<PAGE>
FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended September 30, 1999
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OR
[_] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ________________________ to ___________________
Commission file number 1-10032
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PROVIDENCE ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
Rhode Island 05-0389170
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(State or other jurisdiction of (I . R. S. Employer
incorporation or organization) Identification No.)
100 Weybosset Street, Providence, Rhode Island 02903
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 401-272-9191
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
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registered
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Common Stock, $1.00 Par Value NEW YORK STOCK EXCHANGE
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Securities registered pursuant to Section 12(g) of the Act:
NONE
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(Title of Class)
Indicate by checkmark 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 ___
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
State the aggregate market value of the voting stock held by
non-affiliates of the Registrant, as of November 30, 1999: $229,620,264
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
Common Stock, $1.00 Par Value: 6,140,771 shares outstanding at
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November 30, 1999.
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DOCUMENTS INCORPORATED BY REFERENCE
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Portions of the annual report to shareholders for the fiscal year ended
September 30, 1999 are incorporated by reference into Part II.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I PAGE
<S> <C>
Item 1 - Business
General I-1
Operations of the Gas Companies I-2
Nonregulated Businesses I-7
Special Factors Affecting the
Natural Gas Industry I-8
Environmental Regulations I-8
Other Standards I-10
Item 2 - Properties I-10
Item 3 - Legal Proceedings I-10
Item 4 - Submission of Matters to a Vote of Security Holders I-10
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholders' Matters II-1
Item 6 - Selected Financial Data II-1
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations II-1
Item 8 - Financial Statements and Supplementary Data II-1
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure II-1
PART III
Item 10 - Directors and Executive Officers of the Registrant III-1
Item 11 - Executive Compensation III-4
Item 12 - Security Ownership of Certain Beneficial Owners
and Management III-4
Item 13 - Certain Relationships and Related Transactions III-4
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports
on Form 8-K IV-1
Experts Consent IV-6
Supplemental Schedule IV-7
Signatures IV-11
</TABLE>
For definitions of industry terms, defined terms, acronyms, and abbreviations,
reference is made to the Glossary and Defined Terms, which is pages 43 through
44 of the Registrant's Annual Report to Shareholders (pages 37 through 41 of
this form 10-K) for the fiscal year ended September 30, 1999, which is filed
herewith under Part IV as Exhibit 13.
<PAGE>
PART I
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ITEM 1. BUSINESS
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The Providence Energy Corporation and its subsidiaries and their
representatives may from time to time make written or oral statements, including
statements contained in the Registrant's filings with the Securities and
Exchange Commission and in its reports to shareholders, which constitute or
contain "forward-looking" statements as that term is defined in the Private
Securities Litigation Reform Act of 1995 or by the SEC in its rules,
regulations, and releases.
All statements other than statements of historical facts included in this
Form 10-K including without limitation statements regarding the Registrant's
financial position, strategic initiatives, the effect of its proposed merger
with Southern Union Company, and statements addressing industry developments are
forward-looking statements. Where, in any forward looking statement, the
Registrant, or its management expresses an expectation or belief as to future
results, such expectation or belief is expressed in good faith and believed to
have a reasonable basis, but there can be no assurance that the statement of
expectation or belief will result or be achieved or accomplished. The following
are some of the factors which could cause actual results to differ materially
from those anticipated: general economic, financial, and business conditions;
changes in government regulations, the actions taken or decisions rendered by
any regulatory body, and the impact such changes, actions, or decisions might
have on the Registrant, including the regulatory approvals or the timeliness of
such approvals on the Registrant's proposed merger with Southern Union Company;
competition in the energy services sector; regional weather conditions; the
availability and cost of natural gas and oil; development and operating costs;
the success and costs of advertising and promotional efforts; the availability
and terms of capital; the business abilities and judgment of personnel; the
ability of the Registrant and its suppliers and customers to modify or redesign
their computer systems to work properly in the Year 2000; unanticipated
environmental liabilities; the Registrant's ability to grow its business through
acquisitions and/or significant customer growth; the costs and effects of
unanticipated legal proceedings; the impacts of unusual items resulting from
ongoing evaluations of business strategies and asset valuations; and changes in
business strategy.
General
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The Registrant was organized in 1981 as a Rhode Island business
corporation. The Registrant's outstanding common shares are listed on the New
York Stock Exchange under the ticker symbol "PVY".
The Registrant is the parent of two wholly-owned natural gas distribution
utilities, The Providence Gas Company and North Attleboro Gas Company, together
referred to as the Gas Companies.
In August 1996, the Registrant incorporated Providence Energy Services,
Inc. to market natural gas and energy services and to grow its natural gas, oil,
and electricity business to retail accounts in New England.
In November 1997, the Registrant acquired all of the outstanding common
stock of the Super Service Companies, which marked the Registrant's entrance
into the full service oil heating business. The business has grown through
acquisition and internal growth to approximately 7,000 customers at
September 30, 1999.
ProvGas, Rhode Island's largest natural gas distributor, was founded in
1847 and serves approximately 168,000 customers in Providence, Newport and 23
other cities and towns in Rhode Island. North Attleboro Gas serves
approximately 4,000 customers in North Attleboro and Plainville, Massachusetts,
towns adjacent to the northeastern Rhode Island border. The total natural gas
service territory of the Gas Companies encompasses 760 square miles and has a
population of approximately 853,000.
I-1
<PAGE>
The corporate offices of the Registrant are located at 100 Weybosset Street,
Providence, Rhode Island 02903 (Telephone 401-272-5040).
On November 15, 1999, ProvEnergy and Southern Union announced that their
Boards of Directors had unanimously approved a definitive merger agreement. See
Note 2 in the accompanying Consolidated Financial Statements for additional
information.
Operations of the Gas Companies
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Customers
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The Gas Companies served an average of 172,000 customers for the twelve
months ended September 30, 1999, of which approximately 90% were residential and
10% were commercial and industrial.
The net increase in the average number of customers during fiscal 1999 over
fiscal 1998 was approximately 2,300 or 1.4%. A portion of this increase was the
result of new housing construction and conversions from other energy sources.
This increase was achieved in a local economy which is now beginning to
improve. Seasonally adjusted unemployment stood at 3.8 percent in September
1999, down from 4.8 percent twelve months earlier, and slightly below the
national average of 4.2 percent. New construction contracts in Rhode Island
through September 1999 have increased by 17% on an annual basis compared to
1998's annual average. Recent economic forecasts by the New England Economic
Project predict economic stability in the state for the immediate future.
Gas Service
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The gas services provided by the Gas Companies can be grouped into four
categories -- firm sales, firm transportation, non-firm sales and non-firm
transportation. Firm service is provided to those residential, commercial and
industrial customers that use natural gas throughout the year. Non-firm service
is provided to those commercial and industrial customers that do not require
assured gas service because they can utilize an alternative fuel or otherwise
operate without gas service. Transportation service is a service where the Gas
Companies transport to certain large customers gas owned by those customers or
by third parties selling gas to those customers.
The following table shows the distribution of gas to various customer classes,
and the total gas sold and transported by year since 1995:
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Firm Sales 69.2% 73.9% 80.4% 85.8% 76.4%
Firm Transportation 21.2 16.6 6.7 1.3 0.7
Non-Firm Sales 3.3 5.6 9.6 9.3 17.6
Non-Firm Transportation 6.3 3.9 3.3 3.6 5.3
----- ----- ----- ----- -----
100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
</TABLE>
Total Gas Sold and Transported
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1999 1998 1997 1996 1995
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BCF(*) 25.4 25.4 27.3 28.1 28.1
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(*) Gas sales are denominated in billions of cubic feet of natural gas. Total
gas sales include gas sold and transported by the Gas Companies.
I-2
<PAGE>
The following table shows the difference between actual and normal degree
days since 1995:
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
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<S> <C> <C> <C> <C> <C>
Actual calendar degree days 5,139 5,206 5,657 5,967 5,111
Normal calendar degree days 5,652 5,652 5,652 5,682 5,709
Colder (warmer) than normal (9.1%) (7.9%) 0.1% 5.0% (10.5%)
</TABLE>
Firm Sales
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In the recent year, the distribution of the Gas Companies' firm sales was
approximately 57% to residential and 43% to commercial and industrial and
transportation customers. Firm sales represent the highest percentage of
operating margin and represent the core of the Gas Companies' business.
Non-Firm
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The non-firm customer base consists of seasonal customers that typically
use gas only during the nonwinter months and dual-fuel customers that contract
for gas service on a year round basis, but agree to service interruption during
certain peak periods. By retaining the right to interrupt service to the dual-
fuel customers, the Gas Companies can balance daily demand from firm customers
with available gas supply and pipeline capacity. Non-firm customers may
interrupt their gas service, as well, when it is more economical to utilize an
alternative fuel. Accordingly, the amount of the Gas Companies' non-firm sales
fluctuates depending upon the relative price of natural gas to alternative
fuels.
Non-firm sales produce substantially less margin to the Gas Companies than
firm sales due to the more competitive nature of non-firm sales. Service rates
charged to dual-fuel customers are based on the price that the customer would
otherwise pay for its alternative fuel. In fiscal year 1999, under the terms of
the Price Stabilization Plan Settlement Agreement, any margin earned from these
non-firm customers was retained by the Registrant - See "Rates and Regulation"
--------------------
and "Competition and Marketing".
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Transportation Service
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The Registrant provides both firm and non-firm transportation of gas.
Margin from the firm transportation of gas purchased by certain large customers
from third parties is likely to represent an increasing percentage of the Gas
Companies' future total margin due to the continuing developments affecting the
natural gas industry - see "Competition and Marketing". In general, these
--------------------------
developments now allow customers to buy gas directly from the producer-supplier
rather than solely from the local gas distribution company. Customer-owned gas
is transported to the customer's premises through a combination of the
interstate pipelines and the Gas Companies' distribution systems.
For a given quantity of gas, the Gas Companies' margin from firm
transportation service is comparable to the margin from firm sales. Margin from
nonfirm transportation service is less than the margin from firm sales, but is
generally comparable to the margin from interruptible sales, depending on the
price of alternative fuels. To the extent that the Gas Companies' existing
customers buy gas directly from producer-suppliers, the Gas Companies' revenue
will decrease although firm margin will not be materially impacted.
I-3
<PAGE>
Gas Supply
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The Registrant's principal subsidiary, ProvGas, entered into a full
requirements gas supply contract with DETM, a joint venture of Duke Energy
Corporation and Mobil Corporation, for a term of three years commencing October
1, 1997. Under the contract, DETM guarantees to meet ProvGas' supply
requirements; however, ProvGas must purchase all of its gas supply exclusively
from DETM. In addition, under the contract, ProvGas transferred responsibility
for its pipeline capacity resources, storage contracts, and LNG capacity to
DETM. As a result, ProvGas' gas inventories of approximately $18 million at
September 30, 1997 were sold at book value to DETM on October 1, 1997.
In addition to providing supply for firm customers at a fixed price, DETM
will provide gas at market prices to cover ProvGas' non-firm sales customers'
needs and to make up the supply imbalances of transportation customers. DETM
will also provide various other services to ProvGas' transportation service
customers including enhanced balancing, standby, and the storage and peaking
services available under ProvGas' approved FT-2 storage service effective
December 1, 1997. DETM will receive the supply-related revenues from these
services in exchange for providing the supply management inherent in these
services.
Included in the DETM contract are a number of other important features.
ProvGas has retained the right to continue to make gas supply portfolio changes
to reduce supply costs. To the extent ProvGas makes such changes, ProvGas must
keep DETM whole for the value lost over the remainder of the contract period.
The outsourcing of day-to-day supply management relieves ProvGas of the need to
perform certain upstream supply management functions. This will make it possible
for ProvGas to take on the additional supply management workload required by the
further unbundling of firm sales customers without major staffing additions.
ProvGas has entered into an agreement replacing its existing service
contract with Algonquin, a subsidiary of Duke Energy Corporation. Algonquin is
the owner and operator of a LNG tank located in Providence, Rhode Island.
ProvGas relies upon this service to provide gas supply into its distribution
system during the winter period. The service provided for in the agreement,
subject to the successful completion of construction, is expected to begin in
the first quarter of fiscal 2000. Under the terms of the agreement, Algonquin
replaced and expanded the vaporization capability at the tank. ProvGas will
receive approximately $2.6 million from Algonquin. Of the $2.6 million,
approximately $.9 million represents reimbursement received by ProvGas in 1999
for costs incurred related to the project including labor, engineering, and
legal expenses. The remaining portion of the payment, or approximately $1.7
million, will be paid to DETM under ProvGas' contract with DETM as reimbursement
for the additional costs that DETM will incur when the Algonquin storage
capacity is released to DETM as provided for in the gas supply contract
described above. This payment is expected 60 days after the in-service date of
the project.
In June 1999, the FERC issued an order in Docket Number CP99-113 approving
Algonquin's project described above. In that order FERC also approved the new
10-year contract between Algonquin and ProvGas for service from the tank. Also
approved was ProvGas' parallel filing, PR99-8, requesting regulatory
authorization to charge Algonquin for transportation of gas vaporized for other
Algonquin customers and transported by ProvGas to the Algonquin pipeline on
behalf of those customers.
I-4
<PAGE>
As a result of FERC Order 636 and other related orders, pipeline
transportation companies have incurred significant costs, collectively known as
transition costs. The majority of these costs will be reimbursed by the
pipeline's customers, including ProvGas. ProvGas estimates its transition costs
to be approximately $21.7 million, of which $16.2 million has been included in
the GCC and collected from customers through September 30, 1997. As part of the
above supply contract, DETM assumed liability for these transition costs during
the contract's three-year term. At the end of the three-year term of the
contract, the Registrant will assume any remaining liability, which is not
expected to be material.
Rates and Regulation
- --------------------
ProvGas is subject to the regulatory jurisdiction of the Rhode Island
Public Utilities Commission and North Attleboro Gas is subject to the
jurisdiction of the Massachusetts Department of Telecommunications and Energy
with respect to rates and charges, standards of service, accounting and other
matters.
In August 1997, the RIPUC approved a rate stabilization plan called
Energize RI. The parties to the plan were ProvGas, the Division, the Energy
Council of Rhode Island, and the George Wiley Center. Effective October 1, 1997
through September 30, 2000, Energize RI provides firm customers with a three-
year price freeze and an initial price decrease of approximately 4.0 percent.
Under Energize RI, the GCC mechanism has been suspended for the entire term.
Also, in connection with the Plan, ProvGas wrote off approximately $1.5 million
of previously deferred gas costs in October 1997. Energize RI also provides
funds which allow ProvGas to make significant capital investments to improve its
distribution system and support economic development. It is anticipated that
Energize RI will provide approximately $26 million over its three-year term to
fund specific capital improvements. In addition, under Energize RI, ProvGas
provides funding for the Low-Income Assistance Program at an annual level of
$1.0 million, the Demand Side Management Rebate Program at an annual level of
$.5 million and the Low-Income Weatherization Program at an annual level of $.2
million. Energize RI also continues the process of unbundling by allowing
ProvGas to provide unbundled service offerings for up to 10 percent per year of
firm deliveries.
As part of Energize RI, ProvGas has reclassified and is amortizing
approximately $4.0 million of prior environmental costs. These costs and all
environmental costs incurred during the term of the Plan will be amortized over
a 10-year period, in accordance with the levels authorized in Energize RI.
Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than
7.0 percent, annually on its average common equity, which is capped at $81.0
million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000,
respectively. In the event that ProvGas earns in excess of 10.9 percent or less
than 7.0 percent, ProvGas will defer revenues or costs through a deferred
revenue account over the term of the Plan. Any balance in the deferred revenue
account at the end of the Plan will be refunded to or recovered from customers
in a manner to be determined by all parties to the Plan and approved by the
RIPUC.
As part of Energize RI, ProvGas is permitted to file annually with the
Division for the recovery of exogenous changes which may occur during the three-
year term of the Plan. Exogenous changes are defined as "...significant
increases or decreases in ProvGas' costs or revenues which are beyond ProvGas'
reasonable control." Any disputes between ProvGas and the Division regarding
either the nature or quantification of the exogenous changes are to be resolved
by the RIPUC. The impact of any such exogenous changes will be debited or
credited to a regulatory asset or liability account throughout the term of
Energize RI and will be recovered or refunded at the expiration of the Plan
through a method to be determined.
I-5
<PAGE>
In fiscal 1998, ProvGas did not earn its allowed rate of return primarily
as a result of the extremely warm winter weather and the loss of non-firm
margin. ProvGas believed the causes of these two events were beyond its
reasonable control and thus deemed them to be exogenous changes. In March 1999,
ProvGas reached an agreement with the Division, which allowed it to recover
$2.45 million in revenue losses attributable to exogenous changes experienced by
ProvGas in fiscal 1998. The RIPUC reviewed the exogenous changes agreement to
ensure consistency with the terms of Energize RI and affirmed the agreement at
its May 28, 1999 open meeting.
During fiscal 1999, ProvGas recognized into revenue $2.45 million for the
exogenous changes recovery, and at year-end has deferred approximately $.5
million of revenue under the provisions of the earnings cap of Energize RI.
ProvGas intends to file for recovery of exogenous changes experienced in
1999 which resulted from factors similar to 1998. Absent further exogenous
recovery and/or other factors such as colder than normal weather, ProvGas'
ability to earn a 10.9 percent return on average common equity in the final year
of Energize RI is substantially impaired.
In a decision issued September 1, 1998, the Division rejected allegations
made in a complaint brought by Aurora Natural Gas that ProvGas provided advance
information and undue preference in pricing to its marketing affiliate,
ProvEnergy Services in violation of the Division's regulations. As part of its
investigation, the Division ordered marketer refunds of approximately $.3
million. The Division ordered this refund based on its belief that an unfair
rate was charged to customers who did not have operational telemeters in place
when they began service under the transportation tariff. ProvGas filed a Request
for Reconsideration and Rehearing, and on December 15, 1998 the Division issued
a Reconsideration Order that rescinded the fines stemming from five of the
original 23 violations of the Regulations for Utility Interaction with Gas
Marketers. The Division further offered the Registrant an opportunity to
demonstrate its claim that the ordered refunds would place FT-2 marketers in a
better position than marketers who served FT-1 customers.
On May 6, 1999, ProvGas and Aurora jointly submitted a Stipulation and
Settlement to the Division that: (i) Aurora's complaint in this proceeding is
dismissed; (ii) the prior orders of the Division in the proceeding are
dismissed; (iii) no refunds by ProvGas are required or appropriate in connection
with the proceeding; and (iv) ProvGas does not contest the payment of $18,000 to
the Division in connection with this proceeding. Following a June 16, 1999
hearing on the Stipulation, the Division issued an order on September 23, 1999
approving the Stipulation and Settlement provided that ProvGas ratepayers are
held harmless from the financial transactions stemming from the settlement, that
ProvGas withdraw its appeal in Providence County Superior Court, and that the
Division's prior orders be vacated as described in the order. ProvGas and Aurora
accepted the Division's order. This decision resulted in the reversal of the
reserve established under the original order.
Competition and Marketing
- -------------------------
Energize RI provides opportunities for ProvGas to expand sales. For
example, high pressure service to Quonset/Davisville Industrial Port & Commerce
Park, a key area for State economic development, provides opportunities for
sales growth as commercial and industrial businesses locate within the park. In
addition, Demand Side Management, an equipment rebate program, provides
opportunities to expand sales to non-traditional applications, such as air
conditioning and fuel cells. ProvGas has redirected its sales and marketing
efforts to leverage Energize RI, as well as other opportunities to promote sales
growth within its service territory.
I-6
<PAGE>
In response to the large increase of both state-owned and private fleet
vehicles powered by natural gas, ProvGas invested approximately $.3 million to
renovate its Providence "quick-fill" station for natural gas vehicles - one of
three stations ProvGas operates in the state. Fleet operators throughout the
region are expressing greater interest in alternative-fuel vehicles. One of
these operators is the Rhode Island Public Transit Authority, which recently
launched a major program to replace a large number of its 200 diesel buses with
buses that operate solely on natural gas. A new Rhode Island law provides
substantial tax incentives which, along with the Federal Department of Energy's
designation of Providence as a "clean city" should increase use and awareness of
the benefits of natural gas vehicles.
On August 31, 1999, ProvGas' settlement agreement for enhancements to its
Business Choice program was approved in Docket 2902 and became effective
September 1, 1999. Specifically, there will now be rolling enrollment for
transportation service, which will allow customers to execute transportation
agreements throughout the year, rather than during limited enrollment periods.
The program now has approximately 1,700 firm transportation customers with
annual deliveries of over 5 billion cubic feet per year, which is approximately
25 percent of ProvGas' total annual firm deliveries. There are 14 marketers
serving ProvGas' customers and transporting on the system. Additional
enhancements to the Business Choice program were filed with the RIPUC under a
supplemental settlement agreement in Docket 2902 on October 8, 1999 and were
approved on October 27, 1999. These enhancements do not generate additional
revenue.
In 1996, ProvGas implemented a Demand Side Management Program, which
furnishes rebates to customers installing new technologies, such as gas fired
air conditioning, cogeneration and gas motors. These technologies use
proportionately more natural gas during the summer months, when the distribution
system has available capacity. The DSM Program also allows for the utilization
of existing resources, such as mains, services and year-round supply contracts.
This DSM Program will continue to be funded under Energize RI.
The discussion of Competition and Marketing for the Registrant's non-
regulated businesses can be found in the "Non-regulated Businesses" section.
-----------------------
Employees
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As of September 30, 1998, the Registrant had 615 full-time employees.
Approximately 274 of ProvGas' distribution and customer service employees are
covered by a collective bargaining agreement with Local 12431-01 of the United
Steelworkers of America, which became effective in January 1996.
The bargaining agreement was developed by a labor-management negotiations
committee and contains a provision allowing the agreement to be reopened for any
reason at any time in order for the committee to deal with new issues as they
arise. The provision results in increased flexibility in the use of employees.
The original agreement called for a general wage increase of 3.25 percent each
year from 1997 to 2000.
In April 1998 the contract with Local 12431-01 was renegotiated and
extended to January 2002. This negotiation provides for a 3.5 percent wage
increase in January 1999, January 2000, and January 2001.
Additionally, in March 1996, a 38 month Labor Agreement was ratified by
Local 12431-02 of the United Steelworkers of America, which represents 83 office
and clerical employees of ProvGas. The agreement called for an average general
wage increase of 2.9 percent in 1998.
In April 1998 the contract with Local 12431-02 was renegotiated and
extended to May 2002. This negotiation provides for a 3.5 percent wage increase
in June 1999, June 2000, and June 2001.
I-7
<PAGE>
Gas Distribution Systems
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The Gas Companies' distribution systems consist of approximately 2,400
miles of gas mains ranging in size from 2 to 36 inches in diameter,
approximately 146,000 services (a "service" meaning a pipe connecting a gas main
with piping on a customer's premises), and approximately 173,000 active gas
meters together with related facilities and equipment. The Gas Companies have
regulating and metering facilities at nine points of delivery from Algonquin Gas
Transmission Company and one point of delivery from Tennessee Gas Pipeline
Company, which the Gas Companies presently believe to be adequate for receiving
gas into their distribution systems.
Non-regulated Businesses
- ------------------------
The Registrant's non-regulated operation continues to increase its
contribution to operating margin by adding customers and sales volume, although
it continues to generate a net loss consistent with the start-up of new
businesses. The Registrant intends to continue to grow its residential oil
customer base through future customer acquisitions to build the operational
scale needed to compete effectively in the marketplace. Furthermore, as New
England gas utilities continue to unbundle the sale of the gas commodity from
the distribution of that gas, the opportunity for increased non-regulated
natural gas sales will expand.
The Registrant's joint venture to provide electricity, HVAC, and related
services for most of the Mall began with the Mall's August 1999 opening.
Special Factors Affecting the Natural Gas Industry
- --------------------------------------------------
General
- -------
The natural gas industry is subject to numerous legislative and regulatory
requirements, standards and restrictions that are subject to change and that
affect the Gas Companies to varying degrees. Significant industry factors that
have affected or may affect the Gas Companies from time to time include lack of
assurance that rate increases can be obtained from regulatory authorities in
adequate amounts on a timely basis; changes in the regulations governing the Gas
Companies' operations; ability to adapt to FERC regulatory changes; reductions
in the prices of oil and propane, which can make those fuels less costly than
natural gas in some markets; and increases in the price of natural gas.
FERC Regulations
- ----------------
In recent years, FERC has been attempting to increase competition with
regard to the transportation and sale of natural gas in interstate commerce.
Beginning in late 1985, FERC began promulgating orders that allow all industry
participants access to pipeline transportation on an open, nondiscriminatory
basis to the extent of available capacity.
Recent FERC orders are in furtherance of its policy to make gas
transportation and alternate supply sources more accessible to all parties,
including local distribution companies and their customers. Such open access
allows the Gas Companies to obtain their supply through a more competitive
national gas pipeline system, where and when capacity is available.
FERC Order 636 and other related orders have significantly changed the
structure and types of services offered by pipeline transportation companies.
The most significant components of the restructuring occurred in November 1993.
In response to these changes, the Gas Companies have negotiated new pipeline
transportation and gas storage contracts.
To meet the requirements of the orders, pipeline transportation companies
have incurred significant costs, collectively known as transition costs. The
majority of these costs will be reimbursed by the pipelines' customers including
ProvGas as discussed in the "Gas Supply" section.
----------
I-8
<PAGE>
Environmental Regulations
- -------------------------
Federal, state, and local laws and regulations establishing standards and
requirements for the protection of the environment have increased in number and
in scope within recent years. The Registrant cannot predict the future impact of
such standards and requirements, which are subject to change and can take effect
retroactively. The Registrant continues to monitor the status of these laws and
regulations. Such monitoring involves the review of past activities and current
operations, and may include expending funds to investigate or clean up certain
sites. To the best of its knowledge, subject to the following, the Registrant
believes it is in substantial compliance with such laws and regulations.
At September 30, 1999, the Registrant was aware of five sites at which
future costs may be incurred.
Plympton Sites (2)
The Registrant has been designated as a PRP under the Comprehensive
Environmental Response Compensation and Liability Act of 1980 at two sites in
Plympton, Massachusetts on which waste material is alleged to have been
deposited by disposal contractors employed in the past either directly or
indirectly by the Registrant and other PRPs. With respect to one of the Plympton
sites, the Registrant has joined with other PRPs in entering into an
Administrative Consent Order with the Massachusetts Department of Environmental
Protection. The costs to be borne by the Registrant, in connection with both
Plympton sites, are not anticipated to be material to the financial condition of
the Registrant.
Providence Site
During 1995, the Registrant began a study at its primary gas distribution
facility located in Providence, Rhode Island. This site formerly contained a
manufactured gas plant operated by the Registrant. As of September 30, 1999,
approximately $3.0 million had been spent primarily on studies and the
formulation of remediation work plans at this site. In accordance with state
laws, such a study is monitored by the DEM. The purpose of this study was to
determine the extent of environmental contamination at the site. The Registrant
has completed the study which indicated that remediation will be required for
two-thirds of the property. The remediation began in June 1999 and is
anticipated to be completed during the next fiscal year. During this remediation
period, the remaining one-third of the property will also be investigated and
remediated if necessary.
The Registrant has compiled a preliminary range of costs, based on removal
and off-site disposal of contaminated soil, ranging from $7.0 million to in
excess of $9.0 million. However, because of the uncertainties associated with
environmental assessment and remediation activities, the future cost of
remediation could be higher than the range noted. Based on the proposals for
remediation work, the Registrant has a net accrual of $6.1 million at September
30, 1999 for anticipated future remediation costs at this site.
Westerly Site
Tests conducted following the discovery of an abandoned underground oil
storage tank at the Registrant's Westerly, Rhode Island operations center in
1996 confirmed the existence of coal tar waste at this site. As a result, the
Registrant completed a site characterization test. Based on the findings of that
test, the Registrant concluded that remediation would be required. As of
September 30, 1999, the Registrant had removed an underground oil storage tank
and regulators containing mercury disposed of on the site, as well as some
localized contamination. The costs associated with the site characterization
I-9
<PAGE>
test and partial removal of soil contaminants were shared equally with the
former owner of the property. The Registrant is currently engaged in
negotiations to transfer the property back to the previous owner, who would
continue to remediate the site. The purchase and sale agreement is anticipated
to be signed during fiscal 2000, at which time the previous owner will assume
responsibility for removal of coal tar waste on the site. The Registrant remains
responsible for cleanup of any mercury released into adjacent water.
Contamination from scrapped meters and regulators, which was discovered in 1997,
was reported to the DEM and the Rhode Island Department of Health and the
Registrant has completed the necessary remediation. Costs incurred by the
Registrant to remediate this site were approximately $.1 million.
Allens Avenue Site
In November 1998, the Registrant received a letter of responsibility from
DEM relating to possible contamination on previously-owned property on Allens
Avenue in Providence. The current operator of the property has been similarly
notified. Both parties have been designated as PRPs. A work plan has been
created and approved by DEM. An investigation has begun in order to determine
the extent of the problem and the Registrant's responsibility. The Registrant
has entered into a cost sharing agreement with the current operator of the
property, under which the Registrant will be held responsible for approximately
20 percent of the costs related to the investigation. Total estimated costs of
testing at this site are anticipated to be approximately $.2 million. Until the
results of the investigation are known, the Registrant cannot offer any
conclusions as to its responsibility.
General
In prior rate cases filed with the RIPUC, ProvGas requested that
environmental investigation and remediation costs be recovered by inclusion in
its depreciation factors consistent with the rate recovery treatment for all
types of cost of removal. Due to the magnitude of ProvGas' environmental
investigation and remediation expenditures, ProvGas sought current recovery for
these amounts. As a result, in accordance with the Price Stabilization Plan
Settlement Agreement described in Note 10, effective October 1, 1997, all
environmental investigation and remediation costs incurred through September 30,
1997, as well as all costs incurred during the three-year term of the Plan, will
be amortized over a 10-year period, in accordance with the levels authorized in
Energize RI. Additionally, it is ProvGas' practice to consult with the RIPUC on
a periodic basis when, in management's opinion, significant amounts might be
expended for environmental-related costs. As of September 30, 1999, ProvGas has
incurred environmental assessment and remediation costs of $4.7 million and has
a net accrual of $6.1 million for future costs.
Management has begun discussions with other parties who may assist ProvGas
in paying the costs associated with the remediation of the above sites.
Management believes that its program for managing environmental issues, combined
with rate recovery and financial contributions from others, will likely avoid
any material adverse effect on its results of operations or its financial
condition as a result of the ultimate resolution of the above sites.
Other Standards
- ---------------
The Gas Companies are also subject to standards prescribed by the Secretary
of Transportation under the Natural Gas Pipeline Safety Act of 1968 with respect
to the design, installation, testing, construction and maintenance of pipeline
facilities. The enforcement of these standards has been delegated to the RIPUC
and MDTE and management believes that the Gas Companies are in substantial
compliance with all present requirements imposed by these agencies.
I-10
<PAGE>
ITEM 2. PROPERTIES
- ------------------
In addition to the Registrant's gas distribution system and storage
facilities, which constitute the principal properties of the Registrant, the
Registrant owns several buildings and other facilities in Newport, Warwick,
Providence, and Westerly that house its offices and provide floor space for its
energy distribution and maintenance facilities.
Substantially all the foregoing properties are mortgaged as collateral for
the outstanding First Mortgage Bonds of ProvGas.
ITEM 3. LEGAL PROCEEDINGS
- -------------------------
The Registrant is involved in legal and administrative proceedings in the
normal course of business, including certain proceedings involving material
amounts in which claims have been or may be made. However, management believes,
after review of insurance coverage and consultation with legal counsel, that the
ultimate resolution of the legal proceedings to which it is or can at the
present time be reasonably expected to be a party, will not have a materially
adverse effect on the Registrant's results of operations or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -----------------------------------------------------------
Not Applicable
I-11
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDERS'
- ---------------------------------------------------------------------------
MATTERS
-------
The Registrant's common stock is listed on the New York Stock Exchange and
trades under the symbol "PVY". As of November 30, 1999, there were 6,338
registered holders of record of the Registrant's outstanding common stock. For
the balance of the information called for by this item, reference is made to the
materials under 'Common stock information' in the Registrant's Annual Report to
Shareholders for the fiscal year ended September 30, 1999, which is filed
herewith under Part IV as Exhibit 13.
ITEM 6. SELECTED FINANCIAL DATA
- -------------------------------
For the information called for by this item, reference is made to pages 38
through 41 of the Registrant's Annual Report to Shareholders (pages 35 through
36 of this Form 10-K) for the fiscal year ended September 30, 1999, which is
filed herewith under Part IV as Exhibit 13.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- -------------------------------------------------------------------------------
OF OPERATIONS
-------------
Regarding the information that relates to this item, reference is made to
pages 15 through 18 of the Registrant's Annual Report to Shareholders (pages 1
through 8 of this Form 10-K) for the fiscal year ended September 30, 1999, which
is filed herewith under Part IV as Exhibit 13.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ---------------------------------------------------
For the information called for by this item, reference is made to pages 19
through 34 of the Registrant's Annual Report to Shareholders (pages 9 through 33
of this Form 10-K) for the fiscal year ended September 30, 1999, which is filed
herewith under Part IV as Exhibit 13.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
- -----------------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
Not applicable
II-1
<PAGE>
PART III
--------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- ------------------------------------------------------------
The following information is furnished with respect to the executive officers
of the Registrant:
<TABLE>
<CAPTION>
Year
Office
Name and Age Office First Held
- ------------ ------ ----------
<S> <C> <C> <C>
James H. Dodge (59) Chairman, President and Chief
Executive Officer 1992
James DeMetro (51) Executive Vice President 1999
Kenneth W. Hogan (54) Vice President, Chief
Financial Officer, and
Treasurer 1999
James A. Grasso (45) Vice President, Public and
Government Affairs 1997
Royalynne J. Hourihan (55) Vice President, Human Resources 1998
Susann G. Mark (52) Vice President, General Counsel,
and Secretary 1998
Gerald A. Yurkevicz (42) Vice President, Marketing 1996
Harry J. Bishop (53) Assistant Treasurer 1998
</TABLE>
Mr. Dodge was elected President and Chief Executive Officer of the Registrant
and ProvGas in August 1990 and subsequently became Chairman of the Board in
January 1992. Mr. Dodge currently serves as a member of the Board of Capital
Properties, Inc., a non-affiliated real estate leasing company.
Mr. DeMetro was elected Executive Vice President of the Registrant and ProvGas
in February 1999. Mr. DeMetro served the Registrant and ProvGas as Senior Vice
President and for more than four years prior thereto, Vice President, Energy
Services.
Mr. Hogan was elected Vice President, Chief Financial Officer, and Treasurer
of the Registrant and ProvGas in April 1999. For more than five years prior
thereto, Mr. Hogan served as Senior Vice President, Chief Financial Officer, and
Secretary of Valley Resources, Inc., a diversified energy company.
Mr. Grasso was elected Vice President, Public and Government Affairs in May
1997. For three years prior thereto, Mr. Grasso served as Director of Public and
Government Relations of the Eastern Region of Pan Energy Corporation and Manager
of Public and Government Relations of Algonquin Gas Transmission Company. For
ten years prior thereto, Mr. Grasso served as Manager of Land, Public and
Government Relations of Algonquin Gas Transmission Company.
Mrs. Hourihan was elected Vice President, Human Resources effective
November 1998. For two years prior thereto, Mrs. Hourihan served as the senior
human resources professional of the Boston Public Schools District, Boston,
Massachusetts. For two years prior thereto, Mrs. Hourihan served as Vice
President, Human Resources of the Philadelphia Inquirer & Daily News. For four
---------------------
years prior thereto, Mrs. Hourihan served as Director, Human Resources - Eastern
Region of Wang Laboratories, Inc.
III-1
<PAGE>
Ms. Mark was elected Vice President, General Counsel and Secretary of the
Registrant in April 1998. For one year prior to that, Ms. Mark was a partner in
the Business Law Group at Brown, Rudnick, Freed & Gesmer and for eight years
prior to that was a partner in the Corporate Law Practice Group at Licht and
Seminoff.
Mr. Yurkevicz was elected Vice President, Marketing of the Registrant in
August 1996. For ten years prior thereto, Mr. Yurkevicz served as Principal in
the Energy Practice at Mercer Management Consulting.
Mr. Bishop was elected Assistant Treasurer effective October 1, 1998. For
four years prior thereto, Mr. Bishop served as Director of Finance and Revenue
Requirements for ProvGas.
III-2
<PAGE>
DIRECTORS OF THE REGISTRANT
- ---------------------------
For information called for by this item, reference is made to pages 2
through 6 of the Registrant's proxy statement filed December 21, 1999 with the
Securities and Exchange Commission for the annual meeting of shareholders to be
held January 20, 2000.
III-3
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------
For the information called for by this item, reference is made to pages 7
through 18 of the Registrant's proxy statement filed December 21, 1999 with the
Securities and Exchange Commission for the annual meeting of shareholders to be
held January 20, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
- ------------------------------------------------------------
MANAGEMENT
----------
For the information called for by this item, reference is made to page 19
of the Registrant's proxy statement filed December 21, 1999 with the Securities
and Exchange Commission for the annual meeting of shareholders to be held
January 20, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- -------------------------------------------------------
For the information called for by this item, reference is made to pages 6
through 7 of the Registrant's proxy statement filed December 21, 1999 with the
Securities and Exchange Commission for the annual meeting of shareholders to be
held January 20, 2000.
III-4
<PAGE>
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
- ------------------------------------------------------------------------
PROVIDENCE ENERGY CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(a) Financial Statements and Schedules
----------------------------------
Consolidated Balance Sheets--September 30, 1999 and 1998
Consolidated Statements of Income for the years ended September 30,
1999, 1998 and 1997
Consolidated Statements of Cash Flows for the years ended September 30,
1999, 1998 and 1997
Consolidated Statements of Capitalization--September 30, 1999
and 1998
Consolidated Statements of Changes in Common Stockholders' Investment for
the years ended September 30, 1999, 1998 and 1997
Notes to Consolidated Financial Statements
Report of Independent Public Accountants
Consent of Independent Public Accountants
The financial statements and related notes listed above are incorporated by
reference from Providence Energy Corporation's Annual Report to Shareholders
(see pages 9 through 33 of this Form 10-K) for the year ended September 30,
1999, filed herewith as Exhibit 13.
Schedule II. Reserves for the years ended September 30, 1999, 1998 and 1997.
Schedules I to XIII not listed above are omitted as not applicable or not
required under Regulation S-X.
(b) Reports on Form 8-K
-------------------
Although no reports on Form 8-K have been filed by the Registrant
during the last quarter, on November 15, 1999, the Registrant filed a report on
Form 8-K regarding the Registrant's Agreement and Plan of Merger with Southern
Union.
IV-1
<PAGE>
(c) Exhibits
--------
The following exhibits are filed as part of this report:
3.1 Articles of Incorporation, as amended (incorporated by reference to Exhibit
4(e) to the Registration Statement of the Registrant on Form S-2
(Registration No. 33-24125)).
3.2 Bylaws (incorporated by reference to Exhibit C to the Proxy
Statement/Prospectus forming a part of the Registrant's Registration
Statement on Form S-14 (Registration No. 2-69473), as amended at the annual
meetings of the shareholders held January 14, 1985 and January 14, 1991,
the text of such amendments being set forth in each case as Exhibit A to
the proxy statement for such annual meeting, heretofore filed with the
Securities and Exchange Commission and being incorporated herein by this
reference).
4.1 First Mortgage Indenture of The Providence Gas Company dated as of January
1, 1922, as supplemented by First through Twelfth Supplemental Indentures
(incorporated by reference to Exhibit 10.10 to the Registration Statement
of The Providence Gas Company on Form S-1 (Registration No. 2-72726)).
4.2 Fourteenth, Fifteenth and Sixteenth Supplemental Indentures of The
Providence Gas Company dated as of August 1, 1988, June 1, 1990 and
November 1, 1992, respectively (incorporated by reference to Exhibit 4 to
the report of the Registrant to the Securities and Exchange Commission on
Form 10-Q for the quarter ended March 31, 1993).
4.3 Seventeenth Supplemental Indenture of The Providence Gas Company dated as
of November 1, 1993. (Filed as Exhibit 4.5 to the report of the Registrant
on Form 10-K for the year ended September 30, 1993 incorporated herein by
this reference.)
4.4 Eighteenth Supplemental Indenture of The Providence Gas Company dated as of
December 1, 1995. (Filed as Exhibit 4.6 to the report of the Registrant on
Form 10-K for the year ended September 30, 1995 incorporated herein by this
reference.)
4.5 Nineteenth Supplemental Indenture of The Providence Gas Company dated as of
April 1, 1998. (Filed as Exhibit 4.5 to the report of The Providence Gas
Company on Form 10-K for the year ended September 30, 1998, incorporated
herein by this reference.)
4.6 Stock Rights Agreement (Filed as Exhibit 4.1 to the report of the
Registrant on Form 8-K File No. 001-10632 dated July 29, 1998, incorporated
herein by this reference.)
4.7 Twentieth Supplemental Indenture dated as of February 1, 1999. (Filed as
Exhibit 4.6 to the report of The Providence Gas Company on Form 10-K for
the year ended September 30, 1999, incorporated herein by this reference.)
4.8 Twenty-first Supplemental Indenture dated as of October 12, 1999. (Filed as
Exhibit 4.7 to the report of The Providence Gas Company on Form 10-K for
the year ended September 30, 1999, incorporated herein by this reference.)
10.1 Material contracts filed as Exhibit 10 (a) through 10 (ff) to Registration
Statement of the Registrant on Form S-2 (Registration No. 33-24125),
incorporated herein by this reference.
IV-2
<PAGE>
10.2 Employment Agreement dated October 29, 1997 between James H. Dodge,
Chairman, President and Chief Executive Officer of the Registrant. (Filed
as Exhibit 10.2 to the report of The Registrant in Form 10-K for the year
ended September 30, 1997, incorporated herein by this reference.)
10.3 Employment Agreement dated October 29, 1997 between James DeMetro, Senior
Vice President of The Registrant. (Filed as Exhibit 10.3 to the report of
The Registrant in Form 10-K for the year ended September 30, 1997,
incorporated herein by this reference.)
10.4 Employment Agreement dated October 29, 1997 between Robert W. Owens,
Senior Vice President of the Registrant. (Filed as Exhibit 10.4 to the
report of The Registrant in Form 10-K for the year ended September 30,
1997, incorporated herein by this reference.)
10.5 Change of control agreement dated May 10, 1999 between Kenneth W. Hogan,
Vice President, Chief Financial Officer, and Treasurer and the Registrant.
(Filed as Exhibit 10c to the report of the Registrant in Form 10-Q for the
quarter ended June 30, 1999, incorporated herein by this reference.)
10.6 Employment Agreement dated July 23, 1998 between James A. Grasso, Vice
President, Public and Government Affairs and the Registrant. (Filed as
Exhibit 10.6 to the report of the Registrant in Form 10-K for the year
ended September 30, 1998 incorporated herein by this reference.)
10.7 Employment agreement dated May 27, 1999 between Susann G. Mark, Vice
President, General Counsel, and Corporate Secretary and the Registrant.
(Filed as Exhibit 10a to Form 10-Q for the quarter ended June 30, 1999,
incorporated herein by this reference.)
10.8 Employment Agreement dated October 29, 1997 between Gerald A. Yurkevicz,
Vice President, Marketing and the Registrant. (Filed as Exhibit 10.9 to
the report of the Registrant in Form 10-K for the year ended September 30
1997, incorporated herein by this reference.)
10.9 Employment Agreement date May 2, 1999 between James M. Stephens, President
and Providence Energy Services, Inc. (Filed as Exhibit 10b to the report
of the Registrant in Form 10-Q for the quarter ended June 30, 1999,
incorporated herein by this reference.)
10.10 Employment Agreement dated October 1, 1998 between Peter J. Gill, Vice
President of Information Technology and The Providence Gas Company. (Filed
as Exhibit 10d to the report of the Registrant in Form 10-Q for the
quarter ended June 30, 1999, incorporated herein by this reference.)
10.11 Employment Agreement dated July 9, 1999 between Royalynne J. Hourihan,
Vice President of Human Resources and the Registrant.
10.12 Redacted gas supply contract dated October 1, 1997 between Duke Energy
Trading and Marketing, L.L.C. and The Providence Gas Company. (Filed as
Exhibit 10 to the report of The Providence Gas Company on Form 10-Q for
the quarter ended June 30, 1998, incorporated herein by this reference.)
10.13 1989 Non-Employee Director Stock Option Plan (incorporated by reference to
Exhibit A to the Registrant's proxy statement for the annual meeting of
shareholders held January 9, 1989, heretofore filed with the Securities
and Exchange Commission).
10.14 1989 Stock Option Plan (incorporated by reference to Exhibit B to the
Registrant's proxy statement for the annual meeting of shareholders held
January 9, 1989, heretofore filed with the Securities and Exchange
Commission).
IV-3
<PAGE>
10.15 Non-Employee Director Stock Plan (incorporated by reference to Exhibit
4.3 to Form S-8 (Registration No. 333-25415).
10.16 1998 Performance Share Plan. (Filed as Exhibit 10.13 to the report of the
Registrant on Form 10-K for the year ended September 30, 1998,
incorporated herein by this reference.)
10.17 Performance Share Award Agreement dated January 1, 1999 between James H.
Dodge, Chairman, President, and Chief Executive Officer and the
Registrant. (Filed as Exhibit 10a to the report of the Registrant on Form
10-Q for the quarter ended December 31, 1998, incorporated herein by this
reference.)
10.18 Performance Share Award Agreement dated January 1, 1999 between James
DeMetro, Senior Vice President and the Registrant. (Filed as Exhibit 10b
to the report of the Registrant on Form 10-Q for the quarter ended
December 31, 1998, incorporated herein by this reference.)
10.19 Performance Share Award Agreement dated January 1, 1999 between Gary S.
Gillheeney, Senior Vice President, Chief Financial Officer, Treasurer and
Assistant Secretary and the Registrant. (Filed as Exhibit 10c to the
report of the Registrant on Form 10-Q for the quarter ended December 31,
1998, incorporated herein by this reference.)
10.20 Performance Share Award Agreement dated January 1, 1999 between Robert W.
Owens, Senior Vice President and the Registrant. (Filed as Exhibit 10d to
the report of the Registrant on Form 10-Q for the quarter ended December
31, 1998, incorporated herein by this reference.)
10.21 Performance Share Award Agreement dated January 1, 1999 between Susann G.
Mark, Vice President, General Counsel, and Secretary and the Registrant.
(Filed as Exhibit 10e to the report of the Registrant on Form 10-Q for
the quarter ended December 31, 1998, incorporated herein by this
reference.)
10.22 Liquified Natural Gas Service Precedent Agreement dated December 11, 1998
between Algonquin LNG, Inc. and the Registrant. (Filed as exhibit 10a to
the report of The Providence Gas Company in Form 10-Q for the quarter
ended December 31, 1998, incorporated herein by this reference.)
13 Portions of the Annual Report to Shareholders for the fiscal year ended
September 30, 1999. (Pages 1 through 41)
21 Subsidiaries of the Registrant.
IV-4
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors of
Providence Energy Corporation:
We have audited, in accordance with generally accepted auditing standards, the
consolidated financial statements included in Providence Energy Corporation's
annual report to shareholders incorporated by reference in this Form 10-K, and
have issued our report thereon dated November 2, 1999. Our audit was made for
the purpose of forming an opinion on those statements taken as a whole. The
schedule listed in the accompanying index to the financial statements is the
responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly states, in all material respects, the financial data required to
be set forth therein, in relation to the basic financial statements taken as a
whole.
Arthur Andersen LLP
Boston, Massachusetts
November 2, 1999 (except for the information discussed in Note 2, as to which
the date is November 16, 1999)
IV-5
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors of
Providence Energy Corporation:
As independent public accountants, we hereby consent to the incorporation by
reference of our report dated November 2, 1999 (except for the information
discussed in Note 2, as to which the date is November 16, 1999), included in
this Form 10-K, into the Company's previously filed Registration Statements on
Forms S-3, Registration No. 33-62318; S-3, Registration No. 33-70086; S-3,
Registration No. 33-31768; S-3, Registration No. 333-70997; S-3, Registration
No. 333-84379; S-8, Registration No. 33-31769; S-8, Registration No. 33-31770;
S-8, Registration No. 33-43031; S-8, Registration No. 33-04209; S-8,
Registration No. 333-25415; S-8, Registration No. 333-84311; S-8, Registration
No. 333-84301; and S-8, Registration No. 333-84383. It should be noted that we
have not audited any financial statements of the Company subsequent to September
30, 1999, or performed any audit procedures subsequent to the date of our
report.
Arthur Andersen LLP
/s/ Arthur Andersen LLP
- -----------------------
Boston, Massachusetts
December 21,1999
IV-6
<PAGE>
Supplemental Schedule
PROVIDENCE ENERGY CORPORATION Schedule II
-----------------------------
RESERVES FOR THE YEARS ENDED
----------------------------
SEPTEMBER 30, 1999, SEPTEMBER 30, 1998 AND SEPTEMBER 30, 1997
-------------------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
Charge
for
Which
Additions Reserves
Balance Charged Other Were Balance
9/30/98 to Operations Add (Deduct) Created 9/30/99
------- ------------- ------------ ------- -------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Accounts receivable
Allowance for
doubtful accounts $ 2,604 $ 4,756 $ 150 (D) $ 4,654 $ 2,856
Allowance for lease
receivables -
current 26 - - - 26
other 90 3 (90)(D) 2 1
------- ----------- ------- -------- -------
Total $ 2,720 $ 4,759 $ 60 $ 4,656 $ 2,883
======= =========== ======= ======== =======
Allowance for lease
receivables -
long-term $ 372 $ 72 $ (183)(D) $ 75 $ 186
======= =========== ======= ======== =======
DEFERRED CREDITS AND
RESERVES:
Accumulated deferred
income taxes $22,292 $ 888 $ 971 (F) $ - $24,151
------- ----------- -------- -------- -------
Unamortized investment
tax credit 2,217 - - 158 2,059
------- ----------- -------- -------- -------
Accrued pension 5,812 427 796 (A) 53 6,982
------- ----------- -------- -------- -------
Accrued environmental 1,750 - (1,750)(C) - -
------- ----------- -------- -------- -------
Other-
Liability and
damage reserve 479 126 74 (E) 185 494
Other 52 - - 7 45
------- ----------- -------- -------- -------
Total other 531 126 74 192 539
------- ----------- -------- -------- -------
Total deferred
credits and
reserves $32,602 $ 1,441 $ 91 $ 403 $33,731
======= =========== ======== ======== =======
</TABLE>
IV-7
<PAGE>
Schedule II (cont'd)
<TABLE>
<CAPTION>
Charge
for
Which
Additions Reserves
Balance Charged Other Were Balance
9/30/97 to Operations Add (Deduct) Created 9/30/98
------- ------------- ------------ ------- -------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Accounts receivable
Allowance for
doubtful accounts $ 1,811 $ 5,063 $ 47 $ 4,317 $ 2,604
Allowance for lease
receivables -
current 27 - - 1 26
other 48 42 - - 90
------- ------- ------- ------- -------
Total $ 1,886 $ 5,105 $ 47 $ 4,318 $ 2,720
======= ======= ======= ======= =======
Allowance for lease
receivables -
long-term $ 401 $ 72 $ - $ 101 $ 372
======= ======= ======= ======= =======
DEFERRED CREDITS AND
RESERVES:
Accumulated deferred
income taxes $21,495 $ 1,131 $ (334)(E) $ - $22,292
------- ------- ------- ------- -------
Unamortized investment
tax credit 2,375 - - 158 2,217
------- ------- ------- ------- -------
Accrued pension 6,740 84 (961)(A) 51 5,812
------- ------- ------- ------- -------
Accrued environmental 1,750 - - - 1,750
------- ------- ------- ------- -------
Other-
Liability and
damage reserve 621 (21) - 121 479
Other 58 - - 6 52
------- ------- ------- ------- -------
Total other 679 (21) - 127 531
------- ------- ------- ------- -------
Total deferred
credits and
reserves $33,039 $ 1,194 $(1,295) $ 336 $32,602
======= ======= ======= ======= =======
</TABLE>
IV-8
<PAGE>
Schedule II (cont'd)
<TABLE>
<CAPTION>
Charge
for
Which
Additions Reserves
Balance Charged Other Were Balance
9/30/96 to Operations Add (Deduct) Created 9/30/97
------- ------------- ------------ ------- -------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Accounts receivable
Allowance for
doubtful accounts $ 3,195 $ 5,200 $ - $ 6,584 $ 1,811
Allowance for lease
receivables -
current 27 1 - 1 27
other 9 94 - 55 48
------- ------- ------- ------- -------
Total $ 3,231 $ 5,295 $ - $ 6,640 $ 1,886
======= ======= ======= ======= =======
Allowance for lease
receivables -
long-term $ 403 $ 138 $ - $ 140 $ 401
======= ======= ======= ======= =======
DEFERRED CREDITS AND
RESERVES:
Accumulated deferred
income taxes $20,713 $ 703 $ 79 (E) $ - $21,495
------- ------- ------- ------- -------
Unamortized investment
tax credit 2,533 - - 158 2,375
------- ------- ------- ------- -------
Accrued pension 5,670 634 475 (A) 39 6,740
------- ------- ------- ------- -------
Accrued environmental 1,300 - 450 (B) - 1,750
------- ------- ------- ------- -------
Other-
Liability and
damage reserve 561 281 - 221 621
Other 80 (3) - 19 58
------- ------- ------- ------- -------
Total other 641 278 - 240 679
------- ------- ------- ------- -------
Total deferred
credits and
reserves $30,857 $ 1,615 $ 1,004 $ 437 $33,039
======= ======= ======= ======= =======
</TABLE>
(A) Adjustment to the regulatory pension liability.
(B) Accrual for environmental investigation and remediation costs.
(C) A reclassification of environmental liabilities from long-term to
short-term.
(D) Account reclassifications during system conversion.
(E) Reclassify amounts due to the Registrant to a receivable account.
(F) Represents offset for certain SFAS No. 109 activity in the regulatory asset
and liability accounts, as well as reclassifications among tax accounts
based on tax return as filed and estimated current year tax activity.
IV-9
<PAGE>
INCORPORATION BY REFERENCE INTO REGISTRATION STATEMENTS ON FORM S-8
For the purposes of complying with the amendments to the rules governing
Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the
Registrant hereby undertakes as follows, which undertaking shall be incorporated
by reference into Part II of Registrant's Registration Statements on Form S-8
Nos. 33-31769, 33-31770, 33-43031, 33-04209, 333-25415, 333-84311, 333-84301,
and 333-84383.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
of 1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant of expenses incurred or paid by a director, officer or controlling
person of the Registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the Securities being registered, the Registrant will, unless in
the opinion of its counsel that matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the Act,
will be governed by the final adjudication of such issue.
IV-10
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PROVIDENCE ENERGY CORPORATION
By: /s/ JAMES H. DODGE
----------------------------------------
James H. Dodge, Chairman,
President and CEO
Date: December 21, 1999
----------------------------------------
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.
<TABLE>
<CAPTION>
Signature Title Date
- --------- ----- ----
<S> <C> <C>
/s/ JAMES H. DODGE Chairman, President and CEO 12/21/99
- -------------------------- --------
James H. Dodge (Principal Executive Officer)
/s/ KENNETH W. HOGAN Vice President, Chief Financial 12/21/99
- -------------------------- --------
Kenneth W. Hogan Officer, and Treasurer
/s/ GILBERT R. BODELL, JR. Director 12/21/99
- -------------------------- --------
Gilbert R. Bodell, Jr.
/s/ JOHN H. HOWLAND Director 12/21/99
- -------------------------- --------
John H. Howland
/s/ DOUGLAS H. JOHNSON Director 12/21/99
- -------------------------- --------
Douglas H. Johnson
/s/ WILLIAM KREYKES Director 12/21/99
- -------------------------- --------
William Kreykes
/s/ PAUL F. LEVY Director 12/21/99
- -------------------------- --------
Paul F. Levy
/s/ M. ANNE SZOSTAK Director 12/21/99
- -------------------------- --------
M. Anne Szostak
/s/ KENNETH W. WASHBURN Director 12/21/99
- -------------------------- --------
Kenneth W. Washburn
/s/ W. EDWARD WOOD Director 12/21/99
- -------------------------- --------
W. Edward Wood
</TABLE>
IV-11
<PAGE>
Exhibit 10.11
Providence Energy Corporation
Change of Control Agreement
This AGREEMENT is made, entered into, and is effective as of this 9th day of
July, 1999 (hereinafter referred to as the "Effective Date"), by and between
Providence Energy Corporation, together with its subsidiaries and affiliates
(hereinafter referred to as the "Company"), a Rhode Island corporation having
its principal offices at Providence Rhode Island and Royalynne J. Hourihan
(hereinafter referred to as the "Executive").
WHEREAS, the Executive has been offered employment by the Company in the
capacity of Vice President of Human Resources of the Company;
WHEREAS, the Executive possesses considerable experience and knowledge of
business affairs and operations and, as such, the Executive has unique
qualifications to act in an executive capacity for the Company; and
WHEREAS, the Company is desirous of encouraging the full attention by the
Executive to his/her duties in his/her capacity aforesaid and wishes to make
provisions for certain protections of the Executive in the event of the
termination of his/her employment under specified conditions.
NOW THEREFORE, in consideration of the foregoing and of the mutual covenants and
agreements of the parties set forth in this Agreement, and of other good and
valuable consideration the receipt and sufficiency of which are hereby
acknowledged, the parties hereto, intending to be legally bound, agree as
follows:
Section 1 Termination for Good Reason. At any time during the six (6) full
calendar month period prior to the effective date of a Change in Control (as
defined in Section 2.2) or the twenty four (24) month period following the
effective date of a Change in Control (as defined in Section 2.2), the Executive
may terminate this Agreement for Good Reason (as defined below) by giving the
Board of Directors of the Company thirty (30) calendar days written notice of
intent to terminate, which notice sets forth in reasonable detail the facts and
circumstances claimed to provide a basis for such termination.
Upon the expiration of the thirty (30) day notice period, the Good Reason
termination shall become effective, and the Company shall pay and provide to the
Executive the benefits set forth in Section 2.1 herein.
Good Reason shall mean, without the Executive's express written consent, the
occurrence of any one or more of the following:
<PAGE>
(a) The assignment of the Executive to duties materially inconsistent with the
Executive's authorities, duties, responsibilities, and status as an officer
of the Company, or a reduction or alteration in the nature or status of the
Executive's authorities, duties, or responsibilities from those in effect
during the immediately preceding fiscal year;
(b) The Company's requiring the Executive to be based at a location which is at
least fifty (50) miles further from the Executive's current primary
residence than is such residence from the Company's current headquarters,
except for required travel on the Company's business to an extent
substantially consistent with the Executive's business obligations as of
the Effective Date;
(c) A reduction by the Company in the Executive's Base Salary as in effect on
the Effective Date, which Base Salary is One Hundred Fifteen Thousand
Dollars ($115,000.00) as of the Effective Date, or a reduction from any
subsequent increase to the Base Salary as of the Effective Date;
(d) A material reduction in the Executive's level of participation in any of
the Company's short- and/or long-term incentive compensation plans, or
employee benefit or retirement plans, policies, practices, or arrangements
in which the Executive participates as of the Effective Date; provided,
however, that reductions in the levels of participation in any such plans
shall not be deemed to be "Good Reason" if the Executive's reduced level of
participation in each such program remains substantially consistent with
the average level of participation of other executives who have positions
commensurate with the Executive's position; or
(e) The failure of the Company to obtain a satisfactory agreement from any
successor to the Company to assume and agree to perform this Agreement, as
contemplated in Section 5.1 herein.
Upon a termination for Good Reason within the six (6) full calendar month period
prior to the effective date of a Change in Control, or within the twenty-four
(24) months following the effective date of a Change in Control, the Executive
shall be entitled to receive the payments and benefits set forth in Section 2.1
herein.
The Executive's right to terminate employment for Good Reason shall not be
affected by the Executive's incapacity due to physical or mental illness. The
Executive's continued employment shall not constitute consent to, or a waiver of
rights with respect to, any circumstance constituting Good Reason herein.
2
<PAGE>
Section 2
Change in Control
2.1 Employment Terminations in Connection with a Change in Control. In the
event of a Qualifying Termination (as defined below) within six (6) full
calendar months prior to the effective date of a Change in Control, or within
twenty-four (24) months following the effective date of a Change in Control,
then in lieu of all other benefits provided to the Executive under the
provisions of this Agreement, the Company shall pay to the Executive in a lump
sum payment and provide him/her with the following severance benefits
(hereinafter referred to as the "Severance Benefits"):
(a) An amount equal to two (2) times the highest rate of the Executive's
annualized Base Salary rate in effect at any time up to and including the
effective date of termination;
(b) An amount equal to two (2) times the Executive's target incentive award
(both cash and long-term) established for the fiscal year in which the
Executive's effective date of termination occurs;
(c) An amount equal to the Executive's unpaid Base Salary and accrued vacation
pay through the effective date of termination;
(d) An amount equal to the Executive's unpaid targeted annual bonus,
established for the plan year in which the Executive's effective date of
termination occurs, multiplied by a fraction, the numerator of which is the
number of completed days in the then-existing fiscal year through the
effective date of termination, and the denominator of which is three
hundred sixty-five (365);
(e) A continuation of the welfare benefits of medical insurance, dental
insurance, and group term life insurance for two (2) full years after the
effective date of termination. These benefits shall be provided to the
Executive at the same premium cost, and at the same coverage level, as in
effect as of the Executive's effective date of termination. However, in the
event the premium cost and/or level of coverage shall change for all
employees of the Company, the cost and/or coverage level, likewise, shall
change for the Executive in a corresponding manner.
The continuation of these welfare benefits shall be discontinued prior to
the end of the two (2) year period in the event the Executive has available
substantially similar benefits from a subsequent employer, as determined by
the Company's Board of Directors or the Board's designee.
3
<PAGE>
(f) A lump-sum cash payment of the actuarial present value equivalent of the
aggregate benefits accrued by the Executive as of the effective date of
termination under the terms of any and all supplemental retirement plans in
which the Executive participates. For purposes of determining "final
average pay" under such programs, the Executive's actual pay history as of
the effective date of termination shall be used.
For purposes of this Section 2, a Qualifying Termination shall mean any
termination of the Executive's employment other than: (1) by the Company for
Cause; (2) by reason of death, Disability, or Retirement (as such term is then
defined in the Company's tax qualified defined benefit retirement plan; provided
that a termination which qualifies as a Retirement and which would otherwise
qualify as a termination for Good Reason under Section 1 herein will be deemed
to be a Qualifying Termination).
2.2 Definition of "Change in Control." A Change in Control of the Company shall
be deemed to have occurred as of the first day any one or more of the following
conditions shall have been satisfied:
(a) Any individual, corporation (other than the Company), partnership, trust,
association, pool, syndicate, or any other entity or any group of persons
acting in concert becomes the beneficial owner, as that concept is defined
in Rule 13d-3 promulgated by the Securities and Exchange Commission under
the Securities Exchange Act of 1934, of securities of the Company
possessing twenty percent (20%) or more of the voting power for the
election of directors of the Company;
(b) There shall be consummated any consolidation, merger, or other business
combination involving the Company or the securities of the Company in which
holders of voting securities of the Company immediately prior to such
consummation own, as a group, immediately after such consummation, voting
securities of the Company (or, if the Company does not survive such
transaction, voting securities of the corporation surviving such
transaction) having less than sixty percent (60%) of the total voting power
in an election of directors of the Company (or such other surviving
corporation);
(c) During any period of two (2) consecutive years, individuals who at the
beginning of such period constitute the directors of the Company cease for
any reason to constitute at least a majority thereof unless the election,
or the nomination for election by the Company's shareholders, of each new
director of the Company was approved by a vote of at least two-thirds (2/3)
of the directors of the Company then still in office who were directors of
the Company at the beginning of any such period; or
4
<PAGE>
(d) There shall be consummated any sale, lease, exchange, or other transfer (in
one transaction or a series of related transactions) of all, or
substantially all, of the assets of the Company (on a consolidated basis)
to a party which is not controlled by or under common control with the
Company.
2.3 Excise Tax Equalization Payment. In the event that the Executive becomes
entitled to Severance Benefits or any other payment or benefit under this Plan,
or under any other agreement with or plan of the Company (in the aggregate, the
"Total Payments"), if any of the Total Payments will be subject to the tax (the
"Excise Tax") imposed by Section 4999 of the Code (or any similar tax that may
hereafter be imposed), the Company shall pay to the Executive in cash an
additional amount (the "Gross-Up Payment") such that the net amount retained by
the Executive after deduction of any Excise Tax upon the Total Payments and any
Federal, state and local income tax and Excise Tax upon the Gross-Up Payment
provided for by this Section 7.3 (including FICA and FUTA), shall be equal to
the Total Payments. Such payment shall be made by the Company to the Executive
as soon as practical following the effective date of termination, but in no
event beyond thirty (30) days from such date.
2.4 Tax Computation. For purposes of determining whether any of the Total
Payments will be subject to the Excise Tax and the amounts of such Excise Tax:
(a) Any other payments or benefits received or to be received by the Executive
in connection with a Change in Control of the Company or the Executive's
termination of employment (whether pursuant to the terms of this Plan or
any other plan, arrangement, or agreement with the Company, or with any
person (which shall have the meaning set forth in Section 3(a)(9) of the
Securities Exchange Act of 1934, including a "group" as defined in Section
13(d) therein) whose actions result in a Change in Control of the Company
or any person affiliated with the Company or such persons) shall be treated
as "parachute payments" within the meaning of Section 280G(b)(2) of the
Code, and all "excess parachute payments" within the meaning of Section
280G(b)(1) shall be treated as subject to the Excise Tax, unless in the
opinion of tax counsel as supported by the Company's independent auditors
and acceptable to the Executive, such other payments or benefits (in whole
or in part) do not constitute parachute payments, or unless such excess
parachute payments (in whole or in part) represent reasonable compensation
for services actually rendered within the meaning of Section 280G(b)(4) of
the Code in excess of the base amount within the meaning of Section
280G(b)(3) of the Code, or are otherwise not subject to the Excise Tax;
(b) The amount of the Total Payments which shall be treated as subject to the
Excise Tax shall be equal to the lesser of: (i) the total amount of the
Total Payments; or (ii) the amount of excess parachute payments within the
meaning of Section 280G(b)(1) (after applying clause (a) above); and
5
<PAGE>
(c) The value of any noncash benefits or any deferred payment or benefit shall
be determined by the Company's independent auditors in accordance with the
principles of Sections 280G(d)(3) and (4) of the Code.
For purposes of determining the amount of the Gross-Up Payment, the Executive
shall be deemed to pay federal income taxes at the highest marginal rate of
Federal income taxation in the calendar year in which the Gross-Up Payment is to
be made, and state and local income taxes at the highest marginal rate of
taxation in the state and locality of the Executive's residence on the effective
date of termination, net of the maximum reduction in federal income taxes which
could be obtained from deduction of such state and local taxes.
2.5 Subsequent Recalculation. In the event the Internal Revenue Service adjusts
the computation of the Company under Section 2.4 herein so that the Executive
did not receive the greatest net benefit, the Company shall reimburse the
Executive for the full amount necessary to make the Executive whole, plus a
market rate of interest, as determined by the Human Resources and Planning
Committee.
2.6 Payment of Legal Fees. To the extent permitted by law, the Company shall
pay all legal fees, costs of litigation, prejudgment interest, and other
expenses incurred in good faith by the Executive as a result of the Company's
refusal to provide the severance benefits under this Section 2 to which the
Executive becomes entitled under this Agreement, or as a result of the Company's
contesting the validity, enforceability, or interpretation of this Agreement, or
as a result of any conflict (including conflicts related to the calculation of
parachute payments) between the parties pertaining to their Agreement.
Section 3. Indemnification
The Company hereby covenants and agrees to indemnify and hold harmless the
Executive fully, completely, and absolutely against and in respect to any and
all actions, suits, proceedings, claims, demands, judgments, costs, expenses
(including attorney's fees), losses, and damages resulting from the Executive's
good faith performance of his/her duties and obligations under the terms of this
Agreement.
Section 4. Outplacement Assistance
Following a termination of the Executive's employment as described in Sections 1
or 2 herein, the Executive shall be reimbursed by the Company for the costs of
all outplacement services obtained by the Executive within the six (6) months
prior and two (2) year periods after the effective date of termination;
provided, however, that the total reimbursement shall be limited to an amount
equal to fifteen percent (15%) of the Executive's Base Salary as of the
effective date of termination.
6
<PAGE>
Section 5. Assignment
5.1 Assignment by Company. This Agreement may and shall be assigned or
transferred to, and shall be binding upon and shall inure to the benefit of, any
successor of the Company, and any such successor shall be deemed substituted for
all purposes of the "Company" under the terms of this Agreement. As used in this
Agreement, the term "successor" shall mean any person, firm, corporation, or
business entity which at any time, whether by merger, purchase, or otherwise,
acquires all or essentially all of the assets of business of the Company.
Notwithstanding such assignment, the Company shall remain, with such successor,
jointly and severally liable for all its obligations hereunder.
Failure of the Company to obtain such agreement prior to the effectiveness of
any such succession shall be a breach of this Agreement and shall immediately
entitle the Executive to compensation from the Company in the same amount and on
the same terms as the Executive would be entitled in the event of a termination
by the Company, as provided in Section 2.1 herein.
Except as herein provided, this Agreement may not otherwise be assigned by the
Company.
5.2 Assignment by Executive. This Agreement shall inure to the benefit of and
be enforceable by the Executive's personal or legal representatives, executors,
and administrators, successors, heirs, distributees, devisees, and legatees. If
the Executive should die while any amounts payable to the Executive hereunder
remain outstanding, all such amounts, unless otherwise provided herein, shall be
paid in accordance with the terms of this Agreement to the Executive's devisee,
legatee, or other designee or, in the absence of such designee, to the
Executive's estate.
Section 6. Dispute Resolution and Notice
6.1 Arbitration. Any dispute or controversy arising under or in connection
with this Agreement shall be settled by arbitration, conducted before a panel of
three (3) arbitrators sitting in a location selected by the Executive within
fifty (50) miles from the location of his/her employment with the Company, in
accordance with the rules of the American Arbitration Association then in
effect.
Judgment may be entered on the award of the arbitrator in any court having
proper jurisdiction. All expenses of such arbitration, including the fees and
expenses of the counsel for the Executive, shall be borne by the Company.
6.2 Notice. Any notices, requests, demands, or other communications provided
for by this Agreement shall be sufficient if in writing and if sent by
registered or certified mail to the Executive at the last address she has filed
in writing with the Company or, in the case of the Company, at its principal
offices.
7
<PAGE>
Section 7. Miscellaneous
7.1 Entire Agreement. This Agreement supersedes any prior agreements or
understandings, oral or written, between the parties hereto or between the
Executive and the Company, with respect to the subject matter hereof and
constitutes the entire Agreement of the parties with respect thereto.
7.2 Modification. This Agreement shall not be varied, altered, modified,
canceled, changed, or in any way amended except by mutual agreement of the
parties in a written instrument executed by the parties hereto or their legal
representatives.
7.3 Severability. In the event that any provision or portion of this Agreement
shall be determined to be invalid or unenforceable for any reason, the remaining
provisions of this Agreement shall be unaffected thereby and shall remain in
full force and effect.
7.4 Counterparts. This Agreement may be executed in one or more counterparts,
each of which shall be deemed to be an original, but all of which together will
constitute one and the same Agreement.
7.5 Tax Withholding. The Company may withhold from any benefits payable under
this Agreement all federal, state, city, or other taxes as may be required
pursuant to any law or govern-mental regulation or ruling.
7.6 Beneficiaries. The Executive may designate one or more persons or entities
as the primary and/or contingent beneficiaries of any amounts to be received
under this Agreement. Such designation must be in the form of a signed writing
acceptable to the Board or the Board's designee. The Executive may make or
change such designation at any time.
Section 8. Governing Law
To the extent not preempted by federal law, the provisions of this Agreement
shall be construed and enforced in accordance with the laws of the state of
Rhode Island.
IN WITNESS WHEREOF, the Executive and the Company (pursuant to a resolution
adopted at a duly constituted meeting of its Board of Directors) have executed
this Agreement, as of the day and year first above written.
Executive:
_____________________________________
ATTEST Providence Energy Corporation
By:______________________ By:__________________________________
Corporate Secretary Chairman, President and CEO
8
<PAGE>
Exhibit 13
Management's Discussion and Analysis
of Financial Condition and Results of Operations
Summary
The Company's energy revenues, operating margin, and net income for the
twelve months ended September 30 are as follows:
(000's)
Percent
1999 1998 Change Change
- ----------------------------------------------------------------
Energy Revenues $225,029 $222,112 $2,917 1.3
Operating Margin 105,986 99,121 6,865 6.9
Net Income 8,425 6,442 1,983 30.8
Results of Operations - 1999 Versus 1998
Operating Margin
During the current year, weather was 1.3 percent warmer than last year. The
warmer temperatures served to decrease margin by approximately $.3 million
compared to last year. Despite warmer than normal weather for the year, margin
earned increased as a result of a one-time write-off of $1.5 million in 1998 of
previously deferred gas costs in connection with Energize RI, which became
effective October 1, 1997. Offsetting the warmer weather for the year was $2.0
million of the $2.45 million 1998 exogenous changes recovery, as discussed in
Note 10 in the accompanying Consolidated Financial Statements. Also, ProvGas'
customer growth has resulted in approximately $.6 million of additional margin,
and non-firm margin increased $.4 million when compared with last year.
During April and May 1999, the Algonquin LNG, Inc. tank in Providence was
completely emptied in order to allow access for internal inspection and repairs,
which were completed in September 1999. As a result, 335 million cubic feet of
LNG was vaporized from the tank into the ProvGas distribution system. Since the
vaporized gas had a heat energy content approximately 30 percent higher than the
pipeline supplies normally used, ProvGas' customers' metered volumes were lower
because a smaller volume of gas produced the same quantity of energy. This in
turn adversely impacted margin.
Non-regulated operating margin increased by $2.7 million compared to last
year. The margin earned from oil sales increased by approximately $1.4 million
in 1999 due primarily to the market price of oil and to customer growth.
Natural gas business volumes increased by approximately 50 percent. This
increase was a result of 43 percent customer growth as well as an increase in
dual fuel sales volumes. The receipt of contractually-determined developer fees
related to the Providence Place Mall also contributed to the increase in non-
regulated operating margin.
Operating and Maintenance Expenses
Overall, the Company's operating and maintenance expenses increased
approximately $1.1 million or 2.0 percent versus last year.
ProvGas' operating and maintenance expenses decreased by approximately $.3
million. This decrease was partially attributable to cost control measures which
were implemented in response to warmer weather. These cost control measures were
able to offset a substantial portion of the cost of living and negotiated union
contract salary increases of approximately $.9 million, as well as inflationary
increases in general expenses of approximately $.5 million. Also contributing
to the decrease was a one-time reimbursement of approximately $.9 million for
costs incurred under a FERC-approved contract with Algonquin.
The Company's operating and maintenance expenses have increased primarily due
to the acquisition of oil companies and the expansion of the energy marketing
business.
The Company continually reviews its operating expenses in order to keep
expenses as low as possible; however, expenses can vary from year to year.
Page 1
<PAGE>
Depreciation and Amortization
Depreciation and amortization expense increased approximately $3.0 million or
20.8 percent versus last year. This increase is the result of increased capital
spending for Energize RI commitments; technology projects; Year 2000 costs,
which were capitalized as authorized under the provisions of Energize RI; and
the amortization of environmental costs. Effective October 1, 1997, ProvGas
began amortizing environmental and Year 2000 costs over 10-year and 5-year
periods, respectively, in accordance with the levels authorized in Energize RI.
ProvGas will have increased environmental amortization expense in future years
as its planned environmental remediation program continues. Also, amortization
expense for Year 2000 costs will increase in the future as higher levels of
costs have been incurred from those originally anticipated.
Taxes
Taxes increased approximately $.6 million or 4.1 percent versus last year.
The increase in taxes is primarily due to local property taxes which have
increased as a result of capital spending.
Other Income (Loss)
Other income has increased approximately $1.1 million versus last year.
Since February 1999, ProvGas has provided monitoring and communication
services to the PNGTS. Under its contract, ProvGas hosts PNGTS' Supervisory
Control and Data Acquisition System, continually monitoring system operations
and receiving and forwarding emergency phone calls. ProvGas has recognized as
other income approximately $.2 million in fees for the performance of these
services. The contract is a one year renewable contract, subject to termination
by either party upon six months prior written notice. PNGTS has notified
ProvGas that they will put the contract to bid for the contract year beginning
February 17, 2000.
In a decision issued September 1, 1998, the Division rejected allegations
made in a complaint brought by Aurora Natural Gas that ProvGas provided advance
information and undue preference in pricing to its marketing affiliate,
ProvEnergy Services, in violation of the Division's regulations. As part of its
investigation, the Division ordered marketer refunds of approximately $.3
million. The Division ordered this refund based on its belief that an unfair
rate was charged to customers who did not have operational telemeters in place
when they began service under the transportation tariff. ProvGas filed a Request
for Reconsideration and Rehearing, and on December 15, 1998, the Division issued
a Reconsideration Order that rescinded the fines stemming from five of the
original 23 violations of the Regulations for Utility Interaction with Gas
Marketers. The Division further offered the Company an opportunity to
demonstrate its claim that the ordered refunds would place FT-2 marketers in a
better position than marketers who served FT-1 customers.
On May 6, 1999, ProvGas and Aurora jointly submitted a Stipulation and
Settlement to the Division that: (i) Aurora's complaint in this proceeding is
dismissed; (ii) the prior orders of the Division in the proceeding are
dismissed; (iii) no refunds by ProvGas are required or appropriate in connection
with the proceeding; and (iv) ProvGas does not contest the payment of $18,000 to
the Division in connection with this proceeding. Following a June 16, 1999
hearing on the Stipulation, the Division issued an order on September 23, 1999,
approving the Stipulation and Settlement provided that ProvGas ratepayers are
held harmless from the financial transactions stemming from the settlement, that
ProvGas withdraw its appeal in Providence County Superior Court, and that the
Division's prior orders are vacated as described in the order. ProvGas and
Aurora accepted the Division's order. This decision resulted in the reversal of
the reserve established under the original order, which contributed to the
increase in other income this year.
Interest Expense
Interest expense increased approximately $.6 million or 7.0 percent over last
year. Long-term interest expense increased as a result of ProvGas' Series T
First Mortgage Bond issuance in February 1999, which refinanced short-term
borrowings. The Series T issuance enabled the Company to secure a favorable
long-term financing rate. However, this increase was partially offset by the
Series S First Mortgage Bond issuance in April 1998, which refinanced higher
cost long-term debt.
Page 2
<PAGE>
Future Outlook
A) Regulatory
Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than 7.0
percent, annually on its average common equity, which is capped at $81.0
million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000,
respectively. In the event that ProvGas earns in excess of 10.9 percent or less
than 7.0 percent, ProvGas will defer revenues or costs through a deferred
revenue account over the term of the Plan. Any balance in the deferred revenue
account at the end of the Plan will be refunded to or recovered from customers
in a manner to be determined by all parties to the Plan and approved by the
RIPUC.
As part of Energize RI, ProvGas is permitted to file annually with the
Division for the recovery of exogenous changes which may occur during the three-
year term of the Plan. Exogenous changes are defined as "...significant
increases or decreases in ProvGas' costs or revenues which are beyond ProvGas'
reasonable control." Any disputes between ProvGas and the Division regarding
either the nature or quantification of the exogenous changes are to be resolved
by the RIPUC. The impact of any exogenous changes will be debited or credited
to a regulatory asset or liability account throughout the term of Energize RI
and will be recovered or refunded at the expiration of the Plan through a method
to be determined.
In fiscal 1998, ProvGas did not earn its allowed rate of return primarily as
a result of the extremely warm winter weather and the loss of non-firm margin
resulting from the competitive price of oil in the industrial market. ProvGas
believed the causes of these two events were beyond its reasonable control and
thus deemed them to be exogenous changes. In March 1999, ProvGas reached an
agreement with the Division which allowed it to recover $2.45 million in revenue
losses attributable to exogenous changes experienced by ProvGas in fiscal 1998.
The RIPUC reviewed the exogenous changes agreement to ensure consistency with
the terms of Energize RI and affirmed the agreement at its May 28, 1999 open
meeting.
During fiscal 1999, ProvGas recognized into revenue $2.45 million for the
exogenous changes recovery, and at year-end has deferred approximately $.5
million of revenue under the provisions of the earnings cap of Energize RI.
ProvGas intends to file for recovery of exogenous changes experienced in 1999
which resulted from factors similar to 1998. Absent further exogenous recovery
and/or other factors such as colder than normal weather, ProvGas' ability to
earn a 10.9 percent return on average common equity in the final year of
Energize RI is substantially impaired.
On August 31, 1999, ProvGas' settlement agreement for enhancements to its
Business Choice program was approved by the RIPUC in Docket 2902 and became
effective September 1, 1999. Specifically, there will now be rolling enrollment
for transportation service, which will allow customers to execute transportation
agreements throughout the year, rather than during limited enrollment periods.
The program now has approximately 1,700 firm transportation customers with
annual deliveries of over 5 billion cubic feet per year, which is approximately
25 percent of ProvGas' total annual firm deliveries. There are 14 marketers
serving ProvGas' customers and transporting on the system. Additional
enhancements to the Business Choice program were filed with the RIPUC under a
supplemental settlement agreement in Docket 2902 on October 8, 1999 and were
approved on October 27, 1999. These enhancements do not generate additional
revenue.
B) Business Opportunities
The Company's non-regulated operation continues to increase its contribution
to operating margin by adding customers and sales volume, although it continues
to generate a net loss consistent with the start-up of new businesses. The
Company intends to continue to grow its residential oil customer base through
future customer acquisitions to build the operational scale needed to compete
effectively in the marketplace. Furthermore, the New England gas utilities
continue to unbundle the sale of the gas commodity from the distribution of that
gas, which will also enable future growth.
The Company's joint venture to provide electricity, HVAC, and related
services for most of the Mall began with the Mall's August 1999 opening.
Page 3
<PAGE>
Energize RI provides opportunities for ProvGas to expand sales. For example,
high pressure service to Quonset/Davisville Industrial Port & Commerce Park, a
key area for State economic development, provides opportunities for sales growth
as commercial and industrial businesses locate within the park. In addition,
Demand Side Management, an equipment rebate program, provides opportunities to
expand sales to non-traditional applications, such as air conditioning and fuel
cells. ProvGas has redirected its sales and marketing efforts to leverage
Energize RI, as well as other opportunities to promote sales growth within its
service territory.
C) Merger Agreement
On November 15, 1999, the Company and Southern Union announced that their
Boards of Directors had unanimously approved a definitive merger agreement. See
Note 2 in the accompanying Consolidated Financial Statements for additional
information.
D) New Accounting Pronouncements
Please refer to Note 18 of the accompanying Consolidated Financial
Statements.
Results of Operations - 1998 versus 1997
Operating Margin
During 1998, ProvGas experienced weather that was 8.0 percent warmer than
1997. The warmer temperatures resulted in decreased margin of approximately $4.0
million compared to 1997. Offsetting the warmer than normal weather was $7.2
million of margin generated under Energize RI. The components of this additional
margin included $10.4 million associated with adjusting the GCC offset by the
funding of the Low-Income and Demand Side Management programs of $1.7 million
and the write-off of $1.5 million of previously deferred gas costs. In 1997,
ProvGas funded the Demand Side Management and Low-Income Weatherization programs
under the IRP for $.7 million. Additionally, non-firm margin decreased $2.2
million when compared with 1997 due to an unfavorable pricing difference between
natural gas and alternate fuels.
As part of Energize RI, the Mechanism under the IRP was terminated in
September 1997. In 1997, ProvGas recorded $1.5 million in additional margin as
a result of this Mechanism. Thus, a decrease in margin from 1997 to 1998
occurred because this Mechanism was no longer available in 1998.
Non-regulated operating margin increased by $3.7 million compared to the same
period in 1997. The Company's acquisition of oil distribution companies during
1998 contributed to the majority of this increase. However, the margin earned
from oil sales was lower than expected due to warmer than normal weather, lower
than anticipated commercial margins, and costs associated with liquidating
fixed-purchase commitments and option contracts for oil when market prices
declined significantly. Other increases in non-regulated operating margin were
attributable to increased natural gas business volumes and approximately $.2
million of fees earned for providing energy management services. Natural gas
sales volume grew 150 percent and a fifteen-fold increase in the number of
natural gas customers was achieved.
Operating and Maintenance Expenses
Overall, operating and maintenance expenses increased approximately $3.2
million or 6.6 percent versus 1997. The increase was primarily attributable to
the Company's acquisition of oil companies during 1998 resulting in a $4.1
million increase. This increase was partially offset by decreases in ProvGas'
expenses, primarily bad debts. The decrease in bad debts was attributable to
improved collection experience and the implementation of new credit policies, as
well as decreased operating revenues from warmer than normal weather. ProvGas'
other operating and maintenance expenses were essentially flat as a result of
additional cost management due to the warmer weather.
Depreciation and Amortization
Depreciation and amortization expense increased approximately $1.6 million or
12.5 percent versus 1997. This increase was the result of increased capital
spending for Energize RI commitments as well as the amortization of previously
deferred environmental costs. Effective October 1, 1997, ProvGas began
amortizing environmental costs over a 10-year period in accordance with the
levels approved in Energize RI.
Page 4
<PAGE>
Taxes
Taxes increased approximately $.2 million or 1.8 percent versus 1997. The
overall change in taxes was primarily due to local property and other taxes
which increased as a result of capital spending.
Other Income (Loss)
Other income increased approximately $.3 million versus 1997, primarily
consisting of approximately $.2 million of interest income earned on Federal
income tax refunds resulting from amended tax returns.
Interest Expense
Interest expense increased approximately $.5 million or 7.0 percent versus
1997. ProvGas' interest expense increased by approximately $.3 million as a
result of the Series S First Mortgage Bond issuance in April 1998. The
Company's acquisition of oil distribution companies in November 1997 resulted in
increased interest expense of approximately $.5 million. Offsetting the
increases was a decrease in weighted average short-term borrowings as a result
of the Series S First Mortgage Bond issuance.
Liquidity and Capital Resources
- -------------------------------
The Company's cash flow from operating activities decreased approximately
$17.3 million for the fiscal year ended September 30, 1999 compared to 1998. On
a comparative basis, the current year cash flow decreased as a result of the
prior year reflecting receipt of funds in the first quarter of fiscal 1998 from
the sale of ProvGas' working gas in storage to Duke Energy Trading and
Marketing, L.L.C. under the terms of the parties' gas supply agreement. This
decrease in operating cash flow was offset by a temporary increase in accounts
payable this year related to the timing of such gas supply payments.
Capital expenditures for the fiscal year ended September 30, 1999 of $39.5
million reflect an increase of $8.4 million or 26.9 percent when compared to
$31.1 million last year. This spending increase was due primarily to ProvGas'
technology expenditures related to Year 2000, system enhancements and
environmental remediation expenditures. Capital expenditures for fiscal years
2000 and 2001 are expected to be approximately $54.5 million in total.
During the current fiscal year, the Company's cash provided by financing
activities increased $29.7 million. ProvGas issued $15 million in Series T First
Mortgage Bonds on February 8, 1999. The Series T bonds are for a 30 year term at
an interest rate of 6.5 percent. ProvGas has received an order from the Division
which permits the amortization of the Series M bond repurchase premium over the
life of the Series T bonds. The proceeds were used to reduce borrowings under
its lines of credit as well as for general corporate purposes. This reduction in
borrowings was more than offset by an increase in short-term notes payable of
approximately $18.2 million, which was used primarily as bridge financing for
the Company's investment in the Mall. The Company anticipates obtaining
permanent financing for the Mall during the first quarter of fiscal 2000.
In September 1999, the Company made a capital contribution of $4.8 million to
ProvGas in order to fund working capital requirements.
Hedging
The Company's strategy is to use financial instruments for hedging purposes
to manage the impact of market fluctuations on non-regulated contractual sales
commitments. Financial instruments manage market risks and reduce exposure to
fluctuations in the market prices of home heating oil, diesel, heavy oil, and
natural gas.
At September 30, 1999 and 1998, the non-regulated operation held oil futures
and option contracts with fair market values of approximately $.1 million and
$.2 million, respectively. The estimated fair market value of these contracts
is based on quoted market prices. The contracts have maturities of one year or
less. Net unrealized gains related to these instruments of approximately
$40,000 have been deferred on the
Page 5
<PAGE>
accompanying Consolidated Balance Sheets as a component of common stockholders'
equity at both September 30, 1999 and 1998. During 1998, the non-regulated
operation incurred approximately $.5 million of costs associated with
liquidating fixed purchase commitments and option contracts for oil when market
prices dropped.
At September 30, 1999 and 1998, the non-regulated operation held forward
purchase commitments for its supply needs with fair market values of
approximately $13.8 million and $15.2 million, which were acquired at costs of
approximately $12.2 million and $15.6 million, respectively. The fair market
values of these forward contracts are based on quoted market prices and the
contracts have maturities of less than one year.
Year 2000 Update
The Company's Year 2000 Project is substantially complete. The Project
addresses the problem arising from the use in software programs and computing
infrastructures of two-digit years to define the applicable year, rather than
four-digit years, and from time-sensitive software that may recognize a date
using "00" as the last two digits of the year 1900, rather than the year 2000.
Readiness
The Company recognizes that the products and services that the Company
provides to its customers are essential, and senior management has made Year
2000 readiness a top priority. The Company's Year 2000 Project Office has been
working with two international consulting firms to ensure the continuity of
mission critical business systems and processes before and beyond the Year 2000.
The Company has organized the Project around the following four major areas:
1. Information Technology Systems
The Company continues to implement its technology plan, which includes the
migration from a mainframe centric to a client server centric environment. The
migration includes the replacement of CIS which supports the business functions
of customer inquiry, service orders, and billing. The migration also includes
the replacement of business applications such as financial, human resources, and
procurement with a new client server based financial system. These new business
applications have been represented to be Year 2000 ready by their respective
vendors. Validation testing of these systems for Year 2000 readiness has been
completed. Both the CIS and client server based financial system have been
successfully placed into operation.
The Company completed an inventory and assessment of its existing IT systems
and IT infrastructure in March 1999. All mission critical and important systems
have been remediated and tested for Year 2000 readiness.
The Company has implemented procurement policies as part of its efforts to
ensure Year 2000 readiness. These policies address any future changes to the
Company's IT systems environment and its future acquisitions of IT systems.
2. Embedded Systems
Embedded microprocessors are found in equipment deployed in the Company's
distribution and facility operations. The distribution area includes, but is
not limited to, the monitoring, storage, measurement, and control of the flow of
natural gas. The facility area includes, but is not limited to, back-up power
supply, HVAC, and security at the Company's offices.
The Company has successfully completed the assessment, remediation, and
testing of all mission critical and important embedded systems including
ProvGas' Supervisory Control and Data Acquisition gas distribution system.
3. Upstream/Downstream
The Company has contacted all of its major suppliers, and none has indicated
concern for potential business disruption.
The Company's major suppliers critical to the delivery of natural gas to its
system include interstate pipelines, Duke Energy Trading and Marketing, New
England Electric System, and Bell Atlantic, which have indicated that they are
following comprehensive programs on a timely schedule designed to achieve Year
2000 readiness.
Page 6
<PAGE>
While the Company cannot guarantee Year 2000 readiness of these and other
suppliers, the information received from them indicates that they expect to
fulfill their obligations to the Company on and after January 1, 2000. The
Company will continue to monitor the status of all critical suppliers throughout
1999. Any risk areas that surface as a result of these assessments are being
addressed in contingency planning.
The Company is actively participating with the Rhode Island Y2K Association
which acts as a communication forum for key customers as well as the other
essential suppliers of services such as telecommunications, water, and
electricity. The Company is also communicating its Year 2000 readiness to
customers in bill stuffers, on its website and in state-sponsored "town
meetings" throughout its service territory. On February 17, 1999, ProvGas
provided testimony to the RIPUC regarding ProvGas' Year 2000 readiness and since
then has filed quarterly updates with the RIPUC.
4. Contingency Planning
The Company has contingency plans in place for response to certain emergency
operational situations. In addition, the Company has completed over 50
workshops to develop actionable contingency plans which will specifically
address risks to the top 72 business processes related to the Year 2000 computer
problem. Such contingency plans include using manual procedures and arranging
for alternative suppliers. The Company has developed Year 2000 contingency
plans for all mission critical and important business processes. The Company
participated in a Year 2000 communications drill with other New England Gas
Association local distribution companies and its pipeline supplier, Tennessee
Pipeline Company. This planning will help provide mutual aid and assistance if
necessary.
Year 2000 Costs
The Company is capitalizing Year 2000 costs for ProvGas and will amortize
these costs over a five-year amortization period consistent with the regulatory
levels as authorized by the RIPUC under the Energize RI program. As of
September 30, 1999, the Company has deferred Year 2000 costs of approximately
$7.6 million and has amortized $.3 million of these costs. In addition,
approximately $.1 million of additional costs, which have been expensed, have
been incurred by the non-regulated operation. Total costs for Year 2000 are
expected to range from $7.7 million to $8.1 million. These estimated costs
include external contractors and service providers and the balance of the
unrecovered legacy CIS system that has been replaced, as well as other costs
associated with the discontinuance of the operation of the mainframe. These
estimates do not include Year 2000 costs which may be incurred by joint ventures
or partnerships for which the Company does not have primary operating
responsibility or for the costs of implementing the new CIS and client server
based financial system pursuant to ProvGas' ongoing technology plan.
Additionally, the Company does not separately track the internal costs
incurred for the Year 2000 project. Such costs are principally the related
payroll costs for the information systems group. Internal costs, except for the
Year 2000 project manager, have been expensed as incurred.
These cost estimates are based on management's best current estimates which
were derived utilizing numerous assumptions of future events, including the
continued availability of technological and certain other resources, the
accuracy of third party assurances and other factors. There can be no guarantee
that these estimates will be achieved, and actual results may differ from those
discussed above.
Risk Assessment
No amount of preparation and testing can guarantee Year 2000 readiness.
However, the Company believes that it has taken and will take appropriate
preventative measures designed to minimize disruption before, during, and after
January 1, 2000.
A disruption in the extraction or processing, transmission or storage of gas,
or its distribution due to Year 2000 problems experienced by the Company's gas
suppliers could prevent those suppliers from delivering a sufficient amount of
gas to enable the Company to serve certain customer segments. Even if the flow
of gas is not disrupted, customers may not be able to receive gas if electrical
service is disrupted.
In the event that the Company is unable to obtain supplies of oil from third
parties, its customers may not be able to receive oil necessary to heat their
facilities or residences.
Page 7
<PAGE>
Because of the difficulty of assessing Year 2000 readiness of these suppliers
and others outside the control of the Company, the Company considers potential
disruptions by these third parties to present the "reasonably likely worst case
scenario." The Company's inability to serve its customers could result in
increased costs, loss of revenue, and potential claims.
This Year 2000 update contains "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995. These forward-
looking statements are subject to risks and uncertainties and actual results may
differ materially from those described herein.
Common Stock Information
Dividend Paid
Quarter Ended High Low Per Share
- --------------------------------------------------------------------------
September 30, 1999 $30 1/8 $26 1/16 $.27
June 30, 1999 27 18 .27
March 31, 1999 22 7/16 18 3/8 .27
December 31, 1998 21 1/2 19 1/16 .27
September 30, 1998 $21 3/8 $19 3/16 $.27
June 30, 1998 21 3/8 19 1/2 .27
March 31, 1998 22 1/8 20 1/2 .27
December 31, 1997 22 3/8 17 5/8 .27
Page 8
<PAGE>
Consolidated Balance Sheets
September 30
<TABLE>
<CAPTION>
(thousands of dollars) 1999 1998
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Current assets:
Cash and temporary cash investments (notes 1 and 9) $ 2,804 $ 2,006
Accounts receivable, less allowance of
$2,883 in 1999 and $2,720 in 1998 (notes 1 and 4) 13,684 14,067
Unbilled revenues (note 1) 2,821 1,665
Inventories, at average cost-
Fuel oil and underground gas storage 558 656
Materials and supplies 1,283 1,433
Prepaid and refundable taxes (note 3) 4,215 5,355
Prepayments 2,214 1,853
--------- ----------
27,579 27,035
--------- ----------
Gas plant, at original cost (notes 1, 5, 8, and 10) 345,671 $ 324,502
Less accumulated depreciation and
plant acquisition adjustments (notes 1 and 10) 127,481 125,976
--------- ----------
218,190 198,526
--------- ----------
Other assets:
Other property, net 2,628 2,692
Investments (notes 12 and 14) 11,186 2,169
Deferred environmental costs (notes 8 and 10) 9,719 3,969
Deferred charges and other assets (notes 1, 4, 5, and 7) 28,731 18,997
--------- ----------
52,264 27,827
--------- ----------
Total assets $ 298,033 $ 253,388
========= ==========
Capitalization and Liabilities
Capitalization (see accompanying statement) $ 187,628 $ 173,232
--------- ----------
Current liabilities:
Notes payable (notes 6 and 9) 38,250 20,079
Current portion of long-term debt (note 5) 3,515 3,233
Accounts payable (notes 7 and 9) 12,199 9,310
Accrued compensation 1,634 1,337
Accrued environmental costs (notes 8 and 10) 6,145 -
Accrued interest 1,647 1,496
Accrued taxes 3,557 2,714
Accrued vacation 1,807 1,706
Accrued workers compensation 595 530
Customer deposits 2,973 3,034
Deferred revenue (note 10) 315 -
Energy conservation liablility 1,261 742
Other 2,776 3,373
--------- ----------
76,674 47,554
--------- ----------
Deferred credits, reserves, and other liabilities:
Accumulated deferred Federal income taxes (note 3) 24,151 22,292
Unamortized investment tax credits (note 3) 2,059 2,217
Accrued environmental costs (notes 8 and 10) - 1,750
Accrued pension (note 7) 6,982 5,812
Other 539 531
--------- ----------
33,731 32,602
--------- ----------
Commitments and contingencies (notes 8 and 10)
--------- ----------
Total capitalization and liabilities $ 298,033 $ 253,388
========= ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
Page 9
<PAGE>
Consolidated Statements of Income
For the Years Ended September 30
<TABLE>
<CAPTION>
(thousands, except per share amounts) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Energy revenues $ 225,029 $ 222,112 $ 220,420
Cost of energy 119,043 122,991 124,376
--------- --------- ---------
Operating margin 105,986 99,121 96,044
--------- --------- ---------
Operating expenses:
Operation and maintenance 53,047 51,993 48,768
Depreciation and amortization 17,496 14,485 12,874
Taxes:
State gross earnings 5,673 5,618 6,045
Local property and other 8,880 8,363 7,687
--------- --------- ---------
Total operating expenses 85,096 80,459 75,374
--------- --------- ---------
Operating income 20,890 18,662 20,670
--------- --------- ---------
Other income (loss) (note 1) 1,123 57 (219)
--------- --------- ---------
Interest expense:
Long-term debt 6,827 6,391 6,042
Other 2,262 1,998 1,786
Interest capitalized (389) (256) (225)
--------- --------- ---------
8,700 8,133 7,603
--------- --------- ---------
Income before Federal income taxes 13,313 10,586 12,848
Provision for Federal income taxes (note 3) 4,540 3,657 4,391
--------- --------- ---------
Income before preferred dividends of subsidiary 8,773 6,929 8,457
Preferred dividends of subsidiary (note 5) 348 487 626
--------- --------- ---------
Net income $ 8,425 $ 6,442 $ 7,831
========= ========= =========
Earnings per common share - basic $ 1.40 $ 1.09 $ 1.35
========= ========= =========
Earnings per common share - diluted $ 1.40 $ 1.09 $ 1.35
========= ========= =========
Weighted average common shares outstanding (note 13):
Basic 6,015.7 5,919.7 5,790.1
========= ========= =========
Diluted 6,034.1 5,929.7 5,794.3
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
Page 10
<PAGE>
Consolidated Statements of Cash Flows
For the Years Ended September 30
<TABLE>
<CAPTION>
(thousands of dollars) 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash provided by -
Operating Activities:
Income before preferred dividends of subsidiary $ 8,773 $ 6,929 $ 8,457
Items not requiring cash:
Depreciation and amortization 17,496 14,485 12,874
Changes as a result of regulatory action (2,357) 1,500 -
Gain on sale of financial instruments (note 1) (355) - -
Deferred Federal income taxes 888 1,131 703
Loss on sale of real estate - 37 -
Amortization of investment tax credits (158) (158) (158)
Changes in assets and liabilities which provided (used) cash:
Accounts receivable 549 21,504 (187)
Unbilled revenues (1,156) 1,018 (326)
Deferred gas costs - 78 6,041
Inventories 302 (169) (2,222)
Prepaid and refundable taxes 1,731 (1,646) 14
Prepayments (361) (800) 501
Accounts payable 1,529 (3,495) (617)
Accrued compensation 297 (607) 323
Accrued interest 151 298 (80)
Accrued taxes 1,107 202 526
Accrued vacation, accrued workers compensation,
customer deposits, and other (354) 1,105 (631)
Accrued pension 1,170 (928) 1,070
Deferred charges and other (2,388) 3,638 1,149
-------- -------- --------
Net cash provided by operating activities 26,864 44,122 27,437
-------- -------- --------
Investment Activities:
Expenditures for property, plant, and equipment, net (39,542) (31,150) (20,425)
Expenditures for business acquisitions, net of cash
acquired (note 15) 275 (2,744) -
Investment in joint venture (note 14) (9,071) (2,000) -
Proceeds from sale of real estate - 698 -
Proceeds from (cash paid for) financial instruments (note 12) 403 (104) -
-------- -------- --------
Net cash used in investing activities (47,935) (35,300) (20,425)
-------- -------- --------
Financing Activities:
Issuance of common stock 23 - 44
Proceeds from exercise of stock options 14 115 34
Issuance of mortgage bonds (note 5) 15,000 15,000 -
Repurchase of mortgage bonds - (6,363) -
Premium payment on bonds - (1,392) -
Redemption of preferred stock (1,600) (1,600) (1,600)
Issuance of long-term debt - - 1,345
Payments on long-term debt (4,132) (3,799) (2,164)
Increase (decrease) in notes payable 18,171 (4,462) 405
Cash dividends on preferred shares (note 5) (348) (487) (626)
Cash dividends on common shares (5,259) (4,891) (4,811)
-------- -------- --------
Net cash provided (used) by financing activities 21,869 (7,879) (7,373)
-------- -------- --------
Increase (decrease) in cash and temporary cash investments 798 943 (361)
Cash and temporary cash investments at beginning of year 2,006 1,063 1,424
-------- -------- --------
Cash and temporary cash investments at the end of year $ 2,804 $ 2,006 $ 1,063
======== ======== ========
</TABLE>
Page 11
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
For the Years Ended September 30 (continued)
(thousands of dollars) 1999 1998 1997
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Supplemental disclosure of cash flow information:
Cash paid during the year for-
Interest (net of amount capitalized) $ 8,283 $ 7,606 $ 7,476
Income taxes (net of refunds) $ 2,821 $ 3,750 $ 2,036
Schedule of non-cash investing activities:
Capital lease obligations for equipment $ 131 $ - $ 437
Other long-term debt for equipment $ - $ - $ 1,983
Stock issuance for business acquisition $ 1,548 $ - $ -
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
Page 12
<PAGE>
Consolidated Statements of Capitalization
September 30
<TABLE>
<CAPTION>
(thousands of dollars) 1999 1998
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
Common stockholders' investment (notes 5, 7, and 11):
Common stock, $1 Par
Authorized - 20,000 shares
Outstanding - 6,102 shares in 1999 and 5,969 shares in 1998 $ 6,102 $ 5,969
Amount paid in excess of par 61,966 59,198
Retained earnings 25,000 23,067
---------- ----------
93,068 88,234
Accumulated other comprehensive earnings:
Unrealized gain on financial instruments (notes 12 and 17) 39 43
---------- ----------
Total common equity 93,107 88,277
---------- ----------
Cumulative preferred stock of subsidiary (notes 5 and 9):
Redeemable 8.7% Series, $100 Par
Authorized - 80 shares
Outstanding - 32 shares as of 1999 and 48 shares as of 1998 3,200 4,800
---------- ----------
Long-term debt (notes 5, 8, and 9):
First Mortgage Bonds, secured by property
Series M, 10.25%, due July 31, 2008 1,819 2,728
Series N, 9.63%, due May 30, 2020 10,000 10,000
Series O, 8.46%, due September 30, 2022 12,500 12,500
Series P, 8.09%, due September 30, 2022 12,500 12,500
Series Q, 5.62%, due November 30, 2003 8,000 9,600
Series R, 7.50%, due December 15, 2025 15,000 15,000
Series S, 6.82%, due April 1, 2018 15,000 15,000
Series T, 6.50%, due February 1, 2029 15,000 -
Other long-term debt 4,461 4,890
Capital leases 556 1,170
---------- ----------
94,836 83,388
Less-current portion 3,515 3,233
---------- ----------
Long-term debt, net 91,321 80,155
---------- ----------
Total capitalization $ 187,628 $ 173,232
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
Page 13
<PAGE>
Consolidated Statements of Changes in Common Stockholders' Equity
For the Three Years Ended September 30
<TABLE>
<CAPTION>
Shares Amount Paid Other
Issued and Outstanding In Excess Retained Comprehensive
(thousands of dollars) Number Amount of Par Earnings Income (Loss)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance, September 30, 1996 5,748 $ 5,748 $55,404 $21,413 $ -
Add (deduct):
Net income - - - 7,831 -
Dividends ($1.08 per share) - - - (6,242) -
Dividend reinvestment, cash
stock purchase plan, and employee
benefit plans 82 82 1,392 - -
Exercise of stock options 2 2 32 - -
Accrual for stock compensation
plan - - (110) - -
Amortization of deferred
compensation for stock
compensation plans - - 109 - -
---------- ------------ ------------ ---------- --------------
Balance, September 30, 1997 5,832 5,832 56,827 23,002 -
Add (deduct):
Net income - - - 6,442 -
Dividends ($1.08 per share) - - - (6,377) -
Dividend reinvestment, cash
stock purchase plan, and employee
benefit plans 76 76 1,410 - -
Exercise of stock options 7 7 108 - -
Accrual for stock compensation
plan - - (266) - -
Amortization of deferred
compensation for stock
compensation plans - - 163 - -
Unrealized gain on
financial instruments - - - - 43
Shares issued for acquisition 54 54 956 - -
---------- ------------ ------------ ---------- --------------
Balance, September 30, 1998 5,969 5,969 59,198 23,067 43
Add (deduct):
Net income - - - 8,425 -
Dividends ($1.08 per share) - - - (6,492) -
Dividend reinvestment, cash
stock purchase plan, and employee
benefit plans 63 63 1,170 - -
Exercise of stock options 1 1 13 - -
Accrual for stock compensation
plan - - (98) - -
Amortization of deferred
compensation for stock
compensation plans - - 181 - -
Unrealized (loss) on
financial instruments - - - - (4)
Shares issued for acquisition 68 68 1,480 - -
Shares issued for employee stock
purchase plan 1 1 22 - -
---------- ------------ ------------ ---------- --------------
Balance, September 30, 1999 6,102 $ 6,102 $61,966 $25,000 $ 39
========== ============ ============ ========== ==============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
Page 14
<PAGE>
Notes to Consolidated Financial Statements
1. Significant Accounting Policies
Consolidation
The consolidated financial statements include the accounts of Providence
Energy Corporation and its wholly-owned subsidiaries. All significant
intercompany transactions and balances have been eliminated in consolidation.
The Company will account for its investment in the Capital Center Energy
Company, LLC joint venture under the equity method of accounting at the
conclusion of the construction period (also see Note 14).
Use of Estimates in the Preparation of Financial Statements
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
ProvGas is subject to regulation by the RIPUC. North Attleboro Gas is
subject to regulation by the MDTE. The accounting policies of ProvGas and North
Attleboro Gas conform to GAAP as applied in the case of regulated public
utilities and are in accordance with the regulators' accounting requirements and
rate-making practices.
Energy Revenues
Energy revenues are generated principally from natural gas and oil
activities. The natural gas distribution companies record accrued natural gas
distribution revenues based on estimates of gas volumes delivered but not billed
at the end of an accounting period in order to match revenues with related
costs. Also included in energy revenues are revenues earned from energy
management services, including energy project development fees.
Hedging
The Company's non-regulated operation uses financial instruments to manage
market risks and to reduce exposure to fluctuations in the market prices of home
heating oil, diesel, heavy oil, and natural gas. The Company's policy is not to
hold or issue financial instruments for trading purposes but to utilize such
instruments to hedge the impact of market price fluctuations.
These financial instruments qualify for hedge accounting. Hedge accounting is
used in non-trading activities when there is a high degree of correlation
between price movements in the instrument and the item designated as being
hedged. Under hedge accounting, financial instruments with third parties are
carried at market value with related unrealized gains and losses recorded as
adjustments to equity in the Consolidated Statements of Capitalization. Realized
gains and losses are recognized in the Consolidated Statements of Income when
the hedge transaction occurs.
Lease Accounting
Previously, the Company leased water heaters and other appliances to
customers under finance leases. These leases are recorded on the accompanying
Consolidated Balance Sheets at the gross investment in the leases less unearned
income. Unearned income is recognized in such a manner as to produce a constant
periodic rate of return on the net investment in the finance leases.
Gas Plant
Gas plant is stated at the original cost of construction. In accordance
with the uniform system of accounts prescribed by the RIPUC, the difference
between the original cost of gas plant acquired and the cost to ProvGas is
recorded as a Plant Acquisition Adjustment and is being amortized over periods
ranging from 1 to 24 years.
The Company also capitalizes the costs of all technology investments with
the exception of system maintenance costs, which are expensed unless deferral is
approved by regulators.
Impairment Of Long-lived Assets
SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of" established accounting standards for the
impairment of long-lived assets. SFAS No. 121 also required that regulatory
assets which are no longer probable of recovery through future revenues be
charged to earnings. SFAS No. 121 has not impacted the Company's financial
position or results of operations for the years presented.
Page 15
<PAGE>
Depreciation
For ProvGas and North Attleboro Gas, depreciation is provided on the
straight-line basis at rates approved by the RIPUC and the MDTE which are
designed to amortize the cost of depreciable plant over its estimated useful
life. The composite depreciation rate expressed as a percentage of the average
depreciable gas plant in service was approximately 3.85 percent for 1999, 1998,
and 1997.
For the non-regulated operation, depreciation is provided on the straight-
line basis at rates which are designed to amortize asset costs over their useful
lives.
The Company retires property units for its regulated operation by charging
original cost, cost of removal, including environmental investigation and
remediation costs, and salvage value to accumulated depreciation. Due to the
magnitude of environmental investigation and remediation costs, these amounts
have been separately stated in the accompanying Consolidated Balance Sheets.
Gains and losses on the disposition of assets for the non-regulated
operation are reported in earnings in the period realized.
Gas Charge Clauses
In May 1996, the RIPUC approved a Rate Design Settlement Agreement. The
Agreement included changes to ProvGas' gas cost recovery mechanism.
Specifically, the Agreement replaced the previous CGA with the GCC effective
June 2, 1996. In addition to the commodity and related pipeline transportation
costs historically included in the CGA, the GCC provided for the recovery of:
(1) inventory financing costs; (2) working capital associated with gas supply
purchases; (3) bad debt expenses associated with the gas revenue portion of
customer bills; and (4) a substantial portion of liquefied natural gas operating
and maintenance expenses, all of which were previously recovered in base rates.
Similar to the former CGA, the GCC provided for reconciliation of total gas
costs billed with the actual cost of gas incurred. Any excess or deficiency in
amounts billed as compared to costs incurred was deferred and either refunded
to, or recovered from, customers over a subsequent period. As a result of the
Price Stabilization Plan Settlement Agreement described in Note 10, the GCC has
been suspended for the period from October 1, 1997 through September 30, 2000.
Any excess or deficiency in amounts billed as compared to costs incurred will be
retained or borne by ProvGas during this period.
Allowance For Funds Used During Construction
ProvGas and North Attleboro capitalize interest and an allowance for equity
funds in accordance with established policies of the RIPUC and MDTE. The rates
used are based on the actual cost of debt and the allowed equity return.
Interest capitalized is shown as a reduction of interest expense and the equity
allowance is included in other income (loss) in the accompanying Consolidated
Statements of Income.
Deferred Charges and Other Assets
The Company defers and amortizes certain costs in a manner consistent with
authorized or probable rate-making treatment.
Deferred financing costs are amortized over the life of the related
security while the remaining deferred regulatory charges and other assets are
amortized over a recovery period specified by the respective regulatory
commissions.
Deferred Charges and Other Assets include the following:
(thousands of dollars) 1999 1998
- ------------------------------------------------
Year 2000 costs $ 7,315 $ 2,518
Pension costs 7,177 6,401
Goodwill, net 4,624 2,839
Unamortized debt expense 3,888 3,204
Exogenous recovery (note 10) 2,450 -
Other deferred charges 3,277 4,035
------- -------
Total $28,731 $18,997
======= =======
Temporary Cash Investments
Temporary cash investments are short-term, highly liquid investments with
original maturities to the Company of not more than 90 days.
Stock-based Compensation
Compensation expense associated with awards of stock or options to
employees is measured using the intrinsic value method of Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (see Note 11).
Page 16
<PAGE>
Intangibles
All intangible assets are amortized on a straight-line basis over their
estimated useful lives. The goodwill and customer list amortization periods
associated with the recent oil acquisitions are 20 years and 10 years,
respectively.
Reclassifications
Certain prior year amounts have been reclassified for consistent
presentation with the current year.
2. Subsequent Event - Merger
On November 15, 1999, the Company and Southern Union announced that their
Boards of Directors unanimously approved a definitive merger agreement.
ProvEnergy will serve as Southern Union's headquarters for its New England
operations. The agreement calls for Southern Union to merge with the Company in
a transaction valued at approximately $400 million, including assumption of
debt. Under the terms of the agreement, the Company's shareholders will receive
$42.50 per share of Company stock in cash.
Upon completion of the merger, Southern Union will serve approximately 1.5
million gas, electric, oil, and propane customers in Rhode Island,
Massachusetts, Pennsylvania, Texas, Missouri, Florida, Connecticut, and Mexico.
The Company will operate as an autonomous division of Southern Union with
the headquarters remaining in Rhode Island, and pursuant to terms of the merger
agreement, there will be no material changes in the immediate future to the
operations of the Company. Southern Union will honor all of the Company's union
contracts and no layoffs are anticipated as a result of the transaction. The
Company's Chairman and Chief Executive Officer, James H. Dodge, will also become
a member of Southern Union's Board of Directors.
The transaction may require certain legal approvals, including the approval
of the holders of a majority of the outstanding Company shares, the Division,
the RIPUC, the MDTE, the SEC, and FERC, as well as regulators in Texas,
Missouri, Pennsylvania, and Florida, where Southern Union currently has
operations.
3. Federal Income Taxes
The Company records income taxes in accordance with the Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes", which
requires deferred taxes to be provided for all temporary differences.
The following is a summary of the provision for Federal income taxes for the
three years ended September 30:
(thousands of dollars) 1999 1998 1997
- --------------------------------------------------------------------
Current $3,652 $2,526 $3,688
Deferred 888 1,131 703
------ ------ ------
Total Federal income tax
provision $4,540 $3,657 $4,391
====== ====== ======
The effective Federal income tax rates and the reasons for their
differences from the statutory Federal income tax rates are as follows:
1999 1998 1997
- --------------------------------------------------------------------
Statutory Federal income
tax rates 34.0% 34.0% 34.0%
Reversing temporary differences (.8) (.1) (.3)
Amortization of
investment tax credits (.4) (.5) (.4)
Non-deductible goodwill .6 .3 -
Other .7 .8 .9
------ ------ ------
Effective Federal income
tax rates 34.1% 34.5% 34.2%
====== ====== ======
The Company's deferred tax assets and liabilities for each of the two years
in the period ended September 30 are the result of the following temporary
differences:
Page 17
<PAGE>
(thousands of dollars) 1999 1998
- --------------------------------------------------------------------
Long-term deferred taxes
- ------------------------
Tax assets
Unamortized ITC $ 719 $ 773
Other 222 413
Tax liabilities
Property related (22,575) (22,730)
Pension costs (125) (237)
Deferred charges (2,392) (511)
-------- --------
Net deferred tax liability included
in accompanying Consolidated Balance Sheets $(24,151) $(22,292)
======== ========
Prepaid taxes
- -------------
Tax assets
Accounts receivable reserves $ 1,288 $ 970
Property tax reserves 61 (136)
Other 1,358 927
Tax liabilities
Employee severance 56 56
Other (139) (109)
-------- --------
Net prepaid taxes 2,624 1,708
Prepaid gross earnings tax
and other 1,591 3,647
-------- --------
Net prepaid and refundable taxes
included in accompanying
Consolidated Balance Sheets $ 4,215 $ 5,355
======== ========
Investment tax credits are amortized through credits to other income
(loss), over the estimated lives of related property.
4. Lease Receivables
Previously, the Company financed the installation of water heaters and
other appliances for its customers under one to three-year finance agreements.
Additionally, the Company leased water heaters and appliances to customers under
10-year sales-type leases.
Future minimum lease payments to be received are:
(thousands of dollars)
- -------------------------------------------------
2000 $ 389
2001 295
-------
684
Amount representing interest (99)
-------
Amount representing principal $ 585
=======
5. Capitalization
A. First Mortgage Bonds
In April 1998, ProvGas issued $15 million of Series S First Mortgage Bonds.
These First Mortgage Bonds bear interest at the rate of 6.82 percent and mature
in April 2018. The net proceeds provided by this indebtedness were used to
finance capital expenditures and pay down short-term debt.
In September 1998, ProvGas repurchased $6.4 million of Series M First
Mortgage Bonds. The cost of repurchase was comprised of $6.4 million in
principal and $1.4 million in premium. The premium will be amortized over 30
years, which is the life of the Series T First Mortgage Bonds, which ProvGas
issued in February 1999. ProvGas has received an order from the Division which
permits the amortization of the bond premium over the life of this new debt.
ProvGas issued $15 million in Series T First Mortgage Bonds on February 8,
1999. These First Mortgage Bonds bear interest at the rate of 6.5 percent and
mature in February 2029. The proceeds were used to reduce borrowings under
lines of credit as well as for general corporate purposes.
ProvGas' First Mortgage Bonds are secured by a lien on substantially all of
the tangible and real property.
Page 18
<PAGE>
As of September 30, 1999, the annual sinking fund requirements and
maturities of long-term debt are as follows:
(thousands of dollars)
- ------------------------
2000 $ 2,509
2001 2,509
2002 1,601
2003 1,600
2004 and thereafter 81,600
--------
$ 89,819
========
The Company's ability to pay dividends is largely dependent on the
continuing operations of ProvGas. Approximately $20 million of ProvGas' retained
earnings is available for dividends under the most restrictive terms of ProvGas'
First Mortgage Bond Indenture.
B. Other Long-term Debt
During 1997, the Company financed equipment purchases of approximately
$3,328,000 through the issuance of long-term notes to IBM Credit Corporation.
The notes have five-year terms and interest rates ranging from 4.9 to 7.5
percent. As of September 30, 1999, the maturities of these long-term notes over
the next five years are $663,000 in 2000, $704,000 in 2001, $480,000 in 2002,
$69,000 in 2003, and $78,000 in 2004 and thereafter.
The remainder of the other long-term debt consists primarily of an amount
due to a former owner of an acquired company.
C. Redeemable Preferred Stock
ProvGas' preferred stock, which consists of 80,000 shares of $100 par
value, has an 8.7 percent cumulative annual dividend rate payable on a quarterly
basis, and has no voting power or privileges. The stock is subject to a
cumulative annual sinking fund requirement of 16,000 shares per year at par
($1,600,000) plus accrued or unpaid dividends which commenced in February 1997.
Accordingly, 16,000 shares were redeemed by ProvGas at par value in February
1999 and 1998. Under the agreement, in addition to the sinking fund redemptions
required, the Company has the option to redeem the final 16,000 shares of
preferred stock on March 1, 2000.
6. Notes Payable
The Company meets seasonal cash requirements and finances capital
expenditures on an interim basis through short-term bank borrowings. As of
September 30, 1999, the Company had lines of credit totaling $74,000,000 with
borrowings outstanding of $38,250,000. The Company pays a fee for its lines of
credit rather than maintaining compensating balances. The weighted average
short-term interest rate for borrowings outstanding at the end of the year was
5.52 percent in 1999, 5.86 percent in 1998, and 5.79 percent in 1997.
7. Employee Benefits
A. Retirement Plans
The Company has two pension plans providing retirement benefits for most of
its employees. The benefits under the plans are based on years of service and
the employee's final average compensation. It is the Company's policy to fund at
least the minimum required contribution.
The following table sets forth the funding status of the pension plans and
amounts recognized in the Company's Consolidated Balance Sheets at September 30,
1999 and 1998:
(thousands of dollars) 1999 1998
- -----------------------------------------------------------------------
Accumulated benefit obligation,
including vested benefit obligation
of $(47,881) as of September 30,
1999 and $(46,175) as of
September 30, 1998 $ (57,017) $ (54,986)
========= ========
Projected benefit obligation for
service rendered to date $ (72,366) $ (71,540)
Plan assets at fair value (primarily
listed stocks, corporate bonds, and
U.S. bonds) 83,137 74,862
--------- ----------
Page 19
<PAGE>
Excess of plan assets over
projected benefit obligation 10,771 3,322
Unrecognized (gain) (19,749) (9,872)
Unrecognized prior service cost 4,056 2,559
Unrecognized net transition asset
being recognized over 15 years
from October 1, 1985 (136) (272)
------- --------
Net accrued pension cost included
in accrued pension and accounts payable
at September 30, 1999 and 1998 $(5,058) $ (4,263)
======= ========
Net pension cost for fiscal years 1999, 1998, and 1997 included the following
components:
(thousands of dollars) 1999 1998 1997
- --------------------------------------------------------------------------------
Service cost $ 2,285 $ 1,989 $ 1,824
Interest cost on benefit obligations 4,993 4,904 4,583
Actual return on plan assets (11,605) (1,338) (16,458)
Net amortization and deferral 5,123 (6,515) 10,526
-------- ------- --------
Net periodic pension cost 796 (960) 475
Adjustments due to regulatory
action (796) 960 (475)
-------- ------- --------
Net periodic pension cost recognized
in earnings $ - $ - $ -
======== ======= ========
In 1999, the discount rate and rate of increase in future compensation
levels used in determining the projected benefit obligation were 7.25 percent
and 5 percent, respectively. The expected long-term rate of return on assets was
9 percent in 1999.
In 1998, the discount rate and rate of increase in future compensation
levels used in determining the projected benefit obligation were 6.75 percent
and 5 percent, respectively. In 1997, the discount rate and rate of increase in
future compensation levels used in determining the projected benefit obligation
were 8 percent and 6 percent, respectively. The expected long-term rate of
return on assets was 9 percent in 1998 and 1997.
ProvGas recovers pension costs in rates when such costs are funded.
Therefore, the amount by which funding differs from pension expense, determined
in accordance with GAAP, is deferred and recorded as a regulatory asset or
liability.
B. Post-retirement Benefits Other Than Pensions
ProvGas currently offers retirees who have attained age 55 and worked five
years for ProvGas, healthcare and life insurance benefits during retirement.
These benefits are similar to the benefits offered to active employees.
Although retirees are not required to make contributions for healthcare and life
insurance benefits currently, future contributions may be required if the cost
of healthcare and life insurance benefits during retirement exceed certain
limits.
Since 1993, post-retirement benefit costs for active employees are recorded
by ProvGas on an accrual basis, ratably over their service periods. Benefits of
$10,526,000 earned prior to 1993 have been deferred as an unrecognized
transition obligation, which ProvGas is amortizing over a 20-year period.
ProvGas funds its post-retirement benefit obligation by contributions to a
VEBA Trust. Total contributions of $1,177,000 in 1999, $1,308,000 in 1998, and
$1,372,000 in 1997 were made to the VEBA Trust.
ProvGas recovers its post-retirement benefit obligation in rates to the
extent allowed by the RIPUC. The RIPUC generally allows such costs to be
recovered if amounts are funded into tax-favored investment funds, such as the
VEBA Trust. Accordingly, ProvGas fully recovered its 1999, 1998, and 1997 post-
retirement obligations because such obligations were funded through the VEBA
Trust. In addition, in September 1996, the RIPUC approved a ratable recovery of
the cumulative unrecovered difference of $1,041,000 during 1997, 1998, and 1999.
Of the total post-retirement benefit obligations, $1,523,000, $1,654,000, and
$1,718,000, were included in rates during 1999, 1998, and 1997, respectively.
The healthcare and life insurance benefits' costs and accumulated post-
retirement benefit obligation for 1999, 1998, and 1997 are calculated by
ProvGas' actuaries using assumptions and estimates which include:
Page 20
<PAGE>
1999 1998 1997
- ---------------------------------------------------------------------
Healthcare cost annual growth rate 7.55% 9.0% 10.2%
Healthcare cost annual growth rate - long-term 4.75 6.0 6.0
Expected long-term rate of return (union) 8.5 8.5 8.5
Expected long-term rate of return (non-union) 5.5 5.5 5.5
Discount rate 7.25 6.75 8.0
The healthcare cost annual growth rate significantly impacts the estimated
benefit obligation and annual expense. For example, in 1999, a one percent
increase in the above rates would increase the obligation by $745,000 and the
annual expense by $77,000. Decreasing the assumed health care cost annual
growth rate by one percent would decrease the obligation by $596,000 and the
annual expense by $62,000.
The obligations and assets for the healthcare and life insurance benefits at
September 30, 1999 and 1998 are as follows:
(thousands of dollars) 1999 1998
- -------------------------------------------------------------
Accumulated post-retirement benefit
obligation as of the end of the
prior fiscal year $(12,886) $(11,748)
Service cost (273) (243)
Interest cost (848) (945)
Actuarial loss/(gain) and
assumption change 872 (660)
Expected benefits paid 724 710
-------- --------
Accumulated post-retirement benefit
obligation as of the end
of the fiscal year (12,411) (12,886)
-------- --------
Fair value of plan assets as of
the beginning of the year 5,684 4,704
Return on plan assets 627 377
Employer contributions 1,177 1,308
Expenses paid (13) (18)
Benefits paid (590) (687)
-------- --------
Fair value of plan assets
as of the end of the year 6,885 5,684
-------- --------
Unfunded post-retirement benefit
obligation (5,526) (7,202)
Unrecognized transition obligation 7,368 7,895
Unrecognized net (gain) or loss (1,842) (693)
-------- --------
Prepaid post-retirement
benefit obligation included
in the accompanying Consolidated
Balance Sheets $ - $ -
======== ========
ProvGas' actuarially determined healthcare and life insurance benefits'
costs for 1999, 1998, and 1997 include the following:
(thousands of dollars) 1999 1998 1997
- -----------------------------------------------------------
Service cost $ 273 $ 243 $ 228
Interest cost 849 945 896
Actual return on plan assets (471) (406) (278)
Amortization and deferral 526 526 526
------ ------ ------
Total annual plan costs $1,177 $1,308 $1,372
====== ====== ======
C. Supplemental Retirement Plans
The Company provides certain supplemental retirement plans for key
employees. The projected benefit obligation is approximately $2,111,000 which is
being accrued over the service period of these key employees. The supplemental
retirement plans are unfunded. ProvGas accrued and expensed $407,000, $61,000,
and $612,000, related to these benefits in 1999, 1998, and 1997, respectively.
Page 21
<PAGE>
D. Performance and Equity Incentive Plan
The Providence Energy Corporation Performance and Equity Incentive Plan
provides that up to 225,000 shares of common stock, as well as cash awards, can
be granted to key employees, including employees of ProvGas, at no cost to the
employees. Key employees who receive common shares are entitled to receive
dividends, but full beneficial ownership vests on the fifth anniversary of the
date of the grant provided the participant is still employed by the Company.
Vesting may be accelerated under certain circumstances, including a change in
control. This plan also provides for cash compensation to key employees.
The executive compensation incentive awards totaled approximately $715,000
for 1999, $459,000 for 1998, and $439,000 for 1997. Amounts paid in cash are
charged to expense when earned. However, amounts paid in restricted stock are
deferred and amortized to expense over the five-year vesting period.
Of the $715,000 1999 award, $483,000 will be paid in cash during 2000. Of
the $459,000 1998 award, $310,000 was paid in cash during 1999. Of the $439,000
1997 award, $297,000 was paid in cash during 1998. Grant shares totaling 7,566,
7,230, and 5,989, were purchased by the Company and reissued to key employees
during 1999, 1998, and 1997, respectively.
E. Restricted Stock Incentive Plan
The Restricted Stock Incentive Plan, which was discontinued in 1998,
provided that up to 60,000 shares of common stock may be granted to employees of
the Company with at least three months of service, who were not officers or
covered by a collective bargaining agreement, at no cost to the employee. All
participants were entitled to receive dividends; however, full beneficial
ownership vests on the third anniversary of the date of the grant provided that
the participant is still employed by the Company. Vesting may be accelerated
under certain circumstances.
The purchase of 4,230 shares for the Restricted Stock Incentive Plan for
the 1997 award occurred in 1998 at a cost of approximately $90,000. All amounts
awarded under the Restricted Stock Incentive Plan are deferred and amortized to
expense over a three-year period.
F. 1998 Performance Share Plan
Effective October 1, 1998, the Board of Directors adopted a Performance
Share Plan to encourage executives' interest in longer-term performance by
keying incentive payouts to the total return performance of the Company's common
stock in relation to that of other companies in the Edward Jones & Company gas
distribution group of approximately 30 companies and to the change in the
Company's stock price over three-year performance periods. The number of shares
earned will range from 50 percent to 150 percent of awarded shares, if based on
the relative total shareholder return method, and 50 percent to 100 percent, if
based on the increase in the Company's stock price during the three-year period.
These levels were developed to bring total compensation levels at the Company
more in line with survey data for the relevant labor market. No shares will be
earned unless shareholders have earned a minimum annual return over the three-
year period equal to the total annual return for 30-year Treasury notes during
such period. Upon the occurrence of a change in control, unless otherwise
prohibited, the opportunities under all outstanding awards shall be deemed to
have been fully earned for the entire performance period as of the effective
date of the change in control. Dividends will not be paid on the shares until
they are earned. Awards will be paid half in cash and half in stock. During
1999, 38,000 shares were granted under this plan.
8. Commitments and Contingencies
A. Legal Proceedings
The Company is involved in legal and administrative proceedings in the
normal course of business, including certain proceedings involving material
amounts in which claims have been or may be made. However, management believes,
after review of insurance coverage and consultation with legal counsel, that the
ultimate resolution of the legal proceedings to which it is or can at the
present time be reasonably expected to be a party, will not have a materially
adverse effect on the Company's results of operations or financial condition.
B. Capital Leases
ProvGas has a capital lease with Algonquin for storage space in a LNG tank.
The capital lease arrangement also provides that Algonquin lease from ProvGas,
for a corresponding term at an annual amount of $150,000, the land on which the
tank is situated. ProvGas also leases certain information systems and other
equipment under capital leases.
Page 22
<PAGE>
Property under Capital Leases:
- -----------------------------
<TABLE>
<CAPTION>
(thousands of dollars) 1999 1998
- ------------------------------------------------------------
<S> <C> <C>
Gas Plant $ 6,116 $ 6,116
Computer and other equipment 568 1,988
Accumulated depreciation (6,067) (6,937)
------- -------
$ 617 $ 1,167
======= =======
</TABLE>
Commitments for Capital Leases are:
- -----------------------------------
<TABLE>
<CAPTION>
*LNG Computer
(thousands of dollars) Storage Equipment Total
- --------------------------------------------------------------------
<S> <C> <C> <C>
2000 $ 136 $ 144 $ 280
2001 136 144 280
2002 - 69 69
2003 - 34 34
2004 - 2 2
------- ------- -------
$ 272 $ 393 $ 665
------- ------- -------
Amount representing interest (109)
-------
Amount representing principal $ 556
=======
</TABLE>
* This capital lease will be terminated once the terms of the contract with
Algonquin, which is described below, are met.
C. Operating Leases
The Company also leases facilities and equipment under operating leases
with total future payments as of September 30, 1999 as follows:
(thousands of dollars)
- ----------------------
2000 $ 205
2001 145
2002 61
-----
$ 411
=====
D. Gas Supply
As part of the Price Stabilization Plan Settlement Agreement described in
Note 10, ProvGas entered into a full requirements gas supply contract with DETM,
a joint venture of Duke Energy Corporation and Mobil Corporation, for a term of
three years commencing October 1, 1997. Under the contract, DETM guarantees to
meet ProvGas' supply requirements; however, ProvGas must purchase all of its gas
supply exclusively from DETM. In addition, under the contract, ProvGas
transferred responsibility for its pipeline capacity resources, storage
contracts, and LNG capacity to DETM. As a result, ProvGas' gas inventories of
approximately $18 million at September 30, 1997 were sold at book value to DETM
on October 1, 1997.
In addition to providing supply for firm customers at a fixed price, DETM
will provide gas at market prices to cover ProvGas' non-firm sales customers'
needs and to make up the supply imbalances of transportation customers. DETM
will also provide various other services to ProvGas' transportation service
customers including enhanced balancing, standby, and the storage and peaking
services available under ProvGas' approved FT-2 storage service effective
December 1, 1997. DETM will receive the supply-related revenues from these
services in exchange for providing the supply management inherent in these
services.
Included in the DETM contract are a number of other important features.
ProvGas has retained the right to continue to make gas supply portfolio changes
to reduce supply costs. To the extent ProvGas makes such changes, ProvGas must
keep DETM whole for the value lost over the remainder of the contract period.
The outsourcing of day-to-day supply management relieves ProvGas of the need to
perform certain upstream supply management functions. This will make it
possible for ProvGas to take on the additional supply management workload
required by the further unbundling of firm sales customers without major
staffing additions.
ProvGas has entered into an agreement replacing its existing service
contract with Algonquin, a subsidiary of Duke Energy Corporation. Algonquin is
the owner and operator of a LNG tank located in Providence, Rhode Island.
ProvGas relies upon this service to provide gas supply into its distribution
system during the winter period. The service provided for in the agreement,
subject to the successful completion of
Page 23
<PAGE>
construction, is expected to begin in the first quarter of fiscal 2000. Under
the terms of the agreement, Algonquin replaced and expanded the vaporization
capability at the tank. ProvGas will receive approximately $2.6 million from
Algonquin. Of the $2.6 million, approximately $.9 million represents
reimbursement received by ProvGas in 1999 for costs incurred related to the
project including labor, engineering, and legal expenses. The remaining portion
of the payment, or approximately $1.7 million, will be paid to DETM under
ProvGas' contract with DETM as reimbursement for the additional costs that DETM
will incur when the Algonquin storage capacity is released to DETM as provided
for in the gas supply contract described above. This payment is expected 60 days
after the in-service date of the project.
In June 1999, the FERC issued an order in Docket Number CP99-113 approving
Algonquin's project described above. In that order FERC also approved the new
10-year contract between Algonquin and ProvGas for service from the tank. Also
approved was ProvGas' parallel filing, PR99-8, requesting regulatory
authorization to charge Algonquin for transportation of gas vaporized for other
Algonquin customers and transported by ProvGas to the Algonquin pipeline on
behalf of those customers.
As a result of FERC Order 636 and other related orders, pipeline
transportation companies have incurred significant costs, collectively known as
transition costs. The majority of these costs will be reimbursed by the
pipeline's customers, including ProvGas. ProvGas estimates its transition costs
to be approximately $21.7 million, of which $16.2 million has been included in
the GCC and collected from customers through September 30, 1997. As part of the
above supply contract, DETM assumed liability for these transition costs during
the contract's three-year term. At the end of the three-year term of the
contract, the Company will assume any remaining liability, which is not expected
to be material.
E. Environmental Matters
Federal, state, and local laws and regulations establishing standards and
requirements for the protection of the environment have increased in number and
in scope within recent years. The Company cannot predict the future impact of
such standards and requirements, which are subject to change and can take effect
retroactively. The Company continues to monitor the status of these laws and
regulations. Such monitoring involves the review of past activities and current
operations, and may include expending funds to investigate or clean up certain
sites. To the best of its knowledge, subject to the following, the Company
believes it is in substantial compliance with such laws and regulations.
At September 30, 1999, the Company was aware of five sites at which future
costs may be incurred.
Plympton Sites (2)
- ------------------
The Company has been designated as a PRP under the Comprehensive
Environmental Response Compensation and Liability Act of 1980 at two sites in
Plympton, Massachusetts on which waste material is alleged to have been
deposited by disposal contractors employed in the past either directly or
indirectly by the Company and other PRPs. With respect to one of the Plympton
sites, the Company has joined with other PRPs in entering into an Administrative
Consent Order with the Massachusetts Department of Environmental Protection. The
costs to be borne by the Company, in connection with both Plympton sites, are
not anticipated to be material to the financial condition of the Company.
Providence Site
- ---------------
During 1995, the Company began a study at its primary gas distribution
facility located in Providence, Rhode Island. This site formerly contained a
manufactured gas plant operated by the Company. As of September 30, 1999,
approximately $3.0 million had been spent primarily on studies and the
formulation of remediation work plans at this site. In accordance with state
laws, such a study is monitored by the DEM. The purpose of this study was to
determine the extent of environmental contamination at the site. The Company has
completed the study which indicated that remediation will be required for two-
thirds of the property. The remediation began in June 1999 and is anticipated to
be completed during the next fiscal year. During this remediation period, the
remaining one-third of the property will also be investigated and remediated if
necessary.
The Company has compiled a preliminary range of costs, based on removal and
off-site disposal of contaminated soil, ranging from $7.0 million to in excess
of $9.0 million. However, because of the uncertainties associated with
environmental assessment and remediation activities, the future cost of
remediation could be higher than the range noted. Based on the proposals for
remediation work, the Company has a net accrual of $6.1 million at September 30,
1999 for anticipated future remediation costs at this site.
Page 24
<PAGE>
Westerly Site
- -------------
Tests conducted following the discovery of an abandoned underground oil
storage tank at the Company's Westerly, Rhode Island operations center in 1996
confirmed the existence of coal tar waste at this site. As a result, the Company
completed a site characterization test. Based on the findings of that test, the
Company concluded that remediation would be required. As of September 30, 1999,
the Company had removed an underground oil storage tank and regulators
containing mercury disposed of on the site, as well as some localized
contamination. The costs associated with the site characterization test and
partial removal of soil contaminants were shared equally with the former owner
of the property. The Company is currently engaged in negotiations to transfer
the property back to the previous owner, who would continue to remediate the
site. The purchase and sale agreement is anticipated to be signed during fiscal
2000, at which time the previous owner will assume responsibility for removal of
coal tar waste on the site. The Company remains responsible for cleanup of any
mercury released into adjacent water. Contamination from scrapped meters and
regulators, which was discovered in 1997, was reported to the DEM and the Rhode
Island Department of Health and the Company has completed the necessary
remediation. Costs incurred by the Company to remediate this site were
approximately $.1 million.
Allens Avenue Site
- ------------------
In November 1998, the Company received a letter of responsibility from DEM
relating to possible contamination on previously-owned property on Allens Avenue
in Providence. The current operator of the property has been similarly notified.
Both parties have been designated as PRPs. A work plan has been created and
approved by DEM. An investigation has begun in order to determine the extent of
the problem and the Company's responsibility. The Company has entered into a
cost sharing agreement with the current operator of the property, under which
the Company will be held responsible for approximately 20 percent of the costs
related to the investigation. Total estimated costs of testing at this site are
anticipated to be approximately $.2 million. Until the results of the
investigation are known, the Company cannot offer any conclusions as to its
responsibility.
General
- -------
In prior rate cases filed with the RIPUC, ProvGas requested that
environmental investigation and remediation costs be recovered by inclusion in
its depreciation factors consistent with the rate recovery treatment for all
types of cost of removal. Due to the magnitude of ProvGas' environmental
investigation and remediation expenditures, ProvGas sought current recovery for
these amounts. As a result, in accordance with the Price Stabilization Plan
Settlement Agreement described in Note 10, effective October 1, 1997, all
environmental investigation and remediation costs incurred through September 30,
1997, as well as all costs incurred during the three-year term of the Plan, will
be amortized over a 10-year period, in accordance with the levels authorized in
Energize RI. Additionally, it is ProvGas' practice to consult with the RIPUC on
a periodic basis when, in management's opinion, significant amounts might be
expended for environmental-related costs. As of September 30, 1999, ProvGas has
incurred environmental assessment and remediation costs of $4.7 million and has
a net accrual of $6.1 million for future costs.
Management has begun discussions with other parties who may assist ProvGas
in paying the costs associated with the remediation of the above sites.
Management believes that its program for managing environmental issues, combined
with rate recovery and financial contributions from others, will likely avoid
any material adverse effect on its results of operations or its financial
condition as a result of the ultimate resolution of the above sites.
F. Purchase Commitments
At September 30, 1999 and 1998, the non-regulated operation had forward
purchase commitments for its supply needs with market values of approximately
$13.8 million and $15.2 million, respectively. These contracts were acquired at
costs of approximately $12.2 million and $15.6 million, respectively, and have
maturities of less than one year. All financial instruments held by the Company
currently qualify as hedges due to either anticipated sales contracts or firm
sales commitments.
9. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
disclosures for the following financial instruments:
Page 25
<PAGE>
Cash, Cash Equivalents, Accounts Payable, and Short-term Debt
- -------------------------------------------------------------
The carrying amount approximates fair value due to the short-term maturity
of these instruments.
Financial Instruments for Hedging
- ---------------------------------
The fair value of financial instruments for hedging are the same as the
carrying amount on the balance sheet as these instruments were marked to market
at September 30, 1999 and 1998.
Long-term Debt and Preferred Stock
- ----------------------------------
The fair value of long-term debt and preferred stock is estimated based on
currently quoted market prices for similar types of issues.
The carrying amounts and estimated fair values of the Company's financial
instruments at September 30 are as follows:
<TABLE>
<CAPTION>
1999 1998
-------------------- ------------------
Carrying Fair Carrying Fair
(thousands of dollars) Amount Value Amount Value
- ----------------------------------------------------- ------------------
<S> <C> <C> <C> <C>
Cash and cash equivalents $ 2,804 $ 2,804 $ 2,006 $ 2,006
Financial instruments
for hedging 114 114 169 169
Accounts payable 12,199 12,199 9,310 9,310
Short-term debt 38,250 38,250 20,079 20,079
Long-term debt 94,836 90,099 83,388 96,024
Preferred stock 3,200 3,223 4,800 5,040
</TABLE>
The difference between the carrying amount and the fair value of ProvGas'
preferred stock and 1998 long-term debt, if they were settled at amounts
reflected above, would likely be recovered in ProvGas' rates over a prescribed
amortization period. Accordingly, any settlement should not result in a
material impact on ProvGas' financial position or results of operations.
10. Rate Changes
A. Price Stabilization Plan Settlement Agreement
In August 1997, the RIPUC approved Energize RI among ProvGas, the Division,
the Energy Council of Rhode Island, and the George Wiley Center. Effective
October 1, 1997 through September 30, 2000, Energize RI provides firm customers
with a price decrease of approximately 4.0 percent in addition to a three-year
price freeze. Under Energize RI, the GCC mechanism has been suspended for the
entire term. Also, in connection with the Plan, ProvGas wrote off approximately
$1.5 million of previously deferred gas costs in October 1997. Energize RI also
provides for ProvGas to make significant capital investments to improve its
distribution system and support economic development. Specific capital
improvement projects funded under Energize RI are estimated to total
approximately $26 million over its three-year term. In addition, under Energize
RI, ProvGas provides funding for the Low-Income Assistance Program at an annual
level of $1.0 million, the Demand Side Management Rebate Program at an annual
level of $.5 million and the Low-Income Weatherization Program at an annual
level of $.2 million. Energize RI also continues the process of unbundling by
allowing ProvGas to provide unbundled service offerings for up to 10 percent per
year of firm deliveries.
As part of Energize RI, ProvGas has reclassified and is amortizing
approximately $4.0 million of prior environmental costs. These costs and all
environmental costs incurred during the term of the Plan will be amortized over
a 10-year period, in accordance with the levels authorized Energize RI.
Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than
7.0 percent, annually on its average common equity, which is capped at $81.0
million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000,
respectively. In the event that ProvGas earns in excess of 10.9 percent or less
than 7.0 percent, ProvGas will defer revenues or costs through a deferred
revenue account over the term of the Plan. Any balance in the deferred revenue
account at the end of the Plan will be refunded to or recovered from customers
in a manner to be determined by all parties to the Plan and approved by the
RIPUC.
Page 26
<PAGE>
As part of Energize RI, ProvGas is permitted to file annually with the
Division for the recovery of exogenous changes which may occur during the three-
year term of the Plan. Exogenous changes are defined as "...significant
increases or decreases in ProvGas' costs or revenues which are beyond ProvGas'
reasonable control." Any disputes between ProvGas and the Division regarding
either the nature or quantification of the exogenous changes are to be resolved
by the RIPUC. The impact of any such exogenous changes will be debited or
credited to a regulatory asset or liability account throughout the term of
Energize RI and will be recovered or refunded at the expiration of the Plan
through a method to be determined.
In fiscal 1998, ProvGas did not earn its allowed rate of return primarily
as a result of the extremely warm winter weather and the loss of non-firm
margin. ProvGas believed the causes of these two events were beyond its
reasonable control and thus deemed them to be exogenous changes. In March 1999,
ProvGas reached an agreement with the Division, which allowed it to recover
$2.45 million in revenue losses attributable to exogenous changes experienced by
ProvGas in fiscal 1998. The RIPUC reviewed the exogenous changes agreement to
ensure consistency with the terms of Energize RI and affirmed the agreement at
its May 28, 1999 open meeting.
During fiscal 1999, ProvGas recognized into revenue $2.45 million for the
exogenous changes recovery, and at year-end has deferred approximately $.5
million of revenue under the provisions of the earnings cap of Energize RI.
ProvGas intends to file for recovery of exogenous changes experienced in
1999 which resulted from factors similar to 1998. Absent further exogenous
recovery and/or other factors such as colder than normal weather, ProvGas'
ability to earn a 10.9 percent return on average common equity in the final year
of Energize RI is substantially impaired.
B. North Attleboro Gas Rate Increase
In October 1991, the MDTE released its settlement order in regards to a
rate request which included a qualified phase-in plan.
The rate settlement required North Attleboro Gas to classify $545,000 of
gas plant as plant held for future use. This plant is eligible to be included in
future rates since North Attleboro Gas has met certain growth requirements which
were required by the year 2000. North Attleboro Gas capitalized AFUDC and other
costs of approximately $18,000 in 1998, and $37,000 in 1997 that related
primarily to the gas plant not yet phased into North Attleboro Gas' rates under
the plan. North Attleboro Gas amortized $76,000 in 1999, $214,000 in 1998, and
$214,000 in 1997, of amounts previously deferred.
11. Stock Rights and Options
Currently, one common stock purchase right is attached to each outstanding
share of common stock. Each right entitles the holder to purchase one share of
common stock at a price of $70 per share, subject to adjustment. In the event
that certain transactions as defined in the common stock purchase rights
agreement occur, each common stock purchase right will become exercisable for
that number of shares of common stock of the acquiring company (or of the
Company in certain circumstances) which at the time of the transaction has a
market value of two times the exercise price. These rights expire on August 17,
2008 and may be redeemed by a vote of the Directors at a redemption price of
$.01 per common stock purchase right. Due to the antidilutive characteristics of
these rights, there is no assumed impact on earnings per share.
The Company offered two stock option plans for officers, directors, and key
employees which covered 250,000 shares of the Company's common stock. Options
under the plans were granted at an exercise price equal to fair market value at
the date of grant. The options expire 10 years from the date of grant and in the
case of options granted to the directors, the options become exercisable after
the first anniversary of the date of such grant.
Pursuant to the provisions of the plans, each plan terminated on November
3, 1998 which was 10 years from the effective date of the plan. Any options
outstanding under either of the plans shall remain in effect according to the
plans' terms and conditions.
In connection with the purchase of the oil distribution companies, the
Company issued an option to purchase 100,000 shares of its common stock to a
former owner of an acquired company in 1998.
Stock option data are summarized as follows for the years ended September
30, 1999, 1998, and 1997:
Page 27
<PAGE>
<TABLE>
<CAPTION>
Weighted
Number Average
of Shares Exercise Price
- ----------------------------------------------------------------------------
<S> <C> <C>
Outstanding, September 30, 1996 62,238 $16.77
Granted 9,319 17.50
Exercised (2,130) 16.11
Expired (10,009) 17.71
-------- ------
Outstanding, September 30, 1997 59,418 16.75
Granted 100,000 23.00
Exercised (6,852) 16.79
Expired - -
-------- ------
Outstanding, September 30, 1998 152,566 20.85
Granted - -
Exercised (706) 19.00
Expired (1,206) 16.95
-------- ------
Outstanding, September 30, 1999 150,654 $20.62
======== ======
</TABLE>
The following table sets forth information regarding options outstanding at
September 30, 1999:
Number of Options 150,654
Range of Exercise Prices $ 13.875 - $23
Number Currently Exercisable 150,654
Weighted Average Exercise Price $ 20.62
Weighted Average Remaining Life 4.89 years
Weighted Average Exercise Price for
Currently Exercisable $ 20.62
At September 30, 1998 and 1997, 152,566 and 50,927 were currently
exercisable, respectively.
As described in Note 1, the Company uses the intrinsic method to measure
compensation expense associated with grants of stock options or awards to
employees. Had the Company used the fair value method to measure compensation,
reported net income would have been $6,396,000 in 1998 and $7,822,000 in 1997.
Earnings per share for fiscal year 1998 would have been $1.08. Earnings per
share for fiscal 1997 remain unchanged. Earnings per share for fiscal 1999
remain unchanged as there were no options granted during the year.
For purposes of determining the above disclosure required by Statement of
Financial Accounting Standards No. 123, the fair value of options on their grant
date was measured using the Black-Scholes option pricing model. Key assumptions
used to apply this pricing model were as follows:
<TABLE>
<CAPTION>
1998 1997
----- -----
<S> <C> <C>
Risk-free interest rate 5.01% 5.43%
Expected life of option grants (years) 4.0 7.0
Expected volatility of underlying stock 15% 15%
</TABLE>
The pro-forma presentation only includes the effects of grants made
subsequent to October 1, 1996. The estimated fair value of option grants made
during 1998 and 1997 was $.70 and $1.41, respectively, per option.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
In January 1997, the shareholders of the Company adopted the Non-Employee
Director Stock Plan, which provides that up to 50,000 shares of common stock may
be granted to non-employee directors. The shares are granted, at no cost to the
director, on the first day of each fiscal year based on each director's
aggregate fees earned in the
Page 28
<PAGE>
prior fiscal year. All participants are entitled to vote the grant shares and
receive dividends on the grant shares, however, full beneficial ownership vests
on the third anniversary of the grant date provided the participant is still a
director of the Company. Vesting may be accelerated under certain circumstances.
The Company issued 1,963 and 2,131 shares under the Non-Employee Director Stock
Plan in 1999 and 1998, respectively.
12. Hedging
The Company's strategy is to use financial instruments for hedging purposes
to manage the impact of market fluctuations on contractual commitments. The
Company's non-regulated operation uses financial instruments to manage market
risks and to reduce its exposure to fluctuations in the market prices of home
heating oil, diesel, kerosene, and natural gas.
The futures and option contracts, had net unrealized gains of approximately
$40,000, which have been deferred on the accompanying Consolidated Balance
Sheets at both September 30, 1999 and 1998.
At September 30, 1999 and 1998, the estimated fair market value of the
forward contracts totaled approximately $13.8 million and $15.2 million and were
acquired at costs of approximately $12.2 million and $15.6 million. The fair
market value of these forward contracts is based on quoted market prices and the
contracts have maturities of less than one year.
13. Earnings per Share
During 1998, the Company adopted the provisions of SFAS No. 128 "Earnings
Per Share". Under the provisions of SFAS No. 128, basic earnings per share
replaces primary earnings per share and the dilutive effect of stock options are
excluded from the calculation. Fully diluted earnings per share are replaced by
diluted earnings per share and include the dilutive effect of stock options and
warrants, using the treasury stock method. All prior period earnings per share
data have been restated to conform to the requirements of SFAS No. 128.
A reconciliation of the weighted average number of shares outstanding used
in the computation of basic and diluted earnings per share for the three years
ended September 30, is as follows:
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Weighted average
shares 6,015,691 5,919,699 5,790,087
Effect of dilutive stock
options 18,443 9,963 4,260
--------- --------- ---------
Weighted average
shares diluted 6,034,134 5,929,662 5,794,347
========= ========= =========
</TABLE>
The net income used in the calculation for basic and diluted earnings per
share agrees with the net income appearing in the accompanying Consolidated
Financial Statements.
14. Investments
In July 1998, the Company and ERI Services, Inc. agreed to form CCEC. The
joint venture is owned 50 percent by the Company's subsidiary, ProvEnergy Power
Company, LLC and 50 percent by ERI Services' subsidiary, ERI Providence, LLC.
CCEC's wholly-owned subsidiary DownCity Energy Company, LLC, was selected as the
exclusive electric, heat, air conditioning, and related service provider for the
next 30 years for most of the Providence Place Mall, which opened in August
1999. The Company had invested, primarily as bridge financing, $11.1 million of
its total projected investment of $15 million at September 30, 1999. The Company
anticipates obtaining permanent financing for the Mall during the first quarter
of fiscal 2000, after which the Company projects its equity investment in the
mall to approximate $3.0 million.
15. Acquisitions
In July 1999, the Company acquired Keenan Oil Services, Inc. of Warwick,
Rhode Island, which serves approximately 2,700 full-service residential
customers. In November 1997, the Company acquired all of the outstanding stock
of the Super Service Companies as well as all the assets of the Mohawk
Companies. These acquisitions in
Page 29
<PAGE>
conjunction with the purchase of three small oil companies' customer lists in
1998 serve as a valuable market entry as a full service heating oil company.
The amounts related to the purchases of these companies are not material to
the financial position of the Company. These acquisitions have been accounted
for as purchases and, accordingly, operating results of these businesses
subsequent to the date of acquisition have been consolidated in the financial
statements of the Company. Pro-forma results of operations, which include the
operating results of these acquisitions, are not materially different than the
operating results presented.
On October 1, 1999, the Company acquired the customer list of one small oil
company servicing approximately 600 customers in Northern Rhode Island.
The Company continues to assess the energy market for potential
acquisitions to fulfill its vision.
16. Operating Segments
The Company's operations are classified into two principal reportable
segments: Regulated Operations and Non-regulated Operations.
The Regulated Operations consists primarily of natural gas sales and
distribution to residential, commercial, and industrial customers. The Non-
regulated Operations consists of heating oil, motor oil, and gas commodity sales
to residential, commercial, and industrial customers and other energy management
projects, which include project development fees.
The accounting policies used to develop segment information correspond to
those described in Note 1, "Significant Accounting Policies". The Company
evaluates performance based on net income.
(thousands of dollars) 1999 1998 1997
- -----------------------------------------------------------------------------
Energy Revenues
- ---------------
Regulated operation $ 183,373 $ 189,034 $ 215,258
Non-regulated operation 41,656 33,078 5,162
----------- ---------- ----------
Total $ 225,029 $ 222,112 $ 220,420
=========== ========== ==========
Interest Expense
- ----------------
Regulated operation $ 7,660 $ 7,600 $ 7,570
Non-regulated operation 441 400 23
----------- ---------- ----------
Total reportable segments 8,101 8,000 7,593
Parent company 599 133 10
----------- ---------- ----------
Total $ 8,700 $ 8,133 $ 7,603
=========== ========== ==========
Depreciation and amortization
- -----------------------------
Regulated operation $ 16,925 $ 13,962 $ 12,869
Non-regulated operation 571 523 5
----------- ---------- ----------
Total $ 17,496 $ 14,485 $ 12,874
=========== ========== ==========
Income tax expense
- ------------------
Regulated operation $ 5,083 $ 4,655 $ 4,785
Non-regulated operation (373) (966) (161)
----------- ---------- ----------
Total reportable segments 4,710 3,689 4,624
Parent company (170) (32) (233)
----------- ---------- ----------
Total $ 4,540 $ 3,657 $ 4,391
=========== ========== ==========
Net income (loss)
- -----------------
Regulated operation $ 9,837 $ 8,566 $ 8,546
Non-regulated operation (986) (1,692) (313)
----------- ---------- ----------
Total reportable segments 8,851 6,874 8,233
Parent company (426) (432) (402)
----------- ---------- ----------
Total $ 8,425 $ 6,442 $ 7,831
=========== ========== ==========
Page 30
<PAGE>
Total assets
- ------------
Regulated operation $ 271,115 $ 238,493 $ 251,759
Non-regulated operation 13,870 11,593 1,360
----------- ---------- ----------
Total reportable segments 284,985 250,086 253,119
Parent company 13,048 3,302 2,391
----------- ---------- ----------
Total $ 298,033 $ 253,388 $ 255,510
=========== ========== ==========
Capital expenditures
- --------------------
Regulated operation $ 39,501 $ 30,783 $ 20,335
Non-regulated operation 41 367 90
----------- ---------- ----------
Total $ 39,542 $ 31,150 $ 20,425
=========== ========== ==========
Significant non-cash items
- -------------------------
Deferred Federal income taxes
and amortization of ITC
Regulated operation $ 725 $ 970 $ 544
Non-regulated operation 4 2 -
----------- ---------- ----------
Total reportable segments 729 972 544
Parent company 1 1 1
----------- ---------- ----------
Total $ 730 $ 973 $ 545
=========== ========== ==========
Stock issuance for business
acquisition
Non-regulated operation $ 1,548 $ - $ -
=========== ========== ==========
All segment amounts reported above correspond to items reported in the
Company's consolidated financial statements and are consistent with the
presentation adopted in internal management reports.
Under total assets, the Parent company amount consists primarily of the
Company's investment in the Mall.
17. Comprehensive Income
Effective October 1, 1998, the Company adopted the provisions of SFAS No.
130, "Reporting Comprehensive Income", which requires that an enterprise (a)
classify items of other comprehensive income by their nature in a financial
statement and (b) display the accumulated balance of other comprehensive income
separately from retained earnings and additional paid-in capital in the equity
section of a statement of financial position.
A reconciliation of net income to other comprehensive income is as follows:
(thousands of dollars) 1999 1998 1997
------------------------------------- ------ ------ ------
Net Income $8,425 $6,442 $7,831
Unrealized holding gain (loss) on
investments, net of tax (4) 43 -
------ ------ ------
Comprehensive Income $8,421 $6,485 $7,831
====== ====== ======
The following is a summary of the reclassification adjustments and the
income tax effects for the components of other comprehensive income (loss) for
the year ended September 30:
<TABLE>
<CAPTION>
Unrealized Holding Reclassification
Gains on Adjustments for
Investments Gains Other
Arising During Included in Comprehensive
(thousands of dollars) the Period Net Income Loss
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
1999
Pretax income $ 78 $ (84) $ (6)
Income tax expense 26 (28) (2)
-------- -------- -------
Net change $ 52 $ (56) $ (4)
======== ======== =======
</TABLE>
Page 31
<PAGE>
18. New Accounting Pronouncements
Effective for fiscal year 1999, the Company adopted the provisions of SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information".
SFAS No. 131 requires that a public business enterprise report financial and
descriptive information about its reportable operating segments. This statement
requires additional disclosure only and will not affect the financial position
or results of operations of the Company.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". This Statement establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 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.
SFAS No. 133 is effective in the first fiscal quarter for the Company's
fiscal year ending September 30, 2001. A company may also implement the
Statement as of the beginning of any fiscal quarter after issuance (that is,
fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be
applied retroactively. SFAS No. 133 must be applied to (a) derivative
instruments and (b) certain derivative instruments embedded in hybrid contracts
that were issued, acquired, or substantively modified after December 31, 1997
(and, at a company's election, before January 1, 1998).
The Company has not yet quantified the impact of adopting SFAS No. 133 on
the financial statements and has not determined the timing of or method of
adoption of SFAS No. 133.
In March 1998, the American Institute of Certified Public Accountants
issued SOP 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use". It applies to all non-governmental entities and is
effective for the Company's financial statements for the fiscal year ending
September 30, 2000. The provisions of this SOP should be applied to internal-use
software costs incurred in fiscal years subsequent to December 15, 1998 for all
projects, including those projects in progress upon initial application of the
SOP.
The SOP establishes accounting standards for the determination of capital
or expense treatment of expenditures for computer software developed or obtained
for internal use based upon the stage of development. The SOP defines three
stages as (1) Preliminary Project, (2) Application Development, and (3) Post-
Implementation/Operation. As a general rule, the Preliminary Project and Post-
Implementation/Operation phase expenditures are expensed and Application
Development expenditures are capitalized.
The Company will adopt the SOP in fiscal 2000 and does not expect it to
have a material impact on the financial statements.
19. Unaudited Quarterly Financial Information
The following is unaudited quarterly financial information for the two
years ended September 30, 1999 and 1998. Quarterly variations between periods
are caused primarily by the seasonal nature of energy sales and the availability
of energy products.
<TABLE>
<CAPTION>
(thousands of dollars, except
per share amounts) Quarter Ended
Dec. 31 Mar. 31 June 30 Sept. 30
---------------------------------------
<S> <C> <C> <C> <C>
Fiscal 1999
- ------------------------------------------------------------------
Energy revenues $64,585 $93,690 $38,714 $28,040
Operating income (loss) 8,105 17,976 658 (5,849)
Net income (loss) 3,967 10,373 (376) (5,539)
Net income (loss)
per share* .66 1.73 (.06) (.90)
</TABLE>
Page 32
<PAGE>
<TABLE>
<CAPTION>
FISCAL 1998
- ------------------------------------------------------------------
<S> <C> <C> <C> <C>
Energy revenues $67,942 $87,796 $39,968 $26,406
Operating income (loss) 8,620 16,611 (585) (5,984)
Net income (loss) 4,403 9,535 (1,843) (5,653)
Net income (loss)
per share* .75 1.61 (.31) (.95)
</TABLE>
* Calculated on the basis of the weighted average shares outstanding during the
quarter.
Page 33
<PAGE>
11-Year Financial and Operational Summary
For the Year Ended September 30
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994
----- ----- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Natural gas distribution revenues
(thousands of dollars):
Residential $128,263 $126,479 $135,259 $128,875 $106,387 $130,888
Commercial/industrial 38,882 47,629 66,352 74,625 61,491 76,174
Firm transportation 11,440 7,982 2,251 330 171 -
------------------------------------------------------------------------------
Total firm 178,585 182,090 203,862 203,830 168,049 207,062
Interruptible and other 3,247 5,502 10,299 9,882 14,026 14,471
Non-firm transportation 863 792 504 411 633 287
Other 678 650 593 623 1,284 958
------------------------------------------------------------------------------
Total natural gas distribution revenues $183,373 $189,034 $215,258 $214,746 $183,992 $222,778
==============================================================================
Natural gas distribution - gas sold
and transported (MMcf):
Residential 12,996 13,007 13,853 14,423 12,709 14,122
Commercial/industrial 4,563 5,727 8,086 9,694 8,772 9,360
Firm transportation 5,391 4,223 1,818 379 208 -
------------------------------------------------------------------------------
Total firm 22,950 22,957 23,757 24,496 21,689 23,482
Interruptible and other 848 1,409 2,633 2,610 4,950 4,547
Non-firm transportation 1,600 999 907 1,001 1,473 656
Company use and other 903 946 871 1,017 919 1,182
------------------------------------------------------------------------------
Total gas sold and transported 26,301 26,311 28,168 29,124 29,031 29,867
Less: off-system sales - - 280 412 1,682 2,179
------------------------------------------------------------------------------
Total gas delivered 26,301 26,311 27,888 28,712 27,349 27,688
==============================================================================
Natural gas distribution - gas purchased,
produced, and transported (MMcf):
Pipeline natural gas-contract 19,230 21,008 17,328 17,979 16,591 22,880
Pipeline natural gas-spot purchases - - 3,271 5,197 7,935 3,533
Pipeline natural gas-transportation 6,991 5,222 2,725 1,380 1,681 656
Underground storage 80 81 4,163 3,129 2,270 1,697
Liquefied natural gas and other - - 681 1,439 554 1,101
------------------------------------------------------------------------------
Total gas sold and transported 26,301 26,311 28,168 29,124 29,031 29,867
==============================================================================
Average annual number of natural gas
distribution customers:
Residential:
Heating 125,420 123,023 120,826 118,724 116,826 114,461
Non-heating 29,536 29,814 30,326 30,763 31,109 31,332
Commercial/industrial 15,484 15,981 16,656 16,645 16,509 16,337
Firm transportation 1,576 884 50 6 1 -
------------------------------------------------------------------------------
Total firm 172,016 169,702 167,858 166,138 164,445 162,130
Interruptible and non-firm transportation 112 123 125 138 142 141
------------------------------------------------------------------------------
Total customers 172,128 169,825 167,983 166,276 164,587 162,271
==============================================================================
General:
Average rate per Mcf residential heating $ 9.60 $ 9.51 $ 9.55 $ 8.77 $ 8.19 $ 9.10
Average rate per Mcf residential non-heating $ 13.99 $ 13.95 $ 14.06 $ 12.30 $ 11.76 $ 12.44
Maximum daily MMcf sendout 172 181 188 189 202 206
Actual calendar degree days 5,139 5,206 5,657 5,967 5,111 5,977
Normal calendar degree days 5,652 5,652 5,652 5,682 5,709 5,709
Colder (warmer) than normal -9.1% -7.9% 0.1% 5.0% -10.5% 4.7%
Summary of operations (thousand of dollars):
Natural gas distribution revenues $183,373 $189,034 $215,258 $214,745 $183,992 $222,778
Non-regulated operation revenues 41,656 33,078 5,162 407 - -
------------------------------------------------------------------------------
Total energy revenues 225,029 222,112 220,420 215,152 183,992 222,778
Cost of energy 119,043 122,991 124,376 120,246 100,944 135,104
------------------------------------------------------------------------------
Operating margin 105,986 99,121 96,044 94,906 83,048 87,674
Operating and maintenance expense 53,047 51,993 48,768 49,033 44,368 46,223
Depreciation and amortization 17,496 14,485 12,874 11,997 10,470 9,615
Taxes other than income 14,553 13,981 13,732 13,007 11,769 12,540
Federal income taxes 4,540 3,657 4,391 4,932 3,442 4,446
Interest expense 8,700 8,133 7,603 7,465 7,379 6,247
Other income (loss) 1,123 57 (219) 1,194 1,203 182
Preferred dividend 348 487 626 696 696 696
Loss from discontinued operations, pre-tax - - - - - -
------------------------------------------------------------------------------
Net income (loss) $ 8,425 $ 6,442 $ 7,831 $ 8,970 $ 6,127 $ 8,089
==============================================================================
1993 1992 1991 1990 1989
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Natural gas distribution revenues
(thousands of dollars):
Residential $120,997 $120,208 $105,809 $105,418 $ 96,899
Commercial/industrial 72,974 47,855 44,004 43,120 39,246
Firm transportation - - - - -
----------------------------------------------------------
Total firm 193,971 168,063 149,813 148,538 136,145
Interruptible and other 14,336 21,394 17,681 6,569 5,566
Non-firm transportation 54 74 735 833 1,182
Other 954 810 857 966 747
----------------------------------------------------------
Total natural gas distribution revenues $209,315 $190,341 $169,086 $156,906 $143,640
==========================================================
Natural gas distribution - gas sold
and transported (MMcf):
Residential 13,783 13,166 11,534 14,452 13,948
Commercial/industrial 8,926 8,363 7,637 6,188 5,818
Firm transportation - - - - -
----------------------------------------------------------
Total firm 22,709 21,529 19,171 20,640 19,766
Interruptible and other 3,985 6,717 5,659 2,084 1,641
Non-firm transportation 386 869 4,127 5,026 3,287
Company use and other 1,187 1,264 1,445 985 977
----------------------------------------------------------
Total gas sold and transported 28,267 30,379 30,402 28,735 25,671
Less: off-system sales 501 5 - 12 1
----------------------------------------------------------
Total gas delivered 27,766 30,374 30,402 28,723 25,670
==========================================================
Natural gas distribution - gas purchased,
produced, and transported (MMcf):
Pipeline natural gas-contract 18,044 20,150 21,051 15,060 16,451
Pipeline natural gas-spot purchases 7,936 7,374 3,210 5,848 3,879
Pipeline natural gas-transportation 386 869 4,127 5,026 3,287
Underground storage 879 594 1,038 1,305 853
Liquefied natural gas and other 1,022 1,392 976 1,496 1,201
----------------------------------------------------------
Total gas sold and transported 28,267 30,379 30,402 28,735 25,671
==========================================================
Average annual number of natural gas
distribution customers:
Residential:
Heating 112,497 111,176 110,997 106,984 102,178
Non-heating 31,274 31,938 32,210 32,734 33,096
Commercial/industrial 16,264 15,889 15,114 13,179 12,654
Firm transportation - - - - -
----------------------------------------------------------
Total firm 160,035 159,003 158,321 152,897 147,928
Interruptible and non-firm transportation 123 115 79 65 65
----------------------------------------------------------
Total customers 160,158 159,118 158,400 152,962 147,993
==========================================================
General:
Average rate per Mcf residential heating $ 8.68 $ 7.80 $ 7.91 $ 7.21 $ 6.86
Average rate per Mcf residential non-heating $ 10.57 $ 10.37 $ 9.75 $ 8.68 $ 8.30
Maximum daily MMcf sendout 185 174 172 163 165
Actual calendar degree days 5,718 5,502 4,893 5,750 5,725
Normal calendar degree days 5,811 5,811 5,811 5,938 5,938
Colder (warmer) than normal -1.6% -5.3% -15.8% -3.2% -3.6%
Summary of operations (thousands of dollars)
Natural gas distribution revenues $209,315 $190,341 $169,086 $156,906 $143,640
Non-regulated operation revenues - (19) (14) 289 268
----------------------------------------------------------
Total energy revenues 209,315 190,322 169,072 157,195 143,908
Cost of energy 126,314 111,568 101,707 91,306 83,947
----------------------------------------------------------
Operating margin 83,001 78,754 67,365 65,889 59,961
Operating and maintenance expense 43,848 43,404 39,746 35,091 34,386
Depreciation and amortization 9,073 8,668 7,487 6,513 5,418
Taxes other than income 12,597 11,497 11,031 10,281 9,426
Federal income taxes 3,600 2,721 882 1,818 (2,690)
Interest expense 6,653 6,837 7,764 7,721 6,686
Other income (loss) 83 203 2,236 500 (2,309)
Preferred dividend 696 696 280 - -
Loss from discontinued operations, pre-tax - - - - (7,740)
----------------------------------------------------------
Net income (loss) $ 6,617 $ 5,134 $ 2,411 $ 4,965 $ (3,314)
==========================================================
</TABLE>
1 Mcf is one thousand cubic feet; 1 MMcf is one million cubic feet.
Page 34
<PAGE>
Selected Financial Data
For the years ended September 30
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994 1993
---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Common share data:
Earnings (loss) per share-basic $ 1.40 $ 1.09 $ 1.35 $ 1.57 $ 1.09 $ 1.46 $ 1.39
Earnings (loss) per share-diluted $ 1.40 $ 1.09 $ 1.35 $ 1.57 $ 1.09 $ 1.46 $ 1.39
Weighted average common shares
outstanding-basic 6,015.7 5,919.7 5,790.1 5,709.2 5,624.2 5,534.1 4,761.8
Weighted average common shares
outstanding-diluted 6,034.1 5,929.7 5,794.3 5,712.0 5,624.7 5,537.0 4,764.7
Actual common shares outstanding
(year-end in thousands) 6,102 5,969 5,832 5,748 5,668 5,581 5,486
Dividends paid per share $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.06 $ 1.02
Common dividends (in thousands) $ 6,492 $ 6,377 $ 6,242 $ 6,155 $ 6,062 $ 5,856 $ 4,889
Earnings reinvested in the Corporation
(in thousands) $ 1,933 $ 65 $ 1,589 $ 2,815 $ 65 $ 2,233 $ 1,728
Book value per share $ 15.27 $ 14.78 $ 14.69 $ 14.36 $ 13.85 $ 13.82 $ 13.37
Market data:
Market price per share (year-end) $27 3/4 $19 1/2 $19 5/8 $17 1/2 $ 16 $17 1/4 $20 3/8
Market capitalization (year-end
in thousands) $169,177 $116,394 $114,480 $100,593 $ 90,693 $ 96,267 $111,801
Average daily trading volume 8,530 4,954 9,885 4,533 3,867 4,194 5,771
High/low price range of common stock $30 1/8 $22 1/8 $20 1/2 $18 3/4 $17 1/2 $20 1/2 $21 1/4
to to to to to to to
$ 18 $17 5/8 $16 1/2 $ 16 $14 5/8 $14 5/8 $15 1/8
Quarterly earnings per common share:
December 31 $ 0.66 $ 0.75 $ 0.74 $ 0.90 $ 0.59 $ 0.68 $ 0.91
March 31 1.73 1.61 1.17 1.37 1.04 1.18 1.93
June 30 (0.06) (0.31) 0.02 (0.16) (0.15) (0.21) (0.52)
September 30 (0.90) (0.95) (0.58) (0.54) (0.39) (0.17) (0.74)
-----------------------------------------------------------------------------------
Annual earnings per share (1) $ 1.43 $ 1.10 $ 1.35 $ 1.57 $ 1.09 $ 1.48 $ 1.58
===================================================================================
(3)
Capitalization (in thousands):
Common stock, $1 Par,
Authorized-20,000 shares $ 6,102 $ 5,969 $ 5,832 $ 5,748 $ 5,668 $ 5,581 $ 5,486
Amount paid in excess of par 61,966 59,198 56,827 55,404 54,258 53,042 51,582
Retained earnings 25,000 23,067 23,002 21,413 18,598 18,533 16,300
-----------------------------------------------------------------------------------
93,068 88,234 85,661 82,565 78,524 77,156 73,368
Unrealized gain on financial
instruments 39 43 - - - - -
-----------------------------------------------------------------------------------
Total common equity 93,107 88,277 85,661 82,565 78,524 77,156 73,368
-----------------------------------------------------------------------------------
Preferred stock (4) 3,200 4,800 6,400 8,000 8,000 8,000 8,000
-----------------------------------------------------------------------------------
Long-term debt
First Mortgage Bonds, secured
by property 89,819 77,328 71,200 $ 72,800 74,400 61,000 61,000
Senior debentures - - - - - - -
Other long-term debt 4,461 4,890 3,207 - - - -
Capital leases 556 1,170 1,672 1,678 2,032 1,164 1,629
-----------------------------------------------------------------------------------
Subtotal 94,836 83,388 76,079 74,478 76,432 62,164 62,629
Less-current portion 3,515 3,233 3,707 2,022 1,950 2,085 466
-----------------------------------------------------------------------------------
Total long-term debt 91,321 80,155 72,372 72,456 74,482 60,079 62,163
-----------------------------------------------------------------------------------
Total capitalization $187,628 $173,232 $164,433 $163,021 $161,006 $145,235 $143,531
===================================================================================
Percentage of total capitalization:
Common equity 50% 51% 52% 51% 49% 53% 51%
Preferred stock 2% 3% 4% 5% 5% 6% 6%
Long-term debt 48% 46% 44% 44% 46% 41% 43%
Short term borrowings (in thousands):
Balance outstanding at end of period $ 38,250 $ 20,079 $ 23,675 $ 23,270 $ 7,337 $ 27,700 $ 23,800
Average daily outstanding for
the period $ 23,468 $ 18,342 $ 23,540 $ 13,955 $ 19,197 $ 27,020 $ 28,931
Total assets (in thousands) $298,033 $253,388 $255,510 $250,150 $227,127 $233,311 $224,550
<CAPTION>
1992 1991 1990 1989
---- ---- ---- ----
<S> <C> <C> <C> <C>
Common share data:
Earnings (loss) per share-basic $ 1.15 $ 0.56 $ 1.17 $ (0.80)
Earnings (loss) per share-diluted $ 1.15 $ 0.56 $ 1.17 $ (0.80)
Weighted average common shares
outstanding-basic 4,478.4 4,337.9 4,235.8 4,127.1
Weighted average common shares
outstanding-diluted 4,478.5 4,337.9 4,235.8 4,127.1
Actual common shares outstanding
(year-end in thousands) 4,534 4,408 4,278 4,186
Dividends paid per share $ 1.10 $ 1.40 $ 1.40 $ 1.40
Common dividends (in thousands) $ 4,908 $ 6,057 $ 5,916 $ 5,761
Earnings reinvested in the Corporation
(in thousands) $ 226 $ (3,646) $ (951) $ (9,075)
Book value per share $ 12.02 $ 11.87 $ 12.62 $ 12.74
Market data:
Market price per share (year-end) $ 16 $17 1/4 $15 1/4 $17 7/8
Market capitalization (year-end
in thousands) $ 72,539 $ 76,031 $ 65,234 $ 74,839
Average daily trading volume 2,987 3,146 2,230 2,624
High/low price range of common stock $17 7/8 $17 1/4 $18 7/8 $19 1/8
to to to to
$13 1/8 $14 1/8 $15 1/8 $16 1/4
Quarterly earnings per common share:
December 31 $ 0.58 $ 0.62 $ 1.10 $ 0.61
March 31 1.67 1.33 1.25 1.40
June 30 (0.28) (0.32) (0.29) (1.53)
September 30 (0.81) (1.04) (0.87) (1.25)
--------------------------------------------
Annual earnings per share (1) $ 1.16 $ 0.59 $ 1.19 $ (0.77)
============================================
(2)
Capitalization (in thousands):
Common stock, $1 Par,
Authorized-20,000 shares $ 4,534 $ 4,408 $ 4,278 $ 4,186
Amount paid in excess of par 35,385 33,548 31,705 30,204
Retained earnings 14,572 14,346 17,992 18,943
--------------------------------------------
54,491 52,302 53,975 53,333
Unrealized gain on financial
instruments - - - -
--------------------------------------------
Total common equity 54,491 52,302 53,975 53,333
--------------------------------------------
Preferred stock (4) 8,000 8,000 - -
--------------------------------------------
Long-term debt
First Mortgage Bonds, secured 53,200 39,050 41,750 33,550
by property
Senior debentures 7,533 8,033 8,491 8,962
Other long-term debt 66 132 488 595
Capital leases 2,089 2,549 2,029 2,331
--------------------------------------------
Subtotal 62,888 49,764 52,758 45,438
Less-current portion 1,930 6,879 3,610 2,708
--------------------------------------------
Total long-term debt 60,958 42,885 49,148 42,730
--------------------------------------------
Total capitalization $123,449 $103,187 $103,123 $ 96,063
============================================
Percentage of total capitalization:
Common equity 44% 51% 52% 56%
Preferred stock 6% 8% 0% 0%
Long-term debt 49% 42% 48% 44%
Short term borrowings (in thousands):
Balance outstanding at end of period $ 23,410 $ 38,214 $ 30,601 $ 28,996
Average daily borrowings outstanding
for the period $ 38,877 $ 33,741 $ 27,077 $ 26,488
Total assets (in thousands) $197,459 $189,422 $182,258 $170,782
</TABLE>
(1) Calculated on the basis of the weighted average shares outstanding during
the quarter. Therefore this amount may not equal the earnings per common
share for the year.
(2) Included in the fiscal year 1989 earnings per share is a loss per common
share on the discontinuance of the residential real estate operations of
$1.23.
(3) Includes the effect of the issuance of 850,000 shares of common stock on
June 10, 1993.
(4) This stock is subject to a cumulative annual sinking fund requirement of
16,000 shares per year at par ($1,600,000) plus accrued or unpaid dividends
which commenced in February 1997.
Page 35
<PAGE>
Selected Income Statement and Balance Sheet Data
For the years ended September 30
<TABLE>
<CAPTION>
(in thousands, except where noted) 1999 1998 1997 1996 1995 1994 1993
- --------------------------------- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Federal income tax provision
(benefit):
Current $ 3,652 $ 2,526 $ 3,688 $ 2,989 $ 1,300 $ 3,211 $ 2,487
Deferred 888 1,131 703 1,943 2,142 1,235 1,113
Investment tax credits, net - - - - - - -
-------------------------------------------------------------------------
Total Federal income tax provision (benefit) 4,540 3,657 4,391 4,932 3,442 4,446 3,600
Net income (loss) before preferred dividends of
subsidiary 8,773 6,929 8,457 9,666 6,823 8,785 7,313
-------------------------------------------------------------------------
Income (loss) before income taxes $ 13,313 $ 10,586 $ 12,848 $ 14,598 $ 10,265 $ 13,231 $ 10,913
=========================================================================
Effective tax rate 34.10% 34.50% 34.20% 33.80% 33.60% 33.60% 32.90%
Statutory tax rate 34.00% 34.00% 34.00% 34.00% 34.00% 34.00% 34.00%
Property:
Expenditures for property, plant, and equipment $ 39,542 $ 31,150 $ 20,425 $ 20,781 $ 19,597 $ 19,809 $ 13,882
Gross utility plant $345,671 $324,502 $300,829 $279,849 $262,769 $239,830 $221,769
Net utility plant $227,741 $202,313 $190,307 $179,473 $169,792 $159,012 $149,272
Net non-utility plant $ 2,628 $ 2,692 $ 1,182 $ 1,141 $ 1,958 $ 2,033 $ 2,118
Financial ratios:
Payout ratio 77.14% 99.08% 80.00% 68.79% 99.08% 72.60% 88.70%
Price/earnings ratio 19.82X 17.89x 14.54x 11.46x 14.68x 11.82x 14.66x
Market to book ratio 1.81X 1.31x 1.34x 1.22x 1.16x 1.25x 1.52x
Return on average common equity 9.29% 7.41% 9.31% 11.10% 7.87% 10.75% 10.35%
Times interest charges earned before FIT 2.53X 2.30x 2.69x 2.96x 2.39x 3.12x 2.64x
Times interest charges earned after FIT 2.01X 1.85x 2.11x 2.29x 1.92x 2.41x 2.10x
Depreciation and amortization to energy revenues 7.77% 6.55% 5.84% 5.58% 5.69% 4.32% 4.34%
Depreciation and amortization to utility plant 5.06% 4.30% 4.28% 4.29% 3.98% 4.01% 4.09%
Other:
Number of employees (actual) 615 637 562 575 553 568 608
<CAPTION>
(in thousands, except where noted) 1992 1991 1990 1989
- --------------------------------- ---- ---- ---- ----
<S> <C> <C> <C> <C>
Federal income tax provision
(benefit):
Current $ 2,374 $ 577 $ 1,713 $ (2,210)
Deferred 347 305 107 (474)
Investment tax credits, net - - (2) (6)
----------------------------------------
Total Federal income tax provision (benefit) 2,721 882 1,818 (2,690)
Net income (loss) before preferred dividends of
subsidiary 5,830 2,691 4,965 (3,314)
----------------------------------------
Income (loss) before income taxes $ 8,551 $ 3,573 $ 6,783 $ (6,004)
========================================
Effective tax rate 31.80% 24.70% 26.80% -44.80%
Statutory tax rate 34.00% 34.00% 34.00% 34.00%
Property:
Expenditures for property, plant, and equipment $ 13,391 $ 12,411 $ 15,737 $ 17,019
Gross utility plant $210,087 $199,216 $189,952 $172,302
Net utility plant $144,767 $139,741 $135,331 $124,644
Net non-utility plant $ 2,203 $ 2,655 $ 4,475 $ 4,489
Financial ratios:
Payout ratio 95.65% 250.00% 119.66% NM
Price/earnings ratio 13.91x 30.80x 13.03x NM
Market to book ratio 1.33x 1.45x 1.21x 1.40x
Return on average common equity 9.61% 4.54% 9.25% -5.83%
Times interest charges earned before FIT 2.25x 1.51x 1.86x 0.10x
Times interest charges earned after FIT 1.85x 1.35x 1.64x 0.50x
Depreciation and amortization to energy revenues 4.56% 4.43% 4.15% 3.77%
Depreciation and amortization to utility plant 4.13% 3.76% 3.43% 3.14%
Other:
Number of employees (actual) 610 690 729 704
</TABLE>
NM - Not Meaningful
Page 36
<PAGE>
GLOSSARY AND DEFINED TERMS
- --------------------------
BUNDLING: The sale and/or transportation of natural gas under one rate, which
does not differentiate separate rate components for the sale, transportation,
storage, or gathering services associated with such sale or transportation.
BUSINESS CHOICE: The unbundling program of ProvGas, which enables customers to
purchase gas from other suppliers, i.e. retail marketers that "rent space"
(transportation capacity) on ProvGas pipelines.
CAPACITY: The amount of natural gas that can be produced, transported, stored,
distributed, or utilized in a given period of time under design conditions.
CITY GATE: The city gate is the point at which interstate and intrastate
pipelines deliver natural gas to local distribution companies, in other words,
the physical connection of an interstate pipeline and the pipes of a local gas
utility.
DEGREE DAY: A measure of the coldness of the weather experienced, based on the
extent to which the daily mean temperature falls below a reference temperature,
usually 65 degrees F. For example, on a day when the mean outdoor dry-bulb
temperature is 35 degrees F, there would be 30 degree days experienced. A daily
mean temperature usually represents the sum of the high and low readings divided
by two.
DEMAND SIDE MANAGEMENT REBATE PROGRAM: In 1996, ProvEnergy implemented
this program, which furnishes rebates to customers installing new technologies,
such as gas-fired air conditioning, cogeneration and gas motors--technologies
that use proportionately more natural gas during summer months, ProvGas' off-
peak season.
ENERGIZE RI: An innovative three-year regulatory plan designed to provide price
stability to customers, improve system reliability, and enhance economic
development while improving earnings stability. Effective from the period from
October 1, 1997 to September 30, 2000, the Plan provides customers with an
initial price decrease of approximately four percent in addition to a three-year
price freeze. Under the Plan, ProvGas may earn up to 10.9 percent annually on
its average common equity, subject to certain limits as set forth in the Plan.
ENERGY MARKETER: An entity engaged in selling energy commodities, such as
natural gas. Services typically include procuring supply, arranging
transportation, and delivery. Marketers usually buy for their own account and
resell commodities. A major function of marketers is aggregating natural gas
supplies and/or markets.
EXOGENOUS CHANGE(S): The Energize RI agreement defines certain "Exogenous
Changes," i.e., "...significant increases or decreases in the ProvGas' costs or
revenues which are beyond ProvGas' reasonable control."
FEDERAL ENERGY REGULATORY COMMISSION: An agency within the United States
Department of Energy that, among other things, has jurisdiction over natural gas
companies that sell or transport gas in interstate commerce for resale.
FIRM CUSTOMER: A customer for whom contract demand is reserved and to whom the
supplier is obligated to provide service. Firm customers pay a higher rate but
also receive higher priority delivery service.
Page 37
<PAGE>
FIRM TRANSPORTATION SERVICE: Provides for the transportation on a firm 365-day
basis of gas supplies purchased on a customer's behalf from a supplier other
than ProvGas. Service is classified as either FT-1 or FT-2 SERVICE.
FT-1 SERVICE: Firm transportation service for customers purchasing gas from
other suppliers. This service requires daily balancing of consumption and
deliveries.
FT-2 SERVICE: Same as FT-1 SERVICE, without the requirement for recording daily
usage.
GATE STATION: See CITY GATE.
HEDGING: The simultaneous execution of equal and opposite positions in the cash
and futures markets in order to protect against adverse price movement in the
cash market.
INTERRUPTIBLE SERVICE: See NON-FIRM SERVICE
LIQUEFIED NATURAL GAS: Natural gas that has been super cooled under
pressure to (259 degrees F). Liquefied natural gas is almost pure methane. In
volume it occupies 1/600 of the space occupied in the vapor state at standard
conditions.
LOCAL DISTRIBUTION COMPANY: A company that obtains the major portion of its
natural gas revenues from the operations of a retail gas distribution system and
that operates no transmission system other than incidental connections within
its own system or to the system of another company. Both ProvGas and North
Attleboro Gas are LDCs.
NON-FIRM SERVICE: Sales and transportation service that is offered at both a
lower cost and lower level of reliability. Under this service, gas companies
can interrupt customers on short notice, typically during peak service days in
the winter season. Non-firm services are provided through individually
negotiated contracts and in most cases, the price and availability charge takes
into account the price of the customer's alternative fuel.
OFF-PEAK: The period during a day, week, month, or year when the load being
delivered by a gas system is not at or near the maximum volume delivered by that
system for the corresponding period of time. For ProvGas, the period from May
through October.
PEAK: For ProvGas, the period from November through April.
PORTLAND NATURAL GAS TRANSMISSION SYSTEM: PNGTS is a new 272-mile gas pipeline
that runs from Quebec to Massachusetts. ProvGas is using its Supervisory
Control and Data Acquisition (SCADA) system to monitor the portion of the
pipeline that runs from Pittsburg, New Hampshire, on the Quebec border, to
Westbrook, Maine, just outside of Portland, Maine.
PRICE STABILIZATION PLAN SETTLEMENT AGREEMENT: See ENERGIZE RI.
RATE STABILIZATION PLAN: See ENERGIZE RI.
Page 38
<PAGE>
STORAGE SERVICE: A service in which natural gas is received by the seller of the
service and held for the customer's account for redelivery at a later time. It
requires the use of storage facilities that can be reinjected and produced with
minimal loss. Storage service usually requires payment of injection fees,
withdrawal fees, and holding fees and involves limits on rates and times of
injection and withdrawal, and maximum volumes to be held.
THERM: A unit of heating value equivalent to 100,000 British thermal units
(BTUs).
THROUGHPUT: Total of transportation volumes and tariff sales; gas volumes
delivered through a LDC's gas distribution system.
UNBUNDLING: The process of separating out the package of services offered by a
gas company--i.e., transportation, storage, gathering and products extraction--
and charging separate rates or rate components for each service that fairly
represent the cost of providing that service. See BUSINESS CHOICE.
Page 39
<PAGE>
ABBREVIATIONS, ACRONYMS AND OTHER DEFINED TERMS:
AFUDC: Allowance for Funds Used During Construction
ALGONQUIN: Algonquin Gas Transmission Company
CCEC: Capital Center Energy Company, LLC
CGA: Cost of Gas Adjustment Clause
CIS: Customer Information System
DEM: Rhode Island Department of Environmental Management
DETM: Duke Energy Trading and Marketing, L.L.C.
DIVISION: Rhode Island Division of Public Utilities and Carriers
FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission
GAAP: Generally Accepted Accounting Principles
GCC: Gas Change Clause
HVAC: Heating, Ventilating and Air Conditioning systems
IRP: Integrated Resource Plan
IT: Information Technology
LDC: Local Distribution Company
LNG: Liquefied Natural Gas
MALL: Providence Place Mall
MDTE: Massachusetts Department of Telecommunications and Energy
PBR: Performance Based Regulation
PNGTS: Portland Natural Gas Transmission System
PRP: Potentially Responsible Party
RIPUC: Rhode Island Public Utilities Commission
SCADA: Supervisory Control and Data Acquisition system
SEC: Securities and Exchange Commission
Page 40
<PAGE>
SFAS: Statement of Financial Accounting Standards
SOP: Statement of Position
VEBA TRUST: Voluntary Employee Benefit Association Trust
COMPANY NAMES:
CCEC: Capital Center Energy Company, LLC
COMPANY: Providence Energy Corporation or ProvEnergy
NORTH ATTLEBORO GAS: North Attleboro Gas Company
PROVENERGY FUELS: ProvEnergy Fuels, Inc.
PROVENERGY POWER: ProvEnergy Power, L.L.C.
PROVENERGY SERVICES: Providence Energy Services, Inc.
PROVGAS: The Providence Gas Company
SOUTHERN UNION: Southern Union Company
41
<PAGE>
Exhibit 21
Exhibit 21. SUBSIDIARIES OF THE REGISTRANT
- -------------------------------------------
The Providence Gas Company - Incorporated under the laws of Rhode Island.
Newport America Corporation - Incorporated under the laws of Rhode Island.
Providence Energy Services, Inc. - Incorporated under the laws of Rhode Island.
North Attleboro Gas Company - Incorporated under the laws of Massachusetts.
Providence Energy Oil Enterprises, Inc. - Incorporated under the laws of Rhode
Island.
ProvEnergy Power Company, LLC - Organized under the laws of Rhode Island.
PEC Ventures, Inc. - Incorporated under the laws of Rhode Island.
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<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 218,190
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