UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K/A
(MARK ONE)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended August 31, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from ____________________ to _____________________
Commission File number 1-7924
VALLEY RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
Rhode Island 05-0384723
(State of Incorporation or Organization) (IRS Employer Identification No.)
1595 Mendon Road, Cumberland, Rhode Island 02864
(Address of principal executive offices)
Registrant's Telephone Number, Including Area Code (401) 334-1188
Securities Registered Pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- ---------------------
Common Stock American Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
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 ___.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
form 10-K. [__]
The aggregate market value of the common stock held by non-affiliates,
computed on the basis of $22.25 per share (the closing price of such stock on
March 23, 2000 on the American Stock Exchange) was $111,094,873.
As of February 29, 2000 there were 4,993,028 shares of Valley Resources,
Inc. Common Stock, $1 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Directors and Executive Officers of the registrant, Executive
Compensation and Security Ownership and Certain Beneficial Owners and Management
appearing in the Proxy Statement dated November 9, 1999 as filed with the
Securities and Exchange Commission are incorporated by reference in Part III.
2
PART I
Item 1 Business
--------
Valley Resources, Inc. (the "Corporation") is a holding company organized
in 1979 and incorporated in the State of Rhode Island. The Corporation has five
wholly-owned active subsidiaries: Valley Gas Company ("Valley Gas") and Bristol
& Warren Gas Company ("Bristol & Warren" and collectively with Valley Gas, the
"Utilities")--regulated natural gas distribution companies; Valley Appliance and
Merchandising Company ("VAMCO")--a merchandising and appliance rental company;
Valley Propane, Inc. ("Valley Propane")--a wholesale and retail propane company;
and Morris Merchants, Inc., d/b/a the Walter Morris Company ("Morris
Merchants")--a wholesale distributor of franchised lines in plumbing and heating
contractor supply and other energy-related business. The Corporation also owned
an 80% interest in Alternate Energy Corporation ("AEC") during fiscal 1999. The
Corporation acquired an additional 10% interest from AEC's current management on
September 1, 1999 and has the obligation to acquire the remaining 10% in 2001.
AEC sells, installs and designs natural gas conversion systems and facilities,
is an authorized representative of the ONSI fuel cell, holds a patent for a
natural gas/diesel co-firing system and has a patent pending for a device to
control the flow of fuel on dual-fuel equipment.
Utility Operations
- ------------------
Gas Sales and Transportation
The Corporation's utility operations are conducted through the Utilities.
The Utilities had an average of 63,172 customers during the fiscal year ended
August 31, 1999, of which approximately 91% were residential and 9% were
commercial and industrial. For the fiscal year ended August 31, 1999, 52% of gas
sales were to residential customers and 48% were to commercial and industrial
customers.
The Utilities provide natural gas service to residential, commercial and
industrial customers and transportation services to industrial customers. Valley
Gas' 92 square mile service territory is located in the Blackstone Valley region
in northeastern Rhode Island with a population of approximately 250,000. Bristol
& Warren's 15 square mile service territory is located in eastern Rhode Island
with a population of approximately 35,000. Since November 1995, the Utilities
have operated under a single rate structure.
The following table shows the distribution of gas sold and transported
since fiscal 1995 in millions of cubic feet ("MMcf"):
For the Fiscal Year Ended August 31,
------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Residential .................. 4,165 4,225 4,393 4,612 4,078
Commercial ................... 2,054 2,060 2,161 2,252 1,953
Industrial-firm .............. 1,024 1,133 1,440 1,391 1,338
Industrial-seasonal .......... 692 648 1,110 1,047 1,298
Transportation-firm .......... 543 346 -0- -0- -0-
Transportation-seasonal ...... 4,442 4,895 5,043 3,273 4,419
------ ------ ------ ------ ------
TOTAL ................... 12,920 13,307 14,147 12,575 13,086
====== ====== ====== ====== ======
Firm customers of the Utilities use gas for cooking, heating, water
heating, drying and commercial/industrial processing. Certain industrial
customers use additional gas in the summer months, when it is available at lower
prices. These customers are subject to having their service interrupted at the
discretion of the Utilities with very little notice. This use is classified as
seasonal use. As discussed below, the margin on seasonal use is passed through
the Purchased Gas Price Adjustment ("PGPA") to lower the cost of gas to all
categories of firm customers. Bristol & Warren retained the margin on seasonal
sales prior to November 1995.
3
The primary source of utility revenues is firm use customers under tariffs
which are designed to recover a base cost of gas, administrative and operating
expenses and provide sufficient return to cover interest and profit. The
Utilities also service dual fuel, interruptible and transportation customers
under rates approved by the Rhode Island Public Utilities Commission ("RIPUC").
Additionally, Valley Gas services cogeneration customers under separate contract
rates that were individually approved by the RIPUC.
The Utilities' sales tariffs include a PGPA which allows an adjustment of
rates charged to customers in order to recover all changes in gas costs from
stipulated base gas costs. The PGPA provides for an annual reconciliation of
total gas costs billed with the actual cost of gas incurred. Any excess or
deficiency in amounts collected as compared to costs incurred is deferred and
either reduces the PGPA or is billed to customers over subsequent periods. The
PGPA does not impact operating income as it effectuates a dollar for dollar
recovery of gas costs. All margins from interruptible customers are returned to
firm customers through the workings of the PGPA.
Utility revenues include a surcharge on firm gas throughput to collect a
portion of the costs to fund postretirement medical and life insurance benefits
above the pay-as-you-go costs included in base tariffs. The surcharge was
authorized by the RIPUC in a generic rate proceeding and is being phased in over
a ten-year period which commenced September 1, 1993. Effective November 1995,
the current year funding of postretirement medical and life insurance benefits
is included in base tariffs. In September 1996, the RIPUC authorized the funding
shortages from the first two years of the phase-in to be recovered through a
surcharge over the next three fiscal years.
The prices of alternative sources of energy impact the interruptible and
dual fuel markets. The Utilities serve these customers in the nonpeak periods of
the year or when competitively priced gas supplies are available. These
customers are subject to service discontinuance on short notice as system firm
requirements may demand. Prices for these customers are based on the price of
the customers' alternative fuel. In order to mitigate the volatility of earnings
from interruptible and dual fuel sales, the Utilities roll into the PGPA the
margin earned on these interruptible sales and all margins in excess of $1 per
thousand cubic feet ("Mcf") of gas sold to dual fuel customers. This margin
credit reduces rates to firm customers. This margin treatment alleviates the
negative impact that swings in sales can have on earnings in the highly
competitive industrial interruptible market.
Seasonality
The Utilities business is seasonal. The bulk of firm distribution and sales
are made during the months of November through March. As a result, the highest
levels of earnings and cash flow are generated from the quarters ending in
February and May. The bulk of the capital expenditure programs are undertaken
during the months of May through October, causing cash flow to be at its lowest
during the quarters ending in November and August.
Short-term borrowing requirements vary according to the seasonal nature of
sales and expense activities of the Utilities. As a result, there is a greater
need for short-term borrowings during periods when internally generated funds
are not sufficient to cover all capital and operating requirements, particularly
in the summer and fall. Short-term borrowings utilized for construction
expenditures generally are replaced by permanent financing when it becomes
economical and practical to do so and where appropriate to maintain an
acceptable relationship between borrowed and equity resources.
Rates and Regulation
The Utilities are subject to regulation by the RIPUC with respect to rates,
adequacy of service, issuance of securities, accounting and other matters.
4
Gas Supply and Storage
Tennessee Gas Pipeline Company is the major natural gas transporter for
Valley Gas under long-term contracts. Bristol & Warren's principal gas
transporters are Algonquin Gas Transmission Company and Texas Eastern
Transmission Corporation. The Utilities purchase natural gas from several
suppliers on a long-term firm basis, as well as on the spot market whenever
available.
Year-Round Wellhead Firm Supply - Valley Gas is a charter member of the
Mansfield Consortium, a group of five local distribution companies that joined
together to use their combined market power to secure favorable terms for
long-term gas supply. In addition, Valley Gas is an investor in Boundary Gas,
Inc. and a customer of Alberta Northeast, LTD, both of which were founded by
groups of gas distribution companies in the Northeast to import natural gas from
Canada.
Valley Gas and Bristol & Warren together have 17,367 dekatherms per day
("Dth/day") of year-round firm supply under long-term contracts with two
domestic and two Canadian suppliers. Of these contracts, 15,300 Dth/day are due
to expire on June 30, 2002, 1,067 Dth on December 1, 2002 and the remainder
extends through 2012. All of the Utilities' gas supply contracts are
spot-indexed based. The Utilities have flexible take requirements, with no gas
categorized as "baseload" supply which must be taken every day.
Winter-Only Firm Supply - The Utilities believe they are well-positioned
with respect to winter-only firm supply. Their actual and prospective long-term
contracts are with major participants in this market, and contract prices are at
competitively favorable terms.
Liquefied Natural Gas ("LNG") - Valley Gas is entitled to 5,300 Dth/day of
firm supply from Distrigas, which re-vaporizes LNG at its Everett, Massachusetts
facility for delivery during the winter months to Valley Gas by Tennessee Gas
Pipeline or to Bristol & Warren via Algonquin Gas Transmission. As an option,
Valley Gas may take this gas in its liquefied state for transportation by truck
to and storage at Valley Gas' on-site LNG tank. A further option allows Valley
Gas to increase its maximum daily quantity from 5,300 to 7,550 dekatherms
("Dth"). There are no minimum takes, and the contract runs through October 31,
2005. Valley Gas also has a multi-year contract with Distrigas for 250,000 Dth
of LNG.
Maritimes & Northeast Pipeline - Valley Gas has a one year contract for
180,000 Dth of firm winter-only gas supply which is delivered from Canada by
Maritimes & Northeast Pipeline and then to Valley's city gate by Tennessee Gas
Pipeline.
Pawtucket Power Co-Generation Plant - Valley Gas is entitled under
long-term contract to utilize up to 540 Dth per hour, with a maximum annual
quantity of 333,000 Dth, of natural gas used by Pawtucket Power in its
generation of electricity and steam. This firm gas supply originates in Alberta,
Canada.
Underground Storage - The Utilities have 1,544,258 Dth of underground
storage capacity with Tennessee Gas Pipeline, Texas Eastern Gas Transmission,
CNG Transmission and National Fuel Gas Supply Corporation, with a total maximum
daily withdrawal quantity of 20,589 Dth. The Utilities' inject underground
storage gas during the non-winter months into fields located in Pennsylvania and
New York for subsequent withdrawal during the winter when customer demand is
greatest.
Interstate Pipeline Capacity - The Utilities utilize firm pipeline capacity
for two basic purposes: 1) daily transportation of firm and spot market gas
supply throughout the year from the Gulf Coast to their city gates, and 2)
winter-only transportation of underground storage gas to their city gates.
Gas Supply Pipeline Capacity - Total year-round firm capacity is 24,912
Dth/day. Of this total, 82% expires by November 1, 2002, and the remainder
extends through 2012.
Storage Pipeline Capacity - The Utilities' storage-related pipeline
capacity totals 12,738 Dth/day. About 85% of this capacity expires November 1,
2002, and the remainder extends through 2012.
5
On-Site LNG and Propane Storage - In addition to the gas delivered by the
interstate pipeline, the Utilities have on-site storage facilities for liquid
propane gas ("LPG"), with Valley Gas having about 857,000 gallons and Bristol &
Warren having about 117,000 gallons of LPG storage. Valley Gas also has on-site
storage facilities for 968,320 gallons (about 85,000 Dth) of LNG. Both LPG and
LNG are vaporized into the Utilities' distribution systems during periods of
peak demand and utilized as backup in the event of failure of an upstream
pipeline to deliver needed gas supplies.
Competition and Marketing
The primary competition faced by the Utilities is from other energy
sources, primarily heating oil. The principal considerations affecting a
customer's selection among competing energy sources include price, equipment
cost, reliability, ease of delivery and service. In addition, the type of
equipment already installed in businesses and residences significantly affects
the customer's choice of energy. However, where previously installed equipment
is not an issue, households in recent years have consistently preferred the
installation of gas heat. Valley Gas' statistics indicate that approximately 90%
of the new homes built on or near Valley Gas' service mains in recent years have
selected gas as their energy source.
The Utilities are pursuing new markets believed to have the potential to
provide both growth and/or lessen sales sensitivity to weather: industrial
processing, cogeneration, natural gas vehicles and conversions from oil or
electricity to gas.
In recent utility rate decisions, the RIPUC approved rates which will
retain and attract industrial customers. Additionally, the Utilities have two
rates which promote economic development in its service territory. These rates
provide incentives for companies that add industrial processing load, make a
substantial investment in new natural gas equipment and hire additional
employees.
The cogeneration market is addressed through sales contacts with customers
who have applications suitable to use waste heat through the cogeneration
process. There are established rate tariffs to specifically address the
requirements of the cogeneration market. In addition, Valley Gas has a 50
kilowatt demonstration facility at its Cumberland location which provides
electricity for computer facilities and hot water requirements.
Valley Gas has a compressed natural gas ("CNG") fueling station at its
Cumberland, Rhode Island headquarters. The use of natural gas in vehicles is
promoted through conversions of its own fleet and the CNG rate approved by the
RIPUC.
The Utilities' residential marketing department seeks to increase
conversions from oil to natural gas through installations of conversion burners
and conversions to natural gas of housing developments that initially chose
alternate energy sources. Additional efforts are made to convert homes with
inactive natural gas service and to replace electric heating systems with
natural gas systems.
The distribution company unbundling process will add competition from a new
source-- natural gas suppliers. The Utilities have received approval from the
RIPUC for transportation rates which allow large commercial and industrial
customers the choice to purchase gas from the Utilities or from natural gas
marketers. Gas purchased by users within the Utilities' territories is
transported to the users by the Utilities. Since the Utilities' profits are
derived from distribution of natural gas and not natural gas sales, this process
is not expected to significantly impact the profitability of the Utilities.
6
Gas Distribution System
- -----------------------
Valley Gas' distribution system consists of approximately 900 miles of gas
mains and service lines. Bristol & Warren's gas distribution system consists of
approximately 100 miles of gas mains and service lines. The aggregate maximum
daily quantity of gas that may be distributed through the Utilities from their
own facilities and under existing supply and transportation contracts is
approximately 100 MMcf, and the maximum daily gas sendouts for all sales
customers of the Utilities during the last five fiscal years were 71 MMcf in
1999, 70 MMcf in 1998, 73 MMcf in 1997, 71 MMcf in 1996 and 66 MMcf in 1995.
Gas Marketing
- -------------
The Utilities filed to unbundle their firm commercial and industrial
tariffs with the RIPUC in September 1996. Effective June 1, 1997, the Utilities
were authorized to offer transportation rates to large commercial and industrial
customers and redesign the rates for other customers.
Appliance Contract Sales and Rentals
- ------------------------------------
The Corporation conducts appliance sales, service contract sales and
appliance rentals through its subsidiaries VAMCO and Morris Merchants. VAMCO's
revenues are generated through retail appliance sales, service contract sales
and the rental of gas-fired appliances. Morris Merchants has contracts for the
distribution of certain lines that it wholesales. At this time the Corporation
has no reason to believe it will lose any of its existing lines. The
merchandising subsidiaries are in competitive businesses with competition based
on many factors, including price, quality of product and service.
Propane Operations
- ------------------
The propane operations are conducted through Valley Propane, which sells,
at retail, liquid propane gas to residential and commercial customers in Rhode
Island and nearby Massachusetts. At August 31, 1999, Valley Propane had 2,508
customers. Valley Propane also supplies propane to holding customers of the
Utilities. These customers are serviced by Valley Propane until the Utilities
can connect mains and service lines. Valley Propane is also impacted by weather,
as a large percentage of its customers use propane as a primary source of heat.
Valley Propane increases and decreases the selling price of its gas depending
upon supply and competition.
Natural Gas Conversions
- -----------------------
The Corporation conducts natural gas conversions through AEC. AEC generates
its revenues through the engineering and installation of compressed natural gas
refueling stations, the conversion of gasoline and diesel-powered vehicles to
natural gas and through the implementation of its patented process to co-fire
natural gas and diesel fuel in engines, primarily generators.
In fiscal 1998, AEC opened a public natural gas vehicle ("NGV") refueling
station located at the Valley Resources corporate headquarters. AEC buys gas
from Valley Gas and retails it to a number of different customers.
The Corporation acquired an 80% interest in AEC in May 1996. It acquired an
additional 10% interest from AEC's management on September 1, 1999. The
Corporation is required to acquire the remaining 10%, which is currently held by
the management of AEC, in 2001.
Environmental Proceedings
- -------------------------
For information regarding the Corporation's potential environmental
liabilities, see "Management's Discussion and Analysis of the Results of
Operations and Financial Condition - Liquidity and Capital Resources", in Part
II, Item 7.
7
Item 2 Properties
----------
1595 Mendon Road, Cumberland, Rhode Island
Office, Sales, and Service Center
This location comprises the headquarters, sales and service operation of
the Corporation, Valley Gas, VAMCO and Valley Propane. It includes accounting,
billing, credit, engineering, garage, maintenance, service, storeroom and
construction. The headquarters and sales office for AEC are also located at this
facility. The Corporation considers these facilities to be suitable and adequate
to meet its needs.
425 Turnpike Street
Canton, Massachusetts
Office and Warehouse Facilities
Morris Merchants conducts its business at this leased warehouse and office
building in Canton, MA. Since its business does not require any special
facilities, its leased facilities are not significant to its operation. The
total lease payments are less than 1 percent of all corporate assets of the
Corporation.
106-B Federal Way
Johnston, Rhode Island
Service Center
AEC conducts its servicing business at this leased garage in Johnston, RI.
The leased facility is not significant to its operations and the total lease
payments are less than 1 percent of all corporate assets of the Corporation.
Scott Road, Cumberland, Rhode Island
LNG Storage Plant
Propane Storage Plant
This facility is used for the storage of LNG and propane used in the
peak-shaving operations of Valley Gas. Its daily delivery capacity of LNG and
LPG is 25,000 Mcf's and 12,000 Mcf's, respectively.
100 Broad Common Road
Bristol, Rhode Island
Office, Sales and Service Center
This location comprises the office, sales and service operation of Bristol
& Warren and includes construction, credit, engineering, garage, maintenance,
service, and storeroom.
Brown Street
Warren, Rhode Island
Propane Storage
This facility is used for the storage of propane used in peak-shaving
operations of Bristol & Warren. Its daily delivery capacity of LPG is 1,600
Mcf's.
The Corporation believes its storage facilities are adequate to meet the
needs of the Utilities for the foreseeable future. All of the storage facilities
are owned. All Valley Gas properties, except leased property, are held in fee.
See Item 1 for discussion of gas supply.
8
Item 3 Legal Proceedings
-----------------
There were no material legal proceedings pending to which the Corporation
or any of its subsidiaries is a party, or of which any of their property is the
subject, except two environmental claims that were asserted against Valley Gas
as referred to in Part II, Items 7 and 8.
Item 4 Submission of Matters to a
Vote of Security Holders
None
9
Executive Officers of the Registrant
- ------------------------------------
The names, ages, and position of all the executive officers of the
Corporation on October 15, 1999 are listed below, together with their business
experience during the past five years. All officers of the Corporation are
elected or appointed annually by the board of directors at the directors' first
meeting following the Annual Meeting of Stockholders.
Business Experience
Name Age Position During Last Five Years
---- --- -------- ----------------------
Alfred P. Degen 52 Chairman, President Chairman since December 1997;
and Chief Executive Chief Executive Officer since
Officer March 1995; President, from July
1994; Executive Vice President,
Philadelphia Gas Works for more
than 5 years prior to July 1994.
Charles K. Meunier 57 Vice President, Vice President Operations since
Operations December 1994; Assistant Vice
President Operations and Human
Resources prior to December 1994.
Richard G. Drolet 51 Vice President, Vice President Information Systems
Information Systems and Corporate Planning since
and Corporate December 1994; Assistant Vice
Planning President Information Systems
and Corporate Planning prior to
December 1994.
Sharon Partridge 43 Vice President, Vice President, Chief Financial
Chief Financial Officer and Secretary since June
Officer, Secretary 1999; Assistant Vice President
and Treasurer Finance and Treasurer since
December 1994; Assistant
Treasurer prior to December
1994.
Jeffrey P. Polucha 44 Vice President, Vice President Marketing and
Marketing and Development since December 1994;
Development Manager Residential and Propane
Sales prior to December 1994.
10
PART II
Item 5 Market for the Registrant's Securities
and Related Stockholder Matters
--------------------------------------
Valley Resources common stock is listed and principally traded on the
American Stock Exchange under the symbol "VR." The table below shows the
dividends declared and the high and low sales prices of Valley's common stock
for the fiscal periods indicated as reported in The Wall Street Journal.
Dividends and Market Data
- -------------------------
Cash Market Price
1999 Dividend High Low
- ---- -------- ---- ---
First Quarter $.1875 $13.38 $11.00
Second Quarter .1875 13.00 12.13
Third Quarter .1875 13.00 10.50
Fourth Quarter .1875 16.50 11.00
Cash Market Price
1998 Dividend High Low
- ---- -------- ---- ---
First Quarter $.1850 $11.50 $10.25
Second Quarter .1850 12.38 10.63
Third Quarter .1875 12.13 11.13
Fourth Quarter .1875 12.13 11.13
There were 2,062 shareholders at August 31, 1999. The registrar and
transfer agent for Valley Resources Common Stock is The Bank of New York.
On August 31, 1999, $1,751,400 of the retained earnings of Valley Gas were
available for the payment of cash dividends to the Corporation under the most
restrictive provisions of Valley Gas' first mortgage bonds. There are no
restrictions as to the payment of dividends for the other subsidiaries.
11
Item 6 Selected Financial Data
-----------------------
Summary of Consolidated Operations
August 31 (in thousands) 1999 1998 1997 1996 1995
- ------------------------ ---- ---- ---- ---- ----
Assets
Utility plant - net ............. $ 52,334 $51,310 $50,447 $49,442 $47,411
Leased property - net ........... 1,556 2,303 2,377 2,945 2,014
Nonutility plant - net ....... 4,163 4,106 3,712 3,568 3,547
Current assets ............... 18,612 18,713 20,205 19,307 18,409
Other assets ................. 23,558 22,049 20,956 21,427 20,957
-------- ------- ------- ------- -------
Total ...................... $100,223 $98,481 $97,697 $96,689 $92,338
======== ======= ======= ======= =======
Capitalization and liabilities
Capitalization
Common equity ................. $ 35,805 $35,223 $34,307 $27,092 $25,993
Long-term debt
(less current maturities) .... 29,473 29,638 31,986 23,256 24,616
-------- ------- ------- ------- -------
Total ...................... 65,278 64,861 66,293 50,348 50,609
Revolving credit arrangement .... 2,400 2,400 2,300 2,200 -0-
Obligations under capital leases 775 1,528 1,541 2,134 1,255
Current liabilities ............. 14,598 12,586 10,612 24,005 23,932
Other liabilities ............... 17,172 17,106 16,951 18,002 16,542
-------- ------- ------- ------- -------
Total ...................... $100,223 $98,481 $97,697 $96,689 $92,338
======== ======= ======= ======= =======
For the year ended August 31,
(in thousands, except as to share
and per share data) 1999 1998 1997 1996 1995
- ------------------- ---- ---- ---- ---- ----
Operating revenues ................ $ 81,710 $81,589 $87,484 $80,360 $74,870
Operating expenses:
Cost of gas sold ................ 30,494 31,437 37,844 31,951 30,229
Cost of sales - nonutility ... 15,787 15,517 14,791 13,689 13,190
Other operation and maintenance . 19,246 19,553 19,524 19,379 18,288
Depreciation ................. 3,398 3,274 3,143 2,956 2,685
Taxes - other than Federal income 4,117 4,120 4,243 4,091 4,002
- Federal income .......... 1,772 1,330 1,335 1,444 732
-------- ------- ------- ------- -------
Total ...................... 74,814 75,231 80,880 73,510 69,126
-------- ------- ------- ------- -------
Operating income ................... 6,896 6,358 6,604 6,850 5,744
Other income - net ................. 299 289 423 460 115
Total interest charges ............. 3,008 3,041 3,368 3,312 3,304
-------- ------- ------- ------- -------
Net income ...................... $ 4,187 $ 3,606 $ 3,659 $ 3,998 $ 2,555
======== ======= ======= ======= =======
Shares outstanding - average ....... 4,979,508 4,966,270 4,267,038 4,258,877 4,222,662
Shares outstanding - year-end ...... 4,993,028 4,993,028 4,900,028 4,280,028 4,260,797
Basic and diluted earnings per share $0.84 $0.73 $0.86 $0.94 $0.61
Dividends declared per share ....... $0.75 $0.745 $0.735 $0.725 $0.71
Year-end book value per share ...... $7.17 $7.05 $7.00 $6.33 $6.10
12
Item 7 Management's Discussion and Analysis of the Results of Operations
and Financial Condition
-----------------------------------------------------------------
OVERVIEW
The discussion and analysis that follows reflect the operations of the
Corporation and its six active subsidiaries: Valley Gas and Bristol & Warren
(collectively the "Utilities"), regulated natural gas distribution companies;
VAMCO, a merchandising, appliance rental, and service company; Valley Propane, a
propane sales and service company; Morris Merchants, a representative
distributor of franchised lines; and AEC, which sells, designs and installs
natural gas refueling facilities, natural gas conversion systems and energy use
control devices.
Operating results are derived from three major business segments - Gas
Operations, Contract Sales and All Other Operations. Gas Operations consist of
utility earnings generated from the sale and transportation of natural gas.
Contract Sales, included in nonutility earnings, consists of the Morris
Merchants operations. All Other Operations are comprised of VAMCO, Valley
Propane, AEC, Corporate and Eliminations and is also included in nonutility
earnings (See footnote I Business Segments).
Natural gas sales and transportation to customers, on a year-round basis,
for heating, water heating, cooking and processing are the primary source of
firm utility revenues for gas operations. Firm customers can be residential,
commercial or industrial. Revenues from firm customers are determined by
regulated tariff schedules and through Rhode Island Public Utilities Commission
("RIPUC") approved commodity charge factors. These factors include the Purchased
Gas Price Adjustment ("PGPA"), which requires the Utilities to collect from or
return to firm sales customers changes in gas costs from those included in the
regulated tariffs, and an adjustment to collect post-retirement benefits.
Utility revenues also include seasonal and dual-fuel sales. These sales,
which are made when excess gas supplies are available and gas prices are
competitive with alternative fuel markets, can be interrupted by the Utilities
at any time. Margins from seasonal sales and margins above $1 per thousand cubic
feet ("Mcf") of gas sold to dual fuel customers are returned to firm sales
customers through a reduction in the PGPA. The Utilities also provide
interruptible transportation services through their distribution systems.
Morris Merchants generates nonutility revenues through wholesale sales of
franchised business lines of plumbing and heating equipment.
VAMCO generates its revenues through the sales and installation of heating
equipment and appliances. VAMCO also generates revenues from appliance rentals,
service contract repair program and water filtration sales. Valley Propane sells
propane at both wholesale and retail and provides service to propane customers
in Rhode Island and southeastern Massachusetts. AEC generates revenues through
the design and installation of natural gas refueling facilities and through the
conversion of vehicles and stationary engines to natural gas. The Corporation
owned an 80% interest in AEC during fiscal 1999. The Corporation received an
additional 10% interest from AEC's current management on September 1, 1999 and
has the obligation to acquire the remaining 10% in 2001.
13
RESULTS OF OPERATIONS
Fiscal 1999 versus 1998
Gas Operations
- -----------------------
Utility gas revenues in fiscal 1999 totaled $58,529,400, a decrease of 1.4%
from fiscal 1998. This decrease was attributable to a weather related decline in
firm gas sales, and a decrease of $137,900 in gas costs recovered through the
PGPA which were offset slightly by an increase in transportation revenues. The
PGPA does not impact operating income as it effectuates a dollar for dollar
recovery of gas costs. The transfer of customers to transportation does not
affect margins although it does produce less revenues.
Firm gas throughput, firm gas sales and transportation was 7,786,900 Mcf in
fiscal 1999, an increase of less than one percent over fiscal 1998. The slight
increase was primarily the result of increased firm transportation service
mitigating the effect of decreased firm gas sales. Firm gas sales declined as a
result of weather, which was less than one percent warmer than the prior year
and 9.1% warmer than a normal year, and the transfer of sales customers to firm
transportation. Firm gas sales were primarily impacted by weather related
declines during the critical heating period, December through February. During
this period weather was 3.2% warmer than the prior year and 10.6% warmer than a
normal year.
Throughput to interruptible customers in fiscal 1999 decreased 7.4% as
compared to fiscal 1998 due to the lower price of competing fuels. Interruptible
throughput includes sales to seasonal and dual-fuel customers and the
transportation of customer-owned natural gas to interruptible and off-peak
customers. Interruptible sales and transportation, excluding off-peak, are
dependent on the availability of natural gas and the cost of competitive fuels.
Profits on seasonal sales are returned to firm sales customers through the PGPA
and do not impact operating income. Interruptible transportation revenues
decreased $5,700 from the prior year.
Cost of gas sold includes the cost of natural gas, underground storage gas,
liquefied natural gas and liquid propane gas to serve utility sales customers.
The average cost per Mcf of natural gas distributed in fiscal 1999 was $3.68
versus $4.02 in fiscal 1998. The decline was the result of lower natural gas
commodity prices. All changes in gas costs for utility operations are passed
through to firm sales customers through the PGPA. Therefore, changes in gas
costs do not impact the profitability of the Utilities.
Other operation expenses in fiscal 1999 totaled $12,759,500, a decline of
6.2% from fiscal 1998. A decrease in uncollectible accounts and labor cost
savings associated with the warmer weather caused the decline.
Maintenance expenses increased 2.0% in fiscal 1999 by over the prior fiscal
year to $1,627,600. The slight increase was the result of normal wage and
inflation costs.
Taxes - other than Federal income taxes totaled $3,840,400, a less than 1%
increase over the prior fiscal year. The slight increase was the result of
increased property taxes offset by decreased gross receipts tax on lower utility
revenues.
Other income - net of tax was $25,900 in fiscal 1999 and $75,300 in fiscal
1998. A decrease in earnings from other investments was responsible for the
reduction.
Fiscal 1999 interest expense was $2,788,900, a decrease of less than 1%
when compared to the prior fiscal year. A slight reduction in long-term debt
interest expense was offset slightly by increased interest expense on an
increase in average short-term debt outstanding.
14
CONTRACT SALES
Contract Sales revenues totaled $15,291,400, an increase of 1.2% over
fiscal 1998. Revenues generated from wholesale operations increased over the
prior year through continued emphasis on sales of existing products and an
improvement in economic conditions.
Cost of sales - nonutility includes the cost of goods sold for wholesale
merchandise sold. Fiscal 1999 cost of sales increased 1.9% over fiscal 1998 due
to increased sales.
Other operation expenses in fiscal 1999 totaled $2,342,100, a 2.9% increase
over fiscal 1998. Increased commissions, wages and selling expenses were
responsible for the increase.
Other income - net of tax declined $10,600 when compared to fiscal 1998.
Other income is derived primarily from interest on cash investments and rebates
offered from manufacturers.
ALL OTHER OPERATIONS
The nonutility revenues associated with this segment were $7,889,400, a
10.5% increase over the prior fiscal year. The increase was the result of
increased sales by VAMCO and the Corporation's weather insurance product.
VAMCO's commitment to the commercial and industrial markets continued to
contribute to increased revenues. An increase in the number of customers
participating in the service contract and rental programs also contributed to an
improvement in retail revenues. The Corporation's weather insurance product
produced revenues as a result of the warmer than normal weather experienced
during the measurement period of November through March of fiscal 1999.
Propane revenues experienced a slight decline due to price competition and
the warmer than normal winter weather, despite an increase in gallons sold.
Propane revenues are derived from the sale of liquid propane gas to both retail
and wholesale customers for the use of cooking, heating, hot water and clothes
drying. Although price competition affects the revenue component of this
segment, the focus on margin retention through inventory management and
marketing strategy was responsible for the increased gallons sold. Gallons sold
increased 2.5% over fiscal 1998 as a result of offering customers fixed price
contracts. AEC revenues remained flat when compared to fiscal 1998.
Cost of goods sold for VAMCO and AEC and the purchase, storage and delivery
of liquid propane gas for Valley Propane is included in cost of sales -
nonutility. Fiscal 1999 cost of sales for this segment increased 1.1% when
compared to fiscal 1998. The increase was directly attributable to the increase
in sales of VAMCO.
Other operation expenses in fiscal 1999 totaled $2,456,400, a 22.9%
increase over fiscal 1998. Increased repairs in the rental program, additional
personnel and normal wage and general operating expense increases were
responsible for the increase.
Taxes - other than Federal income taxes totaled $208,900, a 1.8% increase
over fiscal 1998. The increase was the result of increased property tax values
and assessments.
Fiscal 1998 versus 1997
Gas Operations
Utility gas revenues in fiscal 1998 totaled $59,343,600, a decrease of
10.4% from fiscal 1997. The decrease in revenues from the prior year was
attributable to a weather- related decline in firm gas sales, a decrease of
$2,518,000 in gas costs recovered through the PGPA, and the transfer of
customers from sales to transportation.
15
Firm gas throughput, firm gas sales and transportation was 7,763,400 Mcf in
fiscal 1998, a decrease of 2.9% from fiscal 1997. The primary contributor to the
decline in gas throughput was weather which was 8.5% warmer than a normal year
and 6.4% warmer than the prior year.
Throughput to interruptible customers in fiscal 1998 decreased 9.9% as
compared to fiscal 1997 due to the lower price of competitive fuels. Margins
earned from seasonal sales are returned to firm customers through the PGPA and
do not impact the profitability of the Utilities. Interruptible transportation
revenues decreased $206,100 from the prior year.
Cost of gas sold includes the costs of all commodity, storage,
transportation and peak shave fuel requirements to serve utility sales
customers. The average cost per Mcf of natural gas distributed in fiscal 1998
was $4.02 versus $4.07 in fiscal 1997.
Other operation expenses in fiscal 1998 totaled $13,606,400, a decrease of
1.4% from fiscal 1997. Other operation expenses declined as a result of a
decrease in administrative and general expenses due to an additional $803,700 of
net periodic pension income. This decrease was partially offset by increased
uncollectible expense and wages.
Maintenance expenses increased for fiscal 1998 by less than 1% when
compared to fiscal 1997. Normal wage and inflation was primarily responsible for
the increase.
Taxes - other than Federal income taxes totaled $3,833,400, a decrease of
2.7% when compared to fiscal 1997. The impact of gross receipts tax on lower
utility revenues was responsible for the decrease.
Other income - net of tax was $103,600 less than fiscal 1997 as a result of
lower earnings from other investments.
Interest expense for fiscal 1998 was $2,790,800, a decrease of 13.5% from
fiscal 1997. The decrease was the result of the net proceeds of the Valley
Resources debt and equity offerings in August 1997 reducing the short-term
borrowings of the utility operations.
CONTRACT SALES
Contract Sales revenues totaled $15,104,200, an increase of 6.0% over
fiscal 1997. Revenues generated from wholesale operations increased over the
prior year through emphasis on existing products and a new approach to marketing
these products.
Cost of sales - nonutility for wholesale merchandise operations for fiscal
1998 was $12,055,200, a 5.9% increase over fiscal 1997. The increase was the
direct result of increased sales.
Other operation expenses in fiscal 1998 totaled $2,275,800, an 8.0%
increase over fiscal 1997. Increased commissions, wages and selling expenses
were responsible for the increase.
Other income - net of tax declined $15,200 for fiscal 1998 when compared
with the prior fiscal year. The decline was the result of decreased income from
manufacturer rebates.
ALL OTHER OPERATIONS
The nonutility revenues associated with this segment were $7,141,000, a
1.9% increase over the prior fiscal year. The increase was the result of
increased residential and commercial retail sales, offset by a decline in
propane and AEC revenues. VAMCO's commitment to the commercial and industrial
markets, as well as continued efforts in the residential heating replacement
market, contributed to increased revenues. An
16
increase in the number of customers participating in the service contract and
rental programs was also responsible for improvement in retail revenues. Despite
an increase in gallons of propane sold and increased customers, revenues from
the propane operation declined from the prior year. A decrease in revenues from
AEC also impacted nonutility revenues.
Cost of sales - nonutility for other operations increased 1.6% in 1998 when
compared with the prior fiscal year. The increase in cost of sales is directly
attributable to the increase in retail sales partially offset by a decrease in
the cost of propane gas sold.
Other operation expenses in fiscal 1998 totaled $1,998,400, an increase of
less than 1% over fiscal 1997. Normal wage increases were responsible for the
increase.
Maintenance expenses totaled $76,200, an increase of $23,400 over fiscal
1997. Repairs to a propane delivery vehicle was responsible for the increased
expense.
Taxes - other than Federal income taxes totaled $208,900, a 1.8% increase
over fiscal 1997. The increase over the prior fiscal year was the result of
increased property tax values and assessments.
LIQUIDITY AND CAPITAL RESOURCES
Cash is generated through the distribution and sale of natural gas, propane
and merchandise. Additional revenues are collected through the rental and
service contract programs. Operations, external financing and investments are
also used to meet corporate cash needs. Short-term financing under existing
lines of credit are available to meet working capital requirements. When deemed
appropriate by management, long-term and intermediate financing and equity
issues have been used to refinance short-term debt .
Utility operations are subject to seasonality. The bulk of firm sales and
transportation are made during the months of November through March. As a
result, the highest levels of earnings and cash flow are generated in the
quarters ending in February and May. Most capital expenditures occur during the
months of May through October, causing cash flow to be at its lowest during the
quarters ending in November and August.
Short-term borrowing requirements vary according to the seasonal nature of
sales and expense activities of the Utilities. The need for short-term borrowing
arises when internally generated funds are not sufficient to cover all capital
and operating requirements, particularly in the summer and fall. Short-term
borrowings utilized for construction expenditures generally are replaced by
permanent financing when it becomes economical and practical to do so and where
appropriate to maintain an acceptable relationship between borrowed and equity
resources.
The requirement to inventory supplemental gas supplies and the timing of
inventory acquisitions to meet the peak winter demand of the Utilities
negatively impact the cash flow of the Corporation. Supplemental gas inventories
are filled primarily in the summer period for use during the winter period.
Warmer than normal weather in fiscal 1999 resulted in decreased gas sales
and a negative impact on cash flow. Interest costs and the timing of Federal and
state tax payments also impact liquidity.
The Corporation received a payment from its weather insurance product which
positively impacted cash flow. The weather insurance product was paid to the
Corporation as a result of the weather during the measurement period of November
1998 through March 1999 being 6% warmer than normal, based on degree days.
Cash flow was negatively impacted by the maturity of the $2,138,900, 9%
notes which were due April 1, 1999. The Corporation used short-term borrowings
to retire this debt.
17
Funding requirements are met through short-term borrowings under existing
lines of credit. On August 31, 1999, the Corporation had $24,200,000 of
available borrowings under its lines of credit. These lines are reviewed
annually by the lending banks, and management believes they will be renewed or
replaced. Management believes its available financing is sufficient to meet cash
requirements for the foreseeable future.
A lawsuit has been filed against Valley Gas and other parties by Blackstone
Valley Electric Company ("Blackstone") seeking contribution towards a judgment
against Blackstone's share of total clean-up costs of approximately $6,000,000
at the Mendon Road site in Attleboro, Massachusetts. The expenses relate to a
site to which oxide waste was transported in the 1930's prior to the
incorporation of Valley Gas. Management is of the opinion the Corporation will
prevail as a result of the indemnification provisions included in the agreement
entered into when Valley Gas acquired its utility assets from Blackstone.
Management cannot determine the future cash flow impact, if any, of this claim
and related legal fees. In a recent decision of the U.S. Court of Appeals for
the First Circuit, Blackstone's appeal of the judgment against it was sustained
and the case was remanded for further proceedings, including a referral of the
case to the EPA to determine if the substance in question (FFC) is hazardous.
Valley Gas received letters of responsibility from the Rhode Island
Department of Environmental Management ("DEM") with respect to releases from
coal waste on its properties that were the site of the former Tidewater gas
manufacturing plant in Pawtucket, Rhode Island and the former Hamlet Avenue gas
manufacturing plant in Woonsocket, Rhode Island. Valley Gas and Blackstone have
submitted site investigation reports to DEM relating to certain releases on
these sites. Management cannot determine the future cash flow impact, if any, of
these claims and related expenses. As noted above, management takes the position
that it is indemnified by Blackstone for any such expenses. Management intends
to seek recovery from Blackstone and any insurance carriers deemed to be at risk
during the relevant periods. Remediation of sites such as the former Tidewater
plant and the Hamlet Avenue plant are governed by a regulatory framework which
now permits more flexibility in methods of remediation and in property reuse.
The Corporation's net cash from operating activities in fiscal 1999 was
$8,105,200 versus $7,109,800 in fiscal 1998 and $6,164,800 in fiscal 1997.
Investing activities used cash primarily for capital expenditures in the amounts
of $4,586,000 in fiscal 1999, $4,578,500 in fiscal 1998 and $4,374,200 in fiscal
1997. Financing activities in fiscal 1999 used cash of $3,582,500 primarily for
the payment of dividends and the payment of the 9% notes due in this fiscal
period, offset by increased short-term borrowings. Fiscal 1998 financing
activities used cash of $2,538,200 primarily for the payment of dividends.
Fiscal 1997 financing activities used cash of $1,477,400 which is the result of
proceeds from the Corporation's issuance of common equity and long-term debt
that were used to reduce short-term debt and from the payment of dividends.
Capital expenditures are primarily for the expansion and improvement of the
gas utility plant and for the purchase of rental and propane equipment. In
fiscal 1999, capital expenditures were $4,482,600 compared with $4,533,600 in
fiscal 1998 and $4,293,000 in fiscal 1997. Fiscal 2000 capital expenditures are
estimated to be $8,036,300 and will be primarily for the expansion and
improvement of gas utility property. It is anticipated that such expenditures
will be financed through funds from operations and short-term borrowings.
YEAR 2000 ISSUES
Software applications currently in use by the Corporation are certified to
be Year 2000 compliant by the software vendors from whom the applications were
purchased. The Corporation has modified, replaced or upgraded those applications
which were not Year 2000 compliant and based on its testing of its systems,
management believes its systems are Year 2000 compliant. The Corporation
compiled cost estimates of the effort involved to perform those modifications,
replacements and upgrades and to date Year 2000 related costs have not been
material to the Corporation.
18
The Corporation has inquired of third parties; i. e., vendors, suppliers
and customers, which have a material relationship with the Corporation as to the
status of their Year 2000 readiness. The Corporation continues to work with
critical vendors, suppliers and customers to gain assurance of their readiness
for Year 2000 and has developed contingency plans to mitigate anticipated
shortcomings in their readiness. The Corporation cannot guarantee that the
systems of other companies on which the Corporation's systems rely will be
timely converted, or that a failure to convert by another company, or a
conversion that is incompatible with the Corporation's systems, would not have a
material adverse impact on the Corporation.
The Corporation expects its Year 2000 plan will be adequate to address its
Year 2000 issues and has developed contingency plans to further assure that
vital functions of the Corporation dependent on third parties will continue
uninterrupted. Contingency plans include existence of short-term in house
capabilities (i.e., back up power generation), alternate communications
equipment and increased inventory of critical material and supplies. There can
be no assurance as to whether the contingency plans will successfully address
all contingencies that may arise.
FORWARD LOOKING STATEMENTS; RISK AND UNCERTAINTIES
Statements contained in this report that are not historical facts are
forward-looking statements made pursuant to the safe harbor provisions of the
Private Securities Litigation Reform Act of 1995. In addition, words such as
"believes," "anticipates," "expects" and similar expressions are intended to
identify forward looking statements. Certain factors that could cause the actual
results to differ materially from those projected in these forward-looking
statements include, but are not limited to: variations in weather, changes in
the regulatory environment, customers' preferences on energy sources, general
economic conditions, increased competition and other uncertainties, all of which
are difficult to predict and many of which are beyond the control of the
Corporation.
NEW ACCOUNTING STANDARD
In June of 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. The new standard is effective for
fiscal years beginning after June 15, 2000. Adoption of SFAS No. 133 will not
effect the Corporation's financial condition or results of operations.
Item 7A Quantitative and Qualitative Disclosures About Market Risk
----------------------------------------------------------
Not applicable
19
Item 8 Financial Statements and Supplementary Data
Consolidated Statements of Earnings
For the year ended August 31 1999 1998 1997
- ---------------------------- ---- ---- ----
Operating revenues:
Utility gas revenues ............................... $58,529,386 $59,343,603 $66,230,787
Nonutility revenues ................................ 23,180,791 22,245,293 21,253,190
----------- ----------- -----------
Total .......................................... 81,710,177 81,588,896 87,483,977
----------- ----------- -----------
Operating expenses:
Cost of gas sold ................................... 30,493,570 31,437,159 37,843,842
Cost of sales - nonutility ......................... 15,787,006 15,516,609 14,790,835
Operations ............................................ 17,557,983 17,880,673 17,890,281
Maintenance ........................................ 1,689,664 1,671,829 1,633,671
Depreciation ....................................... 3,397,598 3,274,513 3,143,719
Taxes - other than Federal income ................. 4,116,642 4,119,808 4,242,841
- Federal income ............................ 1,772,370 1,330,045 1,334,677
----------- ----------- -----------
Total .......................................... 74,814,833 75,230,636 80,879,866
----------- ----------- -----------
Operating income ...................................... 6,895,344 6,358,260 6,604,111
Other income - net of tax ............................. 299,205 288,464 423,476
----------- ----------- -----------
Total income before interest .......................... 7,194,549 6,646,724 7,027,587
----------- ----------- -----------
Interest charges:
Long-term debt ..................................... 2,388,817 2,482,840 1,957,052
Other .............................................. 619,123 557,923 1,411,222
----------- ----------- -----------
Total .......................................... 3,007,940 3,040,763 3,368,274
----------- ----------- -----------
Net income available for common stock ................. $ 4,186,609 $ 3,605,961 $ 3,659,313
=========== =========== ===========
Average number of common shares outstanding ........... 4,979,508 4,966,270 4,267,038
Basic and diluted earnings per share .................. $0.84 $0.73 $0.86
The accompanying Notes are an integral part of these statements.
20
Consolidated Statements of Cash Flows
For the year ended August 31 1999 1998 1997
- ---------------------------- ---- ---- ----
Increase (decrease) in cash:
Cash flows from operating activities:
Net income .......................................... $ 4,186,609 $ 3,605,961 $ 3,659,313
Adjustments to reconcile net income to net cash:
Depreciation ...................................... 3,397,598 3,274,513 3,143,719
Provision for uncollectibles ...................... 1,247,842 1,912,813 1,603,597
Deferred Federal income taxes ..................... 274,752 773,217 441,638
Amortization of investment tax credits ............ (47,688) (48,402) (49,090)
Change in assets and liabilities:
Accounts receivable ............................... (1,380,511) (413,842) (2,841,404)
Deferred fuel costs ............................... 911,178 (1,277,658) 1,620,252
Unbilled gas costs ................................ 6,104 1,702 (1,140)
Fuel and other inventories ........................ (140,622) 301,688 (71,908)
Prepayments ....................................... (157,965) (63,281) 119,631
Common stock held for dividend reinvestment plan .. (21,472) 230,552 (220,829)
Prepaid pensions .................................. (1,564,044) (1,728,432) (924,745)
Accounts payable .................................. 1,110,923 (23,435) (944,778)
Security deposits ................................. (9,155) (57,230) (61,952)
Taxes accrued ..................................... 173,400 73,554 171,730
Other ............................................. 118,264 548,114 520,799
----------- ----------- -----------
Total adjustments ................................. 3,918,604 3,503,873 2,505,520
----------- ----------- -----------
Net cash provided by operating activities ........... 8,105,213 7,109,834 6,164,833
----------- ----------- -----------
Cash flows from investing activities:
Utility capital expenditures ........................ (3,841,768) (3,555,028) (3,599,752)
Nonutility capital expenditures ..................... (640,849) (978,538) (693,229)
Other investments ................................... (103,422) (44,924) (81,222)
----------- ----------- -----------
Net cash used by investing activities ............... (4,586,039) (4,578,490) (4,374,203)
----------- ----------- -----------
Cash flows from financing activities:
Dividends paid ...................................... (3,723,724) (3,698,155) (3,130,413)
Common stock transactions ........................... (54,870) 869,155 6,450,861
Issuance of long-term debt, net of issuance cost .... -0- -0- 9,655,515
Issuance of revolving credit arrangement ............ -0- 100,000 100,000
Retirement of long-term debt ........................ (2,303,875) (209,200) (1,553,395)
Increase (decrease) in notes payable ................ 2,500,000 400,000 (13,000,000)
----------- ----------- -----------
Net cash used by financing activities ............... (3,582,469) (2,538,200) (1,477,432)
----------- ----------- -----------
Net (decrease) increase in cash ........................ (63,295) (6,856) 313,198
Cash, beginning ........................................ 813,155 820,011 506,813
----------- ----------- -----------
Cash, ending ........................................... $ 749,860 $ 813,155 $ 820,011
----------- ----------- -----------
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest .......................................... $ 2,932,870 $ 2,788,390 $ 3,378,894
=========== =========== ===========
Federal income taxes .............................. $ 1,341,309 $ 500,000 $ 861,140
=========== =========== ===========
Supplemental disclosures of noncash activity:
Capital lease obligations incurred .................. $ 30,297 $ 832,026 $ 388,139
=========== =========== ===========
The accompanying Notes are an integral part of these statements.
21
Consolidated Balance Sheets
August 31 1999 1998
- --------- ---- ----
Assets:
Utility plant, at cost ................................................. $ 86,445,703 $82,964,897
Less: Accumulated provision for depreciation .......................... 34,111,279 31,655,080
------------ -----------
Net utility plant ...................................................... 52,334,424 51,309,817
------------ -----------
Leased property-less accumulated amortization of $4,604,837
and $4,007,748 ...................................................... 1,555,855 2,302,601
------------ -----------
Nonutility property-less accumulated provision for depreciation of
$4,510,553 and $4,315,566 ........................................... 4,162,601 4,106,232
------------ -----------
Other investments ...................................................... 1,740,028 1,636,606
------------ -----------
Current assets:
Cash ............................................................... 749,860 813,155
Accounts receivable-less allowance for uncollectibles of $1,309,410 .
and $928,279 ...................................................... 9,816,986 9,684,317
Deferred fuel costs ................................................. -0- 484,418
Deferred unbilled gas costs ......................................... 432,228 438,332
Fuel and other inventories .......................................... 5,959,289 5,818,667
Prepayments ......................................................... 1,510,917 1,352,952
Common stock held for dividend reinvestment plan .................... 142,568 121,096
------------ -----------
Total current assets ............................................. 18,611,848 18,712,937
------------ -----------
Deferred debits:
Recoverable postretirement benefit .................................. -0- 230,974
Recoverable vacations accrued ....................................... 610,798 632,966
Recoverable deferred Federal income taxes ........................... 6,062,414 6,108,997
Recoverable transition obligation ................................... 10,700 21,300
Unamortized debt discount and expense ............................... 1,643,382 1,711,815
Prepaid pensions .................................................... 10,388,058 8,824,014
Other ............................................................... 3,102,418 2,882,349
------------ -----------
Total deferred debits ........................................... 21,817,770 20,412,415
------------ -----------
Total assets .................................................... $100,222,526 $98,480,608
============ ===========
The accompanying Notes are an integral part of these statements.
22
Consolidated Balance Sheets
August 31 1999 1998
- --------- ---- ----
Capitalization and liabilities:
Capitalization ....................................................... $ 65,278,234 $64,860,725
------------ -----------
Revolving credit arrangement ......................................... 2,400,000 2,400,000
------------ -----------
Obligations under capital leases ..................................... 775,132 1,527,655
------------ -----------
Current liabilities:
Current maturities of long-term debt .............................. 150,000 2,288,937
Obligations under capital leases .................................. 780,723 774,946
Notes payable .................................................... 4,800,000 2,300,000
Accounts payable .................................................. 5,385,917 4,274,994
Security deposits ................................................. 968,410 977,565
Taxes accrued ..................................................... 608,709 435,309
Deferred fuel costs................................................ 426,760 -0-
Accrued interest .................................................. 760,848 793,732
Other ............................................................. 716,594 740,971
------------ -----------
Total current liabilities ..................................... 14,597,961 12,586,454
------------ -----------
Commitments and contingencies
Deferred credits:
Unamortized investment tax credit ................................. 578,508 626,196
Transition obligation ............................................. 10,700 21,300
Unfunded deferred Federal income taxes ............................ 1,802,439 1,849,022
Postretirement benefit obligation ................................. -0- 230,974
Other ............................................................. 1,911,733 1,785,230
------------ -----------
Total deferred credits ........................................ 4,303,380 4,512,722
------------ -----------
Deferred Federal income taxes ........................................ 12,867,819 12,593,052
------------ -----------
Total liabilities ............................................. 34,944,292 33,619,883
------------ -----------
Total capitalization and liabilities .......................... $100,222,526 $98,480,608
============ ===========
The accompanying Notes are an integral part of these statements.
23
Consolidated Statements of Changes in Common Stock Equity
Common Shares Issued Paid in Retained
and Outstanding Capital Earnings
--------------- ------- --------
Number Amount
------ ------
Balance, August 31, 1996 .............. 4,280,028 $4,280,028 $18,204,063 $ 7,750,406
--------- ---------- ----------- -----------
Add (deduct):
Net income ......................... 3,659,313
Cash dividends on common stock ..... (3,130,413)
Issuance of common stock ........... 620,000 620,000 5,893,100
Other .............................. (62,239)
--------- ---------- ----------- -----------
Balance, August 31, 1997 .............. 4,900,028 4,900,028 24,034,924 8,279,306
--------- ---------- ----------- -----------
Add (deduct):
Net income ......................... 3,605,961
Cash dividends on common stock ..... (3,698,155)
Issuance of common stock ........... 93,000 93,000 795,296
Other .............................. (19,141)
--------- ---------- ----------- -----------
Balance, August 31, 1998 .............. 4,993,028 4,993,028 24,811,079 8,187,112
--- ---- --------- ---------- ----------- -----------
Add (deduct):
Net income ......................... 4,186,609
Cash dividends on common stock ..... (3,723,724)
Other .............................. (54,870)
--------- ---------- ----------- -----------
Balance, August 31, 1999 .............. 4,993,028 $4,993,028 $24,756,209 $ 8,649,997
========= ========== =========== ===========
The accompanying Notes are an integral part of these statements.
Consolidated Statements of Capitalization
August 31 1999 1998
- --------- ---- ----
Common stock equity:
Common stock, $1 par value
Authorized 20,000,000 shares
Issued and outstanding 4,993,028 shares ................... $ 4,993,028 $ 4,993,028
Paid in capital ............................................. 24,756,209 24,811,079
Retained earnings............................................ 8,649,997 8,187,112
----------- -----------
38,399,234 37,991,219
Less: Accounts receivable from Valley Resources, Inc. 401(k)
Employee Stock Ownership Plan ............................. 2,593,911 2,768,343
----------- -----------
Total common stock equity .......................... 35,805,323 35,222,876
----------- -----------
Long-term debt:
8% First Mortgage Bonds, due 2022 ........................... 20,029,000 20,039,000
7.7% Debentures, due 2027 ................................... 7,000,000 7,000,000
9% Notes Payable, due 1999 .................................. -0- 2,138,937
Note payable, due 2007 ...................................... 2,593,911 2,748,849
----------- -----------
Total .............................................. 29,622,911 31,926,786
Less: Current maturities .................................... 150,000 2,288,937
----------- -----------
Total long-term debt ............................... 29,472,911 29,637,849
----------- -----------
Total capitalization ............................... $65,278,234 $64,860,725
=========== ===========
The accompanying Notes are an integral part of these statements.
24
Notes to Consolidated Financial Statements
Note A: Summary of Significant Accounting Policies
CONSOLIDATION - The consolidated financial statements include the accounts of
Valley Resources, Inc. and its active wholly-owned subsidiaries (the
"Corporation")--Valley Gas Company ("Valley Gas"), Valley Appliance and
Merchandising Company ("VAMCO"), Valley Propane, Inc. ("Valley Propane"), Morris
Merchants, Inc. ("Morris Merchants") (d/b/a the Walter F. Morris Company), and
Bristol & Warren Gas Company ("Bristol & Warren"). The consolidated financial
statements also include the Corporation's 80% interest in Alternate Energy
Corporation ("AEC"). All significant intercompany transactions have been
eliminated where required.
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.
REGULATION - The utility operations of Valley Gas and Bristol & Warren
(collectively the "Utilities") are subject to regulation by the Rhode Island
Public Utilities Commission ("RIPUC"). Accounting policies conform with
generally accepted accounting principles, as applied in the case of regulated
public utilities, and are in accordance with the accounting requirements and
rate making practices of the RIPUC.
DEPRECIATION - Annual provisions for depreciation for the Utilities are
determined on a composite straight-line basis. The composite rate for fiscal
1999, 1998 and 1997 was 2.91%. Depreciation provisions for other subsidiary
companies are provided on the straight-line and accelerated methods at rates
ranging from 2.86% to 34%.
OTHER ASSETS - Included in other assets is goodwill which is amortized on the
straight-line basis over forty years. The Corporation continually evaluates the
carrying value of goodwill. Any impairments would be recognized when the
expected undiscounted future operating cash flows derived from goodwill is less
than the carrying value.
UNAMORTIZED DEBT EXPENSE - Costs incurred to obtain debt financing are amortized
over the expected term of the related debt. Amortization of deferred financing
costs is recorded as interest expense.
DEFERRED FUEL COSTS - The Utilities' tariffs include a Purchased Gas Price
Adjustment ("PGPA") which allows an adjustment of rates charged to customers in
order to recover all changes in gas costs from stipulated base gas costs. The
PGPA provides for an annual reconciliation of total gas costs billed with the
actual cost of gas incurred. Any excess or deficiency in amounts collected as
compared to costs incurred is deferred and either reduces the PGPA or is billed
to customers over subsequent periods.
DEFERRED UNBILLED GAS COSTS - Revenue is recorded on the basis of bills rendered
on a cycle basis throughout the month. Valley Gas defers to the following month
that portion of the base cost of gas delivered but not yet billed under the
cycle billing system.
ACCOUNTING FOR INCOME TAXES - Income tax regulations allow recognition of
certain transactions for tax purposes in time periods other than the period
during which these transactions will be recognized in the determination of net
income for financial reporting purposes. As required by generally accepted
accounting principles, deferred income taxes are provided to reflect the tax
effect of these timing differences in the proper accounting periods.
In accordance with Financial Accounting Standards Board Statement No. 109
"Accounting for Income Taxes," deferred income taxes are recorded for all book
and tax temporary timing differences.
25
Investment tax credits relating to the Utilities property have been
deferred and will be amortized to income over the productive lives of the
related assets. Investment tax credits earned by the Corporation's other
subsidiary companies were recognized as a reduction of Federal income tax
expense in the year utilized.
PENSION PLANS - The Utilities maintain two non-contributory defined benefit
pension plans covering substantially all of their employees which provide
benefits based on compensation and years of service. The Utilities fund pension
costs that are deductible for Federal income tax purposes (see Note H).
On January 1, 1997, the Valley Gas Company 401(k) plan and the Valley Gas
Employee Stock Ownership Plan ("ESOP") were merged into the Valley Resources
401(k) Employee Stock Ownership Plan ("KSOP"). The KSOP covers all Corporate
employees, if eligible (see Note D). The expense of these plans in fiscal 1999,
1998 and 1997 was $173,300, $144,000, and $160,800, respectively.
Morris Merchants maintains an employee profit sharing plan covering
substantially all of the employees who have completed one year of service.
Contributions to the plan are at the discretion of the Board of Directors. In
fiscal 1999, 1998, and 1997, profit sharing expense was $53,500, $72,000, and
$64,600, respectively.
NEW ACCOUNTING STANDARDS - In June 1998, the FASB issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. The new
standard is effective for fiscal years beginning after June 15, 2000. Adoption
of SFAS No. 133 will not affect the Corporation's financial condition or results
of operations.
INVENTORIES - Fuel and other inventories at August 31 are as follows:
1999 1998
---- ----
Fuels (at average cost) ........................ $3,462,277 $3,542,932
Merchandise and other (at average cost) ........ 1,234,326 1,241,224
Merchandise (at LIFO) .......................... 1,262,686 1,034,511
---------- ----------
$5,959,289 $5,818,667
========== ==========
Merchandise (at LIFO), if valued at current cost, would have been greater by
$205,000 in fiscal 1999 and $246,300 in fiscal 1998.
Note B: Common Stock and Rights
On August 26, 1997, the Corporation issued 620,000 shares of common stock.
The net proceeds of this offering were used to reduce the short-term debt of the
Utilities, to make loans to nonutility subsidiaries, to repay short-term debt
and for working capital requirements. On September 24, 1997, the underwriters of
the stock offering exercised their over-allotment option and 93,000 additional
common shares were issued.
Pursuant to the Corporation's direct stock purchase plan, stockholders can
reinvest dividends and make limited additional cash investments. Shares issued
through dividend reinvestment can be acquired on the open market or original
issue. All shares issued pursuant to the plan in fiscal 1999 and 1998 were
open-market purchases. On August 31, 1999 and 1998, 10,019 and 10,116 shares,
respectively, were held by the Corporation for issuance to the plan.
26
On August 31, 1999, except as mentioned above, no shares of common stock of
the Corporation were held by or for the account of the Corporation or were
reserved for officers or employees or for options, warrants or other rights,
except 41,125, shares of common stock reserved subject to sale under the
Corporation's direct stock purchase plan.
Each share of common stock of the Corporation includes one preferred stock
purchase Right which entitles the holder to purchase one one-hundredth of a
share of Cumulative Participating Junior Preferred Stock, par value $100, at a
price of $35 per one one-hundredth of a share subject to adjustment. The Rights
are not currently exercisable, and trade automatically with the common stock.
The Rights will generally become exercisable, and separate certificates
representing the Rights will be distributed, upon occurrence of certain events
in excess of a stipulated percentage of ownership.
The Rights should not interfere with any merger or business combination
approved by the Board of Directors because, prior to the Rights becoming
exercisable, the Rights may be redeemed by the Corporation at $0.01 per Right.
The Rights have no dilutive effect and will not affect reported earnings per
share.
Note C: Short-Term Debt
The Corporation borrows on bank lines of credit at the prevailing interest
rate available at the time of borrowing. The Corporation either pays commitment
fees or maintains compensating balances in connection with these lines of
credit. Commitment fees paid in fiscal 1999, 1998, and 1997 amounted to
$105,900, $106,800 and $110,000, respectively. There are no legal restrictions
on withdrawal of compensating balances.
A detail of short-term borrowings for fiscal 1999, 1998, and 1997 is as
follows:
1999 1998 1997
---- ---- ----
At year end
Weighted average interest rate ..... 5.4% 5.7% 5.7%
Unused lines of credit ............. $24,200,000 $34,700,000 $35,100,000
For the year ended
Weighted average interest rate ..... 5.5% 5.8% 5.7%
Average borrowings ................. $ 4,162,500 $ 2,433,300 $16,800,000
Maximum month-end borrowings ....... $ 7,400,000 $ 6,200,000 $22,000,000
Month of maximum borrowings ........ December December January
Note D: Long-Term Debt
The composition of long-term debt is included in these financial statements
in the separate Consolidated Statements of Capitalization. The aggregate amount
of maturities and sinking fund requirements for each of the five fiscal years
following fiscal 1999 are: 2000, $930,700; 2001, $2,904,800; 2002, $383,400;
2003, $224,600 and 2004, $212,600, inclusive of capitalized lease obligations.
Valley Gas utility plant and equipment have been pledged as collateral to
secure its long-term debt. In accordance with the redemption provisions of the
Valley Gas 8% First Mortgage Bonds, $10,000, $51,000, and $122,000 of the bonds
were redeemed by holders in fiscal 1999, 1998, and 1997, respectively.
The fair market value of the Corporation's long-term debt is estimated
based on the quoted market prices for the same or similar issues or on the
current rates offered to the Corporation for debt of the same remaining
maturities. Management believes the carrying value of the debt approximates the
fair value at August 31, 1999.
Regulatory treatment allows payments under capital leases to be recorded as
rental expenses. Rental expenses for all leases in fiscal 1999, 1998, and 1997
were $1,028,700, $1,218,600, and $1,169,500, respectively.
Valley Gas entered into an intermediate term financing arrangement with a
bank in November 1995. The terms of the arrangement call for a $6,000,000
revolving line of credit which matures in 2000.
27
The Corporation borrowed funds under a line of credit at rates less than
the prevailing prime rate, which are restricted in their use to being loaned to
the KSOP. The receivable from the KSOP has been shown as a reduction of common
stock equity. The financing by the KSOP is secured by the common stock of two
unregulated subsidiaries and the unallocated shares held by the KSOP.
The Corporation's common stock purchased by the KSOP with the borrowed
money is held by the KSOP trustee in a "suspense account." As the Corporation
matches employee 401(k) contributions and makes discretionary contributions to
the plan, a portion of the common stock is released from the suspense account
and allocated to participating employees. Any dividends on unallocated shares
are used to pay loan interest.
Note E: Restriction on Retained Earnings
On August 31, 1999, $1,751,400 of the retained earnings of Valley Gas were
available for the payment of cash dividends to the Corporation under the most
restrictive provisions of Valley Gas' first mortgage bonds. There are no
restrictions as to the payment of dividends for the other subsidiaries.
Note F: Income Taxes
In accordance with Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" ("SFAS 109"), the Corporation's financial
statements are required, among other things, to record the cumulative deferred
income taxes on all temporary timing differences. As approved by the RIPUC, the
Utilities did not fully record deferred income taxes but, rather, "flowed
through" certain tax benefits to utility customers prior to fiscal 1994. On
August 31, 1999, the Corporation has a liability of $6,062,400 on the
Consolidated Balance Sheets as recoverable deferred income taxes and a
corresponding recoverable deferred charge. The liability represents the tax
effect of timing differences for which deferred income taxes had not been
provided, increased in accordance with SFAS 109 for the tax effect of future
revenue requirements. The Utilities are recovering unfunded deferred taxes from
utility customers over the remaining book life of utility property.
Federal income tax expense has been calculated based on filing a
consolidated corporate tax return and is comprised of the following:
1999 1998 1997
---- ---- ----
Current income tax expense:
Operating expense ................................... $1,497,618 $ 556,828 $ 893,039
Nonoperating expense................................. (4,279) 57,482 103,200
---------- ---------- ----------
1,493,339 614,310 996,239
---------- ---------- ----------
Deferred income tax expense:
Accelerated depreciation............................. 303,332 316,197 332,771
Pensions............................................. 531,775 587,667 314,413
Deferred fuel costs.................................. (111,946) 99,941 (229,039)
Uncollectibles....................................... (126,488) (36,985) (23,830)
Directors' fees and interest......................... (47,438) (42,525) (36,845)
Bond premium ........................................ (6,240) (6,240) (6,240)
Rate case expenses................................... (11,926) (61,308) (97,257)
Capitalization of inventory costs.................... (8,748) 1,155 28,869
Consulting contracts................................. (19,920) (19,920) 30,570
Software amortization................................ (140,332) (86,136) 140,856
Alternative minimum tax.............................. -0- 96,359 -0-
Excess VEBA contribution............................. (78,532) (78,532) (78,532)
Other ............................................... (8,785) 3,544 65,902
---------- ---------- ----------
274,752 773,217 441,638
---------- ---------- ----------
Total ............................................... $1,768,091 $1,387,527 $1,437,877
========== ========== ==========
28
The Federal income tax amounts included in the Consolidated Statements of
Earnings differ from the amounts which result from applying the statutory
Federal income tax rate to income from operations before income tax. The
reasons, with related percentage effects, are shown below:
1999 1998 1997
---- ---- ----
Statutory Federal rate ......................................... 34% 34% 34%
Maintenance costs capitalized for book purposes ............. (4) (4) (4)
Cost of removal ............................................. (1) (1) (1)
ESOP dividends .............................................. (1) (1) (1)
Prior year over accrual ..................................... -0- (2) -0-
Other ....................................................... 2 2 -0-
-- -- --
Total ....................................................... 30% 28% 28%
== == ==
Temporary differences which gave rise to the following deferred tax assets
and liabilities at August 31, 1999 and 1998 are:
1999 1998
---- ----
Unbilled revenues .................... $ 262,737 $ 266,652
Directors' fees and interest ......... 342,285 294,847
Other ................................ 793,234 568,055
------------ ------------
Total deferred tax assets ......... 1,398,256 1,129,554
------------ ------------
Accelerated depreciation ............. (9,499,234) (9,195,902)
Pensions ............................. (3,550,626) (3,018,851)
Software amortization ................ (450,450) (590,782)
Deferred fuel costs .................. (52,757) (164,703)
Other ................................ (713,008) (752,368)
------------ ------------
Total deferred tax liabilities .... (14,266,075) (13,722,606)
------------ ------------
Total deferred taxes ................. $(12,867,819) $(12,593,052)
============ ============
The Corporation's nonutility operations are subject to state income taxes.
For fiscal 1999, 1998, and 1997, state income taxes totaled $93,800, $124,100,
and $170,700, respectively.
Note G: Regulatory Matter
On June 1, 1997, the Utilities received approval to redesign their rates
and offer transportation services to large commercial and industrial customers.
Note H: Commitments and Contingencies
PENSION PLANS - The Utilities have two non-contributory defined benefit pension
plans covering substantially all of their employees and a supplemental pension
plan covering certain officers.
Net periodic pension cost (income) is comprised of the following
components:
For the Year Ended August 31, 1999 1998 1997
- ----------------------------- ---- ---- ----
Service cost ..................................... $ 704,892 $ 640,994 $ 543,241
Interest cost on projected benefit obligation .... 1,448,757 1,360,031 1,337,602
Expected return on plan assets ................... (3,373,477) (3,245,272) (2,579,914)
Recognition of actuarial gain .................... (280,738) (400,878) (142,367)
Net amortization and deferral .................... (63,478) (83,307) (83,307)
----------- ----------- -----------
Net periodic pension income ...................... $(1,564,044) $(1,728,432) $ (924,745)
=========== =========== ===========
29
Assumptions used in actuarial calculations were as follows:
For the Year Ended August 31, 1999 1998 1997
- ----------------------------- ---- ---- ----
Weighted average discount rate .................. 7.00% 7.00% 7.25%
Future compensation increases ................... 5.50 5.50 5.50
Expected long-term rate of return on assets ..... 9.00 9.00 9.00
The following tables set forth the reconciliation of the plans' benefit
obligation and fair value of assets is as follows:
For the Year Ended August 31, 1999 1998
- ----------------------------- ---- ----
Reconciliation of benefit obligation:
Obligation at September 1....................... $21,240,659 $19,266,157
Service cost.................................... 704,892 640,994
Interest cost................................... 1,448,757 1,360,031
Amendments...................................... -0- 297,429
Actuarial (gain) loss........................... (598,721) 716,918
Benefit payments................................ (1,118,340) (1,040,870)
----------- -----------
Obligation at August 31......................... $21,677,247 $21,240,659
=========== ===========
Reconciliation of fair value of plan assets:
Fair value of plan assets at September 1........ $38,027,205 $36,565,680
Actual return on plan assets ................... 3,327,389 2,502,395
Benefit payments................................ (1,118,340) (1,040,870)
----------- -----------
Fair value of plan assets at August 31.......... $40,236,254 $38,027,205
=========== ===========
The funded status of the plans is as follows:
August 31, 1999 1998
- ---------- ---- ----
Plan assets at fair value:
Projected benefit obligation less than (in excess of) plan assets......... $20,401,395 $18,802,795
Unrecognized net gain..................................................... (10,609,146) (10,511,112)
Unrecognized transition amount............................................ (381,660) (529,184)
Unrecognized prior service cost .......................................... 977,469 1,061,515
----------- -----------
Prepaid pension costs .................................................... $10,388,058 $ 8,824,014
=========== ===========
Assets of the employee benefit plans are invested in domestic and international
equities, domestic and international fixed income securities and other
short-term debt instruments.
POSTRETIREMENT LIFE AND HEALTH BENEFIT PLAN - Valley Gas sponsors a
postretirement benefit plan that covers substantially all of its employees
except for nonunion employees hired on or after September 1, 1993 and union
employees hired on or after April 1, 1994. The plan provides medical, dental and
life insurance benefits. The plan is non-contributory.
In accordance with Statement of Financial Accounting Standards No. 106
"Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS
106"), Valley Gas records the cost for this plan on an accrual basis. As
permitted by SFAS 106, Valley Gas will record the transition obligation over 20
years. Valley Gas' cost under this plan for fiscal 1999, 1998 and 1997 was
$701,000, $725,000, and $775,600, respectively.
30
The regulatory asset represents the excess of postretirement benefits on the
accrual basis over amounts authorized to be recovered in rates. The RIPUC
authorized Valley Gas a phase-in recovery of the tax deductible portion of these
postretirement benefits, if funded.
The following table sets forth the reconciliation of the plans' benefit
obligation and fair value of plan assets is as follows:
For the year ended August 31, 1999 1998
- ---------------------------- ---- ----
Reconciliation of benefit obligation:
Obligation at September 1................................... $6,523,627 $6,057,989
Service cost................................................ 144,363 147,852
Interest cost............................................... 443,516 426,588
Actuarial loss.............................................. 418,504 184,606
Benefit payments............................................ (311,095) (293,408)
---------- ----------
Obligation at August 31..................................... $7,218,915 $6,523,627
========== ==========
Reconciliation of fair value of plan assets:
Fair value of plan assets at September 1.................... $2,351,191 $1,699,662
Actual return on plan assets................................ 97,620 (40,980)
Employer contributions...................................... 1,242,884 985,917
Benefit payments............................................ (311,095) (293,408)
---------- ----------
Fair value of plan assets at August 31...................... $3,380,600 $2,351,191
========== ==========
The following table sets forth the plan's funded status reconciled with the
amounts recognized in the Company's financial statements is as follows:
For the year ended August 31, 1999 1998
- ---------------------------- ---- ----
Accumulated postretirement benefit obligation in excess of plan assets..... $(3,838,315) $(4,172,436)
Unrecognized net loss (gain) from past experience different from that
assumed and from changes in assumptions ................................ 208,257 (277,466)
Unrecognized transition obligation......................................... 3,888,824 4,166,598
----------- -----------
Prepaid (accrued) postretirement benefit cost.............................. $ 258,766 $ (283,304)
=========== ===========
Net periodic postretirement benefit cost consisted of the following:
For the Year Ended August 31, 1999 1998 1997
- ----------------------------- ---- ---- ----
Service cost - benefits attributable to service during the period....... $ 144,363 $ 147,852 $ 136,372
Interest cost on accumulated postretirement benefit obligation.......... 443,516 426,588 419,246
Expected return on plan assets.......................................... (147,746) (105,934) (55,569)
Net amortization and deferral........................................... 277,774 277,774 277,774
Recognition of net actuarial gain....................................... (17,093) (21,232) (23,414)
--------- --------- ---------
Net periodic postretirement benefit cost................................ $ 700,814 $ 725,048 $ 754,409
========= ========= =========
For measurement purposes, a 9% (4.5% for dental costs) annual rate of increase
in the per capita cost of covered health care benefits was assumed for 1999; the
rate of increase for medical costs was assumed to decrease gradually to 5% by
fiscal 2002 and to remain at that level thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported. To illustrate,
increasing the assumed health care cost trend rates by one percentage point in
each year would increase the accumulated postretirement benefit obligation at
August 31, 1999 by $534,000 and the aggregate of the service and the interest
cost components of net periodic postretirement benefit cost for the year then
ended by $54,000. The weighted average discount rate used in determining the
30
accumulated postretirement benefit obligation was 7.0%, 7.0% and 7.25% for
fiscal 1999, 1998 and 1997, respectively. The expected long-term rate of return
on plan assets was 8.50% for fiscal 1999, 1998 and 1997, respectively.
LONG-TERM OBLIGATIONS - The Utilities have contracts which expire at various
dates through the year 2012 for the purchase, delivery and storage of natural
gas and supplemental gas supplies. Certain contracts for the purchase of the
supplemental gas supplies contain minimum purchase obligations which approximate
2% of total system requirements.
FERC ORDER NO. 636 TRANSITION COSTS - As a result of FERC Order 636, the
Utilities' interstate pipeline service providers have unbundled their supply,
storage and transportation services. This unbundling caused the interstate
pipeline companies to incur substantial costs in order to comply with Order 636.
These transition costs include four types: (1) unrecovered gas costs (gas costs
that have been incurred but not yet recovered by the pipelines when they were
providing bundled service to local distribution companies); (2) gas supply
realignment costs (the cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that cannot be
assigned to customers of unbundled services); and (4) new facilities costs
(costs of new facilities required to physically implement Order 636).
Pipelines are expected to be allowed to recover prudently incurred
transition costs from customers primarily through a demand charge, after
approval by FERC. The Utilities' pipeline suppliers began direct billing these
costs in fiscal 1994 as a component of demand charges. The Utilities estimate
their remaining portion of transition costs to be $10,700 and have recognized a
liability for these costs as of August 31, 1999. The RIPUC has allowed the
recovery of transition costs through the PGPA. Under the provisions of SFAS 71,
regulatory assets totaling $10,700 were recorded for the expected future
recovery of the transition obligations. Actual transition costs to be incurred
depend on various factors, and, therefore, future costs may differ from the
amounts discussed above.
CONTINGENT LIABILITIES - A lawsuit has been filed against Valley Gas and other
parties by Blackstone Valley Electric Company ("Blackstone") seeking
contribution towards a judgment against Blackstone's share of total cleanup
costs of approximately $6,000,000 at the Mendon Road site in Attleboro,
Massachusetts. The expenses relate to a site to which oxide waste was
transported in the 1930's prior to the incorporation of Valley Gas. Management
is of the opinion the Corporation will prevail as a result of the
indemnification provisions included in the agreement entered into when Valley
Gas acquired the utility assets from Blackstone. Management cannot determine the
future cash flow impact, if any, of this claim and related legal fees. Legal
fees associated with this claim are recovered in rates. In a recent decision of
the U.S. Court of Appeals for the First Circuit, Blackstone's appeal of the
judgment against it was sustained and the case was remanded for further
proceedings, including a referral of the case to the EPA to determine if the
substance in question (FFC) is hazardous.
Valley Gas received letters of responsibility from the Rhode Island
Department of Environmental Management ("DEM") with respect to releases from
coal waste on its properties that were the site of the former Tidewater gas
manufacturing plant in Pawtucket, Rhode Island and the former Hamlet Avenue gas
manufacturing plant in Woonsocket, Rhode Island. Valley Gas and Blackstone have
submitted site investigation reports to DEM relating to certain releases on
these sites. Management cannot determine the future cash flow impact, if any, of
these claims and related expenses. As noted above, management takes the position
that it is indemnified by Blackstone for any such expenses. Management intends
to seek recovery from Blackstone and any insurance carriers deemed to be at risk
during the relevant periods. Remediation of sites such as the former Tidewater
plant and the Hamlet Avenue plant are governed by a regulatory framework which
now permits more flexibility in methods of remediation and in property reuse.
Note I: Segment Information
The Corporation adopted SFAS 131, "Disclosure about Segments of an
Enterprise and Related Information," during fiscal 1999. SFAS 131 established
standards for reporting information about operating segments ("business
segments") in annual financial statements and requires selected information in
interim financial statements. Business segments are defined as components of an
enterprise about which separate financial information is available that is
evaluated regularly by the chief operating decision maker, or decision making
group, to make
32
decisions on how to allocate resources and to assess performance. The
Corporation's chief operating decision making group is the Chief Executive
Officer ("CEO") and certain other executive officers that report directly to the
CEO. The operating segments are organized and managed separately because each
segment offers different products or services. The Corporation evaluates the
performance of its business segments based on the operating income generated.
Operating income does not include income taxes, interest expense, extraordinary
charges, and non-operating income and expense items.
Under SFAS 131, an operating segment that does not exceed certain
quantitative levels is not considered a reportable segment. Instead, the results
of all segments that do not exceed the quantitative thresholds are combined and
reported as one segment and referred to as "all other." The Corporation's
subsidiaries VAMCO, Valley Propane and AEC business segments did not meet these
quantitative threshholds and have been grouped into the "all other" category.
The accounting policies of the operating segments are the same as those
described in Note A except the intercompany transactions have not been
eliminated in determining individual segment results.
The following information is presented relative to the gas, contract sales
and other operations of the Corporation.
1999 1998 1997
---- ---- ----
Gas Operations
Operating revenues........................................... $ 58,529,386 $59,343,603 $66,230,787
Operating income before Federal income taxes................. 6,991,106 6,178,629 6,465,007
Identifiable assets at August 31............................. 95,121,383 89,713,540 88,927,776
Depreciation................................................. 2,817,161 2,692,326 2,594,712
Capital expenditures......................................... 3,841,768 3,555,028 3,599,752
Contract Sales
Operating revenues........................................... $ 15,291,428 $15,104,272 $14,243,778
Operating income before Federal income taxes................. 549,041 646,303 612,744
Identifiable assets at August 31............................. 3,959,667 3,993,215 3,749,762
Depreciation................................................. 44,866 45,703 51,704
Capital expenditures......................................... 9,255 30,704 21,703
All Other Operations, including Corporate & Eliminations
Operating revenues........................................... $ 7,889,363 $ 7,141,021 $ 7,009,412
Operating income before Federal income taxes................. 1,127,567 863,373 861,037
Identifiable assets at August 31............................. 1,141,476 4,773,853 5,019,599
Depreciation................................................. 535,571 536,484 497,303
Capital expenditures......................................... 631,594 947,834 671,526
Total Corporation
Operating revenues........................................... $ 81,710,177 $81,588,896 $87,483,977
Operating income before Federal income taxes................. 8,667,714 7,688,305 7,938,788
Federal income tax expense................................... (1,772,370) (1,330,045) (1,334,677)
Nonoperating income-net...................................... 299,205 288,464 423,476
Interest expense............................................. (3,007,940) (3,040,763) (3,368,274)
Net income................................................... 4,186,609 3,605,961 3,659,313
Identifiable assets at August 31............................. 100,222,526 98,480,608 97,697,137
Depreciation................................................. 3,397,598 3,274,513 3,143,719
Capital expenditures......................................... 4,482,617 4,533,566 4,292,981
33
Expenses used to determine operating income before Federal income taxes are
charged directly to each segment or are allocated based on time studies. Assets
allocated to each segment are based on specific identification of such assets as
provided by corporate records.
Segment Information at August 31, 1998 and 1997 has been restated to
conform with the presentation of SFAS 131 at August 31, 1999.
Note J: Summarized Quarterly Financial Data (Unaudited)
Three months ended
(in thousands, except as to basic and
diluted earnings (loss) per share) November February May August
- ---------------------------------- -------- -------- --- ------
Fiscal 1999
Total operating revenues............................ $15,270 $29,201 $23,581 $13,658
Income (loss) before Federal income taxes........... $(1,091) $ 5,057 $ 3,228 $(1,287)
Net income (loss)................................... $ (637) $ 3,292 $ 2,320 $ (789)
Basic and diluted earnings (loss) per share.......... $ (0.13) $ 0.66 $ 0.47 $ (0.16)
Fiscal 1998
Total operating revenues............................ $15,824 $30,428 $22,587 $12,750
Income (loss) before Federal income taxes........... $(1,288) $ 4,818 $ 2,692 $(1,229)
Net income (loss)................................... $ (761) $ 3,232 $ 1,828 $ (693)
Basic and diluted earnings (loss) per share......... $ (0.15) $ 0.65 $ 0.37 $ (0.14)
34
Report of Independent Certified Public Accountants
To the Stockholders of Valley Resources, Inc.
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Valley Resources, Inc. (a Rhode
Island corporation) and subsidiaries as of August 31, 1999 and 1998 and the
related consolidated statements of earnings, cash flows and changes in common
stock equity for each of the three years in the period ended August 31, 1999.
These consolidated financial statements are the responsibility of the
Corporation's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
consolidated financial presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Valley Resources, Inc. and subsidiaries as of August 31, 1999 and 1998 and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended August 31, 1999, in conformity with generally
accepted accounting principles.
s/Grant Thornton LLP
Boston, Massachusetts
September 27, 1999
35
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
---------------------------------------------
None.
PART III
Item 10 Directors and Executive Officers of the Registrant
--------------------------------------------------
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.
Information regarding the directors of the registrant appearing on pages 2
through 5 of the Proxy Statement filed with the Securities and Exchange
Commission on November 9, 1999 is incorporated herein by reference.
Section 16 (a) Beneficial Ownership Reporting Compliance
-----------------------------------------
Section 16(a) of the Securities Exchange Act of 1934 requires the
Corporation's executive officers and directors and persons who own more than 10%
of a registered class of the Corporation's equity securities ("insiders") to
file reports of ownership and changes in ownership with the Securities and
Exchange Commission ("SEC"). Insiders are required by SEC regulation to furnish
the Corporation with copies of all Section 16(a) forms they file. Based solely
on review of the copies of such forms furnished to the Corporation, the Form 4
for the month of May 1999 for Alfred P. Degen was filed one date late for the
purchase of 1,000 shares of Common Stock. Due to a clerical error, dividend
reinvestment plan acquisitions on Form 5 for Messrs. DeAngelis, Farnum, Davison
and Guthrie were filed 16 days late.
Item 11 Executive Compensation
----------------------
Information regarding management compensation appearing on pages 6 through
9 of the Proxy Statement filed with the Securities and Exchange Commission on
November 9, 1999 is incorporated herein by reference.
Item 12 Security Ownership of Certain
Beneficial Owners and Management
--------------------------------
Information regarding the beneficial owners of more than 5 percent of the
outstanding common stock of the Corporation, the only class of equity security
issued and outstanding, and the security ownership of management appearing on
pages 1 and 2 of the Proxy Statement filed with the Securities and Exchange
Commission on November 9, 1999 is incorporated herein by reference.
36
Item 13 Certain Relationships and Related Transactions
----------------------------------------------
None.
37
PART IV
Item 14 Exhibits, Financial Statement
Schedules and Reports on Form 8-K
---------------------------------
(a) 1. The following consolidated financial statements of Valley Resources,
Inc. and subsidiaries appearing for the year ended August 31, 1999 are
included in Item 8:
Consolidated Statements of Earnings for each of the
three years in the period ended August 31, 1999
Consolidated Statements of Cash Flows for each of the
three years in the period ended August 31, 1999
Consolidated Balance Sheets - August 31, 1999 and 1998
Consolidated Statements of Changes in Common Stock Equity
for each of the three years in the period ended August 31,
1999
Consolidated Statements of Capitalization - August 31, 1999
and 1998
Notes to Consolidated Financial Statements
Report of Independent Certified Public Accountants
(a) 2. Consolidated Financial Schedule
Schedule VIII - Valuation and Qualifying Accounts
Report of Independent Certified Public Accountants on Consolidated
Financial Schedule
Schedules I, II, III, IV, V, VI, VII, IX, X, XI, XII, XIII and XIV are
either inapplicable or not required or the required information is
shown in the financial statements or notes thereto under the
instructions and have been omitted.
(a) 3. Exhibits
3. (a) Articles of Incorporation, as amended (Exhibit 3 to the
Corporation's Annual Report on Form 10-K for the year
ended August 31, 1988 is hereby incorporated by reference.)
3. (b) Bylaws of the Corporation (Exhibit 3 to the Corporation's
Annual Report on Form 10-K for the year ended August 31,
1988 is hereby incorporated by reference.)
4. (a) Shareholder Rights Plan dated as of June 18, 1991 (Filed on
Form 8-K dated June 28, 1991 is hereby incorporated by
reference.)
38
4. (b) Indenture between Valley Resources, Inc. and Mellon Bank,
N.A., Trustee, dated as of September 1, 1997 (Exhibit 4 to
the Corporation's Registration Statement on Form S-2 (File
No. 333-30113) is hereby incorporated by reference.)
4. (c) Indenture of First Mortgage dated as of December 15, 1992
between Valley Gas Company, Valley Resources, Inc. as
guarantor and State Street Bank and Trust Company, Trustee
(Exhibit 4 to the Corporation's Annual Report on Form 10-K
for the year ended August 31, 1993 is hereby incorporated
by reference.)
4. (d) Loan Agreement between Valley Resources, Inc. and Fleet
National Bank dated June 30, 1997 (Exhibit 10 to the
Corporation's Quarterly Report on Form 10-Q for the quarter
ended May 31, 1997 is incorporated herein by reference.)
10. Compensation Contracts or Arrangements
10. (a) Valley Gas Company Supplemental Retirement Plan (Exhibit 10 to
the Corporation's Annual Report on Form 10-K for the year
ended August 31, 1989 is hereby incorporated by reference.)
10. (b) Valley Resources, Inc. Directors Retirement Plan (Exhibit 10
to the Corporation's Annual Report on Form 10-K for the
year ended August 31, 1992 is hereby incorporated by
reference.)
10. (c) Valley Resources, Inc. 1999 Executive Incentive Plan dated
September 1, 1998.
10. (d) Change in Control agreement dated November 30, 1999 between
Valley Resources, Inc. and Alfred P. Degen.
10. (e) Change in Control agreement dated November 30, 1999 between
Valley Resources, Inc. and Sharon Partridge.
10. (f) Change in Control agreement dated November 30, 1999 between
Valley Resources, Inc. and Charles K. Meunier.
10. (g) Change in Control agreement dated November 30, 1999 between
Valley Resources, Inc. and Richard G. Drolet.
10. (h) Change in Control agreement dated November 30, 1999 between
Valley Resources, Inc. and Jeffrey P. Polucha.
Other Material Contracts or Agreements
10. (i) Firm Storage Service Transportation contract between Valley
Gas and Tennessee Gas Pipeline Company, dated December 15,
1985 (Exhibit 10 to the Corporation's Annual Report on Form
10-K for the year ended August 31, 1986 is hereby
incorporated by reference.)
10. (j) Storage Service Agreement dated July 3, 1985 between Valley
Gas and Consolidated Gas Transmission Corporation (Exhibit
10 to the Corporation's Registration Statement on Form S-2
(File No. 2-99315) is hereby incorporated by reference.)
10. (k) Underground Storage Service Agreement dated October 3, 1984
between Valley Gas and Penn-York Energy Corporation
(Exhibit 10 to the Corporation's Registration Statement on
Form S-2 (File No. 2-99315) is hereby incorporated by
reference.)
39
10. (l) Underground Storage Service Agreement dated August 19, 1983
between Valley Gas and Penn-York Energy Corporation
(Exhibit 10 to the Corporation's Annual Report on Form 10-K
for the year ended August 31, 1983 is hereby incorporated
by reference.)
10. (m) Service agreement for storage of LNG dated June 30, 1982
between Valley Gas and Algonquin LNG, Inc. (Exhibit 10 to
the Corporation's Annual Report on Form 10-K for the year
ended August 31, 1982 is hereby incorporated by reference.)
10. (n) Contract for the purchase of natural gas dated March 1, 1981,
between Valley Gas and Tennessee Gas Pipeline Company
(Exhibit 10 to the Corporation's Annual Report on Form
10-K for the year ended August 31, 1981 is hereby
incorporated by reference.)
10. (o) Storage Service Transportation contract dated May 15, 1981,
between Valley Gas and Tennessee Gas Pipeline Company
(Exhibit 10 to the Corporation's Annual Report on Form
10-K for the year ended August 31, 1981 is hereby
incorporated by reference.)
10. (p) Storage Service Transportation contract dated May 26, 1981,
between Valley Gas and Tennessee Gas Pipeline Company
(Exhibit 10 to the Corporation's Annual Report on Form 10-K
for the year ended August 31, 1981 is hereby incorporated
by reference.)
10. (q) Storage Service Agreement dated February 18, 1980, between
Valley Gas and Consolidated Gas Supply Corporation (Exhibit
10 to the Corporation's Annual Report on Form 10-K for the
year ended August 31, 1981 is hereby incorporated by
reference.)
10. (r) Precedent Agreement for Firm Services on Maritimes and
Northeast Pipeline Project Phase II dated September 21,
1996, between Valley Gas and Maritimes and Northeast
Pipeline L.L.C. (Exhibit 10 to the Corporation's
Registration Statement on Form S-2 (File No. 333-30113) is
hereby incorporated by reference.)
10. (s) Gas Sales Agreement dated June 15, 1992 between Aquila Energy
Marketing Corporation and Valley Gas (Exhibit 10 to the
Corporation's Annual Report on Form 10-K for the year ended
August 31, 1992 is incorporated herein by reference.)
10. (t) Gas Sales Agreement dated June 8, 1992 between Natural Gas
Clearinghouse and Valley Gas Company (Exhibit 10 to the
Corporation's Annual Report on Form 10-K for the year ended
August 31, 1992 is incorporated herein by reference).
13. Annual Report to Stockholders (Exhibit 13 to the Corporation's Annual
Report on Form 10-K for the year ended August 31, 1999 is hereby
incorporated by reference.)
21. Subsidiaries of the Registrant (Exhibit 21 to the Corporation's Annual
Report on Form 10-K for the year ended August 31, 1996 is
incorporated herein by reference).
23. Consent of Grant Thornton LLP.
27. Financial Data Schedule. (Exhibit 27 to the Corporation's Annual Report
on Form 10-K for the year ended August 31, 1999 is hereby
incorporated by reference.)
(b) No Form 8-K was required to be filed for the last quarter of the
period covered by this report.
40
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
VALLEY RESOURCES, INC. AND SUBSIDIARIES
Date: March 21, 2000 By s/Sharon Partridge
----------------------------------------
Sharon Partridge
Vice President, Chief Financial Officer,
Secretary & Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 21, 2000 s/Alfred P. Degen
------------------------------------------------------
Alfred P. Degen, President and Chief Executive Officer
Date: March 21, 2000 s/Sharon Partridge
------------------------------------------------------
Sharon Partridge, Vice President, Chief Financial
Officer, Secretary & Treasurer
Date: March 21, 2000 s/Ernest N. Agresti
------------------------------------------------------
Ernest N. Agresti, Director
Date: March 21, 2000 s/Melvin G. Alperin
------------------------------------------------------
Melvin G. Alperin, Director
Date: March 21, 2000 s/C. Hamilton Davison
------------------------------------------------------
C. Hamilton Davison, Director
Date: March 21, 2000 s/Don A. DeAngelis
------------------------------------------------------
Don A. DeAngelis, Director
Date: March 21, 2000 s/James M. Dillon
------------------------------------------------------
James M. Dillon, Director
Date: March 21, 2000 s/Jonathan K. Farnum
------------------------------------------------------
Jonathan K. Farnum, Director
Date: March 21, 2000 s/John F. Guthrie, Jr.
------------------------------------------------------
John F. Guthrie, Jr., Director
Date: March 21, 2000 s/Virginia Roberts
------------------------------------------------------
Virginia Roberts, Director
41