PARTIES
THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE
WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING, WITHOUT
LIMITATION, THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT
OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE
PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE
DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS
INCONVENIENT AND THE LIQUIDATED DAMAGES CONSTITUTE A REASONABLE APPROXIMATION OF
THE HARM OR LOSS. BUYER ACKNOWLEDGES THAT IT HAS ENTERED INTO THIS AGREEMENT AND
IS CONTRACTING FOR THE GOODS TO BE SUPPLIED BY SELLER BASED SOLELY UPON THE
EXPRESS REPRESENTATIONS AND WARRANTIES HEREIN SET FORTH AND SUBJECT TO SUCH
REPRESENTATIONS AND WARRANTIES, ACCEPTS SUCH GOODS 'AS-IS' AND 'WITH ALL FAULTS.
SELLER EXPRESSLY NEGATES ANY OTHER REPRESENTATION OR WARRANTY, WRITTEN OR ORAL,
EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR
WARRANTY WITH RESPECT TO CONFORMITY TO MODELS OR SAMPLES, MERCHANTABILITY, OR
FITNESS FOR ANY PARTICULAR PURPOSE. EACH PARTY HEREBY WAIVES ALL RIGHTS UNDER,
ARISING OUT OF OR ASSOCIATED WITH TEXAS & BUSINESS COMMERCE CODE SECTIONS 17.41
THROUGH 17.63 KNOWN AS THE DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT TO
THE EXTENT ALLOWED BY LAW. The Parties acknowledge the duty to mitigate damages
hereunder. In this connection, the Parties recognize that the ability to
effectuate arrangements for the sale or purchase of Gas is conditioned upon the
volatility of Gas markets, the creditworthiness and reliability of potential
customers, the complexity and size of the portfolios of contracts managed by
each Party and the need to conduct market business in an orderly manner.
Therefore, the Parties agree that (i) three Business Days is a commercially
reasonable period to purchase or sell Gas in respect of a Seller's or Buyer's
Deficiency Default and (ii) three Business Days after the end of the Month in
which the Early Termination Date occurs is a commercially reasonable period
after the establishment of an Early Termination Date to determine the
Termination Payment; provided, notwithstanding the foregoing, if Gas volumes
made the basis of a Seller's or Buyer's Deficiency Default or a Party's
determination of the Termination Payment are in excess of 20,000 MMBtu/Gas Day,
the Parties recognize that a longer period may ordinarily be required to
effectuate cover or determine the Termination Payment in an orderly manner so as
not to adversely affect the Gas market. Each Party may utilize its discretion,
with commercially reasonable foresight, to adjust the timing and staggering of
the
<PAGE>
purchases or sales of Gas volumes in its efforts to mitigate damages. No claim
that a Party failed to mitigate damages shall be grounded solely on the basis of
counter Gas market movement.
8.4. Winding Up Arrangements. Upon the expiration of the Parties' sale and
purchase obligations under this Agreement, any monies, penalties or other
charges due and owing Seller shall be paid, any corrections or adjustments to
payments previously made shall be determined, and any refunds due Buyer made,
within 60 Days. Any Imbalances in receipts or deliveries shall be corrected to
zero balance within 60 Days. Notwithstanding the preceding provisions of this
Article 8.4, all indemnity and confidentiality obligations, audit rights, and
any rights and obligations with regard to Taxes pursuant to Article 6 shall
survive the termination of this Agreement. The Parties' obligations provided in
this Agreement shall remain in effect for the purpose of complying herewith.
8.5. Applicable Law. THIS AGREEMENT AND EACH TRANSACTION AND THE RIGHTS AND
DUTIES OF THE PARTIES ARISING OUT OF THIS AGREEMENT SHALL BE GOVERNED BY AND
CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF
TEXAS, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. THE PARTIES AGREE THAT
THIS AGREEMENT AND ALL TRANSACTIONS SHALL BE ACCEPTED AND FORMED IN THE STATE OF
TEXAS ACCORDING TO THE PROCEDURES HEREIN SET FORTH.
8.6. Document Record Retention and Evidence. This Agreement, the Exhibits and
Appendices hereto, if any, and each Transaction, constitute the entire agreement
between the Parties relating to the subject matter contemplated by this
Agreement. There are no prior or contemporaneous agreements or representations
(whether oral or written) affecting the subject matter other than those herein
expressed. Other than with respect to Transactions entered into in accordance
with the procedures set forth in this Agreement and as otherwise herein
expressly stated (the "Transaction Procedures". ), no amendment or modification
to this Agreement shall be enforceable, unless reduced to writing and executed
by both Parties. The conduct of the Parties in accordance with the Transaction
Procedures shall evidence a course of dealing and a course of performance
accepted by the Parties in furtherance of this Agreement and all Transactions
entered into by the Parties. The provisions of this Agreement shall not impart
rights enforceable by any person, firm or organization not a Party or not bound
as a Party, or not a permitted successor or assignee of a Party bound to this
Agreement. Except as otherwise herein stated, any provision, article or section
declared or rendered unlawful by a court of law or regulatory agency with
jurisdiction over the Parties or deemed unlawful because of a statutory change
will not otherwise affect the lawful obligations that arise under this
Agreement. The headings used for the Articles herein are for convenience and
reference purposes only. All Exhibits and Appendices referenced in this
Agreement, if any, are incorporated. Any original executed Agreement or
Transaction Agreement may be photocopied and stored on computer tapes and disks
(the "Imaged Agreement"). The Imaged Agreement, if introduced as evidence on
paper, the Confirmation, if introduced as evidence in automated facsimile form,
and the Transaction Tape, if introduced as evidence in its original form and as
transcribed onto paper, and all computer records of the foregoing, if introduced
as evidence in printed format, in any judicial, arbitration, mediation or
administrative proceedings, will be admissible as between the Parties to the
same extent and under the same conditions as other business records originated
and maintained in documentary form. Neither Party shall object to the
admissibility of the Transaction Tape, the Confirmation or the Imaged Agreement
(or photocopies of the transcription of the Transaction Tape, the Confirmation
or the Imaged Agreement) on the basis that such were not originated or
maintained in documentary form under either the hearsay rule, the best evidence
rule or other rule of evidence.
8.7. Confidentiality. Each Party shall not disclose the terms of any Transaction
to a third party (other than the Party's and its affiliates' employees, lenders,
counsel, accountants or prospective purchasers of any rights under any
Transactions who have agreed to keep such terms confidential) except in order to
comply with any applicable law, order, regulation or exchange rule; provided,
each Party shall notify the other Party of any proceeding of which it is aware
which may result in disclosure and use reasonable efforts to prevent or limit
the disclosure. The provisions of the Agreement other than the terms of any
Transaction are not subject to this confidentiality obligation. The Parties
shall be entitled to all remedies available at law or in equity to enforce, or
seek relief in connection with, this confidentiality obligation; provided, all
monetary damages shall be limited in accordance with Section 8.3.
The Parties have executed this Agreement in multiple counterparts to be
construed as one effective as of the Effective Date.
PG&E ENERGY TRADING-GAS CORPORATION
By: s/M.E. Flinn
Title: Michael E. Flinn - Exec VP & CEO
ROANOKE GAS COMPANY
By: s/Roger L. Baumgardner
Title: VP / SEC & Treas.
<PAGE>
APPENDIX "l"
PG&E ENERGY TRADING-GAS CORPORATION PROVISIONS
* Usage and Definitions All references to Articles and Sections are to those
set forth in this Agreement. Reference to any document means such document as
amended from time to time and reference to any Party includes any permitted
successor or assignee thereof. The following definitions and any terms defined
internally in this Agreement shall apply to this Agreement and all notices and
communications made pursuant to this Agreement.
"Btu" means the amount of energy required to raise the temperature of
one pound of pure water one degree Fahrenheit from 59 degrees
Fahrenheit to 60 degrees Fahrenheit. The term "MMBtu"means one million
Btus.
"Buyer" means the Party to a Transaction who is obligated to purchase
Gas during a Period of Delivery.
"C.T." means Central Time.
"Claims" means all claims or actions, threatened or filed and whether
groundless, false or fraudulent, that directly or indirectly relate to
the subject matters of the indemnity, and the resulting losses,
damages, expenses, attrneys' fees and court costs, whether incurred by
settlement or otherwise, and whether such claims or actions are
threatened or filed prior to or after the termination of this
Agreement.
"Conformation" means a written notice confirming the specific terms of
a Transaction which may be in any form adequate at law; an example of
a Confirmation which may be utilized hereunder is shown in "Exhibit
B."
"Confirm Deadline" means two (2) business days after a Party receives
a Confirmation; provided, if the Confirmation is not received during a
Business Day it shall be deemed received at the open of the next
Business Day.
"Contract Price" means the price for the purchase or sale of Gas
pursuant to a Transaction.
"Daily Contract Quality" ("DCQ") means the quantity of Gas to be
Scheduled each Gas Day pursuant to a Transaction.
"Day" means a period of 24 consecutive hours, beginning at midnight
C.T. on any calendar Day. "Business Day" means a Day on which Federal
Reserve member banks in New York City are open for business and a
Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local
time. "Gas Day" means a period of 24 consecutive hours beginning at
the time of the applicable Transporters gas day.
"Delivery Point(s)" means the agreed point(s) of delivery pursuant to
a Transaction.
"Force Majeure" means an event not anticipated as of the Effective
Date, which is not within the reasonable control of the Party, or in
the case of third party obligations or facilities, the third party,
claiming suspension, and which by the exercise of due diligence such
Party, or third party, is unable to overcome or obtain or cause to be
obtained a commercially reasonable substitute performance therefor;
provided, neither (i) the loss of Buyer's markets nor Buyers inability
economically to use or resell Gas purchased hereunder nor (ii) the
loss or failure of Seller's Gas supply, including, without limitation,
depletion of reserves or other failure of production, nor Seller's
ability to sell Gas to a market at a more advantageous price, shall
constitute an event of Force Majeure. "Force Majeure" shall include an
event of Force Majeure occurring with respect to the facilities or
services of Buyer's or Seller's Transporter.
"GAAP" means generally accepted accounting principles, consistently
applied.
"Gas" means methane and other gaseous hydrocarbons meeting the quality
standards and specifications of Buyer's Transporter.
"Indemnified Party" and "Indemnifying Party" mean the Party receiving
and providing an indemnity, respectively.
"Interest Rate" means, for any date, two percent over the per annum
rate of interest announced as the "Prime Rate" from time to time for
commercial loans by Citibank, N. A. as established by the
administrative body of such bank charged with the responsibility of
establishing such rate, as same may change from time to time;
provided, the Interest Rate shall never exceed the maximum lawful rate
permitted by applicable law.
"Letter of Credit" means an irrevocable standby letter of credit
established by a Party (the 'Account Party') and issued or confirmed
in a form and by a commercial bank acceptable to the Party in whose
favor it is issued (the "Beneficiary Party").
"Material Adverse Change" means with respect to the Customer, in the
reasonable opinion of the Company, a material change in the
creditworthiness, financial condition, or ongoing business of the
Customer that may adversely affect the Customers ability to perform
hereunder, or (ii) with respect to the Company, in the reasonable
opinion of the Customer, a material change in the creditworthiness,
financial condition, or ongoing business of the Company that may
adversely affect the Company's ability to perform hereunder.
"MaxDq" means the maximum quantity of Gas that Seller is required to
Schedule per Gas Day pursuant to a Transaction, if applicable.
"Maximum Daily Delivery Point Quantity" means the maximum quantity of
Gas which may be Scheduled per Gas Day at each Delivery Point where
there are multiple Delivery Points applicable to a Transaction.
"MinDQ" means the minimum quantity of Gas that Buyer is required to
Schedule per Gas Day pursuant to a Transaction, if applicable.
"MinDQ" means for any Month the minimum quantity of Gas per Gas Day
that Buyer is obligated to Schedule times the number of Days in the
Month pursuant to a Transaction, if applicable.
"Month" means a period of time beginning at midnight C.T. on the first
Day of any calendar Month and ending at midnight C.T. on the first Day
of the following calendar Month.
"New Taxes" means (I) any Taxes enacted and effective after the
Effective Date, including, without limitation, that portion of any
Taxes or New Taxes that constitutes an increase, or (ii) any law,
order, rule or regulation, or interpretation thereof, enacted and
effective after the Effective Date resulting in the application of any
Taxes to a new or different class of parties.
"Period of Delivery" means the period from the date Scheduling
obligations are to commence to the date same are to terminate under a
Transaction.
"Pipeline" means a company authorized to ship Gas on behalf of itself
or others on physical Gas transmission facilities.
"Pricing Hours" means the hours C.T. from 8:00 a.m. to 5:00 p.m. of
each Business Day.
"Replacement Price Differential" means (i) in the event of a Seller's
Deficiency Default, the positive difference, if any, obtained by
subtracting the Contract Price from the greater of (a) the cost to
Buyer, including incremental transportation costs and other basis
adjustments, to replace Sellers Deficiency Quantity for such Gas Day
(but excluding penalties or charges for unauthorized receipts of Gas
by Buyer) or (b) the Spot Price for the Gas Day in which Seller's
Deficiency Default occurred, and (ii) in the event of a Buyer's
Deficiency Default, the positive difference, if any, obtained by
subtracting the lesser of (a) the price obtained by Seller in an
incremental, arms-length sale(s) to a third party of a quantity equal
to Buyer's Deficiency Quantity for such Gas Day, less incremental
transportation charges to Seller, and including other basis
adjustments, or (b) the Spot Price for the Gas Day in which Buyer's
Deficiency Default occurred (or if the MinMQ is applicable, the Spot
Price for the middle Gas Day of the Month in which Buyers Deficiency
Default occurred), from the Contract Price.
"Scheduling" or "Schedule," when used in reference to Seller, means to
make Gas available, or cause Gas to be made available, at the Delivery
Point(s) for delivery to or for the account of Buyer, including making
all Pipeline nominations, and when used in reference to Buyer, means
to cause Buyees Transporter to make available at the Delivery Point(s)
transportation capacity sufficient to permit Buyer's Transporter to
receive on a firm basis the quantities Seller has available at such
Delivery Point(s), including making all Pipeline nominations. Gas
shall be deemed to have been Scheduled when confirmed by Transporter.
"Seller" means the Party to a Transaction who is obligated to sell Gas
during a Period of Delivery.
"Spot Price"means the price set forth in Gas Daily (Pasha
Publications, Inc.), or successor publication, in the column 'Daily
Price Survey' under the listing applicable to the geographic location
agreed pursuant to a Transaction for the relevant Gas Day. If there is
no single
<PAGE>
price published for that particular Gas Day, but there is published a
range of prices under the above column and listing, then the Spot
Price shall be the average of such high and low prices. In the event
that no price or range of prices is published for that particular Gas
Day, then the Spot Price shall be the average of the following: the
price (determined as stated above) for each of the first Gas Day
immediately preceding and following the Gas Day in which the default
occurred for which a Spot Price can be determined.
"Taxes" means any or all ad valorem, property, occupation, severance,
production, extraction, first use, conservation, Btu or energy,
gathering, transport, Pipeline, utility, gross receipts, gas or oil
revenue, gas or oil import, privilege, sales, rentals, use,
consumption, excise, lease, transaction, and other taxes or New Taxes,
franchise fees, governmental charges or fees, licenses, fees, permits
and assessments, or increases therein, and any interest or penalties
on such taxes, charges, licenses, fees, permits, New Taxes and
assessments, other than taxes based on net income or net worth.
"Transaction" means an agreement and any amendment or modification
thereof made in accordance herewith for the purchase or sale of Gas to
be performed hereunder.
"Transaction Agreement" means a written paper-based agreement executed
by the Parties to form and effectuate a Transaction which may be
substantially in the form set forth in Exhibit "B-l."
"Transaction Tape" means the tape recording of a recorded Transaction
effectuated in accordance with Article 2.
"Transporter" means either the Pipeline delivering or receiving Gas at
a Delivery Point in a Transaction.
* Representations and Warranties As a material inducement to entering into this
Agreement, including each Transaction, each Party, with respect to itself,
hereby represents and warrants to the other Party continuing throughout the term
of this Agreement as follows: (i) there are no suits, proceedings, judgments,
rulings or orders by or before any court or any governmental authority that
materially adversely affect its ability to perform this Agreement or the rights
of the other Party under this Agreement, (ii) it is duly organized, validly
existing and in good standing under the laws of the jurisdiction of its
formation, and it has the legal right, power and authority and is qualified to
conduct its business, and to execute and deliver this Agreement and perform its
obligations under the same and each Transaction, and all regulatory
authorizations have been maintained as necessary for it to legally perform its
obligations hereunder, (iii) the making and performance by it of this Agreement
is within its powers, has been duly authorized by all necessary action on its
part, and does not and will not violate any provision of law or any rule,
regulation, order, writ, judgment, decree or other determination presently in
effect applicable to it or its governing documents, (iv) each of this Agreement
and each Transaction when entered into constitutes a legal, valid and binding
act and obligation of it, enforceable against it in accordance with its terms,
subject to bankruptcy, insolvency, reorganization and other laws affecting
creditors rights generally, and with regard to equitable remedies, to the
discretion of the court before which proceedings to obtain same may be pending,
(v) there are no bankruptcy, insolvency, reorganization, receivership or other
arrangement proceedings pending or being contemplated by it, or to its knowledge
threatened against it, (vi) it has assets of $5,000,000 or more according to its
most recent financial statements prepared in accordance with GAAP and knowledge
and experience in financial matters that enable it to evaluate the merits and
risks of this Agreement, and (vii) it is not in a disparate bargaining position
with the other Party.
* Operations and Delivery Scheduling Requests. Not later than two Business Days
prior to the earlier of Buyer's or Seller's Transporter's nomination deadline
for the first Gas Day of each Month during a Period of Delivery, Buyer agrees to
provide to Seller facsimile notice of the quantities Buyer requests Seller to
Schedule for each Gas Day of such Month. Should Buyer desire to change the
requested quantities Scheduled, Buyer shall provide to Seller facsimile notice
thereof not later than one Business Day prior to the earlier of Buyer's or
Sellers Transporters nomination deadline for the applicable Gas Day. In the
event the nomination or Scheduling deadline of a Transporter conflicts with
these notification dates, Buyer and Seller agree to modify the notification
dates accordingly. Scheduling requests to Seller will be accepted at the
telephone number and shall be confirmed by facsimile as set forth in Exhibit
"A." Transportation. Seller shall obtain, or cause to be obtained,
transportation to the Delivery Point, and Buyer shall obtain, or cause to be
obtained, transportation from the Delivery Point. Gas Specifications. Seller
represents that all Gas delivered hereunder shall meet or exceed the
specifications of Buyer's Transporter. Multiple Delivery Point Utilization. In
the event a Transaction shall contain more than one Delivery Point, the Parties
shall specify a Maximum Daily Delivery Point Quantity for each Delivery Point.
The Delivery Points which shall be utilized for delivery of Gas and the
quantities of Gas to be Scheduled for delivery at such Delivery Points shall be
determined by Seller in its sole discretion within each applicable Maximum Daily
Delivery Point Quantity. Seller shall provide to Buyer a list of Delivery Points
and quantities determined by it within a period of time necessary to permit
Buyer to make nominations. Operational Flow Orders. Should either Party receive
an operational flow order or other order or notice from a Transporter requiring
action to be taken in connection with this Agreement or Gas flowing under this
Agreement ("O FO"), such Party shall immediately notify the other Party of the
OFO and provide the other Party a copy of same by facsimile. The Parties shall
take all actions required by the OFO within the time prescribed. Each Party
shall indemnify, defend and hold harmless the other Party from any Claims,
including, without limitation, all non-compliance penalties and aftorneys' fees,
associated with an OFO (i) of which the Indemnifying Party failed to give the
Indemnified Party the notice required hereunder or (ii) under which the
Indemnifying Party failed to take the action required by the OFO within the time
prescribed.
* Financial Matters Billing, Invoice Date, Charges and Payment. By the 10th Day
of each calendar Month following the Month in which Gas was Scheduled under a
Transaction, Seller shall provide Buyer with a written statement setting forth
Gas Scheduled during the preceding Month, and other charges due Seller,
including, without limitation, deficiency charges under Article 3, and any Taxes
for which Buyer has an obligation to pay Seller pursuant to Article 6. If Seller
becomes aware, at a later time, of any Taxes for which Buyer has an obligation
to pay Seller pursuant to Article 6, Seller shall render to Buyer a written
statement setting forth such Taxes, and Buyer shall render payment of such
statement in accordance with this Financial Matters provision. Billing and
payment will be based on Scheduled quantities. Within five Business Days of the
request of either Party, the other Party shall provide, to the extent it has a
legal right of access thereto and/or such statement is then available, a copy of
the Transporter's allocation or imbalance statement applicable to Gas sold
hereunder for the requested period. The difference, if any, between Scheduled
and actual quantities delivered or accepted shall be treated as Imbalances under
Article 7. Buyer shall remit any amounts due on the later of the 25th Day of the
Month in which Seller's statement was received or ten days after receipt of
Sellers invoice. If the due date for any payment to be made under this Agreement
is not a Business Day, the due date for such payment shall be the following
Business Day. Payment of all funds shall be made in U. S. currency and as
indicated in Exhibit "A" in such manner that funds are immediately available to
the payee on the applicable due date. Each Party shall take all actions
necessary to effect payments in accordance with the process stated in Exhibit
"A." If Buyer or Seller should fail to remit any amounts in full when due
hereunder, interest on the unpaid portion shall accrue from the date due at a
rate equal to the Interest Rate. Billings, payments and statements shall be made
to the accounts or the addresses/facsimiles specified in Exhibit "A."
Suspension of Performance. If either Party fails to make a timely payment and
such failure is not remedied within two Business Days after such Party receives
written notice of default, the nondefaulting Party, in addition to other
remedies, may suspend the Scheduling of Gas until such amount, including
interest, is paid; provided, if the defaulting Party, in good faith, shall
dispute the amount of any such billing or part thereof and shall pay such
amounts as it concedes to be correct, no suspension shall be permitted.
Audit Rights. During the term of this Agreement and for a period of two years
from the date of termination of a Transaction, Buyer or Seller or any third
party representative thereof shall have the right, upon reasonable notice and at
<PAGE>
reasonable times, to examine the books and records of the other to the extent
reasonably necessary to verify the accuracy of any billing statement, payment
demand, charge, payment or computation made under this Agreement. The records of
the Parties shall be retained in accordance with Section 8.6 for a like period
to facilitate the audit rights of the Parties.
Financial Information. If requested by Customer, Company shall deliver (i)
within 120 Days following the end of each fiscal year, a copy of the annual
report of PG&E Corporation containing consolidated financial statements for such
fiscal year certified by independent certified public accountants and (ii)
within 60 Days after the end of each of its first three fiscal quarters of each
fiscal year, a copy of the quarterly report of PG&E Corporation containing
unaudited consolidated financial statements for such fiscal quarter. If
requested by Company, Customer shall deliver (i) within 120 Days following the
end of each fiscal year, a copy of its annual report containing consolidated
financial statements for such fiscal year certified by independent certified
public accountants and (ii) within 60 Days after the end of each of its first
three fiscal quarters of each fiscal year, a copy of its quarterly report
containing unaudited consolidated financial statements for such fiscal quarter.
In all cases the statements shall be for the most recent accounting period and
prepared in accordance with GAAP; provided, should any such statements not be
timely due to a delay in preparation or certification, such delay shall not be
considered a default so long as such Party diligently pursues the preparation,
certification and delivery of the statements.
* Warranty of Title to Gas Seller in any Transaction warrants that title to Gas
to be Scheduled by Seller is free from all production burdens, liens and adverse
claims and warrants its right to sell the same. Seller agrees to indemnify,
defend and hold harmless Buyer against all Claims to or against the title of
said Gas. In the event any Claim is asserted to said Gas, Buyer, in addition to
other remedies, may suspend its obligation to pay for said Gas up to the amount
of such Claim.
* Alternate Price Redetermination If any or all of the indices used to determine
the Spot Price or the Contract Price are not available in the future, the
Parties agree to promptly negotiate a mutually satisfactory alternate index for
the Spot Price or Contract Price (each an "Alternate Price"). If the Parties
cannot agree by the end of the first Month for which the Spot Price or Contract
Price could not be determined, then Seller and Buyer shall each prepare a
prioritized list of up to five alternative published reference postings or
prices representative of spot prices for Gas delivered in the same geographic
area. Each Party shall submit its list to the other within 10 Days after the end
of the first Month for which the price could not be determined. The first listed
index appearing in Seller's list that also appears in Buyers list shall
constitute the replacement index. If no common indices appear on the lists, each
Party shall submit a new list adding two indices within 10 Days. If either Party
fails to provide timely a list, such Party's list shall not be considered. From
and after the "Renegotiation Date," which shall be the date the Spot Price or
Contract Price is no longer available, until the Alternate Price is determined,
the Alternate Price shall be the average of the Spot Price(s) or Contract
Price(s) in effect during the 12 Months preceding the Month in which the
Renegotiation Date occurred, which price shall be effective until the Alternate
Price is determined. Upon determination of a new Alternate Price, the Spot Price
or Contract Price, as applicable, will be adjusted retroactively to the
Renegotiation Date.
* Effect of Waiver or Consent No waiver or consent by either Party, express or
implied, of any one or more defaults by the other Party in the performance of
any provision of this Agreement shall operate or be construed as a waiver or
consent of any other default or defaults whether of a like or different nature.
Failure by a Party to complain of any act of the other Party or to declare the
other Party in default with respect to this Agreement, regardless of how long
that failure continues, shall not constitute a waiver by that Party of its
rights with respect to that default until the applicable statute of limitations
period has run.
* Indemnifications With respect to each indemnification included in this
Agreement the indemnity is given to the extent authorized by law and the
following provisions shall be considered applicable. The Indemnified Party shall
promptly notify the Indemnifying Party in writing of any Claim and the
Indemnifying Party shall have the right to assume the investigation and defense
thereof, including the employment of counsel, and shall be obligated to pay the
related aftorneys' fees; provided, the Indemnified Party shall have the right to
employ separate counsel and participate in the defense of any Claim, however,
the attorneys' fees of such counsel shall be paid by the Indemnified Party
unless the employment of such counsel has been consented to in writing by the
Indemnifying Party or the Indemnifying Party has failed to assume the defense
and employ counsel in a timely manner, provided further, if the named parties to
any Claim include both Parties, and the Indemnified Party shall have been
advised by counsel that there may be a legal defense available to it which is
different from those available to the Indemnifying Party, the Indemnified Party
may elect to employ separate counsel at the expense of the Indemnifying Party,
in which case the Indemnifying Party shall pay all attorneys' fees of such
counsel and shall not have the right to assume the defense of the Claim on
behalf of the Indemnified Party. The Parties shall use reasonable efforts to
cooperate in the defense of any Claim. The Indemnifying Party shall not be
liable for any settlement of a Claim without its express written consent
thereto. The Indemnified Party shall reimburse the Indemnifying Party for
payments made or costs incurred in respect of an indemnity with the proceeds of
any judgment, insurance, bond, surety or other recovery made with respect to an
event covered by the indemnity.
*Arbitration Disputes to be Arbitrated. Any and all claims, demands, causes of
action, disputes, controversies, and other matters in question arising out of or
relating to this Agreement, any of its provisions, or the relationship between
the Parties created by this Agreement, whether sounding in contract, tort, or
otherwise, whether provided by statute or the common law, for damages or any
other relief, including, without limitation, all Claims (all of which are
referred to herein as "Disputes"), shall be resolved by binding arbitration
pursuant to the Federal Arbitration Act. The arbitration may be initiated by
either Party by providing to the other a written notice of arbitration
specifying the Disputes to be arbitrated. If a Party refuses to honor its
obligations to arbitrate, the other Party may seek to compel arbitration in
either federal or state court. The arbitration proceeding shall be conducted in
Houston, Texas, or other location mutually agreed upon by the Parties. Within 30
Days of the notice initiating the arbitration procedure, each Party shall
designate one arbitrator, who need not be impartial. If a Party fails to
designate an arbitrator, the other Party may have an arbitrator appointed by
applying to the senior active United States District Judge for the Southern
District of Texas. The two arbitrators shall select a third arbitrator. If the
two arbitrators chosen by the Parties fail to agree upon the third arbitrator,
both or either of the Parties may apply to the senior active United States
District Judge for the Southern District of Texas for the appointment of a third
arbitrator. The third arbitrator shall take an oath of neutrality.
Arbitration Procedures. The three arbitrators shall make all of their decisions
by majority vote. The enforcement of this Agreement to arbitrate, the validity,
construction, and interpretation of this Agreement to arbitrate, and all
procedural aspects of the proceeding pursuant to this Agreement to arbitrate,
including, without limitation, the issues subject to arbitration, the scope of
the arbitrable issues, allegations of fraud in the inducement' to enter into
this entire Agreement or to enter into this Agreement to arbitrate, allegations
of waiver, delay or defenses to arbitrability, and the rules governing the
conduct of the arbitration, shall be governed by and construed pursuant to the
Federal Arbitration Act. In deciding the substance of the parties' Disputes, the
arbitrators shall apply the substantive laws of the State of Texas (excluding
Texas choice-of-law principles that might call for the application of some other
State's law). The arbitration shall be conducted in accordance with the
Commercial Arbitration Rules of the American Arbitration Association, except as
modified in this Agreement. It is contemplated that although the arbitration
shall be conducted in accordance with the Commercial Arbitration Rules of the
American Arbitration Association, the arbitration proceeding will be
selfadministered by the Parties; provided, if a Party believes the process will
be enhanced if it is administered by the American Arbitration Association, such
Party shall have the right to cause the process to become administered by the
American Arbitration Association by applying to the American Arbitration
Association and, thereafter, the arbitration shall be conducted pursuant to the
administration of the American Arbitration Association. In determining the
extent of discovery, the number and length of depositions, and all other pre-
<PAGE>
hearing matters, the arbitrators shall endeavor to the extent possible to
streamline the proceedings and minimize the time and cost of the proceedings.
There shall be no transcript of the hearing. The final hearing shall be
conducted within 120 days of the selection of the third arbitrator. The final
hearing shall not exceed 10 Business Days, with each Party to be granted onehalf
of the allocated time to present its case to the arbitrators. All proceedings
conducted hereunder and the decision of the arbitrators shall be kept
confidential by the Parties.
Arbitration Award. Only damages allowed pursuant to this Agreement may be
awarded. IT IS EXPRESSLY AGREED THAT THE ARBITRATORS SHALL HAVE NO AUTHORITY TO
AWARD TREBLE, EXEMPLARY OR PUNITIVE DAMAGES OF ANY TYPE UNDER ANY CIRCUMSTANCES
REGARDLESS OF WHETHER SUCH DAMAGES MAY BE AVAILABLE UNDER TEXAS LAW. THE PARTIES
HEREBY WAIVE THEIR RIGHT, IF ANY, TO RECOVER TREBLE, EXEMPLARY OR PUNITIVE
DAMAGES IN CONNECTION WITH ANY DISPUTE, EITHER IN ARBITRATION OR IN LITIGATION.
The arbitrators shall render their final decision within 20 Days of the
completion of the final hearing fully resolving all of the Disputes that are the
subject of the arbitration proceeding. The arbitrators' ultimate decision after
final hearing shall be in writing. The arbitrators shall certify in their
decision that no part of their award includes any amount for treble, exemplary
or punitive damages not allowed hereunder. The arbitrators' decision shall be
final and non-appealable to the maximum extent permitted by law. Any and all of
the arbitrators' orders and decisions may be enforceable in, and judgment upon
any award rendered in the arbitration proceeding may be confirmed and entered
by, any federal or state court having jurisdiction.
* Authority for Transactions Each Party represents to the other Party that each
of its employees has authority to enter into Transactions pursuant to this
Agreement on its behalf. Identification and authority of a Party's employee
engaging in a recorded telephonic Transaction shall be conclusively established
for all purposes by a statement on the Transaction Tape by the employee of the
employee's name; provided, failure to state the employee name shall not evidence
any lack of authority of the employee to effectuate and form a Transaction.
* Trigger Pricing During the Period of Delivery for a Transaction expressly
providing for "Trigger Pricing" in the Confirmation, either Party may request a
price other than the original Contract Price, being a Fixed Price, Fixed Basis
Price or Floating Basis Price (each below defined) by contacting the other Party
during Pricing Hours requesting any such price for a specified quantity of Gas
to be Scheduled during selected Months within the Period of Delivery; provided,
such request must be made prior to 12:00 CT on the last trading day of the
applicable exchange (NYMEX Gas futures contract for the selected Month or KCBT
Gas futures contract for the selected month). The terms of this Agreement,
including, without limitation, Article 2, shall apply to Trigger Pricing in
respect of any Transaction hereunder. A Confirmation may be sent by Company to
Customer confirming the Trigger Pricing agreement in accordance with Section
2.4. "Fixed Price" means a fixed dollar amount agreed to by the Parties. "Fixed
Basis Price" means a price agreed to by the Parties on the basis of the Gas
futures contract for the applicable exchange then trading for the applicable
Month, or (unless otherwise indicated in the Confirmation) if no such price is
agreed prior to the Trigger Deadline as set out on the Confirmation, the price
shall be the last posted price by the applicable exchange for any contract month
for Gas futures contracts then trading on the applicable exchange plus a fixed
dollar amount basis adjustment agreed to by the Parties. "Floating Basis Price"
means a price equal to the sum of a fixed dollar amount agreed to by the Parties
plus the difference between the selected reference price for the Delivery
Point(s) and the Average Settlement Price for the applicable Month. The price
for all Gas for which a Flexible Price has not been agreed by the Parties shall
be the original Contract Price applicable to the Transaction.
<PAGE>
EXHIBIT "A"
PG&E ENERGY TRADING-GAS CORPORATION
MASTER FIRM PURCHASE/SALE AGREEMENT
NOTICE / COMMUNICATION / PAYMENT
TO COMPANY:
Notices/Correspondence:
P.O. Box 4791
Houston, Texas 77210-4791
Attn: Contract Administration
Telephone No.: 713-371-6000
Facsimile No.: 713-371-6309
Termination Notice Facsimile No.: 713-371-6309
Duns No.: 83-469-2394
Fed. Tax I.D. No.: 94-3115649
Invoices:
P.O. Box 4791
Houston, Texas 77210-4791
Attn: Accounting
Facsimile No.: 713-371-6821
Payments:
Boston Safe Deposit & Trust
Medford, MA
For the account of PG&E Energy Trading-Gas Corporation
ABA No.: 01 1001234
Account No.: 101036
Confirmations:
Facsimile No.: 713-371-6309
Nominations:
Telephone No.: 713-371-6000
Facsimile No.: 713-371-6821
TO CUSTOMER:
Notices/Correspondence:
Post Office Box 13007
Roanoke,@ Virginia 24030
Attn: Michael Gagnet
Telephone No.:540-777-3838
Facsimile No.: 540-777-3957
Duns. No.: 00-794-1669
Fed. Tax I.D. No.:
Invoices:
Post Office Box 13007
Roanoke, Virginia 24030
Attn: Accounting
Payments:
Bank Name: First Union National Bank of Virginia
City & State: Roanoke, VA
For the account of: ---------------------
- -----------------------------------------
ABA No.: 0514-0054-9
Account No.:2001005287087
Confirmations:
Facsimile No.: 540-777-3957
Nominations:
Telephone No.:540-777-3838
Facsimile No.: 540-777-3957
<PAGE>
TRANSACTION CONFIRMATION
FOR IMMEDIATE DELIVERY
EXHIBIT B
Date:
PG&E Energy Trading - Gas Corporation Transaction Confirm No.:
This Transaction Confirmation is subject to the Master Contract between Seller
and Buyer dated . The terms of this Transaction Confirmation are binding unless
disputed in writing on or before the "Confirm Deadline" specified in the Master
Contract. PG& E Energy Trading-Gas Corporation adopts the confirming letterhead
as its signature on this Transaction Confirmation
Seller: Buyer:
Attn: Attn:
Phone: Phone:
Fax: Fax:
Contract No.: Contract No.:
Pricing Terms:
Delivery Period: Begin: Delivery Point:
End:
Performance Obligation and Contract Quantity:
Firm (Fixed Quantity): Interruptible:
MMBtus/day (DCQ) MMBtus/day
[ ] EFP
Special Conditions:
<PAGE>
TRANSACTION CONFIRMATION Exhibit B-1
PG&E Energy Trading - Gas Corporation Date: October 25, 1999
PG&E Energy Trading is not the same company as Pacific Gas and Electric Company,
the utility; Transaction Confirm No.: ROANOKEGAS-P/S-01 PG&E Energy Trading is
not regulated by the California Public Utilities Commission and you do not have
to buy PG&E Energy Trading's products in order to continue to receive quality
regulated services Trade Date: October 8, 1999 from the utility.
- -------------------------------------------------------------------------------
Seller: Buyer:
PG&E Energy Trading-Gas Corporation ("PG&E ET") Roanoke Gas ("RGC")
1100 Louisiana, Suite 1000 519 Kimball Avenue, N.E.
Houston, Texas 77002 Roanoke, VA 24030
Attn: Alan Ehlers Attn: Mike Gagnet
Phone: 502-895-9404 Phone: 540-777-3838
Fax: 502-896-0384 Fax: 540-777-3957
- -------------------------------------------------------------------------------
Pricing Terms:
Baseload Supply
RGC will be charged for the monthly baseload based upon an average of relevant
(points) published prices in Inside F.E.R.C.'s Gas Market Report. The relevant
points are based upon an average of RGC's current transportation entitlements.
In effect, PG&E ET will supply an "Index Basket" of baseload supply at IFERC
"Index Basket" flat.
Winter baseload deliveries will be priced according to the following rates:
- --------------------------------------------------------------------------
Commodity Supply: Weighted average of the following Indices
7.4% Inside F.E.R.C. Gas Market Report's FOM Tennessee Gas
Pipeline Co. - Texas (Zone 0) index
31.5% Inside F.E.R.C. Gas Market Report's FOM Tennessee
Gas Pipeline Co. - La. & Offshore (Zone 1) index
38.2% Inside F.E.R.C. Gas Market Report's FOM Columbia
Gulf Transmission Co. - Louisiana index
9.2% Gas Daily Monthly Contract Index for Columbia,
Mainline
13.7% Inside F.E.R.C. Gas Market Report's FOM Chicago
Citygate (Midwestern)
Variable Charges: $.06425 Commodity Charges
5.0939% Fuel Retainage
Summer baseload deliveries will be priced according to the following rates:
- --------------------------------------------------------------------------
Commodity Supply: Same as Winter Commodity Supply (see above)
Variable Charges: $.05849 Commodity Charges
4.78% Fuel Retainage
Deliveries TO Columbia Gas Storage will be priced according to the following
- ----------------------------------------------------------------------------
rates:
- -----
Commodity Supply: Weighted average of the following Indices
62.6% Inside F.E.R.C. Gas Market Report's FOM Columbia
Gulf Transmission Co. - Louisiana index
15.4% Gas Daily Monthly Contract index for Columbia,
Mainline
22% Inside F.E.R.C. Gas Market Report's FOM Tennessee Gas
Pipeline Co. - La. & Offshore (Zone 1) index
Variable Charges: $.05987 Commodity Charges
5.6719% Fuel Retainage
Deliveries TO Tennesee Gas Storage will be priced according to the following
- ----------------------------------------------------------------------------
rates:
- -----
Commodity Supply: Weighted average of the following Indices
19% Inside F.E.R.C. Gas Market Report's FOM Tennessee Gas
Pipeline Co. - Texas (Zone 0) index
45.8% Inside F.E.R.C. Gas Market Report's FOM Tennessee
Gas Pipeline Co - La. & Offshore (Zone 1)index
35.2% Inside F.E.R.C. Gas Market Report's FOM Chicago
Citygate (Midwestern)
Variable Charges: $.06233 Commodity Charges
1.5933% Fuel Retainage
Deliveries TO Virginia Gas Storage will be priced according to the following
- ----------------------------------------------------------------------------
rates:
- -----
Commodity Supply: Weighted average of the following Indices
19% Inside F.E.R.C. Gas Market Rcport's FOM Tennessee Gas
Pipeline Co. - Texas (Zone 0) index
45.8% Inside F.E.R.C. Gas Market Report's FOM Tennessee
Gas Pipeline Co - La. & Offshore (Zone 1) index
35.2% Inside F.E.R.C. Gas Market Report's FOM Chicago
Citygate (Midwestern)
Variable Charges: $.07313 Commodity Charges
3.1481% Fuel Retainage
Further, the Contract Price shall be adjusted for any item(s) set forth under
Special Conditions.
- -------------------------------------------------------------------------------
<PAGE>
- -------------------------------------------------------------------------------
Pricing Terms (continued):
Swing Supply
PG&E ET will supply additional swing supply at the Midpoint of Gas Daily's -
Daily Price Survey - Columbia, App. flat. The Gas Daily price billed to RGC will
be dependent upon the day in which the additional supply is actually purchased
by PG&E ET. In addition to the commodity price paid, RGC will also be
responsible for the variable Deportation costs (commodity and fuel retainage
rates) associated with the Columbia, App.
Supply.
PG&E ET will purchase excess baseload supply from RGC at the lower of the
Midpoint of Gas Daily's - Daily Price Survey - Louisiana, Onshore -Columbia flat
or IFERC Columbia Gulf Louisiana flat. The price paid to RGC will be based upon
the day in which the additional supply is actually re-sold in the market by PG&E
ET. PG&E ET will reimburse RGC for any variable transportation costs charged on
the monthly baseload quantity which is sold back to PG&E ET under the
aforementioned method.
- -------------------------------------------------------------------------------
Delivery Period: Begin: November 1, 1999 Delivery Point: Roanoke Gas citygate
End: October 31, 2000
- -------------------------------------------------------------------------------
Performance Obligation and Contract Quantity:
Full Requirements, not to exceed 74,531 MMBtus/day (DCQ)
Baseload Deliveries (Fixed Quantity):
Nov99 - 15,210 MMBtus/day May00 - 20,642 MMBtus/day
Dec99 - 23,441 MMBtus/day Jun00 - 17,534 MMBtus/day
Jan00 - 27,520 MMBtus/day Jul00 - 17,413 MMBtus/day
Feb00 - 22,026 MMBtus/day Aug00 - 17,561 MMBtus/day
Mar00 - 15,224 MMBtus/day Sep00 - 17,542 MMBtus/day
Apr00 - 27,233 MMBtus/day Oct00 - 24,392 MMBtus/day
Swing Deliveries/Purchases:
On any day in which the net natural gas requirements of RGC exceed the monthly
baseload as determined by PG&E ET, PG&E ET will supply the necessary additional
supply up to the Contract Quantity of 74,531 MMBtus/day.
On any day in which the net natural gas requirements of RGC are less than the
monthly baseload established by PG&E ET, PG&E ET will purchase the excess
baseload supply from RGC.
- -------------------------------------------------------------------------------
Special Conditions:
Asset Release: RGC will (i) appoint PG&E ET as its agent for
all of its storage capacity (see Exhibit A, First
Amendment) and (ii) release its transportation
contracts to PG&E ET (see Exhibit C). To facilitate
RGC's release of its transportation contracts, PG&E ET
will pay all pipeline demand charges, but will be
subsequently reimbursed by RGC. At the expiration of
the transaction, all storage assets will be returned
to the control of RGC with inventory levels equal to
those that existed on 10/31/99.
Supply Contracts: RGC will sell all existing supply contracts
to PG&E ET. PG&E ET will reimburse RGC for their costs
associated with this supply, exclusive of demand
charges (see Exhibit D). RGC will pay all supply
invoices.
Demand Payment: Throughout the term of the deal, PG&E ET will pay a
monthly demand charge to RGC equal to $68,348.17.
Extension of Term: PG&E ET will have the unilateral right to
extend the term of this transaction through October
31, 2001. Should PG&E wish to exercise this right,
RGC must be notified prior to the close of business
on February 29, 2000. Should the term of the
transaction be extended and RGC so desire, PG&E ET
will work in good faith to develop a plan which would
provide for PG&E ET to take assignment of RGC's
storage capacity and own RGC's storage gas until
delivery of aforementioned storage
gas to the RGC city-gate.
Storage Billing RGC will be billed monthly for a ratable storage
withdrawal/injection. During the winter, the total
daily withdrawals billed will be equal a citygate
delivery of 14,853/day (9,947/day TCO/3,722/day
TGP/1,184/day Va. Gas). During the summer, the total
daily injections billed equal to 10,550/day (7,065/day
TCO/2,644/day TGP 841/day Va. Gas).
Storage Costs: In addition to the commodity and variable cost
charged to RGC for deliveries to storage facilities,
RGC will also be charged for any variable charges
associated with delivery into storage. RGC will not
pay for the commodity when it is withdrawn from
storage but will be responsible for the associated
variable withdrawal charges.
Variable Charges All variable charges associated with this
transaction are based upon the current commodity and
fuel rates as presented in the applicable pipeline
tariff. These rates will be adjusted to continuously
reflect the most up to date tariff rates.
Non-Performance Notwithstanding any other provisions in this
Transaction Confirmation, RGC shall have a unilateral
right to terminate the Agreement between the parties
as evidenced hereby, before March 31, 2000, upon 10
days' notice to ENERGY TRADING, for inadequate
performance. "Inadequate performance" shall only
mean ENERGY TRADING's failure to supply the firm
citygate natural gas volumes to RGC, as contracted by
the parties, unless ENERGY TRADING's performance is
excused under the Master Firm Agreement
- -------------------------------------------------------------------------------
<PAGE>
- -------------------------------------------------------------------------------
Seller: PG&E Energy Trading-Gas Corporation Buyer: Roanoke Gas
----------------------------------- -----------------------------
By: By: s/John B. Williamson, III
----------------------------------- -----------------------------
Name/Title: Name/Title: John Williamson / CEO
----------------------------------- -----------------------------
Date: Date: Oct. 27, 1999
----------------------------------- -----------------------------
- -------------------------------------------------------------------------------
<PAGE>
EXHIBIT C
EXHIBIT C TO MASTER AGREEMENT
Roanoke Gas Company - Commodity Pricing and Associated Variable Charges
*Winter baseload deliveries will be priced according to the following rates:
<TABLE>
<CAPTION>
Winter Fuel Winter Fuel Winter Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Winter Fuel pipeline 1 pipeline 2
- -------------- ---------- ---------- ---------- ---------- ------------ ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Tennessee Gas-Texas (ZO) 7.4% TGP ZO to ETN to RGC 2.790% 2.220% 4.948% $0.0691 $0.0108
Tennessee Gas-La. (Z1) 17.80% TGP Z1 to ETN to RGC 1.910% 2.220% 4.088% $0.0594 $0.0108
Tennessee Gas-La. (Z1) 13.70% TGP Z1 to TCO to RGC 4.990% 2.116% 7.000% $0.0895 $0.0229
Columbia Gulf-La. 38.20% CGT FTS2 to FTS1 to TCO to RGC 0.590% 2.988% 2.116% 5.601% $0.0039 $0.0192
Columbia Mainline* 9.20% CGT FTS1 to TCO to RGC 2.988% 2.116% 5.041% $0.0192 $0.0229
Midwester** 13.70% MGT to TGP Z1 to ETN to RGC 0.500% 0.500% 2.220% 3.195% $0.0031 $0.0594
5.0939% Fuel
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0799
$0.0702
$0.1124
$0.0229 $0.0460
$0.0421
$0.0108 $0.0733
$0.06529 Commodity
</TABLE>
*(GD - Monthly Contract Index)*
**Midwestern Index = IFERC Chicago Winter Index Basket - Variable Charges
- ------------------------------------------------------------------------------
<TABLE>
<CAPTION>
*Summer baseload deliveries to the citygate will be priced according to the following rates:
Summer Fuel Summer Fuel Summer Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Summer Fuel pipeline 1 pipeline 2
- -------------- ---------- ---------- ---------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Tennessee Gas-Texas (ZO) 7.40% TGP ZO to ETN to RGC 2.440% 1.580% 3.981% $0.0691 $0.0108
Tennessee Gas-La.(Z1) 17.80% TGP Z1 to ETN to RGC 1.700% 1.580% 3.253% $0.0594 $0.0108
Tennessee Gas-La.(Z1) 13.70% TGP Z1 to TCO to RGC 4.290% 2.116% 6.315% $0.0895 $0.0229
Columbia Gulf-La. 38.20% CGT FTS2 to FTS1 to TCO to RGC 0.590% 2.988% 2.116% 5.601% $0.0039 $0.0192
Columbia Mainline* 9.20% CGT FTS1 to TCO to RGC 2.988% 2.116% 5.041% $0.0192 $0.0229
Midwester** 13.70% MGT to TGP Z1 to ETN to RGC 0.500% 0.500% 2.220% 3.195% $0.0031 $0.0594
4.7800% Fuel
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0799
$0.0702
$0.1124
$0.0229 $0.0460
$0.0421
$0.0108 $0.0733
$0.06529 Commodity
</TABLE>
Summer Index Basket - Variable Charges
- -----------------------------------------------------------------------------
* The commodity price of storage injections will be based upon the following
rates:
1) Virginia Gas Storage
<TABLE>
<CAPTION>
Fuel Fuel Fuel Cumulative Commodity Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Summer Fuel pipeline 1 pipeline 2
- -------------- ---------- ---------- ---------- ---------- ------------ ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Tennessee Gas-Texas (ZO) 19.00% TGP ZO to ETN to Va. Gas 2.440% 1.580% 3.981% $0.0691 $0.0108
Tennessee Gas-La. (Z1) 45.80% TGP Z1 to ETN to Va. Gas 1.700% 1.580% 3.253% $0.0594 $0.0108
Midwester** 35.20% MGT to TGP Z1 to ETN to Va .Gas 0.500% 0.500% 1.580% 2.562% $0.0031 $0.0594
3.1481% Fuel
</TABLE>
<TABLE>
<CAPTION>
Commodity Total
pipeline 3 Commodity
- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0799
$0.0702
$0.0108 $0.0733
$0.07313 Commodity
</TABLE>
Variable Charges to Storage
(Variable charges into Storage will be based on actual Storage
Service injected to)
2)Tennessee Storage
<TABLE>
<CAPTION>
Summer Fuel Summer Fuel Cumulative Commodity Commodity Total
IFERC Location Weighting pipeline 1 pipeline 1 Summer Fuel pipeline 1 pipeline 2 Commodity
- -------------- ---------- ---------- ---------- ----------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
Tennessee Gas-Texas (ZO 19.00% TGP ZO to TGP FS 2.440% 2.440% $0.0691 $0.0691
Tennessee Gas-La. (Z1) 45.80% TGP Z1 to TGP FS 1.700% 1.700% $0.0594 $0.0594
Midwester** 35.20% MGT to TGP Z1 to TGP FS 0.500% 0.500% 0.997% $0.0031 $0.0594 $0.0625
Variable Charges to Storage 1.5933% Fuel $0.06233 Commodity
(Variable charges into Storage will be based on actual Storage Service injected to)
</TABLE>
3) Columbia Gas Storage
<TABLE>
<CAPTION>
Fuel Fuel Fuel Cumulative Commodity
IFERC Location Weighting pipeline 1 pipeline 2 pipeline 3 Summer Fuel pipeline 1
- -------------- ---------- ---------- ---------- ---------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C>
Columbia Gulf-La. 62.60% CGT FTS2 to FTS1 to TCO to TCO FSS 0.590% 2.988% 2.116% 5.601% $0.0039
Columbia Mainline* 15.40% CGT FTS1 to TCO to TCO FSS 2.988% 2.116% 5.041% $0.0192
Tennessee Gas-La. (Z1) 22.00% TGP Z1 to TCO to TCO FSS 4.290% 2.116% 6.315% $0.0895
5.6719% Fuel
</TABLE>
<TABLE>
<CAPTION>
Commodity Commodity Total
pipeline 2 pipeline 3 Commodity
- ----------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
$0.0192 $0.0229 $0.0460
$0.0229 $0.0412
$0.0229 $0.1124
$0.05987 Commodity
</TABLE>
Variable Charges to Storage
(Variable charges into Storage will be based on actual Storage
Service injected to)
<PAGE>
EXHIBIT D
EXHIBIT D TO TRANSACTION CONFIRMATION
Roanoke - Capacity Detail
- -------------------------
<TABLE>
<CAPTION>
Pipeline Type Contract # Recpt. No Recpt. Name Receipt Vol Delivery No Delivery Name Delivery Volume
-------- ----- ---------- --------- ----------- ----------- ----------- ------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Tennessee FT 26446 011353 Eugene I 322 5000
020001 Broad Run TCO 5000
Tennessee FT 24376 012447 MGT 5293
020289 ETN 5293
Tennessee FT 5487 010031 Union-E Tx Deh 708
010706 Mobil E Cam 64 1624
011119 Chevron-S Mar 1660
011970 Amoco El 224a 1835
012197 Tejas- King Ran 2000
070017 Bear Ck 310
070020 Portland 1189
020289 ETN
Midwestern FT 24377 017025 Nor. Border 5293
027086 TGP 5293
East Tennessee FT 4267 753101 TGP 9226
759009 Va Gas Sto 857
759004 Clearbrook 5974
759105 CS 55
759110 Elliston 129
759003 Salem 3925
East Tennessee FT 24724 753101 TGP 5150
759004 Clearbrook 5150
Columbia Gulf FTS-2 40432 4041 Dominion 750
4046 PG & E -Lake 3998
433 CGT -Egan A 1750
512 Badger- Lak 750
646 Apache-Lak 750
701 Santa Fe -L 3000
706 Santa Fe -L 3000
2700010 CGT-Rayne 13998
Columbia Gulf FTS-1 38026 2700010 CGT-Rayne 17349
801 Tco-Leach 17349
Columbia FTS 38098 A02 Flat Top 8550
B9 Broad Run 5000
801 Tco-Leach 9959
62 RGC 23509
Columbia FTS 57449 B4 Kenova 3425
62 RGC 3425
Columbia NTS 57449 801 Tco-Leach 7000
62 RGC 7000
Columbia SST 38085 STOW Storage With 19475
62 RGC 19475
Columbia SST 50420 STOW Storage With 5889
62 RGC 5889
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT E
EXHIBIT E TO MASTER AGREEMENT
Supply Contracts
Roanoke, Natural Gas
Supplier Receipt Term Max Volume Min Volume Commodity Demand
Pipeline Point Start End Dth/day Dth/day Index Price Chg Optionality
-------- ----- ----- --- ------- ------- ----- ------ --- -----------
<S> <C> <C> <C> <C> <C> <C>
Engage Cgt On Pool 11/1/97 10/31/00 3,000 3,000 IFGMR FOM, CGT LA 1+.01 NO
Engage Cgt On Pool 12/1/96 11/30/99 1,500 1,500 IFGMR FOM, CGT LA 1+.0125 NO
Coral Cgt orTg On or 500 Pool 11/1/98 10/31/01 1,500 1,500 IFGMR FOM, CGT LA or TGP Z1 1+.0075 YES
Cabot Tco Bradley/Tanner 12/1/97 11/30/00 4,400 0 IFGMR FOM, TCO Appl 1+.035 YES
CES Tco A02 12/1/98 11/30/01 4,400 0 IFGMR FOM, TCO Appl Flat 0.015 YES
Engage Tgp 500 Pool 12/1/97 11/30/00 2,000 2,000 IFGMR FOM, TGP Z1 1+.01
16,800 8,000
</TABLE>
<TABLE>
<CAPTION>
Notification Contact Phone Notes
- ------------ ------- ----- -----
<S> <C> <C> <C> <C> <C> <C>
NA baseload
NA baseload
4 days prior to NYMEX close Rich Gradler 713-371-5845 baseload
6 bus. days prior to month end Robert Williams 304-347-1656 must take CGT thru 3/31/00, then our option
5 bus. days prior to month end Brian Spack 713-693-2555 monthly swing
NA monthly swing
baseload
baseload
</TABLE>
Exhibit 10(e)(e)(e)
FIRST AMENDMENT
TO
THE MASTER FIRM PURCHASE/SALE AGREEMENT
BY AND BETWEEN
ROANOKE GAS COMPANY
AND
PG & E ENERGY TRADING-GAS CORPORATION
DATED
MARCH 1, 1999
This Amendment, (the "Amendment") to that certain Master Firm Purchase/Sale
Agreement between Roanoke Gas Company, a Virginia corporation ("RGC"), and PG &
E Energy Trading-Gas Corporation, a California corporation ("Energy Trading"),
dated March 1, 1999 (the "Master Firm Agreement"), is entered into by RGC and
ENERGY TRADING, effective as of October 20, 1999.
WHEREAS, RGC and ENERGY TRADING have entered into a Letter of Intent,
dated October 18, 1999, pursuant to which ENERGY TRADING has agreed to manage
all of RGC's natural gas, transportation and storage assets, exclusive of LNG
facilities;
WHEREAS, ENERGY TRADING's asset management shall include its assumption
of 100% of RGC's natural gas requirements up to 74,531dth per day, on a firm
uninterruptible basis;
WHEREAS, a portion of RGC's natural gas requirements will be pulled from
storage and on any given day the contract withdrawal plan may differ from
physical storage activities, and a portion of such requirements may be sold to
RGC by ENERGY TRADING under the terms of the Master Firm Agreement; and
WHEREAS, to further facilitate ENERGY TRADING's management of RGC's
assets, the parties desire to amend the Master Firm Agreement to (i) govern
ENERGY TRADING's asset management responsibilities, including management of
RGC's storage capacity located at the storage facilities listed on Exhibit A
hereto and (ii) 2.179122 Bcf of natural gas owned by RGC and stored at the
storage facilities (the "Storage Assets"), which Storage Assets shall then be
loaned back and forth between the parties during the term thereof.
NOW, THEREFORE, in consideration of the mutual covenants herein
contained, RGC and ENERGY TRADING agree as follows:
1. ARTICLE 1. TERM of the Master Firm Agreement is hereby deleted in its
entirety and replaced by the following:
"ARTICLE 1. TERM. This Master Firm Agreement shall govern all
Transactions for (i) the firm purchase or sale of gas between the
parties, and (ii) ENERGY TRADING's
<PAGE>
management of RGC's Storage Assets under Article 9 hereof, to be in
effect until October 31, 2000. At ENERGY TRADING's sole election, the
term of this Master Firm Agreement may be extended through October 31,
2001. Should ENERGY TRADING elect to extend this Master Firm Agreement,
it must give notice to RGC prior to the close of business on February
29, 2000. Both parties agree that if the Master Firm Agreement is
extended, and RGC so desires, they will negotiate in good faith to
develop a plan for Energy Trading to take title to RGC's storage
capacity and stored gas until delivery to RGC's citygate. Termination of
this Master Firm Agreement shall in all instances be subject to Section
8.4.
2. The Master Firm Agreement is hereby amended to add an ARTICLE 9. ASSET
MANAGEMENT. Article 9 shall read as follows:
"ARTICLE 9. ASSET MANAGEMENT. 9.1 Management Services. Beginning on
November 1, 1999, ENERGY TRADING agrees to assume full responsibility
for supplying 100% of RGC's natural gas requirements up to 74,531 dth
per day, on a firm uninterruptible basis, and to provide asset
management services to RGC, such services to be provided for the
remainder of the term of this Master Firm Agreement.
9.2 Limited Agency Appointment. In order to facilitate ENERGY TRADING's
management services, RGC hereby appoints ENERGY TRADING its limited
agent for the purpose of nominating injections and withdrawals from
storage, buying and selling natural gas on its behalf. As RGC's limited
agent, ENERGY TRADING's role shall be one of independent contractor, and
in no event shall the relationship between the parties be construed as a
partnership, joint venture or full agency relationship. At all times
during ENERGY TRADING's agency, title to all gas withdrawn from,
purchased, sold or injected into storage shall reside with RGC.
9.3 Management Fee Waiver. In lieu of any management fee payable to
ENERGY TRADING for its asset management services hereunder, RGC waives
all proceeds, if any, recognized by ENERGY TRADING in the management of
the Storage Assets, other than the demand charge provided for in the
Special Conditions section of the Transaction Confirmation.
9.4 Inadequate Performance. Notwithstanding any other provisions in this
Master Firm Agreement, RGC shall have a unilateral right to terminate
this Master Firm Agreement before March 31, 2000, upon 10 days' notice
to ENERGY TRADING, for inadequate performance. "Inadequate performance"
shall only mean ENERGY TRADING's failure to supply the firm citygate
natural gas volumes to RGC, as contracted by the parties unless ENERGY
TRADING'S performance is excused under the Master Firm Agreement.
3. For purposes of incorporating this Amendment into the Master Firm
Agreement, as
<PAGE>
between the parties, the term "Seller" shall refer to ENERGY TRADING,
either in its own right or on behalf of RGC, and the terms "Buyer" and
"Customer" shall refer to RGC.
4. The commercial terms of the Letter of Intent between the parties are
incorporated herein by this reference and made a part hereof
5. Except as set forth in this Amendment, the terms of the Master Firm
Agreement are ratified and confirmed in all respects by the parties.
IN WITNESS WHEREOF, the parties have executed this Amendment effective as of the
______ day of October, 1999.
ROANOKE GAS COMPANY
By: s/John B. Williamson, III
Name: John B. Williamson, III
Title: Chairman and CEO
PG & E ENERGY TRADING-GAS CORPORATION
By: s/Tony Chovanec/SBS
Name: Tony Chovanec
Title: Vice President
<PAGE>
EXHIBIT A
[Storage Asset details]
<PAGE>
EXHIBIT A TO THE FIRST AMENDMENT
Firm Storage Contracts
Roanoke Gas Company
<TABLE>
<CAPTION>
Storage Max Daily Max Daily
Pipeline Type SCQ Withdrawal Rights Injection Rights
<S> <C> <C> <C> <C> <C> <C>
Columbia Transmission FSS 1,511,939 25,364 12,096
Tennessee Gas Pipeline FS-PA 400,000 3,500 2,667
Tennessee Gas Pipeline FS-MA 134,603 978 897
Tennessee Gas Pipeline FS-PA 31,174 211 208
Virginia Gas Firm 180,000 2,000 1,200
</TABLE>
Exhibit 13
THE NEXT GENERATION
[Pictures of caterpillar, cocoon and butterfly.]
Roanoke Gas Company
becomes
RGC Resources, Inc.
RGC Resources [symbol]
1999 ANNUAL REPORT
<PAGE>
TABLE OF CONTENTS
1. Letter To Shareholders 17. Independent Auditors' Report
2. Board of Directors 18. Consolidated Balance Sheets
3. The Next Generation 20. Consolidated Statement of Earnings
5. Heritage 21. Consolidated Statement of Stockholders'
Weather, Price & Policy Equity
22. Consolidated Statements of Cash Flows
7. Community
Natural Gas Growth 38. Summary of Gas Sales and Statistics
9. Diversity 39. Capitalization Statistics
Diversified Operations
40. Board of Directors and Officers
10. Management's Discussion and Analysis
of Financial Condition Corporate Information - Inside Back Cover
& Results of Operations
16. 1999 Financial Highlights
SERVICE AND MARKET AREA
[MAP OF SERVICE AND MARKET AREA]
<PAGE>
LETTER TO SHAREHOLDERS
Dear Shareholder:
I am pleased to report that we completed our corporate restructuring this
year and established RGC Resources, Inc. as our holding company effective July
1, 1999. I am also pleased that 1999 was another record earnings year with net
income of $2.9 million, a 6 % increase over 1998. The improvement in total
earnings occurred in spite of 8% warmer weather, primarily as a result of
customer growth, improved rate design, and cost management.
Solid customer growth was realized with 4,529 net customer additions, a 7%
growth rate overall, driven by a 3.2% increase in natural gas customers and a
26% increase in propane customers. A new record was set for propane deliveries
at 9 million gallons, up 17%. Natural gas volumes were down 5% as a result of
the warmer weather.
I believe we have positioned RGC Resources, Inc. to grow and prosper in the
new century. Our natural gas subsidiaries in Roanoke and Bluefield are
consistently demonstrating customer growth above the national average with
earnings growth even in years when the weather is not favorable to gas sales.
Our propane subsidiary is now operating in 33 counties in western Virginia and
southern West Virginia with substantial opportunities for customer growth within
existing market areas, as well as further geographic expansion.
With the holding company structure now in place, we can begin to develop
and provide additional services to existing and new customers that were not
possible while we were operating under the Roanoke Gas Company utility corporate
structure. We are analyzing the potential for additional services based on input
from our customers and the opportunity for synergies with our operating systems,
management talents, and work flows. One focus will be to balance seasonal
workloads and to lessen our revenue and earnings sensitivity to fluctuations in
winter weather patterns.
I believe we made major strides in our core business operation in 1999. In
addition to the customer growth, we replaced over 12 miles of bare steel and
cast iron mains as part of our distribution system renewal program. We obtained
regulatory approval for an annual rate adjustment to recover the cost associated
with the distribution system renewal program for the next three years. This
arrangement eliminates the necessity to file formal rate cases during this
period to recover the incremental depreciation and interest expense associated
with the renewal program. We also further expanded our geographic propane
footprint with new bulk storage facilities constructed in Beckley, West Virginia
and Weyers Cave, Virginia. These two locations further our strategy of expanding
in the interstate corridors.
We spent a significant amount of employee time and effort this year in
addressing systems replacement and upgrades to address Y2K concerns and to
modernize our customer information system. In addition to customer, accounting,
and financial system upgrades, we replaced gas control and remote electronic
metering systems, pressure regulation and monitoring control systems and our
telephone system to ensure Y2K readiness. These efforts, combined with our
contingency planning and the readiness planning of our major supplier and
vendors, positions us well for the year 2000 date change.
The year just ended has been an exciting one for the energy industry. Early
in the year energy prices fell dramatically with the significantly warmer than
normal weather, followed by price spikes during the summer and fall associated
with air conditioning energy demand and an OPEC reduction in crude oil
production. In addition, it was a very active year for mergers and acquisitions
as the electric and larger natural gas utilities made or attempted to make
acquisitions either as defensive or offensive moves in anticipation of perceived
opportunities or threats with further deregulation of natural gas and
electricity commodity prices. The merger mania has generally not impacted our
service areas, but has been confined to much larger metropolitan markets where
some industry executives and analysts believe that economies of scale are needed
to compete in more deregulated commodity markets.
While we understand the economies of scale issue, we also recognize that we
are one of the lowest cost providers of natural gas in Virginia and West
Virginia. We do not believe the theoretical savings promised by consolidation
would result in our becoming a more competitive service provider, in our less
densely populated markets. We have already realized many of these economies of
scale through selective outsourcing. Our strategy will be to profitably grow our
core energy markets and to use or new holding company structure to add
shareholder value by providing new products and services developed around our
natural gas and propane delivery systems and customers.
I am pleased with our growth and earnings this year as well as our progress
on a variety of fronts ranging from systems enhancements to creating a
performance culture among Company employees. I thank you for your interest in
the growth and evolution of our Company and for your continuing decision to
invest in RGC Resources stock.
Sincerely,
s/John B. Williamson, III
John B. Williamson, III
President and CEO
1
<PAGE>
[Picture of Board of Directors]
Seated: Frank Ellett, Frank Farmer, John Williamson, Wilbur Hazlegrove
Standing: Frank Smith, Ab Boxley, Lynn Avis, Allen Layman, Tom Robertson
BOARD OF DIRECTORS
Lynn D. Avis Wilbur L. Hazlegrove
President, Avis Construction Co., Inc. Woods, Rogers & Hazlegrove, PLC
Abney S. Boxley, III J. Allen Layman
President & CEO, Boxley Co., Inc. President & CEO, R & B Communications,
Inc.
Frank T. Ellett Thomas L. Robertson
President, Virginia Truck Center, Inc. President & CEO, Carilion Health
System and Carilion Medical Center
F. A. Farmer
Chairman of the Board of Directors S. Frank Smith
RCG Resources Vice President,
Coastal Coal Company, LLC
John B. Williamson, III
President & CEO, RGC Resources
2
<PAGE>
THE NEXT GENERATION
In 1999 Roanoke Gas Company underwent a metamorphosis (like the caterpillar
on our cover) from a regulated utility company of the past to a modern holding
company of the future, poised to take advantage of significant opportunities in
today's marketplace.
The next generation of our company, RGC Resources, Inc. is a new order of
corporate structure that provides for rapid start-ups, increased flexibility and
broadened potential for growth and profits. RGC currently consists of three
subsidiaries:
Roanoke Gas Company: the regulated company in Virginia, which now includes
the former Commonwealth Public Service Company, providing natural gas sales and
services.
Bluefield Gas Company: the regulated company in West Virginia providing
natural gas sales and services.
Diversified Energy Company: the non-regulated company providing propane
sales and services in Virginia and West Virginia, doing business as Highland
Propane Company and Highland Gas Marketing.
Financial
The Company has once again surpassed the previous year's earnings even
though this year's weather was 8% warmer than the previous year. Net earnings
for fiscal 1999 were approximately $2,883,000 as compared with approximately
$2,727,000 for fiscal 1998. Basic earnings per share were $1.59 in fiscal 1999
compared with $1.60 in fiscal 1998 on average shares of 1,814,864 and 1,701,048,
respectively. At September 30, 1999, the market value of the Company's stock was
$20.125 per share, or 131% of book value.
In November 1998, the directors voted to increase the regular quarterly
dividend from $0.265 to $0.27 per share effective February 1, 1999. The annual
dividend of $1.08 per share is a 5.37% yield on the September 30, 1999 market
value of the Company's stock and represents a payout of 68% based on earnings
for fiscal 1999.
In August 1999, Highland Propane Company issued intermediate debt at a
variable rate in the amount of $2,500,000 for seven years.
The Company has unsecured lines of credit totaling $22,500,000, at indexed
interest rates. These lines are subject to annual renewal and do not require
compensating balances. The average month-end balance of short-term debt in
fiscal 1999 was approximately $6,216,000. The average interest rate on unsecured
lines of credit during fiscal 1999 was 5.80%. The month-end balance at September
30, 1999 was $6,363,000 at an average interest rate of 5.86%.
Please refer to "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for additional information on the Company's
capital resources and for an analysis of changes in revenue and expenses.
3
<PAGE>
HERITAGE
[Pictures]
Roanoke Gas Company, the cornerstone of the RGC Resources family, has been
providing natural gas service to Roanoke, Virginia and surrounding areas since
1883.
(Photos circa 1930)
4
<PAGE>
Weather, Price & Supply
The RGC Resources service area experienced some of the warmest weather on
record during winter 1998-99. Nationally, since record keeping began in 1895-96,
this past winter (December - February) was the second warmest ever recorded.
During RGC's 1999 fiscal year, Roanoke, Virginia unofficially recorded 3717
Heating Degree Days (HDD), or 12 percent less than the long-term normal. In
Bluefield, West Virginia the unofficial total was 4490 HDD, again almost 12
percent fewer HDD than normal.
The warm weather along with higher than normal storage levels combined to
quickly lower winter heating fuel prices. Commodity gas and propane prices were
both lower than the previous year.
While the average commodity prices have once again fallen over the past
fiscal year, natural gas and propane remain highly volatile commodities and
prices may increase significantly in the next fiscal year. To mitigate such
volatility and create a more stable environment for Roanoke Gas Company and its
customers, Roanoke Gas uses a variety of mechanisms to manage price risk
including summer storage injections. Roanoke Gas will continue its Virginia
financial hedging pilot program for a third year and Bluefield Gas Company will
continue the second year of a similar West Virginia pilot program. Highland
Propane Company also uses a mixture of fixed price contracts, pre-buys and
financial hedges to control volatility in propane prices.
RGC regards storage supplies as an integral component of its natural gas
supply portfolio. The Roanoke and Bluefield operations combined hold the rights
to about 2.9 billion cubic feet (BCF) of natural gas storage space. This storage
includes pipeline and third party underground facilities in both the Gulf coast
and Appalachian areas as well as our own liquefied natural gas (LNG) storage in
Botetourt County, Virginia.
Historically, Roanoke Gas Company and Bluefield Gas Company have handled
their gas supply and transportation functions internally. As a means to more
fully utilize pipeline capacity and further lower costs to its customers,
Roanoke Gas Company and Bluefield Gas Company have entered into asset management
agreements. Effective November 1, 1999, PG&E Energy Trading, the asset manager,
will manage nomination, confirmation and scheduling of all existing supply and
storage contracts as well as supply any additional natural gas requirements.
[Graph showing the comparison of net income to heating degree days]
<TABLE>
<CAPTION>
Comparison of Net Income to Heating Degree Days (HDD)
Year Net Income HDD
<S> <C> <C> <C> <C> <C> <C>
1994 1,677,098 4,416
1995 1,777,240 3,791
1996 2,196,672 4,696
1997 2,309,880 4,298
1998 2,726,879 4,054
1999 2,883,407 3,717
</TABLE>
RGC Resources shows profits despite year's warmth
5
<PAGE>
COMMUNITY
[Pictures]
From its origin in 1883, RGC Resources and its predecessors have bene committed
to improving the communities which it serves. Management and employees not only
focus their time and attention to providing safe and reliable services, they
also give generously of themselves. This generosity is reflected in the areas of
education, child development, and health issues to just name a few. John
D'Orazio, President and COO of Diversified Energy, is on the board of directors
of the Boys and Girls Club of the Roanoke Valley.
RGC Resources CEO John Williamson, a Hollins University trustee, reviews with
Hollins President Janet Rasmussen plans for the university's Richard Wetherill
Visual Arts Center. Hollins University is transforming the former Fishburn
Library into a center for the visual arts. Plans for the 58,650-square-foot
renovation and addition feature large flexible galleries to offer more
exhibitions, which will be open to the public. To honor the Fishburn legacy, the
university is naming the arts center's entrance, Fishburn Hall.
6
<PAGE>
Natural Gas Growth
Roanoke Gas Company and Bluefield Gas Company experienced another year of
excellent customer growth with approximately 1,700 customer additions. This
represents an overall growth rate of 3.2%. On an individual company basis,
customer additions were approximately 3.4% for Roanoke Gas Company and 1.2% for
Bluefield Gas Company.
Our commission sales force focuses on the addition of new gas customers
along existing gas mains. Natural gas conversions totaled 721, representing
higher than average growth for the fourth year in a row. These conversions
represented approximately 48% of the new customer growth for Roanoke Gas Company
and 88% for Bluefield Gas Company.
New commercial accounts represented 11.6% of the customer growth for
Roanoke Gas Company and 14.9% of Bluefield Gas Company. For the fiscal year,
Roanoke Gas installed 73,866 feet, or 14.0 miles, of new mains over 64 different
projects. Bluefield Gas installed 7,359 feet, or 1.4 miles, of new mains over 16
different projects.
The marketing strategy for natural gas continues to center around
maintaining strong trade ally relationships, establishing one-on-one contacts
with members of the RGC sales team and providing real-time customer service.
This strategy has been the nucleus of our success, and the number of trade
allies continues to grow. As we expand our trade ally base, we seek feedback
from the trade ally group to improve our sales and service to our customers. The
trade ally program will be expanded in fiscal 2000 to include a structured
incentive program that rewards individuals for the total volume of connected gas
load. A major marketing objective for fiscal 2000 will be the feasibility
analysis for natural gas geographic expansion. A primary area to be targeted is
Rocky Mount, Virginia. Rocky Mount has historically experienced a steady blend
of residential, commercial and industrial growth.
The future looks very bright for Roanoke Gas Company and Bluefield Gas
Company. The Year 2000 is certain to bring many new and exciting challenges and
opportunities. Our commitment to both our customers and their communities will
carry us far into the new millennium.
<TABLE>
<CAPTION>
Natural Gas Customer Growth
Year Number of Customers
<S> <C> <C> <C> <C> <C> <C>
1994 48,544
1995 49,813
1996 51,094
1997 52,763
1998 54,114
1999 55,654
</TABLE>
7
<PAGE>
DIVERSITY
[Pictures]
Propane installations are increasing steadily, especially in areas where natural
gas is not available because customers continue to choose gas as their
energy source.
Creative marketing has produced some customers who use both natural gas and
propane. Art Pendleton, President and COO of Roanoke Gas Company assesses gas
needs at R. R. Donnelley in Salem, Virginia.
8
<PAGE>
Diversified Operations
- -------------------------------------------------------------------------------
Highland Propane
Fiscal year 1999 marked the third year in a row that Highland Propane's
customer growth exceeded 25%. In fiscal 1999, Highland's customer base grew from
11,004 to 13,832, for a net gain of 2,828 new customers or a 25.7% increase.
Highland surpassed the 4,000 tank installations in a single year for the first
time in the Company's history. These installations represent a 40% increase over
last year's installations. Tank installations were up in most geographic areas
with our Bluefield, West Virginia division leading the way with an increase of
92% from fiscal 1998, followed by Rainelle, West Virginia division with a 57%
increase and Lexington, Virginia division with a 49% increase.
Highland Propane expanded its service area through the acquisition of Four
C's Enterprises in Dunmore, West Virginia. The acquisition added 388 new propane
customers to our base and expanded our service area into Pocahontas County, West
Virginia. Since the acquisition, that customer base has increased from 388 to
558 in a 10-month period, a 44% increase. Other system expansions include a new
bulk facility in Weyers Cave, Virginia and a new facility in Beckley, West
Virginia. We now have a total of 15 bulk storage facilities located throughout
our service area.
Total sales by Highland Propane were 8.98 million gallons with 3,717
Roanoke Heating Degree Days in fiscal 1999, compared to 7.7 million gallons with
4,054 heating degree days in fiscal 1998. Increase in customer growth offset the
warmer weather, resulting in a 16.6 % increase in total gallons delivered.
Highland Gas Marketing
Highland Gas Marketing sold just over 2 million decatherms (Dth) of natural
gas in 1999. This represents a slight decrease over last year's totals. The
decrease was due to an 8% warmer winter this year compared to last year.
Highland Gas Marketing buys interruptible supplies of spot gas and temporary
interstate pipeline transportation services, and resells them to large
industrial customers that contract with the local utility for delivery from the
interstate pipeline to the customer's meter. The natural gas marketing business
is highly competitive with relatively low margins; however, it also has a low
cost of operation with minimal facility and personnel requirements.
Other Opportunities
We are constantly evaluating other non-regulated operations that will
enhance our core services, provide a needed service to our area and are
profitable. Some of the areas currently being evaluated as part of our
diversification efforts are home security services, HVAC (Heating, Ventilation
and Air Conditioning) sales and service, Internet service provider, home
appliance lease program and GPS/GIS (Global Positioning Systems/Geographic
Information Systems) mapping information system services.
<TABLE>
<CAPTION>
Propane Customer Growth
Year Number of Customers
<S> <C> <C> <C> <C> <C> <C>
1994 5,684
1995 6,006
1996 6,410
1997 8,829
1998 10,432
1999 13,342
</TABLE>
9
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF
FINANCIAL CONDITION & RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
RGC Resources, Inc.
SELECTED FINANCIAL DATA
Years Ended September 30
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenues $57,088,871 $59,387,092 $65,047,826 $65,770,873 $48,611,147
Operating Margin 23,579,244 23,279,585 22,464,921 22,030,795 19,435,864
Operating Earnings 4,820,917 4,717,026 4,403,423 4,035,304 3,522,258
Earnings Before Interest Charges 4,967,249 4,822,590 4,550,333 4,113,044 3,701,907
Net Earnings 2,883,407 2,726,879 2,309,880 2,196,672 1,777,240
Net Earnings Per Share 1.59 1.60 1.54 1.51 1.26
Cash Dividends Declared
Per Share 1.08 1.06 1.04 1.02 1.00
Book Value Per Share 15.36 14.75 13.48 12.86 12.25
Average Shares Outstanding 1,814,864 1,701,048 1,503,388 1,455,999 1,408,659
Total Assets 77,789,982 69,134,920 62,593,258 58,921,099 51,614,667
Long-Term Debt
(Less Current Portion) 23,336,614 20,700,000 17,079,000 20,222,124 17,504,047
Stockholders' Equity 28,154,923 26,464,581 20,596,951 18,975,001 17,555,172
Shares Outstanding at Sept. 30 1,832,771 1,794,416 1,527,486 1,475,843 1,432,512
</TABLE>
General
The core business of RGC Resources is the distribution of natural gas to
approximately 55,300 customers in the cities of Roanoke, Salem, and Bluefield,
Virginia and Bluefield, West Virginia, and the surrounding areas and the sale
and distribution of propane to approximately 13,800 customers in southern West
Virginia and Western Virginia. Natural gas service is provided at rates and for
the terms and conditions set forth, approved and regulated by the State
Corporation Commission in Virginia (the Virginia Commission) and the Public
Service Commission in West Virginia (the West Virginia Commission). The Company
continues to experience customer growth and plans to meet the needs of its
current and future customers by attracting adequate investment capital and by
maintaining adequate rates.
Propane sales have become an important aspect of the consolidated
operations, with the annual growth in propane customers now exceeding the annual
growth in natural gas customers. While the demand for natural gas and propane
continues to increase in the Roanoke Gas and Bluefield Gas service territory,
the weather normalized per capita residential usage is declining due to energy
conservation, high efficiency furnaces and appliances, and better-insulated
homes. The effect of such per capita declines, unless offset by new customer
growth, a strong revenue stream during the winter, or other forms of revenue
stabilization, could result in a decline in the Company's net operating
earnings. Competition from alternative fuels and/or suppliers could also impact
the Company's profitability levels.
Roanoke Gas Company and Bluefield Gas Company currently hold the only
franchises and/or certificates of public convenience and necessity to distribute
natural gas in its Virginia and West Virginia service areas. These franchises
are for multi-year periods and are effective through January 1, 2016 in Virginia
and August 23, 2009 in West Virginia. While there are no assurances, the Company
believes that it will be able to negotiate acceptable franchises when the
current agreements expire. Certificates of public convenience and necessity are
exclusive and are of perpetual duration.
10
<PAGE>
Forward-Looking Statements
From time to time, RGC may publish forward-looking statements relating to
such matters as anticipated financial performance, business prospects,
technological developments, new products, research and development activities
and similar matters. The Private Securities Litigation Reform Act of 1995
provides a safe harbor for forward-looking statements. In order to comply with
the terms of the safe harbor, the Company notes that a variety of factors could
cause the Company's actual results and experience to differ materially from the
anticipated results or other expectations expressed in the Company's
forward-looking statements. The risks and uncertainties that may affect the
operations, performance, development and results of the Company's business
include the following: (i) frozen rates in both regulated jurisdictions; (ii)
earning on a consistent basis an adequate return on invested capital; (iii)
increasing expenses and labor costs and availability; (iv) price competition
from alternative fuels; (v) volatility in the price of natural gas and propane;
(vi) uncertainty in the projected rate of growth of natural gas and propane
requirements in the Company's service area; (vii) general economic conditions
both locally and nationally; and (viii) developments in electricity and
natural gas deregulation and associated industry restructuring. In addition, the
Company's business is seasonal in character and strongly influenced by weather
conditions. Extreme changes in winter heating degree days from the normal or
mean can have significant short-term impacts on revenues and gross margins.
Capital Resources & Liquidity
RGC Resources' primary capital needs are the funding of its continuing
construction program and the seasonal funding of its stored gas inventories. The
Company's capital expenditures for fiscal 1999 were a combination of
replacements and expansions, reflecting the need to replace older cast iron and
bare steel pipe with plastic pipe, while continuing to meet the demands of
customer growth. Total capital expenditures for fiscal 1999 were approximately
$9.1 million allocated as follows: $5.3 million for Roanoke Gas Company, $.5
million for Bluefield Gas Company and $3.3 million for Highland Propane Company.
Cash flow from operations provided approximately $4.1 million in support of
capital expenditures, or approximately 45% of total investment. Historically,
consolidated capital expenditures were $9.6 million in 1998 and $8.1 million in
1997. It is anticipated that future capital expenditures will be funded with the
combination of internal cash flow, sale of Company equity securities, and
issuance of debt.
At September 30, 1999, the Company had available lines of credit for its
short-term borrowing needs totaling $22.5 million, of which $6,363,000 was
outstanding. Short-term borrowing, in addition to providing limited capital
project bridge financing, is used to finance summer and fall gas purchases,
which are stored in the underground facilities of Columbia Gas Transmission
Corporation, Tennessee Gas Pipeline Company and Virginia Gas Storage Company, as
well as in the Company's above-ground LNG storage facility, to ensure adequate
winter supplies to meet customer demand. At September 30, 1999, the Company has
$7,371,646 in inventoried natural gas supplies.
The terms of short-term borrowings result in average rates of 5.80% in
1999, 6.19% in 1998 and 5.97% in 1997. The lines do not require compensating
balances. The Company utilizes a cash management program, which provides for
daily balancing of the Company's temporary investment and short-term borrowing
needs with interest rates indexed to the 30-day LIBOR interest rate plus a
premium. The program allows the Company to maximize returns on temporary
investments and minimize the cost of short-term borrowings. Short-term
borrowings, together with internally generated funds, long-term debt and the
sale of common stock through the Company's Dividend Reinvestment and Stock
Purchase Plan (Plan), have been adequate to cover construction costs, debt
service and dividend payments to shareholders.
Stockholders' equity increased for the period by $1,690,342, reflecting an
increase of $918,161 in retained
11
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS
earnings and proceeds of $772,181 of new common stock purchases through the Plan
and the Restricted Stock Plan For Outside Directors.
At September 30, 1999, the Company's consolidated capitalization was 55%
equity and 45% debt, compared to 56% equity and 44% debt at September 30, 1998.
Plant Additions
RGC Resources invested $9,111,000 in fiscal year 1999 in capital additions.
Roanoke Gas Company added $5,310,000, Bluefield added $502,000, and Highland
Propane added $3,299,000 including the acquisition of Star Gas. New business
expenditures, including mains, meters, new service lines, and new propane
installations totaled $5,003,000. The natural gas companies installed 1,361 new
service lines and 15.4 miles of new mains. Highland Propane experienced its
fourth consecutive year of record growth by adding 4,000 new tank sets.
During the year the natural gas companies continued to maintain the 25-year
program to replace all of its bare steel and cast iron facilities by replacing
651 service lines and 12.2 miles of main. Other major increases in plant
additions included $254,000 for propane transportation equipment, $161,000 for
propane storage facilities, $726,000 for new customer support services
equipment, including a new telephone system and the implementation of Enterprise
Customer Information System (E-CIS).
For fiscal year 2000 the Company has budgeted $8,500,000 for capital
expenditures including $2,500,000 to support Highland Propane customer growth,
$2,400,000 for natural gas customer additions, $1,750,000 for the renewal
program, $500,000 for technology advancements and implementation of the new
propane E-CIS software.
Regulatory Affairs
During the past fiscal year, the Company received a Final Order in two rate
increase requests and has entered into a joint stipulation and agreement for
settlement in a third case. On August 27, 1999, the West Virginia Public Service
Commission (PSC) issued a Final Order accepting the filed stipulation and
authorizing a rate increase of $80,000 effective November 30, 1999 for Bluefield
Gas Company. This Order also approved a stepped-in rate increase of 3 cents per
MCF effective November 1, 2000 and another 3 cents per MCF effective on November
1, 2001.
On September 15, 1999, the Virginia State Corporation Commission (SCC)
issued a Final Order accepting the filed stipulation and authorizing a rate
increase of $433,650 effective February 28, 1999 in the Roanoke Gas Company rate
case. This Order also approved the implementation of a Distribution System
Renewal (DSR) Surcharge and the movement to therm billing. In the Order the
Commission commended Roanoke Gas for proposing the DSR surcharge stating that it
will provide an innovative approach to cost recovery, allowing for continued
improvement of the safety and reliability of Roanoke's gas distribution system
and including adequate safeguards that will protect the interest of customers.
The approval of the DSR surcharge will permit Roanoke Gas to recover on a timely
basis, the carrying costs and depreciation on an investment of up to $1,500,000,
annually, in the distribution renewal program through a surcharge. Roanoke Gas
implemented the first surcharge on December 1, 1999. Additional surcharge
amounts will be implemented on December 1, 2000 and December 1, 2001.
The Company currently has one rate increase application pending before the
SCC for Commonwealth Public Service Corporation (CPSC). While Commonwealth is
now structurally part of Roanoke Gas Company, the company's will keep their
rates separate until a consolidating rate case. On June 29, 1999, the CPSC filed
for a rate increase of $36,547 in annual revenue. This case included the
movement to therm billing and a request for the implementation of a Distribution
System Renewal Surcharge like that approved for Roanoke Gas to cover investment
in the distribution system renewal program of up to $200,000 annually. The CPSC,
Staff, and the Attorney General entered into a joint stipulation settling
12
<PAGE>
all of the issues in the case including an agreement on the revenue requirement
of the entire requested amount of $36,547. A Final Order is expected by the end
of the calendar year.
Results of Operations
Fiscal Year 1999 Compared With Fiscal Year 1998
Operating Revenues - Fiscal 1999 operating revenues for natural gas
decreased 6.2% compared with fiscal 1998 primarily because weather was
approximately 8.3% warmer in fiscal 1999 compared with fiscal 1998 and the unit
cost of natural gas decreased by 2%.
Operating revenues for propane in fiscal 1999 increased 12.5% compared with
fiscal 1998 because the propane business had a 16.6% increase in the number of
gallons sold due to a 25.7% increase in customer growth even though the weather
was warmer.
Cost of Gas - The cost of sales for natural gas purchased and resold to
customers decreased 8.7% in fiscal 1999 compared with fiscal 1998 due to the
same reasons operating revenue decreased. The cost of gas per MCF was $3.97 in
fiscal 1999 and $4.03 in fiscal 1998.
Propane cost of sales increased 6.6% in fiscal 1999 compared to fiscal 1998
primarily as a result of customer growth.
Operating Margin - Because the utility's cost of gas is recovered from its
customers it has no effect on operating margin. Operating margin decreased 2.1%
in fiscal 1999 compared to fiscal 1998 because volumetric margins decreased 6.5%
due to weather partially offset by an approximately 7% increase in the service
charge rate effective February 28, 1999.
The unit margins on propane are market based and are greatly influenced by
competition. Highland Propane had a 17.9% increase in margin associated with a
16.6% increase in gallons delivered due to a 25.7% increase in customer growth.
<TABLE>
<CAPTION>
MARKET PRICE AND DIVIDEND INFORMATION
Range of Prices
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Fiscal Year Ended High Low Cash Dividend
September 30 $ $ Declared ($)
- -------------------------------------------------------------------------------------------------------------------
1999
- -------------------------------------------------------------------------------------------------------------------
First Quarter 22.250 18.500 0.270
Second Quarter 22.000 19.500 0.270
Third Quarter 21.250 19.375 0.270
Fourth Quarter 23.250 20.000 0.270
1998
- -------------------------------------------------------------------------------------------------------------------
First Quarter 21.375 17.500 0.265
Second Quarter 22.750 19.250 0.265
Third Quarter 22.250 19.750 0.265
Fourth Quarter 20.703 18.125 0.265
</TABLE>
RGC Resources' common stock is listed on the Nasdaq National Market under the
trading symbol RGCO. Payment of dividends is within the discretion of the Board
of Directors and will depend on, among other factors, earnings, capital
requirements, and the operating and financial condition of the Company. The
Company's long-term indebtedness contains restrictions on cumulative net
earnings and dividends previously paid. At September 30, 1999 and 1998,
respectively, the company had 1,796 and 1,837 common shareholders of record with
1,832,771 and 1,794,416 common shares outstanding.
Other Operating Expenses - Operation and maintenance expenses decreased by
10% in fiscal 1999 compared with fiscal 1998 primarily because the Company
continued its expense reduction program in response to the warm winter. The
Company redirected its maintenance program from repair to replacement where
applicable.
General taxes decreased 5.3 % in fiscal 1999 over fiscal 1998. Although
payroll and property taxes were up $63,000, revenue sensitive taxes were down
$156,000.
Income taxes on the utility increased 19.6% in fiscal 1999 compared with
fiscal 1998 due to an increase in pre-tax income in fiscal 1999.
Depreciation and amortization expenses increased 7.4% in fiscal 1999
compared with fiscal 1998 primarily because of more depreciable plant in
service.
Other operating expenses-propane operations includes the operating and
maintenance expenses, taxes and depreciation of Highland Propane Company. These
expenses increased 24.4% in fiscal 1999 compared with fiscal 1998. General taxes
were up $34,000 associated with additional property and payroll taxes.
13
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS
Depreciation was up $340,000 due to increased tanks and transportation
equipment associated with customer growth. Transportation expense, sales
expense, insurance, customer accounting expense, delivering expenses, management
expense and fringe benefits increased $429,000 also associated with customer
growth.
Other Income - Other income, net of other deductions, increased 38.6% in
fiscal 1999 compared with fiscal 1998 primarily due to other income in the
propane business.
Interest Charges - Total interest charges on the utility decreased 7.6% in
fiscal 1999 compared with fiscal 1998. Interest on long-term debt increased
$22,000 due to a slightly higher daily average balance in fiscal 1999 compared
with fiscal 1998. Interest on short-term debt decreased $170,000 due to an
approximately $1,000,000 reduction in average daily balance and a reduction in
short-term borrowing rates. Interest charges for Highland Propane were up
$136,000 in fiscal 1999 compared to fiscal 1998 due to additional tanks and
transportation equipment associated with customer growth.
Net Earnings and Dividends - Net earnings for fiscal 1999 were $2,883,000
as compared with $2,727,000 in fiscal 1998. The increase was primarily due to
increased margins in the propane business due to higher sales volumes and the
reduction in operation and maintenance expense in the utility business due to
increased capitalization of labor and overheads associated with additional
capital projects. Basic earnings per share of common stock were $1.59 in fiscal
1999 compared with $1.60 in fiscal 1998. Dividends per share of common stock
were $1.08 in fiscal 1999 compared with $1.06 in fiscal 1998.
Fiscal Year 1998 Compared With Fiscal Year 1997
Operating Revenues - Fiscal 1998 operating revenues for natural gas
decreased 10.4% compared with fiscal 1997 primarily because the change in sales
mix due to weather that was approximately 6.0% warmer in fiscal 1998 compared to
fiscal 1997 and a decrease of 7.5% in the unit cost of natural gas.
Operating revenues for propane increased 4.5% in fiscal 1998 compared to
fiscal 1997 due to a 25% increase in customer growth even though revenues per
gallon decreased 10.9% due to the lower price of propane.
Cost of Gas - Cost of sales for natural gas decreased 16.0% in fiscal 1998
compared with fiscal 1997 because there was a 7.5% decrease in the unit cost of
natural gas and a 786,876 MCF decrease in interruptible sales purchases.
The cost of propane sales decreased 6.9% in fiscal 1998 compared with
fiscal 1997 primarily due to a decrease in the unit cost of propane associated
with an abundant supply of propane due to warm weather.
Operating Margin - Because the utility's cost of gas is recovered from its
customers it has no effect on operating margin. Operating margin increased 1.1%
in fiscal 1998 compared with fiscal 1997. In addition to increased margins from
customer growth, Roanoke Gas & Bluefield Gas realized the full annual effect of
rate increases which produced an $815,000 increase in operating margin.
The unit margins on propane are market based and are greatly influenced by
competition. Highland Propane had an 18.1% increase in margins associated with a
17.3% increase in gallons delivered due to a 25% increase in customer growth.
Other Operating Expenses - Operations and maintenance expenses decreased by
5.2% in fiscal 1998 compared with fiscal 1997 primarily due to a reduction in
bad debt accruals of $210,000 and the absence of regulatory asset write-offs
which occurred in 1997 in the amount of $307,000.
General taxes decreased 3.3% in fiscal 1998 compared with fiscal 1997.
Increases in business license and merchant taxes, franchise taxes and property
taxes in the amount of $7,400 were more than offset by decreases in the
revenue-sensitive taxes in the amount of $75,600.
Income taxes on the utility increased 28.3% in fiscal 1998 compared with
fiscal 1997 due to higher pre-tax income in 1998.
Depreciation and amortization expenses increased 10.8% in fiscal 1998
compared with fiscal 1997 due to increased depreciation related to normal
additions to plant in service.
14
<PAGE>
Other operating expenses - propane operations includes the operating and
maintenance expenses, taxes and depreciation of Highland Propane Company. These
expenses increased 20.9% in fiscal 1998 compared with fiscal 1997. The increase
was primarily attributable to growth in customers and propane assets and the
associated increase in volumes delivered. Depreciation on tanks and equipment
increased by $78,000, property and related taxes increased by $33,000,
transportation and delivery costs increased by $157,000 and sales expense
increased by $65,000 and a variety of other growth-driven operating costs
increased associated with billing and collecting, accounting and management
overhead.
Other Income - Other income, net of other deductions, decreased 28.1% in
fiscal 1998 compared with fiscal 1997 primarily associated with rate refund
expenses of $9,000 and the write-off of obsolete and damaged propane tanks in
the amount of $31,000.
Interest Charges - Total interest charges on the utility decreased 10.7% in
fiscal 1998 compared with fiscal 1997 due to the payoff of $2,500,000 in
long-term debt in October 1997 and the use of the proceeds from the issuance of
181,500 shares of common stock in January 1998.
Interest charges for Highland Propane were up $89,000 in fiscal 1998
compared with fiscal 1997 due to additional tanks and transportation equipment
associated with customer growth.
Net Earnings & Dividends - Net earnings for fiscal 1998 were $2,727,000 as
compared with $2,310,000 in fiscal 1997. The increase can be attributed to cost
management which resulted in operation and maintenance expenditures for natural
gas being $497,000 less than the prior year off-setting increased propane
operations expense related to customer growth and increased revenue from natural
gas customer growth combined with the full effect of rate increases which
produced an $815,000 increase in operating margin. Basic earnings per share of
common stock were $1.60 in fiscal 1998 compared with $1.54 in 1997. Dividends
per share of common stock were $1.06 in fiscal 1998 compared with $1.04 in
fiscal 1997.
Recent Accounting Developments
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, effective for all fiscal quarters
of fiscal years beginning after June 15, 1999. SFAS No. 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
It requires the recognition of all derivative instruments as assets or
liabilities in Resources' balance sheet and measurement of those instruments at
fair value. The accounting treatment of changes in fair value is dependent upon
whether or not a derivative instrument is designated as a hedge and if so, the
type of hedge. The subsidiaries have entered into certain arrangements for
hedging the price of natural gas and propane gas for the purpose of providing
price stability during the winter months. Resources has not fully analyzed the
impact of the provisions of FAS No. 133 on its financial statements.
In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date of SFAS No. 133 to all fiscal quarters of fiscal years beginning after June
15, 2000.
In 1998 the American Institute of Certified Public Accountants issued
Statement of Position 98-5 (SOP 98-5), Reporting on the Costs of Start-Up
Activities. SOP 98-5 requires that start-up activities, including organization
costs, be expensed as incurred. SOP 98-5 is effective for financial statements
for fiscal years beginning after December 15, 1998. However, Resources elected
to early adopt SOP 98-5. The adoption did not have a material impact on
Resources' financial position or results of operation.
Impact of Inflation
The cost of natural gas represented approximately 67% for fiscal 1999, 68%
for fiscal 1998 and 72% for fiscal 1997 of the total operating expenses of the
Company's gas utilities operations. However, under the present regulatory
Purchased Gas Adjustment mechanisms, the increases and decreases in the cost of
gas are passed through to the Company's customers.
15
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS
Inflation impacts the Company through increases in non-gas costs such as
insurance, labor costs, supplies and services used in operations and maintenance
and the replacement cost of plant and equipment. The rates charged to natural
gas customers to cover these costs can only be increased through the regulatory
process via a rate increase application. In addition to stressing performance
improvements and higher gas sales volumes to offset inflation, management must
continually review operations and economic conditions to assess the need for
filing and receiving adequate and timely rate relief from the state commissions.
Other Issues
RGC Resources, Inc. is in the final stages of its Year 2000 readiness
planning. The Company has identified all internal systems and processes that are
date sensitive and has either taken corrective action to make the systems or
processes Year 2000 compliant or has developed a detailed contingency plan. The
Company believes that it has taken reasonable measures to ensure the safe and
uninterrupted delivery of natural gas. There can be no guarantee that the
systems of other companies and external services such as water, electricity, or
telephone will be converted in a timely manner. If interruptions were to occur
in any such outside service, such interruptions would create a significant
barrier to providing service to the Company's customers and could result in
material increases in operating expenses and lost revenue.
The Notes to Consolidated Financial Statements contained on pages 24
through 37 may contain a discussion of an Environmental Matter.
<TABLE>
<CAPTION>
RGC Resources, Inc.
1999 FINANCIAL HIGHLIGHTS
<S> <C>
Operating Revenue - Natural Gas $ 48,619,143
Operating Revenue - Propane $ 8,469,728
Other Revenue - Gas Marketing $ 5,639,783
Merchandising and Jobbing $ 522,149
Interest Income $ 24,966
Net Earnings $ 2,883,407
Net earnings per Share $ 1.59
Dividends per Share - Cash $ 1.08
Total Customers - Natural Gas 55,283
Total Customers - Propane 13,832
Customers per Employee 424
Total Natural Gas Deliveries - MCF 10,318,043
Total Propane Sales - Gallons 8,977,524
Capitalization Ratio (Debt/Equity) 45%/55%
Total Additions to Plant $ 9,111,000
</TABLE>
16
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
RGC Resources, Inc.:
We have audited the accompanying consolidated balance sheets of RGC Resources,
Inc. and Subsidiaries (the "Company") as of September 30, 1999 and 1998, and the
related consolidated statements of earnings, stockholders' equity and cash flows
for each of the two years in the period then ended. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits. The
consolidated financial statements of the Company for the year ended September
30, 1997 were audited by other auditors whose report, dated October 17, 1997,
expressed an unqualified opinion on those consolidated statements.
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 1999 and 1998 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of the
Company as of September 30, 1999 and 1998, and the results of its operations and
its cash flows for the years then ended in conformity with generally accepted
accounting principles.
S/Deloitte & Touche LLP
Charlotte, North Carolina
October 22, 1999
17
<PAGE>
Independent Auditors' Report
The Board of Directors and Stockholders
RGC Resources, Inc.:
We have audited the accompanying consolidated statements of earnings,
stockholders' equity and cash flows of RGC Resources, Inc. and subsidiaries
(successor to Roanoke Gas Company and subsidiaries) for the year ended September
30, 1997. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the consolidated 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 audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the results of operations and the cash flows
of RGC Resources, Inc. and subsidiaries for the year ended September 30, 1997,
in conformity with generally accepted accounting principles.
s/KPMG LLP
KPMG LLP
Roanoke, Virginia
October 17, 1997
<PAGE>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 1999 AND 1998
<TABLE>
<CAPTION>
ASSETS 1999 1998
<S> <C> <C> <C> <C> <C> <C>
UTILITY PLANT:
In service $ 74,710,899 $ 69,986,124
Accumulated depreciation and amortization (26,499,546) (24,644,581)
---------------- ----------------
In service, net 48,211,353 45,341,543
Construction work-in-progress 1,425,918 1,674,543
---------------- ----------------
Total utility plant, net 49,637,271 47,016,086
---------------- ----------------
NON-UTILITY PROPERTY:
Propane 13,463,990 10,188,124
Accumulated depreciation and amortization (3,984,241) (3,059,870)
---------------- ----------------
Total non-utility property, net 9,479,749 7,128,254
---------------- ----------------
CURRENT ASSETS:
Cash and cash equivalents 139,501 84,037
Accounts receivable, less allowance for doubtful accounts
of $229,238 in 1999 and $202,652 in 1998 6,306,117 3,051,474
Inventories 8,363,199 7,969,730
Prepaid income taxes 430,992 712,687
Deferred income taxes 1,962,448 1,868,888
Other 572,154 451,027
---------------- ----------------
Total current assets 17,774,411 14,137,843
---------------- ----------------
OTHER ASSETS 898,551 852,737
---------------- ----------------
TOTAL ASSETS $ 77,789,982 $ 69,134,920
================ ================
</TABLE>
See notes to consolidated financial statements.
18
<PAGE>
<TABLE>
<CAPTION>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 1999 AND 1998
LIABILITIES AND STOCKHOLDERS' EQUITY 1999 1998
<S> <C> <C> <C> <C> <C> <C>
CAPITALIZATION:
Stockholders' equity:
Common stock, $5 par value; authorized 10,000,000 shares;
issued and outstanding 1,832,771 and 1,794,416 shares in
1999 and 1998, respectively $ 9,163,855 $ 8,972,080
Preferred stock, no par; authorized 5,000,000 shares;
0 shares issued and outstanding in both 1999 and 1998 - -
Capital in excess of par value 9,489,551 8,909,145
Retained earnings 9,501,517 8,583,356
---------------- ----------------
Total stockholders' equity 28,154,923 26,464,581
Long-term debt, excluding current maturities 23,336,614 20,700,000
---------------- ----------------
Total capitalization 51,491,537 47,164,581
---------------- ----------------
CURRENT LIABILITIES:
Current maturities of long-term debt 24,282 -
Borrowings under lines of credit 6,363,000 4,584,000
Dividends payable 495,055 476,140
Accounts payable 9,206,173 6,968,594
Customer deposits 546,364 399,750
Accrued expenses 4,605,376 4,224,693
Refunds from suppliers - due customers 26,062 85,572
Overrecovery of gas costs 684,155 1,269,829
---------------- ----------------
Total current liabilities 21,950,467 18,008,578
---------------- ----------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes 3,934,489 3,508,838
Deferred investment tax credits 413,489 452,923
---------------- ----------------
Total deferred credits and other liabilities 4,347,978 3,961,761
---------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 77,789,982 $ 69,134,920
================ ================
</TABLE>
19
<PAGE>
<TABLE>
<CAPTION>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Gas utilities $48,619,143 $51,857,052 $57,842,181
Propane operations 8,469,728 7,530,040 7,205,645
------------- ------------- -------------
Total operating revenues 57,088,871 59,387,092 65,047,826
------------- ------------- -------------
COST OF GAS:
Gas utilities 29,631,592 32,471,072 38,675,337
Propane operations 3,878,035 3,636,435 3,907,568
------------- ------------- -------------
Total cost of gas 33,509,627 36,107,507 42,582,905
------------- ------------- -------------
OPERATING MARGIN 23,579,244 23,279,585 22,464,921
------------- ------------- -------------
OPERATING EXPENSES:
Gas utilities:
Operations 7,033,018 7,583,583 8,049,833
Maintenance 1,083,190 1,432,203 1,462,764
Taxes - general 2,250,794 2,376,227 2,456,399
Taxes - income 1,316,190 1,100,506 857,964
Depreciation and amortization 3,015,001 2,806,278 2,533,912
Propane operations (including income taxes of $260,037,
$326,206 and $309,137 in 1999, 1998 and 1997,
respectively) 4,060,134 3,263,762 2,700,626
------------- ------------- -------------
Total operating expenses 18,758,327 18,562,559 18,061,498
------------- ------------- -------------
OPERATING EARNINGS 4,820,917 4,717,026 4,403,423
------------- ------------- -------------
OTHER INCOME (DEDUCTIONS):
Gas utilities, net 58,805 67,759 68,240
Propane operations, net 120,274 80,248 116,222
Taxes - income (32,747) (42,443) (37,552)
------------- ------------- -------------
Total other income 146,332 105,564 146,910
------------- ------------- -------------
EARNINGS BEFORE INTEREST CHARGES 4,967,249 4,822,590 4,550,333
------------- ------------- -------------
INTEREST CHARGES:
Gas utilities:
Long-term debt 1,572,862 1,550,734 1,740,998
Other 227,987 398,409 441,444
Propane operations 282,993 146,568 58,011
------------- ------------- -------------
Total interest charges 2,083,842 2,095,711 2,240,453
------------- ------------- -------------
NET EARNINGS $ 2,883,407 $2,726,879 $2,309,880
============= ============= =============
BASIC EARNINGS PER SHARE $ 1.59 $ 1.60 $ 1.54
============= ============= =============
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC 1,814,864 1,701,048 1,503,388
============= ============= =============
DILUTED EARNINGS PER SHARE $ 1.59 $ 1.60 $ 1.53
============= ============= =============
WEIGHTED AVERAGE SHARES OUTSTANDING -
DILUTED 1,818,541 1,706,902 1,504,915
============= ============= =============
See notes to consolidated financial statements.
</TABLE>
20
<PAGE>
<TABLE>
<CAPTION>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
Capital in Total
Common Excess of Retained Stockholders'
Stock Par Value Earnings Equity
<S> <C> <C> <C> <C> <C> <C>
BALANCE, SEPTEMBER 30, 1996 $ 7,379,215 $ 4,647,163 $ 6,948,623 $ 18,975,001
Net earnings - - 2,309,880 2,309,880
Cash dividends declared ($1.04 per share) - - (1,570,649) (1,570,649)
Issuance of common stock (51,643 shares) 258,215 624,504 - 882,719
------------- ------------- --------------- --------------
BALANCE, SEPTEMBER 30, 1997 7,637,430 5,271,667 7,687,854 20,596,951
Net earnings - - 2,726,879 2,726,879
Cash dividends declared ($1.06 per share) - - (1,831,377) (1,831,377)
Issuance of common stock (266,930
shares) 1,334,650 3,637,478 - 4,972,128
------------- ------------- --------------- --------------
BALANCE, SEPTEMBER 30, 1998 8,972,080 8,909,145 8,583,356 26,464,581
Net earnings - - 2,883,407 2,883,407
Cash dividends declared ($1.08 per share) - - (1,965,246) (1,965,246)
Issuance of common stock (38,355 shares) 191,775 580,406 - 772,181
------------- ------------- --------------- --------------
BALANCE, SEPTEMBER 30, 1999 $ 9,163,855 $ 9,489,551 $ 9,501,517 $ 28,154,923
============= ============= =============== ==============
See notes to consolidated financial statements.
</TABLE>
21
<PAGE>
<TABLE>
<CAPTION>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $2,883,407 $2,726,879 $2,309,880
Adjustments to reconcile net earnings to net cash provided
by (used in) operating activities:
Depreciation and amortization 4,131,688 3,577,872 3,247,015
Loss (gain) on asset disposition (3,277) 40,380 6,562
Writeoff of regulatory assets - - 132,523
Change in over/under recovery of gas costs (585,674) 1,857,286 1,195,133
Deferred taxes and investment tax credits 292,657 (338,421) (681,937)
Other noncash items, net (45,814) (284,466) 93,131
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net (3,108,030) 1,109,365 (266,066)
Inventories (393,469) (542,149) (24,995)
Prepaid income taxes and other current assets 160,568 (735,672) 349,405
Accounts payable and accrued expenses 2,618,262 1,447,079 1,599,788
Refunds from suppliers - due customers (59,510) (340,288) 401,995
----------- ----------- -----------
Net cash provided by operating activities 5,890,808 8,517,865 8,362,434
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and non-utility property (8,940,093) (9,238,614) (8,052,801)
Cost of removal of utility plant, net (64,209) (70,949) (158,855)
Proceeds from sales of assets 73,720 225,159 192,063
----------- ----------- -----------
Net cash used in investing activities (8,930,582) (9,084,404) (8,019,593)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 2,500,000 3,356,000 -
Retirement of long-term debt (9,614) (2,878,124) (669,423)
Net borrowings (repayments) under lines of credit 1,779,000 (2,545,000) 476,500
Proceeds from issuance of common stock 772,181 4,601,069 882,719
Common stock issuance costs - (246,647) -
Cash dividends paid (1,946,329) (1,752,767) (1,549,914)
----------- ----------- -----------
Net cash provided by (used in) financing activities 3,095,238 534,531 (860,118)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 55,464 (32,008) (517,277)
CASH AND CASH EQUIVALENTS:
Beginning of year 84,037 116,045 633,322
----------- ----------- -----------
End of year $ 139,501 $ 84,037 $ 116,045
=========== =========== ===========
</TABLE>
22
<PAGE>
<TABLE>
<CAPTION>
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS
INFORMATION:
Cash paid during the year for:
Interest $2,036,967 $2,148,861 $2,065,893
=========== =========== ===========
Income taxes, net of refunds $1,034,623 $2,512,897 $1,575,952
=========== =========== ===========
Noncash transactions:
The assets of a propane company were acquired in December 1997 in exchange
for 34,317 shares of stock for a total value of $617,706.
In June 1998, the Company refinanced the remaining balances of Series K and
Series L First Mortgage Bonds in the amount of $3,344,000 through the
issuance of a First Mortgage Note due July 1, 2008.
In February 1999, a capital lease obligation of $170,510 was incurred when
the Company entered into an equipment lease.
</TABLE>
See notes to consolidated financial statements.
23
<PAGE>
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reorganization - On July 1, 1999, Roanoke Gas Company, Bluefield Gas
Company and Diversified Energy Corporation became subsidiaries of RGC
Resources, Inc., an exempt holding company. Also on this date,
Commonwealth Public Service Corporation was merged into Roanoke Gas
Company and new Affiliate Agreements were signed between and among
RGC Resources, Inc. and each affiliate. On July 2, 1999 NASDAQ began
trading RGC Resources, Inc. as RGCO.
General - The consolidated financial statements include the accounts
of RGC Resources, Inc. and its wholly owned subsidiaries (the
"Company"), Roanoke Gas Company, Bluefield Gas Company and
Diversified Energy Company, operating as Highland Propane Company and
Highland Gas Marketing. Roanoke Gas Company and Bluefield Gas Company
are gas utilities, which distribute and sell natural gas to
residential, commercial and industrial customers within their service
areas. Highland Propane Company distributes and sells propane in
southwestern Virginia and southern West Virginia. Highland Gas
Marketing brokers natural gas to several industrial transportation
customers of Roanoke Gas Company and Bluefield Gas Company.
The primary business of the Company is the distribution of natural
gas to residential, commercial and industrial customers in Roanoke,
Virginia; Bluefield, Virginia; Bluefield, West Virginia; and the
surrounding areas. The Company distributes natural gas to its
customers at rates and charges regulated by the State Corporation
Commission in Virginia and the Public Service Commission in West
Virginia.
All significant intercompany transactions have been eliminated in
consolidation.
Regulation - The Company's regulated operations meet the criteria,
and accordingly, follow the accounting and reporting requirements of
Statement of Financial Accounting Standards ("SFAS") No. 71,
Accounting for the Effects of Certain Types of Regulation. The
economic effects of regulation can result in a regulated company
recording costs that have been or are expected to be allowed in the
rate-setting process in a period different from the period in which
the costs would be charged to expense by an unregulated enterprise.
When this results, costs are deferred as assets in the consolidated
balance sheet (regulatory assets) and recorded as expenses as those
same amounts are reflected in rates. Additionally, regulators can
impose liabilities upon a regulated company for amounts previously
collected from customers and for recovery of costs that are expected
to be incurred in the future (regulatory liabilities).
24
<PAGE>
The amounts recorded by the Company as regulatory assets and
regulatory liabilities are as follows:
<TABLE>
<CAPTION>
September 30,
------------------------------------------
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Regulatory assets:
Early retirement incentive costs $ 7,560 $ 20,520
Rate case costs 52,988 1,163
Other 74,171 101,043
---------------- ----------------
Total regulatory assets $ 134,719 $ 122,726
================ ================
Regulatory liabilities:
Refunds from suppliers - due customers $ 26,062 $ 85,572
Overrecovery of gas costs 684,155 1,269,829
---------------- ----------------
Total regulatory liabilities $ 710,217 $ 1,355,401
================ ================
</TABLE>
Utility Plant - Utility plant is stated at original cost. The cost of
additions to utility plant includes direct charges and overhead. The
cost of depreciable property retired, plus cost of removal, less
salvage is charged to accumulated depreciation. Maintenance, repairs,
and minor renewals and betterments of property are charged to
operations.
Depreciation and Amortization - Provisions for depreciation are
computed principally on composite straight-line rates for financial
statement purposes and on accelerated rates for income tax purposes.
Depreciation and amortization for financial statement purposes are
provided on annual composite rates ranging from 2 percent to 33
percent. The annual composite rates are determined by periodic
depreciation studies.
Cash and Cash Equivalents - For purposes of the consolidated
statements of cash flows, the Company considers all highly liquid
debt instruments purchased with an original maturity of three months
or less to be cash equivalents.
Inventories - Inventories consist primarily of propane and natural
gas. Natural gas is valued at the weighted average cost charged to
inventory and propane is valued at the lower of average cost or
market.
Unbilled Revenues - The Company bills its natural gas customers on a
monthly cycle basis, although certain large industrial customers are
billed at or near the end of each month. The Company records revenue
based on service rendered to the end of the accounting period. The
amounts of unbilled revenue receivable included in accounts
receivable on the consolidated balance sheets at September 30, 1999
and 1998 were $919,903 and $795,438, respectively.
Income Taxes - Income taxes are accounted for using the liability
method. Under the liability method, deferred tax assets and
liabilities are recognized for the estimated future tax consequences
attributable to differences between the financial statement carrying
amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted
tax rates in effect for the years in which those temporary
differences are expected to be recovered or settled.
The Company and its subsidiaries file a consolidated federal income
tax return. Federal income taxes have been provided by the Company on
the basis of the separate company income and deductions.
Bond Expenses - Bond expenses are being amortized over the lives of
the bonds using the bonds outstanding method.
Over/Under Recovery of Gas Costs - Pursuant to the provisions of the
Company's Purchased Gas Adjustment ("PGA") clause, increases or
decreases in gas costs are passed on to its customers.
25
<PAGE>
Accordingly, the difference between actual costs incurred and costs
recovered through the application of the PGA is reflected as a net
deferred charge or credit. At the end of the deferral period, the
balance of the net deferred charge or credit is amortized over the
next 12-month period as amounts are reflected in customer billings.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Derivative and Hedging Activities - In June 1998, the Financial
Accounting Standards Board (FASB) issued SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, effective for all
fiscal quarters of fiscal years beginning after June 15, 1999. SFAS
No. 133 establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. It requires the
recognition of all derivative instruments as assets or liabilities in
the Company's balance sheet and measurement of those instruments at
fair value. The accounting treatment of changes in fair value is
dependent upon whether or not a derivative instrument is designated
as a hedge and if so, the type of hedge.
The Company has entered into certain arrangements for hedging the
price of natural gas and propane for the purpose of providing price
stability during the winter months. The Company has not fully
analyzed the provisions of SFAS No. 133 on the Company's financial
statements.
In June 1999, the FASB issued SFAS No. 137 which deferred the
effective date of SFAS No. 133 to all fiscal quarters of all fiscal
years beginning after June 15, 2000.
Reorganization Costs - The Company has elected to early adopt
Statement of Position (SOP) 98-5, Reporting on the Costs of Start-Up
Activities. SOP 98-5 requires that start-up costs and organizational
costs be expensed as incurred. The adoption did not have a material
impact on the Company's financial position or results of operations.
Reclassifications - Certain reclassifications were made to prior year
balances to conform with current year presentations.
2. FINANCIAL INFORMATION BY BUSINESS SEGMENTS
The reportable segments disclosed herein were determined based on a
variety of factors, including the regulatory environment and the
types of products and services offered.
Natural Gas - The natural gas segment of the Company generates
revenue from its tariff rates under which it provides distribution
energy services for its residential, commercial and industrial
customers.
Propane Gas - The propane gas segment of the Company generates
revenue from the sale and delivery of propane gas and related
services to its residential, commercial and industrial customers
located in southwestern Virginia and southern West Virginia.
Parent and Other - The parent and other segment of the Company
contains certain transactions incurred at the parent company level
and miscellaneous other operating activities.
26
<PAGE>
Information related to the segments of the Company is detailed below:
<TABLE>
<CAPTION>
Parent
and Consolidated
Gas Propane Other Total
<S> <C> <C>
For the year ended September 30, 1999:
Total revenues $ 48,619,143 $ 8,469,728 $ 522,149 $ 57,611,020
Operating margin 19,002,388 4,576,856 202,192 23,781,436
Operations, maintenance and
general taxes 10,367,002 2,894,587 32,392 13,293,981
Depreciation and amortization 3,015,001 957,396 - 3,972,397
Interest charges 1,800,849 282,993 - 2,083,842
Income taxes 1,306,986 242,001 59,987 1,608,974
Segment net earnings (loss) 2,454,903 318,691 109,813 2,883,407
As of September 30, 1999:
Total assets $ 65,832,140 $ 11,956,853 $ 989 $ 77,789,982
Gross additions to long-lived
assets 5,811,671 3,298,932 - 9,110,603
For the year ended September 30, 1998:
Total revenues $ 51,857,052 $ 7,530,040 $ 587,030 $ 59,974,122
Operating margin 19,385,980 3,893,605 189,634 23,469,219
Operations, maintenance and
general taxes 11,392,013 2,372,339 9,313 13,773,665
Depreciation and amortization 2,806,278 617,086 - 3,423,364
Interest charges 1,949,143 146,568 - 2,095,711
Income taxes 1,085,895 321,335 61,925 1,469,155
Segment net earnings (loss) 2,132,317 476,166 118,396 2,726,879
As of September 30, 1998:
Total assets $ 60,586,015 $ 8,548,905 $ - $ 69,134,920
Gross additions to long-lived assets 5,892,438 3,691,223 - 9,583,661
For the year ended September 30, 1997:
Total revenues $ 57,842,181 $ 7,205,645 $ 567,128 $ 65,614,954
Operating margin 19,166,844 3,298,077 215,604 22,680,525
Operations, maintenance and
general taxes 11,968,996 1,881,412 7,958 13,858,366
Depreciation and amortization 2,533,912 539,063 - 3,072,975
Interest charges 2,182,442 58,011 - 2,240,453
Income taxes 845,123 285,786 73,744 1,204,653
Segment net earnings 1,739,548 436,430 133,902 2,309,880
As of September 30, 1997:
Total assets $ 57,770,655 $ 4,822,603 $ - $ 62,593,258
Gross additions to long-lived assets 5,726,579 2,326,222 - 8,052,801
</TABLE>
During 1999, 1998 and 1997, no single customer accounted for more
than five percent of the Company's sales, and no accounts receivable
from any customer exceeded five percent of the Company's total
accounts receivable at September 30, 1999 and 1998.
27
<PAGE>
3. ALLOWANCE FOR DOUBTFUL ACCOUNTS
A summary of the changes in the allowance for doubtful accounts
follows:
<TABLE>
<CAPTION>
Years Ended September 30,
-------------------------------------------------------------
1999 1998 1997
<S> <C> <C> <C>
Balances, beginning of year $ 202,652 $ 368,345 $ 279,316
Provision for doubtful accounts 234,705 481,297 660,400
Recoveries of accounts written off 208,584 188,309 125,035
Accounts written off (416,703) (835,299) (696,406)
---------------- ---------------- ----------------
Balances, end of year $ 229,238 $ 202,652 $ 368,345
================ ================ ================
</TABLE>
4. BORROWINGS UNDER LINES OF CREDIT
A summary of short-term lines of credit follows:
<TABLE>
<CAPTION>
September 30,
-------------------------------------------------------------
1999 1998 1997
<S> <C> <C> <C>
Lines of credit $ 22,500,000 $ 21,000,000 $ 20,000,000
Outstanding balance 6,363,000 4,584,000 7,129,000
Highest month end balances outstanding 10,364,000 12,929,000 15,896,000
Average month end balances 6,216,000 5,280,000 8,098,000
Average rates of interest during year 5.80% 6.19% 5.97%
Average rates of interest on balances
outstanding at year end 5.86% 6.18% 6.14%
</TABLE>
5. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
September 30,
------------------------------------------------
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Roanoke Gas Company:
First Mortgage notes payable, interest fixed at 7.804%
due July 1, 2008 $ 5,000,000 $ 5,000,000
Term debentures, collateralized by indenture dated October 1,
1991, with provision for retirement in varying annual payments through
October 1, 2016, at interest rates ranging
from 6.75% to 9.625% 4,700,000 4,700,000
Unsecured senior notes payable, interest at 7.66%, with provision for
retirement of $1,600,000 each year
beginning December 1, 2014 through December 1, 2018 8,000,000 8,000,000
Obligations under capital leases, aggregate monthly payments
of $2,924 including interest, through April 2005 160,896 -
</TABLE>
28
<PAGE>
<TABLE>
<CAPTION>
September 30,
------------------------------------------------
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Bluefield Gas Company:
Unsecured note payable, interest at 7.28%, with provision for retirement of
$25,000 quarterly beginning January 1, 2002 and a final payment of
$1,125,000 on October 1, 2003 $ 1,300,000 $ 1,300,000
Highland Propane Company:
Unsecured note payable, with variable interest rate based on 90-day LIBOR plus
95 basis-point spread, with provision
for retirement on August 26, 2006 2,500,000 -
Unsecured note payable, interest at 7%, with
provision for retirement on December 31, 2007 1,700,000 1,700,000
------------------- -------------------
Total long-term debt 23,360,896 20,700,000
Less current maturities (24,282) -
------------------- -------------------
Total long-term debt, excluding current maturities $ 23,336,614 $ 20,700,000
=================== ===================
</TABLE>
The above debt obligations contain various provisions including a
minimum interest charge coverage ratio and limitations on debt as a
percentage of total capitalization. The obligations also contain a
provision restricting the payment of dividends, primarily based on
the earnings of the Company and dividends previously paid. At
September 30, 1999, approximately $5,416,000 of retained earnings
were available for dividends.
The aggregate annual maturities of long-term debt, subsequent to
September 30, 1999 are as follows:
<TABLE>
<CAPTION>
Years ending September 30:
<S> <C>
2000 $ 24,282
2001 26,092
2002 803,037
2003 130,126
2004 2,157,372
Thereafter 20,219,987
----------------
Total $ 23,360,896
================
</TABLE>
29
<PAGE>
6. INCOME TAXES
The details of income tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
Years Ended September 30,
-----------------------------------------------------------------
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
Charged to operating expenses - gas utilities:
Current:
Federal $ 1,147,215 $ 1,566,868 $ 1,561,779
State 37,246 54,764 (15,946)
------------- ------------- -------------
Total current 1,184,461 1,621,632 1,545,833
------------- ------------- -------------
Deferred:
Federal 180,709 (447,054) (668,660)
State (9,546) (34,638) 20,226
------------- ------------- -------------
Total deferred 171,163 (481,692) (648,434)
------------- ------------- -------------
Investment tax credits, net (39,434) (39,434) (39,435)
------------- ------------- -------------
Total charged to operating expenses -
gas utilities 1,316,190 1,100,506 857,964
------------- ------------- -------------
Charged to other operating expenses - propane operations:
Current 101,455 139,592 282,380
Deferred 158,582 186,614 26,757
------------- ------------- -------------
Total charged to other operating expenses -
propane operations 260,037 326,206 309,137
------------- ------------- -------------
Charged to other income and deductions gas utilities:
Current 30,401 46,353 37,892
Deferred 2,346 (3,910) (340)
------------- ------------- -------------
Total charged to other income and deductions -
gas utilities 32,747 42,443 37,552
------------- ------------- -------------
Total income tax expense $ 1,608,974 $ 1,469,155 $ 1,204,653
============= ============= =============
</TABLE>
30
<PAGE>
Income tax expense for the years ended September 30, 1999, 1998 and
1997 differed from amounts computed by applying the U.S. Federal
income tax rate of 34 percent to earnings before income taxes as a
result of the following:
<TABLE>
<CAPTION>
Years Ended September 30,
-----------------------------------------------------------------
1999 1998 1997
<S> <C> <C> <C>
Net earnings $ 2,883,407 $ 2,726,879 $ 2,309,880
Income tax expense 1,608,974 1,469,155 1,204,653
------------- ------------- -------------
Earnings before income taxes $ 4,492,381 $ 4,196,034 $ 3,514,533
============= ============= =============
Computed "expected" income tax expense $ 1,527,410 $ 1,426,652 $ 1,194,941
Increase (reduction) in income tax expense
resulting from:
Amortization of deferred investment tax credits (39,434) (39,434) (39,435)
Other, net 120,998 81,937 49,147
------------- ------------- -------------
Total income tax expense $ 1,608,974 $ 1,469,155 $ 1,204,653
============= ============= =============
</TABLE>
The tax effects of temporary differences that give rise to the
deferred tax assets and deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
September 30,
--------------------------------------------
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Deferred tax assets:
Allowance for uncollectibles $ 82,898 $ 74,740
Accrued pension and medical benefits 1,088,777 909,898
Accrued vacation 174,504 172,707
Over/under recovery of gas costs 233,373 430,529
Costs on gas held in storage 360,062 245,902
Other 22,834 35,112
---------------- ----------------
Total gross deferred tax assets 1,962,448 1,868,888
---------------- ----------------
Deferred tax liabilities:
Utility plant basis differences 3,966,982 3,508,489
Other (32,493) 349
---------------- ----------------
Total gross deferred tax liabilities 3,934,489 3,508,838
---------------- ----------------
Net deferred tax liability $ 1,972,041 $ 1,639,950
================ ================
</TABLE>
7. EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the "Plan") covering
substantially all of its employees. The benefits are based on years
of service and employee compensation. Plan assets are invested
principally in cash equivalents and corporate stocks and bonds.
Company contributions are intended to provide not only for benefits
attributed to date but also for those expected to be earned in the
future.
31
<PAGE>
The following sets forth the Pension Plan's funded status and amounts
recognized in the consolidated balance sheet as of September 30 as
determined by an independent actuary:
<TABLE>
<CAPTION>
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Reconciliation of funded status:
Funded status $ 131,349 $ (959,486)
Unrecognized actuarial gain (1,397,341) (297,949)
Unrecognized transition obligation 119,089 224,533
Unrecognized prior service cost 37,755 56,629
Contribution made between measurement date and fiscal
year end 50,000 40,000
--------------- ---------------
Net pension liability recognized $ (1,059,148) $ (936,273)
=============== ===============
Change in projected benefit obligation:
Benefit obligation at beginning of year $ 7,989,241 $ 5,940,051
Service cost 239,185 157,705
Interest cost 523,844 444,696
Actuarial (gain) loss (961,328) 1,812,080
Benefit payments (398,325) (365,291)
--------------- ---------------
Benefit obligation at end of year $ 7,392,617 $ 7,989,241
=============== ===============
Change in plan assets:
Fair value of plan assets at beginning of year $ 7,029,755 $ 6,299,249
Actual return on plan assets 722,536 1,005,797
Employer contribution 170,000 90,000
Benefit payments (398,325) (365,291)
--------------- ---------------
Fair value of plan assets at end of year $ 7,523,966 $ 7,029,755
=============== ===============
</TABLE>
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic pension cost:
Service cost $ 239,185 $ 157,705 $ 142,467
Interest cost 523,844 444,696 419,474
Expected return on plan assets (584,472) (523,334) (454,175)
Amortization of unrecognized transition
obligation or asset 105,444 105,444 105,444
Prior service cost recognized 18,874 18,874 18,874
Recognized gains - (81,537) (53,626)
---------------- -------------- --------------
Net periodic pension cost $ 302,875 $ 121,848 $ 178,458
================ ============== ==============
Assumptions used for net periodic pension cost:
Discount rate 6.75% 7.75% 7.75%
Expected rate of compensation increase 5.00 5.00 5.00
Expected long-term rate of return on plan assets 8.50 8.50 8.50
</TABLE>
In addition to pension benefits, the Company has a postretirement
benefits plan which provides certain health care, supplemental
retirement and life insurance benefits to active and
32
<PAGE>
retired employees who meet specific age and service requirements. The
plan is contributory. The Company has elected to fund the plan over
future years.
The following sets forth the postretirement medical and life insurance
plans' funded status and amounts recognized in the consolidated balance
sheet, as determined by an independent actuary, as of September 30:
<TABLE>
<CAPTION>
1999 1998
<S> <C> <C> <C> <C> <C> <C>
Reconciliation of funded status:
Funded status $ (5,071,792) $ (4,604,982)
Unrecognized actuarial (gain) loss 294,361 (216,562)
Unrecognized transition obligation 3,322,200 3,559,500
--------------- ---------------
Net postretirement benefit liability $ (1,455,231) $ (1,262,044)
=============== ===============
Change in projected benefit obligation:
Benefit obligation at beginning of year $ 5,769,802 $ 4,820,564
Service cost 118,847 86,436
Interest cost 377,830 362,179
Participant contributions 22,885 28,503
Actuarial (gain) loss 515,825 790,444
Benefit payments (314,645) (318,324)
--------------- ---------------
Benefit obligation at end of year $ 6,490,544 $ 5,769,802
=============== ===============
Change in plan assets:
Fair value of plan assets at beginning of year $ 1,164,820 $ 988,734
Actual return on plan assets 72,902 154,998
Employer contributions - 310,909
Participant contributions 495,675 28,503
Benefit payments (314,645) (318,324)
--------------- ---------------
Fair value of plan assets at end of year $ 1,418,752 $ 1,164,820
=============== ===============
</TABLE>
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic postretirement benefit cost:
Service cost $ 118,847 $ 86,436 $ 96,255
Interest cost 377,830 362,179 325,036
Amortization of unrecognized transition obligation
or asset 237,300 237,300 237,300
Expected return on plan assets (68,000) (59,000) (89,542)
Recognized gains - (27,532) (25,201)
-------------- -------------- --------------
Net periodic benefit cost $ 665,977 $ 599,383 $ 543,848
============== ============== ==============
</TABLE>
The weighted average discount rate used in determining the accumulated
postretirement benefits obligation was 7.5 percent, 6.75 percent and
7.75 percent for 1999, 1998 and 1997, respectively.
33
<PAGE>
For measurement purposes, 8.5 percent, 9 percent and 10 percent annual
rates of increase in the per capita cost of covered benefits (i.e.,
medical trend rate) were assumed for 1999, 1998 and 1997, respectively;
the rates were assumed to decrease gradually to 5.25 percent by the
year 2006 and remain at that level thereafter. The medical trend rate
assumption has a significant effect on the amounts reported. For
example, increasing the assumed medical cost trend rate by one
percentage point each year would increase the accumulated
postretirement benefits obligation as of September 30, 1999 by
approximately $779,000 or 12 percent, and would increase the aggregate
of the service and interest cost components of net postretirement
benefits cost by approximately $80,000, or 16 percent.
The Company also has a defined contribution plan covering all of its
employees who elect to participate. The Company made annual matching
contributions to the plan based on 70 percent in 1999, 1998 and 1997 of
the net participants' basic contributions (from 1 to 6 percent of their
total compensation). The annual cost of the plan was $212,344, $206,766
and $217,466 for 1999, 1998 and 1997, respectively.
8. COMMON STOCK OPTIONS
During 1997, the Company's stockholders approved the RGC Resources,
Inc. Key Employee Stock Option Plan (the "Plan"). The Plan provides for
the issuance of common stock options to officers and certain other
full-time salaried employees to acquire a maximum of 50,000 shares of
the Company's common stock. The Plan requires each option's exercise
price per share to equal the fair value of the Company's common stock
as of the date of grant.
The aggregate number of shares under option pursuant to the RGC
Resources, Inc. Key Employee Stock Option Plan are as follows:
<TABLE>
<CAPTION>
Weighted
Average Option
Number Exercise Price
of Shares Price Per Share
<S> <C> <C> <C> <C> <C> <C>
Options outstanding, September 30, 1997 34,500 $ 16.357 $15.500-16.875
Options granted 15,500 20.625 -
Options exercised (13,000) 16.346 -
--------------
Options outstanding, September 30, 1998 37,000 $ 18.149 $15.500-20.625
Options granted - - -
Options exercised - - -
--------------
Options outstanding, September 30, 1999 37,000 $ 18.149 $15.500-20.625
==============
</TABLE>
Under the terms of the Plan, the options become exercisable 6 months
from the grant date and expire 10 years subsequent to the grant date.
All options outstanding were fully vested and exercisable at September
30, 1999 and 1998.
34
<PAGE>
The per share weighted-average fair values of stock options granted
during 1998 and 1997 were $2.85 and $1.08, respectively, on the dates
of grant using the Black-Scholes option-pricing model with the
following weighted-average assumptions. There were no options granted
during 1999.
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Expected dividend yield 5.14% 5.78%
Risk-free interest rate 4.33% 6.29%
Expected volatility 21% 10%
Expected life 10 years 10 years
</TABLE>
The Company uses the intrinsic value method of APB Opinion No. 25 for
recognizing stock-based compensation in the consolidated financial
statements. Had the Company determined compensation cost based on the
fair value at the grant date for its stock options, the Company's net
earnings and basic earnings per share would have been as follows:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Net earnings $ 2,697,709 $ 2,278,093
Basic earnings per share $ 1.58 $ 1.52
</TABLE>
9. RELATED PARTY TRANSACTIONS
Certain of the Company's directors are affiliated with companies that
render services or sell products to the Company. Such transactions are
conducted under normal business terms. The significant services relate
to legal fees charged to the Company of approximately $168,000,
$185,000 and $182,000 in 1999, 1998 and 1997, respectively. The
products sold to the Company include natural gas purchases of
approximately $5,628,000, $6,052,000 and $3,052,000 in 1999, 1998 and
1997, respectively. It is anticipated that similar services and
products will be provided to the Company in 2000.
10. ENVIRONMENTAL MATTER
Both RGC Resources, Inc. and Bluefield Gas Company operated
manufactured gas plants ("MGPs") as a source of fuel for lighting and
heating until the early 1950's. A by-product of operating MGPs was coal
tar, and the potential exists for on-site tar waste contaminants at the
former plant sites. The extent of contaminants at these sites, if any,
is unknown at this time. An analysis at the Bluefield Gas Company site
indicates some soil contamination. The Company, with concurrence of
legal counsel, does not believe any events have occurred requiring
regulatory reporting. Further, the Company has not received any notices
of violation or liabilities associated with environmental regulations
related to the MGP sites and is not aware of any off-site contamination
or pollution as a result of prior operations. Therefore, the Company
has no plans for subsurface remediation at the MGP sites. Should the
Company eventually be required to remediate either site, the Company
will pursue all prudent and reasonable means to recover any related
costs, including insurance claims and regulatory approval for rate case
recognition of expenses associated with any work required. A stipulated
rate case agreement between the Company and the West Virginia Public
Service Commission recognized the Company's right to defer MGP clean-up
costs, should any be incurred, and to seek rate relief for such costs.
If the Company eventually incurs costs associated with a required
clean-up of either MGP site, the Company anticipates recording a
regulatory asset for
35
<PAGE>
such clean-up costs to be recovered in future rates. Based on
anticipated regulatory actions and current practices, management
believes that any costs incurred related to this matter will not have a
material effect on the Company's financial condition or results of
operations.
11. COMMITMENTS
The Company has short-term contracts with natural gas suppliers
requiring the purchase of approximately 2,873,000 dekatherms of natural
gas at varying prices during the period October 1, 1999 through
September 30, 2000. In addition, the Company has short-term contracts
with propane suppliers requiring the purchase of approximately
3,854,000 gallons of propane during the period October 1, 1999 through
September 30, 2000. Management does not anticipate that these contracts
will have a material impact on the Company's fiscal year 2000
consolidated results of operations.
Both Roanoke Gas Company and Bluefield Gas Company participate in pilot
gas cost hedging programs approved by their respective public utility
commissions which are intended to help protect against supply related
price volatility adversely impacting customer billing rates. Under the
pilot programs, gas cost hedges may be employed for up to 50% of normal
winter demand not supplied from storage. Under the pilot programs, the
Company has entered into options to purchase approximately 690,000
dekatherms of natural gas during fiscal 2000. All costs and benefits of
the Company's natural gas hedging programs are reflected in cost of gas
and recovered through customer billing rates.
In addition to natural gas hedging transactions, the Company has also
entered into options to purchase approximately 1.2 million gallons of
propane during fiscal 2000. The costs associated with the purchase of
these options will be expensed during the year ended September 30,
2000.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents and borrowings under
lines of credit are a reasonable estimate of fair value due to their
short-term nature and because the rates of interest paid on borrowings
under lines of credit approximate market rates.
The fair value of long-term debt is estimated by discounting the future
cash flows of each issuance at rates currently offered to the Company
for similar debt instruments of comparable maturities. The carrying
amounts and approximate fair values are as follows:
<TABLE>
<CAPTION>
September 30,
-----------------------------------------------------------------------------------
1999 1998
---------------------------------------- -----------------------------------------
Carrying Approximate Carrying Approximate
Amounts Fair Value Amounts Fair Value
<S> <C> <C> <C> <C> <C> <C>
Long-term debt $ 23,360,896 $ 23,662,491 $ 20,700,000 $ 24,287,744
</TABLE>
Judgment is required in interpreting market data to develop the
estimates of fair value. Accordingly, the estimates determined as of
September 30, 1999 and 1998 are not necessarily indicative of the
amounts the Company could have realized in current market exchanges.
36
<PAGE>
13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarterly financial data for the years ended September 30, 1999 and
1998 is summarized as follows:
<TABLE>
<CAPTION>
First Second Third Fourth
1999 Quarter Quarter Quarter Quarter
<S> <C> <C> <C> <C>
Operating revenues $ 16,444,192 $ 23,027,809 $ 9,429,972 $ 8,186,898
================= ================= ================ ===============
Operating earnings (loss) $ 1,444,714 $ 3,202,960 $ 373,437 $ (200,194)
================= ================= ================ ===============
Net earnings (loss) $ 956,759 $ 2,690,937 $ (73,315) $ (690,974)
================= ================= ================ ===============
Basic earnings (loss) per share $ .53 $ 1.49 $ (.04) $ (.39)
================= ================= ================ ===============
First Second Third Fourth
1998 Quarter Quarter Quarter Quarter
Operating revenues $ 20,796,021 $ 21,750,333 $ 8,982,316 $ 7,858,422
================= ================= ================ ===============
Operating earnings (loss) $ 2,071,945 $ 2,662,581 $ 153,192 $ (170,692)
================= ================= ================ ===============
Net earnings (loss) $ 1,544,234 $ 2,123,464 $ (281,216) $ (659,603)
================= ================= ================ ===============
Basic earnings (loss) per share $ 1.00 $ 1.24 $ (.16) $ (.48)
================= ================= ================ ===============
</TABLE>
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.
* * * * * * * *
37
<PAGE>
<TABLE>
<CAPTION>
RGC Resources, Inc.
SUMMARY OF GAS SALES AND STATISTICS
Years Ended September 30
REVENUES: 1999 1998 1997 1996 1995
- --------- ------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential Sales $ 28,152,236 $ 30,396,540 $ 32,595,261 $ 33,981,835 $ 25,078,211
Commercial Sales 17,812,922 18,764,195 19,879,180 20,219,289 14,313,723
Interruptible Sales 646,256 695,279 3,892,301 4,569,766 3,513,181
Transportation Gas Sales 1,776,049 1,715,032 1,107,922 943,215 909,515
Backup Services 89,061 97,552 173,655 190,310 107,652
Late Payment Charges 108,340 156,634 157,369 135,838 115,130
Miscellaneous 34,279 31,820 36,493 27,154 24,325
Propane 8,469,728 7,530,040 7,205,645 5,703,466 4,549,410
------------------------------------------------------------------------------------
Total $ 57,088,871 $ 59,387,092 $ 65,047,826 $ 65,770,873 $ 48,611,147
NET INCOME $ 2,883,407 $ 2,726,879 $ 2,309,880 $ 2,196,672 $ 1,777,249
------------------------------------------------------------------------------------
MCF's DELIVERED
Residential 4,271,243 4,633,403 4,651,819 5,108,553 4,204,222
Commercial 3,020,147 3,228,452 3,230,714 3,385,962 2,834,884
Interruptible 156,148 172,270 959,146 1,088,921 1,240,658
Transportation Gas 2,855,938 2,822,856 1,933,236 1,549,854 1,660,504
Backup Service 14,567 18,500 29,130 36,658 21,609
------------------------------------------------------------------------------------
Total 10,318,043 10,875,481 10,804,045 11,169,948 9,961,877
GALLONS DELIVERED
(PROPANE) 8,977,524 7,702,384 6,568,066 5,997,912 4,822,277
HEATING DEGREE DAYS 3,717 4,054 4,298 4,696 3,791
NUMBER OF CUSTOMERS:
Natural Gas
Residential 49,860 48,265 47,539 46,007 44,873
Commercial 5,379 5,272 5,181 5,043 4,896
Interruptible and Interruptible
Transportation Service 44 45 43 44 44
------------------------------------------------------------------------------------
Total 55,283 53,582 52,763 51,094 49,813
Propane 13,832 11,004 8,829 6,410 6,006
------------------------------------------------------------------------------------
Total Customers 69,115 64,586 61,592 57,504 55,819
GAS ACCOUNT (MCF):
Natural Gas Available 10,883,269 11,316,714 11,406,613 11,756,089 10,453,696
Natural Gas Deliveries 10,318,043 10,875,481 10,804,045 11,169,948 9,961,877
Storage - LNG 129,369 69,343 106,892 142,297 118,393
Company Use And Miscellaneous 58,982 37,998 49,444 54,140 46,532
System Loss 376,875 333,892 446,232 389,704 326,894
------------------------------------------------------------------------------------
Total Gas Usage 10,883,269 11,316,714 11,406,613 11,756,089 10,453,696
TOTAL ASSETS $ 77,789,982 $ 69,134,920 $ 62,593,258 $ 58,921,099 $ 51,614,667
LONG-TERM OBLIGATIONS $ 23,336,614 $ 20,700,000 $ 17,079,000 $ 20,222,124 $ 17,504,047
</TABLE>
38
<PAGE>
<TABLE>
<CAPTION>
RGC Resources, Inc.
CAPITALIZATION STATISTICS
Years Ended September 30
COMMON STOCK: 1999 1998 1997 1996 1995
- ------------- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Shares Issued 1,832,771 1,794,416 1,527,486 1,475,843 1,432,512
Earnings Per Share:
Net earnings $ 1.59 $ 1.60 $ 1.54 $ 1.51 $ 1.26
Dividends Paid Per Share (Cash) $ 1.08 $ 1.06 $ 1.04 $ 1.02 $ 1.00
Dividends Paid Out Ratio 67.9% 66.3% 67.5% 67.5% 79.4%
Number of Shareholders 1,796 1,836 1,853 1,713 1,699
--------------------------------------------------------------------------
CAPITALIZATION RATIOS:
Long-Term Debt,
Including Current Maturities 45.3 43.9 49.5 52.4 51.6
Common Stock And Surplus 54.7 56.1 50.5 47.6 48.4
Total 100.0 100.0 100.00 100.0 100.0
--------------------------------------------------------------------------
Long-Term Debt,
Including Current Maturities $ 23,360,896 $ 20,700,000 $ 20,222,124 $ 20,891,547 $ 18,683,462
Common Stock And Surplus 28,154,923 26,464,581 20,596,951 18,975,001 17,555,172
--------------------------------------------------------------------------
Total Capitalization
Plus Current Maturities $ 51,515,819 $ 47,164,581 $ 40,819,075 $ 39,866,548 $ 36,238,634
--------------------------------------------------------------------------
</TABLE>
39
<PAGE>
RGC RESOURCES, INC.
& SUBSIDARIES
BOARD OF DIRECTORS
Lynn D. Avis
Avis Construction Co., Inc.
President
Abney S. Boxley III
Boxley Co., Inc.
President & CEO
Frank T. Ellett
Virginia Truck Center, Inc.
President
Frank A. Farmer, Jr.
Chairman Of The Board
Wilbur L. Hazlegrove
Woods, Rogers and Hazlegrove,
P.L.C.
J. Allen Layman
R & B Communications, Inc.
President and CEO
Thomas L. Robertson
Carilion Health System &
Carilion Medical Center
President & CEO
S. Frank Smith
Coastal Coal Co., LLC
Vice President
John B. Williamson III
President and CEO
RGC RESOURCES, INC.
OFFICERS
Frank A. Farmer, Jr.
Chairman of the Board
John B. Williamson, III
President and CEO
Roger L. Baumgardner
Vice President
Secretary and Treasurer
Howard T. Lyon
Controller & Assistant Treasurer
Dale P. Moore
Assistant Vice President
& Assistant Secretary
ROANOKE GAS COMPANY
OFFICERS
John B. Williamson, III
Chairman & CEO
Arthur L. Pendleton
President and COO
Roger L. Baumgardner
Vice President
Secretary and Treasurer
J. David Anderson
Assistant Sec. & Assistant Treas.
Richard F. Pevarski
Vice President
Operations and Marketing
Jane N. O'Keeffe
Vice President
Human Resources
BLUEFIELD GAS COMPANY
BOARD OF DIRECTORS
Roger L. Baumgardner
Vice President, Secretary & Treasurer
Arthur L. Pendleton
President & COO
John C. Shott (thru 3/31/99)
Paper Supply Company
President
Scott H. Shott
Paper Supply Company
Secretary & Treasurer
John B. Williamson III
Chairman & CEO
OFFICERS
John B. Williamson, III
Chairman and CEO
Arthur L. Pendleton
President and COO
Roger L. Baumgardner
Vice President
Secretary and Treasurer
DIVERSIFIED ENERGY COMPANY
BOARD OF DIRECTORS
Roger L. Baumgardner
Vice President, Secretary & Treasurer
Frank T. Ellett
Virginia Truck Center, Inc.
President
Arthur L. Pendleton
Roanoke Gas Company
President & COO
S. Frank Smith
Coastal Coal Co., LLC
Vice President
John B. Williamson III
Chairman & CEO
OFFICERS
John B. Williamson III
Chairman & CEO
John S. D'Orazio
President & COO
Roger L. Baumgardner
Vice President
Secretary & Treasurer
40
<PAGE>
CORPORATE INFORMATION
Corporate Office
RGC Resources, Inc.
519 Kimball Avenue, N.E.
PO Box 13007
Roanoke, VA 24030
(540) 777-4GAS (4427)
Fax (540) 777-2636
Auditors
Deloitte & Touche LLP
1100 Carillon
227 West Trade Street
Charlotte, NC 28202-1675
Common Stock Transfer Agent, Registrar, Dividend Disbursing Agent & Dividend
Reinvestment Agent First Union National Bank of North Carolina First Union
Customer Information Center Corporate Trust Client Services NC-1153 1525 West
W.T. Harris Boulevard - 3C3 Charlotte, NC 28288-1153
Common Stock
RGC Resources' common stock is listed on the Nasdaq National Market under the
trading symbol RGCO.
Direct Deposit Of Dividends &
Safekeeping of Stock Certificates
Shareholders can have their cash dividends deposited automatically into
checking, saving or money market accounts. The shareholder's financial
institution must be a member of the Automated Clearing House. Also, RGC
Resources offers safekeeping of stock certificates for shares enrolled in the
dividend reinvestment plan. For more information about these shareholder
services, please contact the Transfer Agent, First Union National Bank of North
Carolina.
10-K Report
A copy of RGC Resources, Inc. latest annual report to the Securities and
Exchange Commission on Form 10-K will be provided without charge upon written
request to:
Roger L. Baumgardner
Vice President, Secretary & Treasurer
RGC Resources, Inc.
PO Box 13007
Roanoke, VA 24030
Shareholder Inquiries
Questions concerning shareholder accounts, stock transfer requirements,
consolidation of accounts, lost stock certificates, safekeeping of stock
certificates, replacement of lost dividend checks, payment of dividends, direct
deposit of dividends, initial cash payments, optimal cash payments and name or
address changes should be directed to the Transfer Agent, First Union National
Bank. All other shareholder questions should be directed to:
Roger L. Baumgardner
Vice President, Secretary & Treasurer
RGC Resources, Inc.
PO Box 13007
Roanoke, VA 24030
Financial Inquiries
All financial analysts and professional investment managers should direct their
questions and requests for financial information to:
Roger L. Baumgardner
Vice President, Secretary & Treasurer
RGC Resources, Inc.
PO Box 13007
Roanoke, VA 24030
Access up-to-date information on
RGC Resources and its subsidiaries at www.rgcresources.com
<PAGE>
RGC Resources (Symbol)
Trading on NASDAQ as RGCO
Transfer Agent and Dividend Disbursing Agent:
First Union National Bank of North Carolina
First Union Customer Information Center
Corporate Trust Client Services NO-1153
1525 West W. T. Harris Boulevard - 3C3
Charlotte, North Carolina 28288-1153
1-800-829-8432
Exhibit 21
RGC Resources, Inc.
Subsidiaries of Registrant
Roanoke Gas Company (incorporated in Virginia)
Bluefield Gas Company (incorporated in West Virginia)
Diversified Energy Company (incorporated in Virginia)
Exhibit 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-69902 on Form S-2, as amended, Registration Statement No. 333-02455 on Form
S-8, and Registration Statement No. 333-67311 on Form S-4 of RGC Resources, Inc.
of our report dated October 22, 1999, incorporated by reference in the Annual
Report on Form 10-K of RGC Resources, Inc. for the years ended September 30,
1999 and 1998.
s/Deloitte & Touche LLP
Charlotte, North Carolina
December 16, 1999
Exhibit 23(b)
Accountants' Consent
The Board of Directors
RGC Resources, Inc.
We consent to incorporation by reference in Registration Statements No. 33-69902
on Form S-2, as amended, No. 333-02455 on Form S-8, as amended, and No.
333-67311 on Form S-4, as amended, of RGC Resources, Inc. (successor to Roanoke
Gas Company) of our report dated October 17, 1997, relating to the consolidated
statements of earnings, stockholders' equity and cash flows of RGC Resources,
Inc. and subsidiaries for the year ended September 30, 1997, which report is
included in the September 30, 1999 Annual Report on Form 10-K of RGC Resources,
Inc.
s/KPMG LLP
KPMG LLP
Roanoke, Virginia
December 16, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM RGC
RESOURCES INC.'S CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED SEPTEMBER
30, 1999, AS SET FORTH IN THE COMPANY'S ANNUAL REPORT ON FORM 10-K, AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 49,637,271
<OTHER-PROPERTY-AND-INVEST> 9,479,749
<TOTAL-CURRENT-ASSETS> 17,774,411
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 898,551
<TOTAL-ASSETS> 77,789,982
<COMMON> 9,163,855
<CAPITAL-SURPLUS-PAID-IN> 9,489,551
<RETAINED-EARNINGS> 9,501,517
<TOTAL-COMMON-STOCKHOLDERS-EQ> 28,154,923
0
0
<LONG-TERM-DEBT-NET> 23,336,614
<SHORT-TERM-NOTES> 6,363,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 24,282
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 19,911,163
<TOT-CAPITALIZATION-AND-LIAB> 77,789,982
<GROSS-OPERATING-REVENUE> 57,088,871
<INCOME-TAX-EXPENSE> 1,316,190
<OTHER-OPERATING-EXPENSES> 50,951,764
<TOTAL-OPERATING-EXPENSES> 52,267,954
<OPERATING-INCOME-LOSS> 4,820,917
<OTHER-INCOME-NET> 146,332
<INCOME-BEFORE-INTEREST-EXPEN> 4,967,249
<TOTAL-INTEREST-EXPENSE> 2,083,842
<NET-INCOME> 2,883,407
0
<EARNINGS-AVAILABLE-FOR-COMM> 2,883,407
<COMMON-STOCK-DIVIDENDS> 1,965,246
<TOTAL-INTEREST-ON-BONDS> 443,750
<CASH-FLOW-OPERATIONS> 5,890,808
<EPS-BASIC> 1.59
<EPS-DILUTED> 1.59
</TABLE>
