Back to GetFilings.com
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-8858
UNITIL CORPORATION
(Exact name of registrant as specified in its charter)
New Hampshire 02-0381573
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6 Liberty Lane West, Hampton, New Hampshire 03842-1720
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (603) 772-0775
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Exchange on Which Registered
Common Stock, No Par Value American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendments to this Form 10-K [ X ]
Based on the closing price of March 1, 1999, the aggregate market value of
common stock held by non-affiliates of the registrant was $106,027,649.
The number of common shares outstanding of the registrant was 4,660,556
as of March 1, 1999.
Documents Incorporated by Reference:
Portions of the Proxy Statement relating to the Annual Meeting of
Shareholders to be held April 15, 1999, are incorporated by reference
into Part III of this Report.
UNITIL CORPORATION
FORM 10-K
For the Fiscal Year Ended December 31, 1998
Table of Contents
Item Description Page
PART I
1. Business
The Unitil System ................................. 2
Utility Operations ............................... 2
Rates and Regulation ................................. 3
Electric Utility Industry Restructuring and Competition.. 5
Gas Utility Industry Restructuring and Competition..... 6
Electric Power Supply ............................... 6
Gas Supply ............................................. 8
Environmental Matters ................................ 8
Capital Requirements ................................. 9
Financing Activities............................... 9
Employees................................................ 10
Executive Officers of the Registrant............... 11
2. Properties ................................................ 12
3. Legal Proceedings.............................................. 13
4. Submission of Matters to a Vote of Securities Holders.......... 13
PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters ...................................... 14
6. Selected Financial Data ................................. 15
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations .................................. 16
8. Financial Statements and Supplementary Data................ 26
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure ................................. 48
PART III
10. Directors and Executive Officers of the Registrant .. . 49
11. Executive Compensation ................................. 49
12. Security Ownership of Certain Beneficial Owners
and Management .............................................. 49
13. Certain Relationships and Related Transactions ............. 49
PART IV1
14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K ........................................... 50
Consent of Independent Certified Public Accountants.......... 56
Signatures .................................................. 57
Schedule VIII Valuation and Qualifying Accounts and Reserves ......... 59
Exhibit 11.1 Computation in Support of Earnings per Share
Exhibit 12.1 Computation in Support of Ratio of Earnings
to Fixed Charges
Exhibit 21.1 Subsidiaries of Registrant
Exhibit 27 Financial Data Schedule
Exhibit 99.1 1998 Proxy Statement
Exhibit 4.23 Eleventh Supplemental Indenture relating to Exeter & Hampton
First Mortgage Bonds
Exhibit 4.24 Ninth Supplemental Indenture relating to Concord Electric
Company First Mortgage Bonds
Exhibit 10.2 Exeter & Hampton Company Labor Agreement
Exhibit 10.3 Fitchburg Gas and Electric Company Labor Agreement
Exhibit 10.12 Unitil Corporation 1998 Stock Option Plan
Exhibit 10.13 Unitil Corporation Management Incentive Plan
PART I
Item 1. Business.
THE UNITIL SYSTEM
Unitil Corporation (Unitil or the Company) was incorporated under
the laws of the State of New Hampshire in 1984. Unitil is a registered
public utility holding company under the Public Utility Holding Company Act
of 1935 (the 1935 Act), and is the parent company of the Unitil System. The
following companies are wholly owned subsidiaries of Unitil, which together
make up the Unitil System:
Unitil Corporation
Subsidiaries State and Principal Type
Year of of Business
Organization
Concord Electric Company (CECo) NH-1901 Retail Electric Distribution Utility
Exeter & Hampton Electric
Company (E&H) NH-1908 Retail Electric Distribution Utility
Fitchburg Gas and Electric
Light Company(FG&E) MA-1852 Retail Electric & Gas
Distribution Utility
Unitil Power Corp. (Unitil Power)NH-1984 Wholesale Electric Power Utility
Unitil Realty Corp.
(Unitil Realty) NH-1986 Real Estate Management
Unitil Service
Corp. (Unitil Service) NH-1984 System Service Company
Unitil Resources, Inc.
(Unitil Resources) NH-1993 Energy Marketing and Services
The Unitil System's principal business is the retail sale and
distribution of electricity and related services in several cities and towns
in the seacoast and capital city areas of New Hampshire, and both electricity
and gas and related services in north central Massachusetts, through Unitil's
three wholly owned retail distribution utility subsidiaries (CECo, E&H and
FG&E, collectively referred to as the Retail Distribution Utilities). The
Company's wholesale electric power utility subsidiary, Unitil Power Corp.,
principally provides all the electric power supply requirements to CECo and
E&H for resale at retail, and also engages in various other wholesale
electric power services with affiliates and non-affiliates throughout the
New England region.
Unitil has three additional wholly owned subsidiaries: Unitil Realty
Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and Unitil
Resources, Inc. (Unitil Resources). Unitil Realty owns and manages the
Company's corporate office building and property located in Hampton, New
Hampshire and leases this facility at cost to Unitil Service under a
long-term lease arrangement. Unitil Service provides, at cost, centralized
management, administrative, accounting, financial, engineering, information
systems, regulatory, planning, procurement, and other services to the Unitil
System companies. Unitil Resources is the Company's wholly owned non-utility
subsidiary and has been authorized by the Securities and Exchange Commission,
pursuant to the rules and regulations of the 1935 Act, to engage in business
transactions as a competitive marketer of electricity, gas and other energy
commodities in wholesale and retail markets, and to provide energy brokering,
consulting and management related services within the United States.
On March 25, 1999 Unitil acquired a minority interest in North
American Power Brokers, Inc., a privately held company providing Internet
technology solutions to the energy industry. Unitil, through Unitil
Resources, has licensed and deployed North American Power's innovative
Internet-based technology for electricity and natural gas energy
transactions between retail consumers and energy suppliers. Unitil will
offer the retail energy electronic commerce system developed and owned by
North American Power to medium and large commercial and industrial
customers, co-branded under the name "Usource", powered by North American
Power's World Wide Retail Energy Exchange.
UTILITY OPERATIONS
CECo is engaged principally in the distribution and sale of
electricity at retail to approximately 26,700 customers in the City of
Concord, which is the state capital, and twelve surrounding towns, all in
New Hampshire. CECo's service area consists of approximately 240 square
miles in the Merrimack River Valley of south central New Hampshire. The
service area includes the City of Concord and major portions of the
surrounding towns of Bow, Boscawen, Canterbury, Chichester, Epsom, Salisbury
and Webster, and limited areas in the towns of Allenstown, Dunbarton,
Hopkinton, Loudon and Pembroke.
The State of New Hampshire's government operations are located
within CECo's service area, including the executive, legislative, judicial
branches and offices and facilities for all major state government services.
In addition, CECo's service area is a retail trading center for the north
central part of the state and has over sixty diversified businesses relating
to insurance, printing, electronics, granite, belting, plastic yarns,
furniture, machinery, sportswear and lumber. Of CECo's 1998 retail electric
revenues, approximately 33% were derived from residential sales, 55% from
commercial, government and nonmanufacturing sales, and 12% from industrial/
manufacturing sales.
E&H is engaged principally in the distribution and sale of
electricity at retail to approximately 39,200 customers in the towns of
Exeter and Hampton and in all or part of sixteen surrounding towns, all in
New Hampshire. E&H's service area consists of approximately 168 square miles
in southeastern New Hampshire. The service area includes all of the towns of
Atkinson, Danville, East Kingston, Exeter, Hampton, Hampton Falls,
Kensington, Kingston, Newton, Plaistow, Seabrook, South Hampton and Stratham,
and portions of the towns of Derry, Brentwood, Greenland, Hampstead and
North Hampton.
Commercial and industrial customers served by E&H are quite
diversified and include retail stores, shopping centers, motels, farms,
restaurants, apple orchards and office buildings, as well as manufacturing
firms engaged in the production of sportswear, automobile parts and
electronic components. It is estimated that there are over 150,000 daily
summer visitors to E&H's territory, which includes several popular resort
areas and beaches along the Atlantic Ocean. Of E&H's 1998 retail electric
revenues, approximately 47% were derived from residential sales, 43% from
commercial and nonmanufacturing sales, 10% from industrial/manufacturing
sales.
FG&E is engaged principally in the distribution and sale of both
electricity and natural gas in the City of Fitchburg and several surrounding
communities. FG&E's service area encompasses approximately 170 square miles
in north central Massachusetts.
Electricity is supplied and distributed by FG&E to approximately
25,900 customers in the communities of Fitchburg, Ashby, Townsend and
Lunenburg. FG&E's industrial customers include paper manufacturing and paper
products companies, rubber and plastics manufacturers, chemical products
companies and printing, publishing and allied industries. Of FG&E's 1998
electric revenues, approximately 34% were derived from residential sales,
33% from commercial and nonmanufacturing sales, and 33% from industrial/
manufacturing sales.
Natural gas is supplied and distributed by FG&E to approximately
14,900 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby,
Gardner and Westminster, all located in Massachusetts. Of FG&E's 1998 gas
operating revenues, approximately 52% were derived from residential sales,
23% from commercial sales, 13% from firm sales to industrial customers, and
12% from interruptible sales (which are sales to customers that have agreed
to discontinue use of the Company-supplied service temporarily upon notice
by the Company, and which customers usually have an alternate fuel
capability, e.g., fuel oil, that they can employ during the interruption
periods). FG&E's industrial gas revenue is primarily derived from firm sales
to paper manufacturing and paper products companies, fabricated metal
products manufacturers, rubber and plastics manufacturers, primary iron
manufacturers and other miscellaneous industries.
Natural gas sales in New England are seasonal, and the Company's
results of operations reflect this seasonality. Accordingly, results of
operations are typically positively impacted by gas operations during the
five heating season months from November through March of the following year.
Electric sales in New England are far less seasonal than natural gas sales;
however, the highest usage typically occurs in the summer and winter months
due to air conditioning and heating requirements, respectively. The Unitil
System is not dependent on a single customer or a few customers for its
electric and gas sales.
(For details on the Unitil System's Results of Operations see
Part II, Item 7 herein.)
(For segment information see Part II, Item 8, Footnote 11 herein.)
RATES AND REGULATION
The Company is registered with the Securities and Exchange Commission
(SEC) as a holding company under the 1935 Act, and it and its subsidiaries
are subject to the provisions of the 1935 Act. Accordingly, the Securities
and Exchange Commission (SEC) has jurisdiction over Unitil and its
subsidiaries with respect to, among other things, securities issues, sales
and acquisitions of securities and utility assets, intercompany loans,
services performed by and for affiliated companies, certain accounts and
records, and involvement in non utility operations. The Company and its
subsidiaries, where applicable, are subject to regulation by the Federal
Energy Regulatory Commission (FERC), the New Hampshire Public Utilities
Commission (NHPUC) and the Massachusetts Department of Telecommunications
and Energy (MDTE) with respect to rates, adequacy of service, issuance of
securities, accounting and other matters. Unitil Power, as a wholesale
utility, is subject to rate regulation by the FERC. Both CECo and E&H, as
retail electric utilities in New Hampshire, are subject to rate regulation
by the NHPUC, and FG&E is subject to MDTE regulation with respect to gas and
electric retail rates, and FERC regulation with respect to New England Power
Pool (NEPOOL) interchanges and other wholesale sales of electricity.
Current Rate Regulation--- The revenues of Unitil's Retail
Distribution Utilities are collected pursuant to rates on file with the
NHPUC, the MDTE and, to a minor extent, the FERC. In general, the Retail
Distribution Companies current retail rates are comprised of a base rate
component, established during comprehensive base rate cases, and various
periodic rate adjustment mechanisms, which track and reconcile particular
expense elements with associated collected revenues. The last comprehensive
regulatory proceedings to increase base electric rates for Unitil's Retail
Distribution Utilities were in 1985 for CECo, 1984 for FG&E, and 1982 for
E&H. FG&E was granted its first Gas Base Rate adjustment in 14 years
effective December 1, 1998. The majority of the Unitil System's utility
operating revenues are presently collected under various rate adjustment
mechanisms, including revenues collected from customers for fuel, purchased
power, cost of gas, and demand-side management program costs.
The Unitil System Agreement (System Agreement), as approved by the
FERC, governs wholesale sales by Unitil Power to its New Hampshire retail
distribution affiliates, CECo and E&H, and provides for recovery by Unitil
Power of all costs incurred in the provision of service. Unitil Power has
continued to adjust its wholesale rates every six months in accordance with
the System Agreement, and CECo and E&H have continued to file corresponding
semiannual changes in their retail fuel and purchased power adjustment
clauses with the NHPUC which have been routinely approved.
Recent changes in legislation and regulation in Massachusetts has
changed the way FG&E provides service to its electric customers. Instead of
supplying energy on demand to all its customers, FG&E will deliver energy to
its customers on behalf of competitive suppliers and will supply energy to
customers who do not choose Standard Offer Service, and to customers whose
supplier fails to deliver Default Service. The result of these changes will
be the replacement of FG&E's quarterly filed electric fuel charge with:
a) an annually determined Standard Offer Service charge and reconciliation
adjustment mechanism; and b) a monthly determined Default Service charge and
reconciliation adjustment mechanism both of which are designed to allow FG&E
to recover all its power supply costs. In addition FG&E has implemented a
Transition Cost Charge and reconciliation adjustment mechanism enabling it
to recover all its stranded costs (See Electric Utility Industry
Restructuring and Competition).
FG&E's gas costs are recovered through a cost of gas adjustment
(CGA) mechanism, through which firm gas customers pay the costs incurred for
procuring and transporting gas to FG&E's local distribution system for
delivery to customers. FG&E gas operations have been incurring FERC-approved
transition charges from interstate pipeline suppliers since 1992, resulting
from the transition to a comprehensive set of new regulations under FERC
Order 636. These costs have been recovered directly from FG&E's gas
customers through the CGA mechanism, as authorized by the MDTE. FG&E does
not expect to incur any additional transition costs in 1999.
Millstone Unit No. 3- FG&E has a 0.217% nonoperating ownership in the
Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it
with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear
Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which
calls for increased NRC inspection attention. On March 30, 1996, as a result
of an engineering evaluation completed by the operator, Northeast Utilities,
Millstone 3 was taken out of service. NRC authorization for restart was
given on June 29, 1998. Millstone 3 began producing electric power in early
July, 1998 and reached full output on July 15, 1998. The unit remains on
the NRC's Watch List.
During the period that Millstone 3 was out of service, FG&E continued
to incur its proportionate share of the unit's ongoing Operations and
Maintenance (O&M) costs, and may incur additional O&M costs and capital
expenditures to meet NRC requirements. FG&E also incurred costs to replace
the power that was expected to be generated by the unit. During the outage,
FG&E had been incurring approximately $35,000 per month in replacement power
costs, and had been recovering those costs through its fuel adjustment
clause, which will be subject to review and approval by the MDTE.
In August 1997, FG&E, in concert with other non-operating joint
owners, filed a demand for arbitration in Connecticut and a lawsuit in
Massachusetts, in an effort to recover costs associated with the extended
unplanned shutdown. The arbitration and legal cases are proceeding.
SFAS No. 71 --- The Company accounts for all its regulated operations
in accordance with Statement of Financial Accounting Standard ("SFAS") No. 71,
"Accounting for the Effects of Certain Types of Regulation," requiring the
Company to record the financial statement effects of the rate regulation to
which the Company is currently subject. If a separable portion of the
Company's business no longer meets SFAS No. 71, the Company is required to
eliminate the financial statement effects of regulation for that portion.
(See "Impact of Electric Restructuring" in Note 8 of the financial statements
contained herein.)
(For a discussion of utility rates and regulation under a more
competitive environment, see the following sections on Electric Utility
Industry Restructuring and Competition, and Gas Utility Industry
Restructuring and Competition)
ELECTRIC UTILITY INDUSTRY RESTRUCTURING AND COMPETITION
Restructuring and Competition -Regulatory activity surrounding
restructuring and competition continues in both Massachusetts and New
Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition
for all electric consumers in Massachusetts, while New Hampshire's "Choice
Date" slipped past both the proposed date of January 1, 1998, and the
legislature's mandated July 1, 1998. Currently, approximately 10% of New
Hampshire electric consumers can choose their electric supplier. The ability
to choose for the remaining 90% is currently the subject of a federal court
preliminary injunction (see below).
Massachusetts gas industry restructuring plans continue to be under
development. The MDTE, gas utilities and other stakeholders began a
collaborative effort in late 1997 to develop solutions to the many issues
that surround restructuring the local natural gas distribution business.
Unitil has been preparing for electric and gas industry restructuring
by developing transition plans that will move its utility subsidiaries into
this new market structure in a way that will ensure fairness in the treatment
of the Company's assets and obligations that are dedicated to the current
regulated franchises and, at the same time, provide choice for all customers.
New Hampshire - On February 28, 1997, the New Hampshire
Public Utilities Commission (NHPUC) issued its Final Plan for transition to a
competitive electric market in New Hampshire. The order allowed CECo and E&H,
Unitil's New Hampshire retail distribution utilities, to recover 100% of
"stranded" costs for a two-year period, but excluded recovery of certain
administrative-related charges.
Northeast Utilities' affiliate, Public Service Company of New
Hampshire, appealed the NHPUC order in Federal District Court. A temporary
restraining order was issued on March 10, 1997. In June 1997, Unitil was
admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June
9, 1998, the Federal Court issued an injunction continuing the freeze on
NHPUC efforts to implement restructuring. Several parties have filed
interlocutory appeals, and no date has been scheduled for a trial in the
federal court. The Company will vigorously pursue its action in the federal
court and simultaneously look for ways to resolve issues and bring forth
choice to its retail customers.
In September of 1998, the Company reached a comprehensive
restructuring settlement with key parties and filed this voluntary Agreement
with the NHPUC. The Agreement was modified on October 20, 1998. In oral
deliberations on November 2 and November 18, 1998, the NHPUC imposed
conditions to approval of the Settlement which were unacceptable to the
Company, and the Settlement was subsequently withdrawn. The component of the
Agreement dealing with wholesale rates was filed with the FERC in September
1998, and approved by the FERC in early November. However, implementation
will not occur, as the changes were conditioned upon approval by the NHPUC.
Unitil continues to participate actively in all proceedings and in several
NHPUC-established working groups which will define details of the transition
to competition and customer choice.
NH Pilot Program -- In June 1996, the New Hampshire Retail
Competition Pilot Program (Pilot Program), mandated by legislation enacted a
year earlier, became operational. During the two-year term of the Pilot
Program, up to 3% or some 17,000 New Hampshire electric consumers were
allowed to choose from competing electric suppliers, and have this supply
delivered across the local utility system. The Company's subsidiary, Unitil
Resources, Inc., began competitive marketing efforts in May 1996, and began
making sales in June, 1996. The State of New Hampshire recently extended
this program beyond the original 24 month period. As of March 1, 1999, Unitil
Resources, Inc. is marketing energy competitively to over 700 customers
outside the Unitil companies' traditional franchise territories under the
Pilot Program.
Massachusetts (Electric)- On January 15, 1999, the MDTE gave
final approval to FG&E's restructuring plan with certain modifications. The
Plan provides customers with: a) a choice of energy supplier; b) an option
to purchase Standard Offer Service (i.e. state-mandated energy service)
provided by FG&E at regulated rates for up to seven years; and c) a
cumulative 15% rate reduction. The Plan also provides for FG&E to divest of
its generation assets and its portfolio of purchased power contracts. The
Company will be afforded full recovery of any transition costs through a
non-bypassable retail Transition Charge.
Pursuant to the Plan, on October 30, 1998, the Company filed with the
MDTE a proposed contract with Constellation Power Services Inc. for provision
of Standard Offer Service. The MDTE's January 15, 1999 Order approves the
FG&E/Constellation contract, and service thereunder is scheduled to commence
on March 1, 1999, and is scheduled to continue through February 28, 2005.
This contract is the result of the first successful Standard Offer auction
conducted in Massachusetts.
The January 15 Order also approved the Company's power supply
divestiture plan for its interest in three generating units and four
long-term power supply contracts. A contract for the sale of FG&E's interest
in the New Haven Harbor plant was filed with the MDTE on November 20, 1998.
The MDTE's decision is pending. Contracts for the sale of the Company's
remaining generating assets and purchased power contracts are expected to be
filed with the MDTE in the near future. All such contracts are subject to
MDTE approval.
GAS UTILITY INDUSTRY RESTRUCTURING AND COMPETITION
In mid-1997, the MDTE directed all Massachusetts natural gas Local
Distribution Companies (LDCs) to form a collaborative with other stakeholders
to develop common principles and appropriate regulations for the unbundling
of gas service, and directed FG&E and four other LDCs to file unbundled gas
rates for its review. FG&E's unbundled gas rates were approved by the MDTE
and implemented in November of 1998.
On July 2, 1998 the MDTE established April 1, 1999 as the date by
which unbundled gas service would begin to be implemented by all LDCs. On
February 1, 1999, the MDTE issued an order in which it determined that the
LDCs would continue to have an obligation to provide gas supply and delivery
services for another five years, with a review after three years. That order
also set forth the MDTE's decision regarding release by LDCs of their
pipeline capacity contracts to competitive marketers. In January of 1999,
the LDCs reported to the MDTE that they were continuing to work to develop
systems and practices to implement unbundling. The MDTE has not yet
responded to the LDCs' report, and it appears unlikely that full
implementation will be achieved by the April 1, 1999 target date.
ELECTRIC POWER SUPPLY
New England Power Pool --- FG&E, UPC, CECo, E&H and URI are members
of the New England Power Pool (NEPOOL). NEPOOL was formed to assure reliable
operation of the bulk power system in the most economic manner for the
region. Under the NEPOOL Agreement, to which virtually all New England
electric utilities are parties, substantially all operation and dispatching
of electric generation and bulk transmission capacity in New England is
performed on a regional basis. NEPOOL is governed by an agreement that is
filed with the FERC and its provisions are subject to continuing FERC
jurisdiction. The NEPOOL Agreement imposes generating capacity and reserve
obligations, provides for the use of major transmission facilities and
payments associated therewith. The most notable benefits of NEPOOL are
coordinated power system operation in a reliable manner and providing a
supportive business environment for the development of a competitive electric
marketplace.
As a result of ongoing legislative and regulatory initiatives which
are primarily focused on the deregulation of the generation and supply of
electricity and the corresponding development of a competitive market place
from which customers could choose their electric energy supplier, the NEPOOL
Agreement is being restructured. NEPOOL's membership provisions have been
broadened to cover all entities engaged in the electricity business in New
England, including power marketers and brokers, independent power producers,
load aggregators and retail customers in states that have enacted retail
access statutes. The regional bulk power system is operated by an
independent corporate entity, ISO New England (ISO-NE), so that there is no
opportunity for conflicting financial interests between the system operator
and the market-driven participants. Various energy and capacity products will
be traded in open, competitive markets, with transmission access and pricing
subject to a regional tariff designed to promote competition among power
suppliers. A new capacity market was implemented last year, and the other
markets are expected to begin on April 1, 1999. Furthermore, on April 1, 1999
or shortly thereafter, the ISO-NE is scheduled to begin dispatching
generating units using a bid-based system rather than the current system of
dispatching units based on fuel costs.
Energy Resources --- Effective April 1, 1998, each electric utility's
capability responsibility under the NEPOOL Agreement involves carrying an
allocated share of New England capacity requirements which is determined for
each month based on regional reliability criteria. Unitil Power Corp., the
full requirements supplier to CECo and E&H, had a capability responsibility
for December, 1998 of 232.16 MW and a corresponding monthly peak demand of
180.13 MW. FG&E's capability responsibility for December, 1998 was 110.62 MW,
with a corresponding monthly peak demand of 85.72 MW.
To meet the needs of CECo and E&H, Unitil Power Corp. has contracted
for generating capacity and energy and for associated transmission services
as needed to meet NEPOOL requirements and to provide a diverse and economical
energy supply. Unitil Power's purchases are from various utility and
non-utility generating units using a variety of fuels and from several
utility systems in the U.S. and Canada. For the twelve months ended December
31,1998, Unitil Power's energy needs were provided by the following fuel
sources: nuclear (27%), oil (18%), coal (11%), gas (21%), wood and refuse
(4%) , hydro (1%), and system and other (18%).
FG&E meets its capacity requirements through purchase power contracts
and ownership interests in three generating units in which FG&E participates
on a tenancy-in-common basis as a nonoperating owner. FG&E's purchases are
from various utility and non-utility generating units using a variety of
fuels and from several utility systems in the U.S. and Canada. For the twelve
months ended December 31, 1998, FG&E's energy needs, including generation
from joint-owned units, were provided from the following fuel sources: oil
(25%), wood (26%), hydro (4%), coal (19%) and nuclear, system and other (26%).
FG&E has a 4.5% ownership interest, or 20.12 MW, in an oil and
natural gas-fired generating plant in New Haven, Connecticut, which is
operated by The United Illuminating Company, the plant's majority owner.
FG&E also has a 0.1822% ownership interest, or 1.13 MW, in an oil-fired
generating plant in Yarmouth, Maine, which is operated by Central Maine Power
Company as the majority owner, and a 0.217% ownership interest, or 2.5 MW,
in the Millstone 3 nuclear unit operated by Northeast Utilities, parent of
the principal owners of that unit. In addition, FG&E operates an oil-fired
combustion turbine with a current capability of 26.6 MW under a long-term
financing lease. As a result of the aforementioned FG&E Electric
Restructuring Plan approved by the MDTE, FG&E will divest of its electric
generating assets. (See Management Discussion and Analysis for further
discussion of the FG&E Electric Restructuring Plan).
Fuel --- Oil: Approximately 25% of FG&E's and 18% of UPC's electric power
in 1998 was provided by oil-fired units, some of which are owned by FG&E.
Most fuel oil used by New England electric utilities is acquired from foreign
sources and is subject to interruption and price increases by foreign
governments.
Coal: Approximately 19% of FG&E's and 11% of UPC's 1998 requirements
were from coal-burning facilities. The facilities generally purchase their
coal under long term supply agreements with prices tied to economic indices.
Although coal is stored both on-site and by fuel suppliers, long term
interruptions of coal supply may result in limitations in the production of
power or fuel switching to oil and thus result in higher energy prices.
Nuclear: FG&E has a 0.217% ownership interest in Millstone Unit No. 3
(the Unit). The Unit has contracted for certain segments of the nuclear fuel
production cycle through various dates. This cycle includes, among other
things, mining, enrichment and disposal of used fuel.
Pursuant to the Nuclear Waste Policy Act of 1982, the participants
in Millstone 3 were required to enter into contracts with the United States
Department of Energy, prior to the operation of that Unit, for the transport
and disposal of spent fuel at a nuclear waste repository. FG&E cannot predict
whether the Federal government will be able to provide storage or permanent
disposal repositories for spent fuel.
GAS SUPPLY
FG&E distributes gas purchased from domestic and Canadian suppliers
under long term contracts as well as gas purchased from producers and
marketers on the spot market. The following tables summarize actual gas
purchases by source of supply and the cost of gas sold for the years 1996
through 1998.
Sources of Gas Supply
(Expressed as percent of total MMBtu of gas purchased)
Natural Gas: 1998 1997 1996
Domestic firm............................ 78.4% 82.7% 80.8%
Canadian firm............................... 6.4% 5.7% 7.0%
Domestic spot market....................... 14.5% 10.5% 10.7%
Total natural gas............................. 99.3% 98.9% 98.5%
Supplemental gas............................. 0.7% 1.1% 1.5%
Total gas purchases........................... 100.0% 100.0% 100.0%
Cost of Gas Sold
1998 1997 1996
Cost of gas purchased and sold per MMBtu.... $3.30 $3.55 $3.95
Percent Increase (Decrease) from prior year...(7.0)% (10.1)% 30.4%
As a supplement to pipeline natural gas, FG&E owns a propane air gas
plant and a liquefied natural gas (LNG) storage and vaporization facility.
These plants are used principally during peak load periods to augment the
supply of pipeline natural gas.
ENVIRONMENTAL MATTERS
The Company does not expect that compliance with environmental laws
or regulations will have a material effect on its business, or the businesses
of its subsidiaries. The Company does not know whether, or to what extent,
such regulations may affect it or its subsidiaries by impinging on the
operations of other electric and gas utilities in New England.
Unitil Power Corp. and FG&E purchase wholesale capacity and energy
from a diverse group of suppliers using various fuel sources and FG&E has
ownership interests in certain generating plants. Some of the purchase power
contracts contain cost adjustment provisions that may allow the supplier to
pass through environmental remediation costs. The Company has not been
informed whether any of these suppliers are likely to incur significant
environmental remediation costs and, if so, which if any such costs may be
passed through.
In September 1998, the FG&E signed a memorandum of understanding with
the Massachusetts Highway Department and the Massachusetts Department of
Environmental Protection that accommodates the construction of a new highway
bridge across Sawyer Passway, the Company's former manufactured gas plant
(MGP) site. This memorandum satisfies the requirements of the Massachusetts
Contingency Plan for temporary closure at this last remaining portion of the
site. Specifically, this agreement allows for current FG&E efforts to
perform remediation work required as result of bridge construction. Upon
completion of site remediation associated with the bridge construction, this
last remaining portion of the Sawyer Passway MGP site is expected be closed
out and attain the status of temporary closure in late 1999. This temporary
closure allows FG&E to monitor the site every five years to determine if a
more feasible remediation alternative can be developed and achieved.
The costs of remedial action at this site are initially funded from
traditional sources of capital and recovered from customers under a rate
recovery mechanism approved by the MDTE. The Company also has a number of
liability insurance policies that may provide coverage for environmental
remediation at this site.
CAPITAL REQUIREMENTS
Net capital expenditures increased approximately $0.6 million in 1998
compared to 1997, reflecting higher planned spending for utility customer
and distribution system additions and improvements. The decrease of $4.6
million in 1997 compared to 1996 reflected spending, in 1996, for the
construction of the Company's new corporate headquarters. The Company also
received cash payments of $0.9 million from the State of New Hampshire in
1996, related to the eminent domain taking of is former corporate
headquarters for a highway expansion project .
In 1999, total capital expenditures are expected to approximate
$15.7 million. This projection reflects normal capital expenditures for
system expansions, replacements and other improvements.
FINANCING ACTIVITIES
The increase in cash flows in 1998 compared to 1997 reflects higher
net borrowings of $6.1 million and increased common stock issued of $0.3
million, net of other items.
During the year ended December 31, 1998, Concord Electric Company
(CECo) sold $10,000,000 of 30-year Series J First Mortgage Bonds at par to
an institutional investor, bearing an interest rate of 6.96%. Proceeds were
used to repay short-term indebtedness, incurred to fund CECo's ongoing
construction programs, and to redeem a higher coupon long-term debt issue
prior to its maturity. The redemption of $4,550,000 was on the 9.43% Series
H First Mortgage Bonds.
During the year ended December 31, 1998, Exeter & Hampton Electric
Company (E&H) sold $10,000,000 of 30-year Series L First Mortgage Bonds at
par to an institutional investor, bearing an interest rate of 6.96%.
Proceeds were used to repay short-term indebtedness, incurred to fund E&H's
ongoing construction programs, and to redeem two higher coupon long-term
debt issues prior to their maturity. The redemptions, which totaled
$4,200,000, included $700,000 of 8.5% Series H First Mortgage Bonds, and
$3,500,000 of 9.43% Series J First Mortgage Bonds.
Additional short-term borrowings were incurred, primarily to fund
1998 costs related to electric industry restructuring in Massachusetts that
will be collected in future periods.
The change in Cash Flows from Financing Activities in 1997 compared
to 1996 reflects a decrease in borrowings due to the repayment of short-term
debt. Higher short-term borrowings in 1996 were primarily due to funding of
the timing difference (under collection) between payments on fuel, purchased
power and purchased gas costs and the corresponding recovery of these costs
in revenue billed under periodic cost recovery mechanisms as well as the
construction financing of the Company's new corporate headquarters.
The Company currently has unsecured committed bank lines for
short-term debt aggregating $25,000,000 with four banks for which it pays
commitment fees. At December 31, 1998, the unused portion of the committed
credit lines outstanding was $5,000,000. The average interest rate on all
short-term borrowings were 5.95% and 5.98% during 1998 and 1997, respectively.
EMPLOYEES
As of December 31, 1998, the Company and its subsidiaries had 324
full-time employees. The Company considers its relationship with its
employees to be good and has not experienced any major labor disruptions
since the early 1960's.
There are 101 employees represented by labor unions. In 1998, E&H
reached a new three year pact with its employees covered by a collective
bargaining agreement which will expire effective May 31, 2000. In 1997, CECo
reached a new three year pact with its employees covered by a collective
bargaining agreement which will expire effective May 31, 2000. In 1998,
FG&E reached a one year pact with its employees covered by collective
bargaining agreements which will expire effective May 31, 2000. The
agreements provided for discreet salary adjustments, established work
practices and provided uniform benefit packages. The Company expects to
successfully negotiate new agreements prior to the expiration dates of these
contracts.
The Company and its subsidiaries, where applicable, have in force
funded Retirement Plans and related Trust Agreements providing retirement
annuities for participating employees at age 65. The Company's policy is to
fund the pension cost accrued (see Note 9 of Notes to Consolidated Financial
Statements contained in Part II, Item 8).
The Company established a new Key Employee Stock Option Plan (KESOP)
scheduled to begin in 1999, which provides for the granting of options to key
employees. The number of shares granted under this plan, as well as the terms
and conditions of each grant, are determined by the Board of Directors,
subject to plan limitations. All options granted under the KESOP vest upon
grant (See Exhibit 10.12).
The original KESOP plan that began in 1989 included a provision that
no options could be issued after March, 1999. All of the options that were
granted under the original plan were exercised as of March 31, 1999 except
for 25,000 which remain outstanding.
The Company established a the "Unitil Corporate Management Incentive
Plan" which provides key management employees of Unitil Corporation and its
subsidiaries with incentives related to the performance of the Corporation
(See Exhibit 10.13).
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of the
Company as of March 1, 1999 are listed below, along with a brief account of
their business experience during the past five years. All officers are
elected annually by the Board of Directors at the Directors' first meeting
following the annual meeting which is held on the third Thursday in April,
or at a special meeting held in lieu thereof. There are no family
relationships among these officers, nor is there any arrangement or
understanding between any officer and any other person pursuant to which the
officer was selected. Officers of the Company also hold various Director and
Officer positions with subsidiary companies.
Name, Age
and Position Business Experience
During Past 5 years
Robert G. Schoenberger, 48,
Chairman of the Board of Directors
and Chief Executive Officer Mr. Schoenberger has been Chairman of
the Board and Chief Executive Office
of Unitil since 1997. Prior to his
employment with Unitil, Mr.
Schoenberger was President and Chief
Operating Officer at New York Power
Authority (NYPA) from 1993 until
1997. Prior to 1993, he was Executive
Vice President - Finance and
Administration, also at NYPA (state
owned public power enterprise).
Michael J. Dalton, 58,
President and Chief Operating Officer Mr. Dalton has been a Director,
President and Chief Operating
Officer of the Company since its
incorporation in 1984.
Anthony J. Baratta, Jr., 55,
Senior Vice President and
Chief Financial Officer Mr. Baratta has been Senior Vice
President and Chief Financial
Officer of Unitil since 1998. Prior
to his employment with Unitil, Mr.
Baratta was Executive Vice President
and Chief Financial Officer at New
World Power Corporation. From 1990
to 1995, Mr. Baratta was President,
Chief Executive Officer and Director
at HYDRA-CO Enterprises, Inc., a
wholly-owned subsidiary of Niagara
Mohawk Power Corp., and prior to
that held several senior management
positions within Niagara Mohawk.
Mark H. Collin, 40,
Treasurer and Secretary and
Vice President, Unitil Service Mr. Collin was appointed Treasurer
and Secretary in January, 1998. Mr.
Collin has been the System subsidiary
Treasurer and Vice President of
Unitil Service Corp. since 1992.
James G. Daly, 41
Senior Vice President Energy
Resources Unitil Service Mr. Daly has been Senior Vice
President of Unitil Service since
1994. Mr. Daly was Vice President of
Unitil Service Corp. from 1992 to
1994.
George R. Gantz, 47
Senior Vice President Business
Development Unitil Service Mr. Gantz has been Senior Vice
President of Unitil Service since
1994. Mr. Gantz was Vice President
of Unitil Service from 1989 to 1994.
Item 2. Properties
CECo's distribution service center building and adjoining
administration building, totaling 37,560 square feet of office, warehouse
and garage area, are located on land in the City of Concord owned by CECo in
fee. CECo's sixteen electric distribution substations constitute 100,790 kVA
of capacity for the transformation of electric energy from the 34.5 kV
transmission voltage to primary distribution voltage levels. The electric
substations are, with one exception, located on land owned by CECo in fee.
The sole exception is located on land occupied pursuant to a perpetual
easement.
CECo has in excess of 34 pole miles of 34.5 kV electric transmission
facilities located, with minor exceptions, either on land owned by CECo in
fee or on land occupied pursuant to perpetual easements. CECo also has a
total of approximately 632 pole miles of overhead electric distribution
lines and a total of approximately 44 conduit bank miles (118 cable miles)
of underground electric distribution lines. The electric distribution lines
are located in, on or under public highways or private lands pursuant to
lease, easement, permit, municipal consent, tariff conditions, agreement or
license, expressed or implied through use by CECo without objection by the
owners. In the case of certain distribution lines, CECo owns only a part
interest in the poles upon which its wires are installed, the remaining
interest being owned by telephone and telegraph companies.
Additionally, CECo owns in fee 137.7 acres of land located on the
east bank of the Merrimack River in the City of Concord. Of the total
acreage, 81.2 acres are located within an industrial park zone, as specified
in the zoning ordinances of the City of Concord.
The physical properties of CECo (with certain exceptions) and its
franchises are subject to the lien of its Indenture of Mortgage and Deed of
Trust, as supplemented, under which the respective series of First Mortgage
Bonds of CECo are outstanding.
E&H's distribution and engineering service center building is
located on land owned by E&H in fee. E&H's fourteen electric distribution
substations, including a 5,000 kVA mobile substation, constitute 91,400 kVA
of capacity for the transformation of electric energy from the 34.5 kV
transmission voltage to primary distribution voltage levels. The electric
substations are located on land owned by E&H in fee.
E&H has in excess of 68 pole miles of 34.5 kV electric transmission
facilities located on land either owned or occupied pursuant to perpetual
easements. E&H also has a total of approximately 713 pole miles of overhead
electric distribution lines and a total of approximately 87 conduit bank
miles of underground electric distribution lines. The electric distribution
lines are located in, on or under public highways or private lands pursuant
to lease, easement, permit, municipal consent, tariff conditions, agreement
or license, expressed or implied through use by E&H without objection by the
owners. In the case of certain distribution lines, E&H owns only a part
interest in the poles upon which its wires are installed, the remaining
interest being owned by telephone and telegraph companies.
Certain physical properties of E&H and its franchises are subject to
the lien of its Indenture of Mortgage and Deed of Trust, as supplemented,
under which the respective series of First Mortgage Bonds of E&H are
outstanding.
FG&E owns a liquid propane gas plant and a liquid natural gas plant,
both of which are located on land owned in fee. The Company has entered into
agreements for joint ownership with others of one nuclear and two fossil fuel
generating facilities. As a result of the aforementioned FG&E electric
restructuring plan that was approved by the MDTE, FG&E will divest its
electric generating assets. At December 31, 1998, the electric properties of
the Company consisted principally of 69 miles of transmission lines, 16
transmission and distribution substations with a total capacity of 562,900
kVA and 467 miles of distribution lines. Electric transmission facilities
(including substations) and steel, cast iron and plastic gas mains owned by
the Company are, with minor exceptions, located on land owned by the Company
in fee or occupied pursuant to perpetual easements. The Company leases its
service building. (See Business - Electric Power Supply and Gas Supply above
for additional information regarding the Company's plants, facilities and
gas mains and services.)
Unitil Realty owns the Company's corporate headquarters building and
12 acres of land in fee, which is located in the town of Hampton, New
Hampshire. The Company believes that its facilities are currently adequate
for their intended uses.
Item 3. Legal Proceedings
The Company is involved in legal and administrative proceedings and
claims of various types which arise in the ordinary course of business. In
the opinion of the Company's management, based upon information furnished by
counsel and others, the ultimate resolution of these claims will not have a
material impact on the Company's financial position.
Item 4. Submission of Matters to a Vote of Security Holders
None
PART II
Item 5. Market For Registrant's Common Equity and
Related Stockholder Matters
Common Stock Data
Dividends Paid Per Common Share 1998 1997
1st Quarter $0.34 $0.335
2nd Quarter $0.34 $0.335
3rd Quarter $0.34 $0.335
4th Quarter $0.34 $0.335
The Year $1.36 $1.34
1998 1997
High/Ask Low/Bid High/Ask Low/Bid
1st Quarter 27 1/4 23 5/8 21 1/8 18 5/8
2nd Quarter 25 5/8 22 1/4 21 3/8 18 3/4
3rd Quarter 24 3/8 21 1/8 23 3/8 20 3/8
4th Quarter 28 13/16 22 3/4 24 5/16 21 1/8
Item 6. Selected Financial Data
1998 1997 1996 1995 1994
Consolidated Statements of
Earnings (000's)
Operating Income $15,306 $15,562 $14,273 $14,225 $13,754
Non-operating Expense (Income) 156 160 (627) 217 64
Income Before Interest Expense 15,150 15,402 14,900 14,008 13,690
Interest Expense, Net 6,901 7,167 6,171 5,639 5,652
Net Income 8,249 8,235 8,729 8,369 8,038
Dividends on Preferred Stock 274 276 278 284 291
Net Income Applicable to
Common Stock $7,975 $7,959 $8,451 $8,085 $7,747
Balance Sheet Data (000's)
Utility Plant (Original Cost) $209,462 $219,475 $207,545 $190,177$178,777
Total Assets 376,835 238,531 232,108 211,702 204,521
Capitalization and Short-term Debt:
Common Stock Equity $75,351 $71,644 $67,974 $63,895 $59,997
Preferred Stock 3,843 3,891 3,891 3,999 4,094
Long-Term Debt 75,222 68,366 62,211 63,505 65,580
Total Capitalization $154,416 $143,901 $134,076 $131,399$129,671
Capitalization Ratios:
Common Stock Equity 49% 50% 51% 49% 46%
Preferred Stock 2% 3% 3% 3% 3%
Long-Term Debt 49% 47% 46% 48% 51%
Short-Term Notes Payable $20,000 $18,000 $21,400 $2,700 ---
Common Stock Data (000's)
Shares of Common Stock (Year-End) 4,575 4,464 4,384 4,330 4,268
Shares of Common Stock (Average) 4,506 4,413 4,354 4,299 4,234
Per Share Data
Basic Earnings Per Average Share $1.77 $1.80 $1.94 $1.88 $1.83
Diluted Earnings per Average Share $1.72 $1.76 $1.89 $1.85 $1.80
Dividends Paid Per Share (Year-End) $1.36 $1.34 $1.32 $1.28 $1.24
Book Value Per Share (Year-End) $16.47 $16.05 $15.50 $14.76 $14.06
Electric and Gas Statistics 1998 1997 1996 1995 1994
Electric Sales - (MWH) 1,540,96 1,491,103 1,532,015 1,401,292 1,358,165
Customers Served - Year End 92,495 91,492 89,865 88,316 86,782
Gas Sales - (000's of
Firm Therms) 22,027 23,716 24,508 22,303 23,057
Customers Served - Year End 14,915 14,943 14,848 14,846 15,012
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
FINANCIAL HIGHLIGHTS - 1998
1998 was a year of significant changes for the electric and gas
utility operations of Unitil Corporation ("Unitil" or the "Company") in the
state of Massachusetts. Changes in the Massachusetts regulatory environment
had a major impact on the Company's financial position at December 31, 1998,
and those regulatory changes have created a new definition of utility
operations at Unitil's Massachusetts subsidiary, Fitchburg Gas and Electric
Light Company (FG&E), on a going-forward basis.
As discussed below, several major events shaped our financial
position and results of operations in 1998. Electric utility industry
restructuring was implemented in Massachusetts with a 10% rate reduction
effective March 1, 1998. Under FG&E's restructuring plan (the "Plan"), which
received final approval on January 15, 1999, FG&E will complete the auction
of its electric generation and power supply portfolio and will receive 100%
recovery of its stranded costs.
FG&E also was granted its first Gas Base Rate adjustment in 14 years,
an annual increase of approximately $1 million or 7%, effective December 1,
1998. Even after the increase, the FG&E's gas rates are among the lowest in
Massachusetts. Also, on November 1, 1998, Gas utility industry bills were
"unbundled" in Massachusetts, and, based on an order issued by the
Massachusetts Department of Telecommunications and Energy (MDTE) on February
1, 1999, FG&E expects to begin transitioning out of the gas merchant function
for gas supply under a multi-year phase-in of a restructured natural gas
industry in Massachusetts.
Finally, the early 1998 record-setting weather conditions (the
warmest winter in at least 103 years) had a negative impact on the Company's
financial results, due to lower gas and electric sales in the first quarter
of 1998.
UNITIL RECEIVES FINAL ORDER ON FG&E'S ELECTRIC RESTRUCTURING PLAN IN
MASSACHUSETTS (SUBSEQUENT EVENT)
On January 15, 1999, the MDTE issued an order (the "Order")
approving FG&E's Electric Restructuring Plan with certain modifications.
Electric utility industry restructuring in Massachusetts became effective on
March 1, 1998, ("Choice Date"). On that date, FG&E implemented open retail
access, under its Plan, and all of FG&E's customers gained the right to
choose their electricity supplier. Regardless of the supplier chosen, FG&E
will continue to deliver electricity to all of its customers within its
distribution system, which remains a regulated business. On Choice Date,
FG&E's customers received a 10% rate discount. Since Choice Date, FG&E has
been authorized to earn a lower return on its generation-related investments.
FG&E is required to provide an additional 5% discount upon the earlier of
completion of its divestiture of generation investments or September 1, 1999.
FG&E has been allowed recovery of its restructuring transition costs,
estimated at $140 million, including its above-market or stranded generation
and power supply-related costs, via a non-bypassable uniform Transition
Charge. Estimated Regulatory Assets, based upon the Transition Charges to be
collected according to the Plan, have been recorded together with the
recognition of certain liabilities related to power supply contracts and
generation assets. The Company's estimate, based on the competitive bidding
process, of the above-market portion of its power supply contract obligations
is approximately $129 million. The net book value of its investment in other
generation assets, principally investments in Joint Owned generation
facilities, is approximately $11 million. Also, as a result of the
competitive bidding process, FG&E expects to receive approximately $5
million in proceeds from the disposition of its investment in a Joint Owned
generation facility. Deferred Tax Assets and Liabilities related to the
adjustments above, are reflected in the Company's Balance Sheet.
EARNINGS AND DIVIDENDS
Net income for 1998 was $8.0 million, slightly above 1997 earnings.
Lower interest expense, lower operating expenses, and a lower effective
income tax rate contributed positively to the Company's earnings performance.
Sales revenues in 1998 were comparable to 1997, as system growth was offset
by a mild winter heating season.
Basic earnings per average common share were $1.77 for the year ended
December 31, 1998, compared to $1.80 and $1.94 for 1997 and 1996,
respectively. The decrease in 1998 from 1997, on a per share basis, is
attributable to higher common shares outstanding in 1998 which were issued
through the Company's Dividend Reinvestment and Stock Purchase Plans (see
Capital Requirements and Liquidity and Note 2). Diluted earnings per share
were $1.72, $1.76 and $1.89 for 1998, 1997 and 1996, respectively. The
average return on common equity was 10.9%, 11.4%, and 12.8% in 1998, 1997,
and 1996, respectively.
Unitil's common stock dividends in 1998 were $1.36 per share, an
increase of 1.5% over 1997's annual dividend of $1.34 per share. This annual
dividend of $1.36 in 1998 resulted in a payout ratio of 77%. At its January
1999 meeting, the Unitil Board of Directors increased the quarterly dividend
rate by an additional 1.5%, resulting in the current effective annualized
dividend of $1.38 per share.
OPERATING REVENUES-ELECTRIC
Unit (KWH) Sales - Unitil's total electric kilowatt-hour sales
increased by 3.3% in 1998 compared to 1997, primarily due to system growth
and increased activity of a major industrial customer, offset by the milder
winter weather in early 1998. The 1998 winter heating season was 16% warmer
than normal and 7% warmer than the same period in 1997.
Sales to residential customers increased by 1.4% in 1998 compared to
1997, and were 2.7% higher than 1996 sales. These energy sales increases are
due to the expansion of our residential customer base within our service
territories and overall healthy regional economic conditions.
Commercial and industrial sales of electricity in 1998 were boosted
by the resumption of operations of a major industrial customer which had been
curtailed through the first quarter of 1998. Electric energy sales to all
commercial and industrial customers were up 4.4% in 1998, due to a strong
economy and the fact that the major customer mentioned above had curtailed
operations for all of 1997. 1998 sales are lower by 0.6% compared to 1996,
as the major customer mentioned above was in full operation for most of 1996.
The following table details total kilowatt-hour sales for the last
three years by major customer class:
KWH Sales (000's)
1998 1997 1996
Residential 541,492 533,907 527,107
Commercial 415,482 400,760 396,475
Industrial 583,994 556,436 608,433
Total KWH Sales 1,540,968 1,491,103 1,532,015
Electric utility rates before and after industry restructuring in
Massachusetts show the significant change in the way the Company's combined
electric and gas utility, FG&E, provides electric utility service to its
customers. Prior to March 1, 1998, FG&E provided all of its customers with
"bundled" electric service that reflected its obligation to provide energy
supply and the delivery of that energy to and across its system.
After March 1, 1998, FG&E "unbundled" its prices for energy supply,
transmission and distribution (or delivery services), and for the first time
allowed customers to choose an alternative energy supplier from the
competitive market. FG&E will continue to provide for the delivery of all
energy supply across its system. Customers' monthly bills, after March 1,
reflect these unbundled prices and individually display energy supply,
Transition Charges, delivery, and other related services.
As part of the transition to the new market structure, FG&E will
offer Standard Offer Service ("SOS") to its customers who elect not to choose
a competitive energy supplier, for up to 7 years. FG&E has contracted with
an energy supplier to provide SOS to its customers at no profit to FG&E. One
of the purposes of this service is to give customers a power supply price
from which they can measure competitive offers before they are ready to
enter the competitive market.
Two other important features of FG&E's unbundled rates are: 1) the
Transition Charge component of the bill, which is designed to recover FG&E's
transition costs resulting from restructuring over approximately 12 years,
and 2) the provision of a total rate discount of 10%. FG&E will provide an
additional 5% discount upon the earlier of completion of its divestiture of
generation investments or September 1, 1999.
Electric Operating Revenue decreased by $0.3 million, or 0.2%, in
1998 compared to 1997. The impact of higher sales volume across all customer
classes was offset by lower electric rates, due to the 10% discount mandated
in Massachusetts, and overall lower energy supply prices. Energy supply costs
are normally collected from customers through periodic cost recovery
adjustment mechanisms. Changes in energy supply prices do not affect net
income, as they normally mirror corresponding changes in energy supply costs.
Electric Operating Revenue (000's)
1998 1997 1996
Residential $57,242 $57,947 $57,124
Commercial 44,122 44,170 44,076
Industrial 48,275 47,856 48,496
Total Operating Revenue $149,639 $149,973 $149,696
OPERATING REVENUES-GAS
Unit (Therm) Sales - Total firm therm gas sales decreased 7.1% in
1998 when compared to 1997. The decrease in sales is primarily attributable
to the mild winter heating season, which was the warmest in the 103 years
such data has been kept. Sales to residential and commercial customers,
which are most sensitive to weather, decreased by 10.6% and 7.0%,
respectively, while sales to industrial customers were up by 3.9%. Total
firm therm sales decreased 10.1% in the two-year period from 1996 to 1998,
as the winter heating season in 1996 was significantly colder than in 1998.
The following table details total firm therm gas sales for the
last three years by major customer class:
Firm Therm Gas Sales (000's)
1998 1997 1996
Residential 11,656 13,038 13,835
Commercial 6,162 6,628 6,728
Industrial 4,209 4,050 3,945
Total Therm Sales 22,027 23,716 24,508
Gas Operating Revenues, which represent approximately 10% of Unitil's
total operating revenues, decreased by $2.7 million, or 13.8%, in 1998
compared to 1997. This decrease is primarily attributable to the decrease in
firm therm gas sales related to weather, as discussed above. In December
1998, FG&E concluded its gas base rate case, which resulted in a rate
increase of approximately 7.0%. Concurrent with the rate increase, FG&E
"unbundled" its gas bills, showing a separate itemization of all delivery
service charges, as well as supplier service charges. This will allow
customers to compare their current gas supply rates against offers they
receive from competitive suppliers, once competition begins in 1999 (see
Regulatory Matters).
Gas Operating Revenue (000's)
1998 1997 1996
Residential $8,581 $10,179 $10,654
Commercial 4,140 4,784 4,781
Industrial 4,288 4,766 5,670
Total Operating Revenue $17,009 $19,729 $21,105
OPERATING REVENUES-OTHER
Other Revenue declined from $36,000 in 1997 to $30,000 in 1998. The
decrease in Other Revenue from $45,000 in 1996 is the result of the
termination of an administrative services agreement between Unitil Resources,
Inc. and a principal customer.
OPERATING EXPENSES
Fuel and Purchased Power expense is the cost of power supply,
including fuel used in electric generation and the price of wholesale energy
and capacity, that meets the Unitil's electric energy requirements. Fuel and
purchased power expenses (normally recoverable from customers through
periodic cost recovery adjustment mechanisms) decreased $1.4 million, or
1.4% in 1998 compared to 1997. The change reflects a decrease in wholesale
power prices offset by an increase in the Company's total energy
requirements in 1998. The combined power supply portfolio of the Unitil is
comprised of a variety of resources. For 1998, the portfolio was comprised
of: 14% owned generation; 75% purchased power from utilities; and 11%
purchased power from non-utility generators.
The Company anticipates that power supply-related costs and
corresponding revenues will decline in future years, as customers choose
alternate competitive energy suppliers under a restructured electric utility
industry.
Gas Purchased for Resale reflects gas purchased and manufactured to
supply the Company's total gas energy requirements. Gas supply costs are
recoverable from customers through the Cost of Gas Adjustment mechanism.
Purchased Gas costs decreased by approximately $2.2 million or 18.0% in 1998
as compared to 1997, reflecting a decrease in therms purchased in 1998 and
lower wholesale gas prices in 1998. Gas purchased for resale decreased by
$3.4 million, or 25.9% in the two-year period from 1996 to 1998, based on
lower wholesale prices and a decrease in therms purchased due to warmer
weather.
Under Order 636, the Federal Energy Regulatory Commission
(FERC) has allowed gas pipeline suppliers to recover prudently incurred costs
resulting from the transition into a deregulated environment. FG&E has been
incurring FERC-approved transition charges from its natural gas pipeline
supplier since 1992. Through the end of 1998, the amount of transition costs
incurred by the Company totaled approximately $3.4 million. These costs are
being recovered directly from gas customers through the Cost of Gas
Adjustment mechanism. The Company does not expect to incur any additional
transition costs in 1999.
Operation and Maintenance expense, which includes utility operating
costs, Conservation and Load Management program expenditures and the
Company's share of operating costs related to power production at the
generation facilities in which the Company has a partial ownership interest,
increased by approximately $0.1 million, or 0.4% in 1998 compared to 1997.
The increase in Operation and Maintenance expenses compared to last year
reflects higher administrative costs associated with filing and
implementation of FG&E's restructuring plan and energy supply divestiture
efforts. These additional expenses related to industry restructuring in
Massachusetts are partially offset by revenues accrued to be recovered, in
the future, upon divestiture of the energy supply portfolio, or through other
rate cost reconciliation mechanisms.
In 1997, Operation and Maintenance expense decreased from 1996 by
approximately $0.6 million, or 2.3%, due to lower distribution operating
expenses partially offset by the higher costs of power production.
DEPRECIATION, AMORTIZATION AND TAXES
Depreciation and Amortization expense increased $0.8 million, or
9.0%, for 1998 over the prior year due to the accelerated write-off of
electric generating assets, in accordance with FG&E's restructuring plan.
Federal and State Income Taxes decreased in 1998 compared to 1997 by
$0.5 million. This result reflects lower net income before taxes, as well as
higher amortization of flow-through Investment Tax Credits in 1998.
Local Property and Other Taxes increased $0.3 million, or 5.0%, in
1998. This increase mainly reflects higher payroll taxes slightly offset by
lower local property taxes. Local property and other taxes increased in 1997,
compared to 1996, by 5.9%.
NON-OPERATING INCOME/EXPENSES
Non-Operating Expenses/Income in 1998 were relatively unchanged from
1997, as there was a continuation of community service programs throughout
the Unitil,s service territory. In 1996, Non-Operating Income of $0.6 million
reflects the one-time gain on the sale of the Company's former corporate
headquarters.
INTEREST EXPENSE
Interest Expense, Net decreased $0.3 million or 3.7% in 1998 from
1997, primarily reflecting an increase in accrued interest income associated
with deferred rate recovery mechanisms and interest on refunds received from
suppliers. Interest expense remained flat, as increased borrowing levels were
offset by lower interest rates. The increase in interest expense for 1997
over 1996 was a result of higher interest rates and the construction
financing of the Company's new corporate headquarters.
CAPITAL REQUIREMENTS AND LIQUIDITY
Unitil requires capital for the acquisition of property, plant and
equipment in order to improve, protect, maintain and expand its electric and
gas distribution systems, and to improve customer service operations and
capabilities. The capital necessary to meet these requirements is derived
primarily from the Company's retained earnings and through the sale of
shares of common stock through the Company's Dividend Reinvestment and Stock
Purchase Plans. When internally-generated funds are not available, it is the
Company's policy to borrow funds on a short-term basis to meet the capital
requirements of its subsidiaries and, when necessary, to repay short-term
debt through the issuance of permanent financing.
Cash Flows from Operating Activities decreased by $3.3 million in
1998, after increasing by $10.3 million in 1997.
The decrease in 1998 compared to 1997 was primarily due to higher
working capital needs at the year-end Balance Sheet date, as a result of
timing differences of payments on energy supply contracts, as well as
increased refunds of customer deposits.
In 1997 compared to 1996, $8.3 million of the increase in operating
cash flow was the result of a decrease in the timing difference
(undercollection) between the payment on fuel, purchased power and purchased
gas costs, and the corresponding recovery of these costs in revenue billed
under periodic cost recovery mechanisms. The balance of the increase
reflects other changes in the Company's working capital requirements as
detailed in the Consolidated Statements of Cash Flows.
Operating Activities (000's) 1998 1997 1996
Cash Provided by
Operating Activities $13,215 $16,555 $6,260
Cash Flows Used in Investing Activities increased approximately
$0.6 million in 1998 reflecting higher planned spending for utility customer
and distribution system additions and improvements. The decrease of $4.6
million in 1997 compared to 1996, reflected spending, in 1996, for the
construction of the Company's new corporate headquarters. The Company also
received cash payments of $0.9 million from the State of New Hampshire in
1996, related to the eminent domain taking of is former corporate
headquarters for a highway expansion project.
Investing Activities (000's) 1998 1997 1996
Cash Used in Investing Activities $(14,463) $(13,887 $(18,484)
Cash Flows from Financing Activities increased by $6.2 million in
1998 compared to 1997. This increase reflects higher net borrowings of $6.1
million and increased common stock issued of $0.3 million, net of other
items.
On September 3, 1998, Concord Electric Company (CECo) sold
$10,000,000 of 30-year Series J First Mortgage Bonds at par to an
institutional investor, bearing an interest rate of 6.96%. Proceeds were
used to repay short-term indebtedness, incurred to fund CECo's ongoing
construction program, and to redeem a higher coupon long-term debt issue
prior to its maturity. The redemption of $4,550,000 was on the 9.43% Series
H First Mortgage Bonds.
On September 3, 1998, Exeter & Hampton Electric Company (E&H) sold
$10,000,000 of 30-year Series L First Mortgage Bonds at par to an
institutional investor, bearing an interest rate of 6.96%. Proceeds were
used to repay short-term indebtedness, incurred to fund E&H's ongoing
construction program, and to redeem two higher coupon long-term debt issues
prior to their maturity. The redemptions, which totaled $4,200,000, included
$700,000 of 8.5% Series H First Mortgage Bonds, and $3,500,000 of 9.43%
Series J First Mortgage Bonds.
Additional short-term borrowings were incurred, primarily to fund
1998 costs related to electric industry restructuring in Massachusetts that
will be collected in future periods.
During 1998, the Company raised $1.0 million of additional common
equity capital through the issuance of 43,862 shares of common stock in
connection with the Dividend Reinvestment and Stock Purchase plans. The
Company raised $1.0 million of additional common equity capital in 1997
and $1.1 million of additional equity capital in 1996, through the issuance
of 51,529 and 52,081 shares, respectively of common stock in connection with
these plans. The Company also raised $566,000, $242,000, and $20,000 of
additional common equity capital in 1998, 1997, and 1996, respectively,
through the issuance of shares, as a result of the exercise of options
granted under the Company's Key Employee Stock Option Plan (KESOP). The
total number of shares issued under the KESOP plan in 1998, 1997 and 1996
were 66,951 shares, 28,222 shares and 2,400 shares, respectively.
The change from 1996 to 1997 reflects a decrease in borrowings,
due to the repayment of short-term debt. Higher short-term borrowings in
1996 were primarily due to funding of the timing difference
(undercollection) between payments on fuel, purchased power and purchased
gas costs and the corresponding recovery of these costs in revenue billed
under periodic cost recovery mechanisms, as well as the construction
financing of the Company's new corporate headquarters.
Financing Activities (000's) 1998 1997 1996
Cash From Financing Activities $2,994 $(3,234) $11,729
Subsequent Event - FG&E Financing
On January 26, 1999, FG&E sold $12,000,000 of long-term notes at par
to institutional investors, bearing an interest rate of 7.37%. Proceeds were
used to repay short-term indebtedness, incurred to fund FG&E's ongoing
construction programs.
REGULATORY MATTERS
Restructuring and Competition -Regulatory activity surrounding
restructuring and competition continues in both Massachusetts and New
Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition
for all electric consumers in Massachusetts, while New Hampshire's "Choice
Date" slipped past both the proposed date of January 1, 1998, and the
legislature's mandated July 1, 1998. Currently, approximately 10% of New
Hampshire electric consumers can choose their electric supplier. The ability
to choose for the remaining 90% is currently the subject of a federal court
preliminary injunction (see below).
Massachusetts gas industry restructuring plans continue to be under
development. The MDTE, gas utilities and other stakeholders began a
collaborative effort in late 1997 to develop solutions to the many issues
that surround restructuring the local natural gas distribution business.
Unitil has been preparing for electric and gas industry restructuring
by developing transition plans that will move its utility subsidiaries into
this new market structure in a way that will ensure fairness in the treatment
of the Company's assets and obligations that are dedicated to the current
regulated franchises and, at the same time, provide choice for all customers.
Massachusetts (Electric)- On January 15, 1999, the MDTE gave final
approval to FG&E's restructuring plan with certain modifications. The Plan
provides customers with: a) a choice of energy supplier; b) an option to
purchase Standard Offer Service (i.e. state-mandated energy service) provided
by FG&E at regulated rates for up to seven years; and c) a cumulative 15%
rate reduction. The Plan also provides for FG&E to divest generation assets
and its portfolio of purchased power contracts. The Company will be afforded
full recovery of any transition costs through a non-bypassable retail
Transition Charge.
Pursuant to the Plan, on October 30, 1998, the Company filed with
the MDTE a proposed contract with Constellation Power Services Inc. for
provision of Standard Offer Service. The MDTE's January 15, 1999 Order
approves the FG&E/Constellation contract, and service thereunder is scheduled
to commence on March 1, 1999, and is scheduled to continue through February
28, 2005. This contract is the result of the first successful Standard
Offer auction conducted in Massachusetts.
The January 15 Order also approved the Company's power supply
divestiture plan for its interest in three generating units and four
long-term power supply contracts. A contract for the sale of FG&E's
interest in the New Haven Harbor plant was filed with the MDTE on November
20, 1998. The MDTE's decision is pending. Contracts for the sale of the
Company's remaining generating assets and purchased power contracts are
expected to be filed with the MDTE in the near future. All such contracts
are subject to MDTE approval.
Massachusetts (Gas) -In mid-1997, the MDTE directed all Massachusetts
natural gas Local Distribution Companies (LDCs) to form a collaborative with
other stakeholders to develop common principles and appropriate regulations
for the unbundling of gas service, and directed FG&E and four other LDCs to
file unbundled gas rates for its review. FG&E's unbundled gas rates were
approved by the MDTE and implemented in November of 1998.
On July 2, 1998 the MDTE established April 1, 1999 as the date by
which unbundled gas service would begin to be implemented by all LDCs. On
February 1, 1999, the MDTE issued an order in which it determined that the
LDCs would continue to have an obligation to provide gas supply and delivery
services for another five years, with a review after three years. That order
also set forth the MDTE's decision regarding release by LDCs of their
pipeline capacity contracts to competitive marketers. In January of 1999,
the LDCs reported to the MDTE that they were continuing to work to develop
systems and practices to implement unbundling. The MDTE has not yet responded
to the LDCs' report, and it appears unlikely that full implementation will
be achieved by the April 1, 1999 target date.
New Hampshire - On February 28, 1997, the New Hampshire Public
Utilities Commission (NHPUC) issued its Final Plan for transition to a
competitive electric market in New Hampshire. The order allowed CECo and E&H,
Unitil's New Hampshire retail distribution utilities, to recover 100% of
"stranded" costs for a two-year period, but excluded recovery of certain
administrative-related charges.
Northeast Utilities' affiliate, Public Service Company of New
Hampshire, appealed the NHPUC order in Federal District Court. A temporary
restraining order was issued on March 10, 1997. In June 1997, Unitil was
admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June
9, 1998, the Federal Court issued an injunction continuing the freeze on
NHPUC efforts to implement restructuring. Several parties have filed
interlocutory appeals, and no date has been scheduled for a trial in the
federal court. The Company will vigorously pursue its action in the federal
court and simultaneously look for ways to resolve issues and bring forth
choice to its retail customers.
In September of 1998, the Company reached a comprehensive
restructuring settlement with key parties and filed this voluntary Agreement
with the NHPUC. The Agreement was modified on October 20, 1998. In oral
deliberations on November 2 and November 18, 1998, the NHPUC imposed
conditions to approval of the Settlement which were unacceptable to the
Company, and the Settlement was subsequently withdrawn. The component of the
Agreement dealing with wholesale rates was filed with the FERC in September
1998, and approved by the FERC in early November. However, implementation
will not occur, as the changes were conditioned upon approval by the NHPUC.
Unitil continues to participate actively in all proceedings and in several
NHPUC-established working groups which will define details of the transition
to competition and customer choice.
Rate Cases -The last formal regulatory hearings to increase base
electric rates for Unitil's three retail operating subsidiaries occurred in
1985 for Concord Electric Company, 1984 for Fitchburg Gas and Electric Light
Company and 1981 for Exeter & Hampton Electric Company.
On May 15, 1998, FG&E filed a gas base rate case with the MDTE.
After evidentiary hearings, the MDTE issued an Order allowing FG&E to
establish new rates, effective November 30, 1998, that would produce an
annual increase of approximately $1.0 million in gas revenues. However, as
part of the proceeding, the Attorney General of the Commonwealth of
Massachusetts alleged that FG&E had double-collected fuel inventory finance
charges, since 1987, and requested that the MDTE require FG&E to refund
approximately $1.6 million to its customers. The Company believes that the
Attorney General's claim is without merit and that a refund is not justified
or warranted. The MDTE stated its intent to open a separate proceeding to
investigate the Attorney General's claim.
A majority of the Company's operating revenues are collected under
various periodic rate adjustment mechanisms including fuel, purchased power,
cost of gas and energy efficiency program cost recovery mechanisms.
Restructuring will continue to change the methods of how certain costs are
recovered from customers and from suppliers. Transition costs, Standard
Offer Service and Default Service power supply costs, internal and external
transmission service costs and energy efficiency and renewable energy
program costs for FG&E are being recovered via fully reconciling rate
adjustment mechanisms in Massachusetts.
Millstone Unit No. - FG&E has a 0.217% nonoperating ownership in the
Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it
with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear
Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which
calls for increased NRC inspection attention. On March 30, 1996, as a result
of an engineering evaluation completed by the operator, Northeast Utilities,
Millstone 3 was taken out of service. NRC authorization for restart was given
on June 29, 1998. Millstone 3 began producing electric power in early July,
1998 and reached full output on July 15, 1998. The unit remains on the NRC's
Watch List.
During the period that Millstone 3 was out of service, FG&E
continued to incur its proportionate share of the unit's ongoing Operations
and Maintenance (O&M) costs, and may incur additional O&M costs and capital
expenditures to meet NRC requirements. FG&E also incurred costs to replace
the power that was expected to be generated by the unit. During the outage,
FG&E had been incurring approximately $35,000 per month in replacement power
costs, and had been recovering those costs through its fuel adjustment clause,
which will be subject to review and approval by the MDTE.
In August 1997, FG&E, in concert with other non-operating joint
owners, filed a demand for arbitration in Connecticut and a lawsuit in
Massachusetts, in an effort to recover costs associated with the extended
unplanned shutdown. The arbitration and legal cases are proceeding.
Environmental Matters - In September 1998, the FG&E signed a
memorandum of understanding with the Massachusetts Highway Department and
the Massachusetts Department of Environmental Protection that accommodates
the construction of a new highway bridge across Sawyer Passway, the Company's
former manufactured gas plant (MGP) site. This memorandum satisfies the
requirements of the Massachusetts Contingency Plan for temporary closure at
this last remaining portion of the site. Specifically, this agreement allows
for current FG&E efforts to perform remediation work required as result of
bridge construction. Upon completion of site remediation associated with the
bridge construction, this last remaining portion of the Sawyer Passway MGP
site is expected to be closed out and attain the status of temporary closure
in late 1999. This temporary closure allows FG&E to monitor the site every
five years to determine if a more feasible remediation alternative can be
developed and achieved.
The costs of remedial action at this site are initially funded from
traditional sources of capital and recovered from customers under a rate
recovery mechanism approved by the MDTE. The Company also has a number of
liability insurance policies that may provide coverage for environmental
remediation at this site.
Market Risk - Although Unitil's utility operating companies are
subject to commodity price risk as part of their traditional operations, the
current regulatory framework within which these companies operate allows for
full collection of fuel and gas costs in rates. Consequently, there is
limited commodity price risk after consideration of the related rate-making.
As the utility industry deregulates, the Company will be divesting its
commodity-related energy businesses and therefore will be further reducing
its exposure to commodity-related risk.
YEAR 2000 SOFTWARE COMPLIANCE DISCUSSION
The Company recognizes the need to ensure its operations are not
adversely affected by software or device failures related to the Year 2000
date recognition problem, (the "Y2K Issues"). Specifically, Y2K Issues would
arise when software applications, or devices with embedded chips, fail to
correctly recognize and process the year 2000 and beyond. Certain software
applications and devices are certified to recognize and process date
references to the year 2000 and beyond and they are deemed to be Year 2000
compliant, ("Year 2000 Compliance"). Potential software failures could
create incorrect calculations, among other errors, and they present a risk
to the integrity of our Company's financial systems and the reliability of
our operating systems. In order to minimize the risk of disruption to our
business operations, the Company is taking the actions described below,
including communicating with suppliers, dealers, financial institutions and
others with which it does business, to coordinate the identification,
evaluation, remediation and testing of possible Y2K Issues which may affect
the Company
The Company has established a centralized task force to identify and
implement necessary changes to the Company's internal computer systems,
controlling hardware devices and software applications in order to achieve
Year 2000 Compliance for those systems. The remediation of Y2K Issues and
testing of all critical components of the Company's internal systems is
scheduled to be completed by June 30, 1999.
The Company has also established processes for evaluating and
managing the risks and possible costs associated with Y2K Issues which may
exist in systems external to the Company's operations, but could affect the
Company's operations indirectly. The Company has already directed efforts to
notify our critical vendors and suppliers about Y2K Issues which may affect
our operations, and most are already providing important information about
the Year 2000 readiness of their organizations. Testing of certain critical
systems has already begun, in conjunction with our key suppliers and vendors,
and the Company is planning to develop contingency plans in circumstances
where assurance of Year 2000 Compliance cannot be obtained.
The Company currently estimates it will invest in the range of
$250,000 to $500,000 plus internal costs, over the cost of normal software
upgrades and replacements to achieve Year 2000 Compliance. These additional
capital outlays include costs to replace certain devices and software, and
the costs for consultants to assist us with software programming and testing.
Unitil relies on the proper operation of a regional network of
systems and devices to transport and distribute electricity and gas to its
customers. Any disruption in those systems caused by Y2K Issues could
interrupt the reliable delivery of electric and gas service through our
Distribution Operating Companies. Some of these software systems and devices
belong to other companies and are beyond the control of Unitil to ensure that
they are properly remediated for Year 2000. However, several agencies,
including the Department of Energy, The New England ISO, and The National
Electricity Reliability Council, have active Year 2000 programs in place.
These programs will ensure that member companies are actively and
comprehensively dealing with any Year 2000 Issues in their supply,
generation, transportation and distribution facilities and systems. Unitil
participates in these groups and currently believes that satisfactory
progress is being made and will continue to be made to ensure a reliable
supply and delivery of energy. Furthermore, these groups plan to establish
contingency plans to cover delivery difficulties during key Year 2000 dates.
The Company also plans to work with local, state and regional agencies and
other utility companies to ensure that appropriate contingency plans are in
place for energy supply and delivery systems which could be affected by Year
2000 difficulties.
In addition, while the Company currently anticipates that its own
mission-critical systems will be Year 2000 Compliant in a timely fashion, it
cannot guarantee the compliance of other systems operated by other companies
upon which it depends. For example, the Company's ability to provide
electricity to its customers depends upon the regional electric transmission
grid which connects the systems of neighboring utilities to provide electric
power for the region. If one company's system is not Year 2000 Compliant,
then a failure could impact all providers within the grid, including Unitil.
Similarly, the Company's gas operations depend upon natural gas pipelines
that it does not own or control, and any Year 2000 noncompliance associated
with these pipelines may affect the Company's ability to provide natural gas
to its customers. Failure to achieve Year 2000 readiness could have a
material effect on the Company's results of operations, financial position
and cash flows.
NEW ACCOUNTING STANDARDS
During 1998, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and
Related Information." This Statement supersedes all previous accounting
pronouncements regarding the reporting of segment information and requires
companies to report financial and descriptive information about reportable
operating segments in annual and interim financial statements.
Also in 1998, the Company adopted SFAS No. 132, "Employer's
Disclosures about Pensions and Other Postretirement Benefits" (an amendment
of FASB Statements No. 87, 88, and 106). This Statement standardizes the
disclosure requirements for pensions and other postretirement benefits,
requires additional information on changes in the benefit obligations and
fair values of plan assets, and eliminates certain disclosures that are no
longer useful.
During 1997, the Company adopted SFAS No. 128, "Earnings per Share."
This Statement supersedes all previous accounting pronouncements regarding
the reporting of Earnings per Share data and requires the presentation of
basic and diluted Earnings per Share information by all publicly traded
entities. The adoption of this reporting standard by the Company is
effective with the reporting years presented in the financial statements.
FORWARD-LOOKING INFORMATION
This report contains forward-looking statements which are subject to
the inherent uncertainties in predicting future results and conditions.
Certain factors that could cause the actual results to differ materially
from those projected in these forward-looking statements include, but are
not limited to; variations in weather, changes in the regulatory environment,
customers' preferences on energy sources, general economic conditions,
increased competition and other uncertainties, all of which are difficult to
predict, and many of which are beyond the control of the Company.
Item 8. Financial Statements and Supplemental Data
Report of Independent Certified Public Accountants
To the Shareholders of Unitil Corporation:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Unitil Corporation and
subsidiaries as of December 31, 1998 and 1997, and the related consolidated
statements of earnings, cash flows and changes in common stock equity for
each of the three years in the period ended December 31, 1998. These
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Unitil Corporation and subsidiaries as of December 31, 1998 and 1997, and
the consolidated results of their operations and their consolidated cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
We have also audited Schedule VIII of Unitil Corporation and
subsidiaries as of December 31, 1998 and for the three years then ended
included in Part IV Item 14(a)(2). In our opinion, the schedule presents
fairly, in all material respects, the information required to be set forth
therein.
GRANT THORNTON LLP
CONSOLIDATED STATEMENTS OF EARNINGS
(000's, except common shares and per share data)
Year Ended December 31, 1998 1997 1996
Operating Revenues:
Electric $149,639 $149,973 $149,696
Gas 17,009 19,729 21,105
Other 30 36 45
Total Operating Revenues 166,678 169,738 170,846
Operating Expenses:
Fuel and Purchased Power 98,589 99,974 100,768
Gas Purchased for Resale 9,874 12,032 13,323
Operation and Maintenance 23,652 23,550 24,110
Depreciation and Amortization 10,007 9,178 8,776
Provisions for Taxes:
Local Property and Other 5,540 5,276 4,983
Federal and State Income 3,710 4,166 4,613
Total Operating Expenses 151,372 154,176 156,573
Operating Income 15,306 15,562 14,273
Non-Operating Expenses (Income) 156 160 (627)
Income Before Interest Expense 15,150 15,402 14,900
Interest Expense, Net 6,901 7,167 6,171
Net Income 8,249 8,235 8,729
Less Dividends on Preferred Stock 274 276 278
Net Income Applicable to Common Stock $7,975 $7,959 $8,451
Average Common Shares Outstanding 4,505,784 4,412,869 4,354,297
Basic Earnings Per Share $1.77 $1.80 $1.94
Diluted Earnings Per Share $1.72 $1.76 $1.89
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED BALANCE SHEETS (000's)
ASSETS
December 31, 1998 1997
Utility Plant:
Electric $152,940 $166,636
Gas 32,622 30,473
Common 20,876 19,689
Construction Work in Progress 3,024 2,677
Utility Plant 209,462 219,475
Less: Accumulated Depreciation 63,428 68,360
Net Utility Plant 146,034 151,115
Current Assets:
Cash 4,083 2,337
Accounts Receivable - Less Allowance for
Doubtful Accounts of $646 and $653 15,999 16,890
Taxes Refundable 1,056 554
Materials and Supplies 2,962 2,663
Prepayments 1,147 434
Accrued Revenue 5,322 6,796
Total Current Assets 30,569 29,674
Deferred Tax Assets
Noncurrent Assets:
Regulatory Assets 163,034 23,885
Prepaid Pension Costs 8,591 8,120
Debt Issuance Costs 1,320 918
Other Noncurrent Assets 27,287 24,819
Total Noncurrent Assets 200,232 57,742
TOTAL $376,835 $238,531
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED BALANCE SHEETS (Cont.) (000's)
CAPITALIZATION AND LIABILITIES
December 31, 1998 1997
Capitalization:
Common Stock Equity $75,351 $71,644
Preferred Stock, Non-Redeemable, Non-Cumulative 225 225
Preferred Stock, Redeemable, Cumulative 3,618 3,666
Long-Term Debt, Less Current Portion 74,047 63,896
Total Capitalization 153,241 139,431
Current Liabilities:
Long-Term Debt, Current Portion 1,175 4,470
Capitalized Leases, Current Portion 907 883
Accounts Payable 11,382 14,734
Short-Term Debt 20,000 18,000
Dividends Declared and Payable 232 212
Refundable Customer Deposits 1,293 2,187
Interest Payable 841 1,087
Other Current Liabilities 2,776 2,635
Total Current Liabilities 38,606 44,208
Deferred Income Taxes 43,027 42,295
Noncurrent Liabilities:
Power Supply Contract Obligations 129,688 --
Capitalized Leases, Less Current Portion 4,287 4,733
Other Noncurrent Liabilities 7,986 7,864
Total Noncurrent Liabilities 141,961 12,597
TOTAL $376,835 $238,531
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(000's except number of shares)
December 31, 1998 1997
Common Stock Equity
Common Stock, No Par Value
(Authorized - 8,000,000 shares; $38,407 $35,653
Outstanding - 4,574,629 and 4,463,816 Shares)
Stock Options 543 1,452
Retained Earnings 36,401 34,539
Total Common Stock Equity 75,351 71,644
Preferred Stock
CECo Preferred Stock,
Non-Redeemable, Non-Cumulative: 225 225
6% Series, $100 Par Value
CECo Preferred Stock, Redeemable, Cumulative: 215 215
8.70% Series, $100 Par Value
E&H Preferred Stock, Redeemable, Cumulative:
5% Series, $100 Par Value 91 91
6% Series, $100 Par Value 168 168
8.75% Series, $100 Par Value 333 344
8.25% Series, $100 Par Value 406 406
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value 998 1,035
8% Series, $100 Par Value 1,407 1,407
Total Preferred Stock 3,843 3,891
Long-Term Debt
CECo First Mortgage Bonds:
Series C, 6.75%, Due January 15, 1998 --- 1,520
Series H, 9.43%, Due September 1, 2003 --- 5,200
Series I, 8.49%, Due October 14, 2024 6,000 6,000
Series J, 6.96%, Due September 1, 2028 10,000
E&H First Mortgage Bonds:
Series E, 6.75%, Due January 15, 1998 --- 498
Series H, 8.50%, Due December 15, 2002 --- 700
Series J, 9.43%, Due September 1, 2003 --- 4,000
Series K, 8.49%, Due October 14, 2024 9,000 9,000
Series L, 6.96%, Due September 1, 2028 10,000
FG&E Long-term Notes:
Twelve year Notes, 8.55%, Due March 31, 2004 14,000 15,000
Thirty year Notes, 6.75%,
Due November 30, 2023 19,000 19,000
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes Due August 1, 2017 7,222 7,448
Total Long-Term Debt 75,222 68,366
Less: Long-Term Debt, Current Portion 1,175 4,470
Total Long-Term Debt,
Less Current Portion 74,047 63,896
Total Capitalization $153,241 $139,431
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CASH FLOWS (000's)
Year Ended December 31, 1998 1997 1996
Operating Activities:
Net Income $8,249 $8,235 $8,729
Adjustments to Reconcile Net Income to
Cash Provided by Operating Activities:
Depreciation and Amortization 10,068 9,238 8,832
Deferred Tax Provision 1,515 660 458
Amortization of Investment Tax Credit (402) (172) (194)
Gain on Taking of Land and Building ---- ---- (875)
Changes in Working Capital:
Accounts Receivable 891 (506) (1,451)
Materials and Supplies (299) (184) (203)
Prepayments (713) (725) (705)
Accrued Revenue 1,474 2,063 (6,281)
Accounts Payable (3,352) (370) 539
Refundable Customer Deposits (894) 602 (1,629)
Taxes and Interest Payable (748) (804) (306)
Other, Net (2,574) (1,482) (654)
Cash Provided by Operation Activities 13,215 16,555 6,260
Cash Flows Used In Investing Activities:
Acquisition of Property, Plant & Equipment (14,463) (13,887) (19,359)
Proceeds from Taking of Land & Building ---- ---- 875
Cash Used in Investing Activities (14,463) (13,887) (18,484)
Cash Flows From Financing Activities:
Proceeds From (Repayment of)
Short-Term Debt, net 2,000 (3,400) 18,700
Proceeds From Issuance of Long-Term Debt 20,000 7,500 ----
Repayment of Long-Term Debt (13,144) (1,345) (1,294)
Dividends Paid (6,368) (6,159) (5,998)
Issuance of Common Stock 1,600 1,285 1,132
Retirement of Preferred Stock (48) ---- (108)
Repayment of Capital Lease Obligations (1,046) (1,115) (703)
Cash Provided by (Used In)
Financing Activities 2,994 (3,234) 11,729
Net Increase (Decrease) in Cash 1,746 (566) (495)
Cash at Beginning of Year 2,337 2,903 3,398
Cash at End of Year $4,083 $2,337 $2,903
Supplemental Cash Flow Information:
Interest Paid $7,445 $7,531 $6,133
Federal Income Taxes Paid $2,490 $3,340 $3,982
Supplemental Schedule of Noncash Activities:
Capital Leases Incurred $624 $1,057 $1,858
The Company recorded the estimated impact of the Order from the
Massachusetts Department of Telecommunications and Energy related to its
Electric Utility Restructuring Plan on its December 31, 1998 balance sheet
as follows:
Net Decrease in Utility Plant-Electric $(11,302) --- ---
Increase in Regulatory Assets 140,871 --- ---
Decrease in Investment Tax Credits 119 --- ---
Increase in Power Supply Contract Obligations (129,688) --- ---
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY (000's)
Deferred
Stock
Common Option Retained
Shares Plan Earnings Total
Balance at January 1, 1996 $32,822 $1,299 $29,773 $63,894
Net Income for 1996 8,729 8,729
Dividends on preferred shares (278) (278)
Dividends on common shares -
at an annual rate of $1.32 per share (5,740) (5,740)
Stock Option Plan 237 237
Exercised stock options - 2,400 shares 50 (30) 20
Issuance of 52,081 common shares (a) 1,112 1,112
Balance at December 31, 1996 33,984 1,506 32,484 67,974
Net Income for 1997 8,235 8,235
Dividends on preferred shares (276) (276)
Dividends on common shares -
at an annual rate of $1.34 per share (5,904) (5,904)
Stock Option Plan 330 330
Exercised stock options - 28,222 shares 626 (384) 242
Issuance of 51,529 common shares (a) 1,043 1,043
Balance at December 31, 1997 35,653 1,452 34,539 71,644
Net Income for 1998 8,249 8,249
Dividends on preferred shares (274) (274)
Dividends on common shares -
at an annual rate of $1.36 per share (6,113) (6,113)
Stock Option Plan 245 245
Exercised stock options-66,951 shares 1,720 (1,154) 566
Issuance of 43,862 common shares (a) 1,034 1,034
Balance at December 31, 1998 $38,407 $543 $36,401 $75,351
(a) Shares sold and issued in connection with the Company's
Dividend Reinvestment and Stock Purchase Plan and Employee 401(k)
Tax Deferred Savings and Investment Plan (See Note 2).
(The accompanying Notes are an integral part of these statements.)
Note 1: Summary of Significant Accounting Policies
Nature of Operations -- Unitil Corporation (Unitil or the Company) is
registered with the Securities and Exchange Commission (SEC) as a public
utility holding company under the Public Utility Holding Company Act of 1935
(the 1935 Act), and is the parent of the Unitil System. The following
companies are wholly owned subsidiaries of Unitil: Concord Electric Company
(CECo), Exeter & Hampton Electric Company (E&H), Fitchburg Gas and Electric
Light Company (FG&E), Unitil Power Corp. (UPC), Unitil Realty Corp. (URC),
Unitil Service Corp. (USC), and Unitil Resources, Inc. (URI).
Unitil's principal business is the retail sale and distribution of
electricity in New Hampshire and both electric and gas services in
Massachusetts through its retail distribution subsidiaries CECo, E&H, and
FG&E. The Company's wholesale electric power subsidiary, UPC, principally
provides all the electric power supply requirements to CECo and E&H for
resale at retail, and also engages in various other wholesale electric power
services with affiliates and non-affiliates throughout the New England
region. URI is engaged in business transactions as a competitive marketer of
electricity. Finally, URC and USC provide centralized operations to support
the Unitil System.
With respect to rates and accounting practices, CECo and E&H are
subject to regulation by the New Hampshire Public Utilities Commission
(NHPUC), FG&E is regulated by the Massachusetts Department of
Telecommunications & Energy (MDTE), and UPC is regulated by the Federal
Energy Regulatory Commission (FERC).
The Company accounts for all its regulated operations in accordance
with Statement of Financial Accounting Standard ("SFAS") No. 71, "Accounting
for the Effects of Certain Types of Regulation," requiring the Company to
record the financial statement effects of the rate regulation to which the
Company is currently subject. If a separable portion of the Company's
business no longer meets SFAS No. 71, the Company is required to eliminate
the financial statement effects of regulation for that portion.
Basis of Presentation
Principles of Consolidation --- Unitil Corporation (the Company) is
the parent company of the Unitil System (the System). The consolidated
financial statements include the accounts of the Company and all of its
wholly-owned subsidiaries. All material intercompany balances and
transactions have been eliminated in consolidation.
Use of Estimates --- The preparation of financial statements in
conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amounts of assets
and liabilities, and requires 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.
Revenue Recognition --- The Company's operating subsidiaries record
electric and gas operating revenues based upon the amount of electricity and
gas delivered to customers through the end of the accounting period.
Depreciation and Amortization --- Depreciation provisions for the
Company's utility operating subsidiaries are determined on a group
straight-line basis. Provisions for depreciation were equivalent to the
following composite rates, based on the average depreciable property balances
at the beginning and end of each year: 1998 - 3.21 percent; 1997 - 3.45
percent; and 1996 - 3.45 percent.
Amortization provisions include the recovery of a portion of FG&E's
former investment in the Seabrook Nuclear Power Plant in rates to its
customers through a Seabrook Amortization Surcharge as ordered by the MDTE.
In addition, FG&E is amortizing electric generating assets, in accordance
with its electric restructuring plan approved by the MDTE (See Note 12).
Federal Income Taxes --- Deferred tax assets and liabilities are
determined based on differences between the financial reporting and tax bases
of assets and liabilities, and are measured by applying tax rates applicable
to the taxable years in which those differences are expected to reverse.
The Tax Reduction Act of 1986 eliminated investment tax credits. Investment
tax credits generated prior to 1986 are being amortized, for financial
reporting purposes, over the productive lives of the related assets.
New Accounting Standards --- During 1998, the Company adopted SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information.
" This Statement supersedes all previous accounting pronouncements regarding
the reporting of segment information and requires companies to report
financial and descriptive information about reportable operating segments in
annual and interim financial statements (See Note 11).
Also in 1998, the Company adopted SFAS No. 132, "Employer's
Disclosures about Pensions and Other Postretirement Benefits" (an amendment
of FASB Statements No. 87, 88, and 106). This Statement standardizes the
disclosure requirements for pensions and other postretirement benefits,
requires additional information on changes in the benefit obligations and
fair values of plan assets and eliminates certain disclosures that are no
longer useful (See Note 9).
During 1997, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 128, "Earnings per Share." This Statement supersedes
all previous accounting pronouncements regarding the reporting of earnings
per share data and requires the presentation of basic and diluted earnings
per share information by all publicly traded entities. The adoption of this
reporting standard by the Company is effective with the reporting years
presented in the financial statements (See Note 10).
Reclassifications --- Certain amounts previously reported have been
reclassified to conform with current year presentation.
Note 2: Common Stock
New Shares Issued --- During 1998, the Company raised $1,034,195 of
additional common equity capital through the issuance of 43,862 shares of
common stock in connection with the Dividend Reinvestment and Stock Purchase
Plan and the Employee 401(k) Tax Deferred Savings and Investment Plan. The
Dividend Reinvestment and Stock Purchase Plan provides participants in the
plan a method for investing cash dividends on the Company's Common Stock and
cash payments in additional shares of the Company's Common Stock. The
Employee 401(k) Tax Deferred Savings and Investment Plan is described in
Note 9 below. In 1997, the Company raised $1,042,974 of additional common
equity capital through the issuance of 51,529 shares of common stock in
connection with these plans.
The Company maintains a Key Employee Stock Option Plan (KESOP), which
provides for the granting of options to key employees. The number of shares
granted under this plan, as well as the terms and conditions of each grant,
are determined by the Board of Directors, subject to plan limitations. All
options granted under the KESOP vest upon grant. No option can be issued
under the current plan after 1999. The plan provides options and dividend
equivalents on options granted, which are recorded at fair value as
compensation expense. The total compensation expenses recorded by the
Company with respect to this plan were $244,903, $330,098 and $237,044 for
the years ended December 31, 1998, 1997 and 1996, respectively.
Share Option Activity of the KESOP is presented in the following table:
1998 1997 1996
Beginning Options Outstanding & Exercisable 191,365 182,495 173,362
Options Granted --- 25,000 1,000
Dividend Equivalents Earned 10,327 12,092 10,533
Options Exercised (66,951) (28,222) (2,400)
Options Canceled --- --- ---
Ending Options Outstanding & Exercisable 134,741 191,365 182,495
Range of Option Exercise
Price per Share $12.11-$18.28 $12.11-$18.28 $12.11-$18.28
The Company has adopted Statement of Financial Accounting
Standards (SFAS) No. 123, "Accounting for Stock Based Compensation," and
recognizes compensation costs at fair value.
The weighted average fair value per share of options granted during
1997 and 1996 was $3.21 and $3.23, respectively. No options were granted in
1998. The weighted average exercise price of options and dividend equivalents
exercised in 1998 was $8.38 per share. The fair value of options at the date
of grant was estimated using the Black-Scholes model with the following
weighted average assumptions:
1998 1997 1996
Expected Life (Years) None Granted 2 3
Interest Rate 6.0% 6.0%
Volatility 19.5% 19.4%
Dividend Yield 5.5% 6.6%
Restrictions on Retained Earnings ---Unitil Corporation has no
restriction on the payment of common dividends from retained earnings. Its
three retail distribution subsidiaries do have restrictions. Under the terms
of the First Mortgage Bond Indentures, CECo and E&H had $3,336,986 and
$3,366,816, respectively, available for the payment of cash dividends on
their common stock at December 31, 1998. Under the terms of long-term debt
Purchase Agreements, FG&E had $16,421,494 of retained earnings available for
the payment of cash dividends on its common stock at December 31, 1998.
Note 3: Preferred Stock
Certain of the Unitil subsidiaries have redeemable Cumulative
Preferred Stock outstanding and one subsidiary, CECo, has a Non-Redeemable,
Non-Cumulative Preferred Stock issue outstanding. All such subsidiaries are
required to offer to redeem annually a given number of shares of each series
of Redeemable Cumulative Preferred Stock and to purchase such shares that
shall have been tendered by holders of the respective stock. All such
subsidiaries may redeem, at their option, the Redeemable Cumulative
Preferred Stock at a given redemption price, plus accrued dividends.
The aggregate purchases of Redeemable Cumulative Preferred Stock
during 1998, 1997 and 1996 were: 1998 - $47,300; 1997 - $0; and
1996 - $108,000. The aggregate amount of sinking fund requirements of the
Redeemable Cumulative Preferred Stock for each of the five years following
1998 are $206,000 per year.
Note 4: Long-Term Debt
Certain of the Company's long-term debt agreements contain provisions
which, among other things, limit the incursion additional long-term debt.
Total aggregate amount of sinking fund payments relating to bond
issues and normal scheduled long-term debt repayments amounted to $4,394,000
and $1,294,000 in 1998 and 1997, respectively.
The aggregate amount of bond sinking fund requirements and normal
scheduled long-term debt repayments for each of the five years following 1998
are: 1999 - $1,176,307; 2000 - $1,190,940; 2001 - $3,206,788;
2002 - $3,223,951 and 2003 - $3,242,539.
On September 3, 1998, Concord Electric Company sold $10,000,000 of
30-year Series J First Mortgage Bonds at par to an institutional investor,
bearing an interest rate of 6.96%. Proceeds were used to repay short-term
indebtedness, incurred to fund CECo's ongoing construction program, and to
redeem a higher coupon long-term debt issue prior to its maturity. The
redemption of $4,550,000 was on the 9.43% Series H First Mortgage Bonds.
On September 3, 1998, Exeter & Hampton Electric Company sold
$10,000,000 of 30-year Series L First Mortgage Bonds at par to an
institutional investor, bearing an interest rate of 6.96%. Proceeds were
used to repay short-term indebtedness, incurred to fund E&H's ongoing
construction program, and to redeem two higher coupon long-term debt issues
prior to their maturity. The redemptions, which totaled $4,200,000,
included $700,000 of 8.5% Series H First Mortgage Bonds, and $3,500,000 of
9.43% Series J First Mortgage Bonds.
On January 26, 1999, FG&E sold $12,000,000 of Long-term Notes at par
to institutional investors, bearing an interest rate of 7.37%. Proceeds were
used to repay short-term indebtedness, incurred to fund FG&E's ongoing
construction program.
The fair value of the Company's long-term debt is estimated based on
the quoted market prices for the same or similar issues, or on the current
rates offered to the Company for debt of the same remaining maturities. In
management's opinion, the carrying value of the debt approximated its fair
value at December 31, 1998 and 1997.
Note 5: Credit Arrangements
At December 31, 1997, the Company had unsecured committed bank lines
for short-term debt aggregating $25,000,000 with four banks for which it pays
commitment fees. At December 31, 1998, the unused portion of the committed
credit lines outstanding was $5,000,000. The average interest rates on all
short-term borrowings were 5.95% and 5.98% during 1998 and 1997,
respectively.
Note 6: Leases
The Company's subsidiaries conduct a portion of their operations in
leased facilities and also lease some of their machinery and office
equipment. FG&E has a facility lease for twenty-two years which began in
February 1981. The lease allows five, five-year renewal periods at the
option of FG&E. The equipment leases, which expired in 1998, included a
twenty-five-year lease, which began on April 1, 1973, for a combustion
turbine and a liquefied natural gas storage and vaporization facility. In
addition, Unitil's subsidiaries lease some equipment under operating leases.
The following is a schedule of the leased property under
capital leases by major classes:
Asset Balances at
December 31,
Classes of Utility Plant (000's) 1998 1997
Electric --- $2,054
Gas --- 726
Common $6,899 6,420
Gross Plant 6,899 9,200
Less: Accumulated Depreciation 1,705 3,584
Net Plant $5,194 $5,616
The following is a schedule by years of future minimum lease
payments and present value of net minimum lease payments under
capital leases as of December 31, 1998:
Year Ending December 31, (000's)
1999 $1,920
2000 1,362
2001 1,214
2002 1,123
2003 810
2004 - 2008 1,532
Total Minimum Lease Payments $7,961
Less: Amount Representing Interest 2,767
Present Value of Net Minimum Lease Payments $5,194
Total rental expense charged to operations for the years ended
December 31, 1998, 1997 and 1996 amounted to $88,000, $110,000; and $161,000,
respectively. There are no material future operating lease payment
obligations at December 31, 1998.
Note 7: Income Taxes
Federal Income Taxes were provided for the following items for the years
ended December 31, 1998, 1997 and 1996, respectively:
1998 1997 1996
Current Federal Tax Provision (000's):
Operating Income $2,221 $2,999 $3,658
Amortization of Investment Tax Credits (402) (172) (194)
Total Current Federal
Tax Provision 1,819 2,827 3,464
Deferred Federal Tax Provision (000's):
Accelerated Tax Depreciation 488 500 603
Abandoned Properties (656) (589) (655)
Allowance for Funds Used During Construction
("AFUDC") and Overheads (58) (65) (72)
Post Retirement Benefits
Other Than Pensions (32) (33) (20)
Environmental Remediation 45 112 ---
Deferred Maintenance Cost and Other (76) 251 (175)
Accrued Revenue 1,042 --- ---
Deferred Gas Rate Case Expense 283 --- ---
Percentage Repair Allowance 115 108 124
Deferred Advances (72) 52 304
Deferred Pensions 146 237 212
Total Deferred Federal Tax Provision 1,225 573 321
Total Federal Tax Provision $3,044 $3,400 $3,785
The components of the Federal and State income tax provisions
reflected in the accompanying consolidated statements of earnings
for the years ended December 31, 1998, 1997 and 1996 were as follows:
(000's) 1998 1997 1996
Federal
Current $2,221 $2,999 $3,658
Deferred 1,225 573 321
Amortization of Investment Tax Credits (402) (172) (194)
Total Federal Tax Provision 3,044 3,400 3,785
State
Current 377 679 691
Deferred 289 87 137
Total State Tax Provision 666 766 828
Total Provision for Federal and State
Income Taxes $3,710 $4,166 $4,613
The differences between the Company's provisions for Federal Income
Taxes and the provisions calculated at the statutory federal tax
rate, expressed in percentages, are shown below:
Year Ended December 31, 1998 1997 1996
Statutory Federal Income Tax Rate 34% 34% 34%
Income Tax Effects of:
Investment Tax Credits (3) (1) (1)
Abandoned Property (6) (5) (5)
Other, Net 2 1 2
Effective Federal Income Tax Rate 27% 29% 30%
Temporary differences which gave rise to deferred tax assets and liabilities
are shown below:
Deferred Income Taxes for the Year Ended December 31,
(000's) 1998 1997
Accelerated Depreciation $24,658 $24,625
Abandoned Property 8,442 9,098
Contributions in Aid to Construction (2,819) (2,750)
Percentage Repair Allowance 1,924 1,792
Cathodic Protection 369 372
Retirement Loss 2,348 1,823
Deferred Pensions 2,870 2,758
AFUDC 31 45
Overheads 202 249
KESOP (442) (544)
Bad Debts (225) (246)
Accumulated Deferred 3,179 3,441
Environmental Remediation 186 132
Accrued Revenue 1,199 ---
Deferred Gas Rate Case Expense 337 ---
Investment Tax Credit 916 1,437
Other (148) 63
Total Deferred Income Taxes $43,027 $42,295
Note 8: Energy Supply
Massachusetts:
Joint Owned Units --- FG&E is participating, on a tenancy-in-common
basis with other New England utilities, in the ownership of three generating
units. New Haven Harbor is a dual-fired oil-and-gas station, and Wyman Unit
No. 4 is an oil-fired station. They have been in commercial operation since
August 1975 and December 1978, respectively. Millstone Unit No. 3, a nuclear
generating unit, has been in commercial operation since April 1986.
Kilowatt-hour generation and operating expenses of the joint ownership units
are divided on the same basis as ownership. FG&E's proportionate costs are
reflected in the 1998 Consolidated Statements of Earnings. Information with
respect to these units as of December 31, 1998 is shown below:
Joint Ownership Proportionate Share Company's Net
Units State Ownership % of Total MW Book Value
Millstone Unit No.3 CT 0.2170 2.50 $7,581
Wyman Unit No.4 ME 0.1822 1.13 117
New Haven Harbor CT 4.5000 20.12 2,000
23.75 $9,698
Purchased Power and Gas Supply Contracts --- FG&E has commitments
under long-term contracts for the purchase of electricity and gas from
various suppliers. Generally, these contracts are for fixed periods and
require payment of demand and energy charges. Total costs under these
contracts are included in Electricity and Gas Purchased for Resale in the
Consolidated Statements of Earnings. These costs are normally recoverable in
revenues under various cost recovery mechanisms.
The status of FG&E's electric purchased power contracts at December 31, 1998,
is as shown below:
Unit
Fuel Energy Contract
Type Entitlements End Date
Hydro 8 MW 2001
Hydro 3 MW 2012
Wood 17 MW 2012
System 15 MW 2001
Impact of Electric Restructuring --- On January 15, 1999 the MDTE
issued an order (the Order) approving FG&E's Electric Restructuring Plan
(the Plan) with certain modifications. The January 15 Order included approval
of the Company's power supply divestiture plan for its interest in the three
generating units and four long-term power supply contracts outlined, above.
FG&E has been allowed recovery of its transition costs, estimated at
$140 million, including the above-market or stranded generation and
power-supply related costs via a non-bypassable uniform Transition Charge.
Estimated Regulatory Assets, based upon the Transition Charges to be
collected, have been recorded together with the recognition of certain
adjustments related to power supply contract liabilities and generation
assets.
FG&E recorded, based on the competitive bidding process, the
estimated above-market portion of its power supply contracts obligations of
$129 million. The net book value of its investment in generation assets,
principally investments in Joint Owned facilities and inventories, is
approximately $11 million and has been reclassified to Regulatory Assets.
Also, as a result of the competitive bidding process, FG&E expects to receive
approximately $5 million in proceeds from the disposition of its investment
in Joint Owned facilities in 1999, which has been recorded in Regulatory
Assets at December 31, 1998. Also, Deferred Tax Assets and Liabilities
related to the adjustments above, are reflected in the Company's Balance
Sheet at December 31, 1998.
As a result of the Order by the MDTE related to Electric Industry
Restructuring in Massachusetts (See Note 12), the Company is required to
discontinue the provisions of Statement of Financial Accounting Standards 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71),
to the generation and power supply portion of FG&E's business. FG&E's
electric distribution business and gas supply and distribution business, as
well as the power supply and distribution business of CECo, E&H and UPC will
continue to apply SFAS No. 71.
New Hampshire:
Purchased Power Contracts --- UPC also has commitments under long-term
contracts for the purchase of electricity from various suppliers. These
wholesale contracts are generally for fixed periods and require payment of
demand and energy charges. The total costs under these contracts are included
in Electricity Purchased for Resale in the Consolidated Statements of
Earnings and are normally recoverable in revenues under various cost
recovery mechanisms.
The status of UPC's electric purchased power contracts at
December 31, 1998, is as shown below:
Est. Annual Min
Payments Which
Unit 1998 Energy Cover Future
Fuel MW Winter Purchased Contract Debt Service
Type Entitlements (MWH's) End Date Requirements (000's)
Unitil Power Corp.
Gas 24 127,221 2010 $5,047 [1]
Gas 2 4,631 2008 None
Oil/Gas 2 5,768 2003 None
Oil/Gas 16 75,889 2006 None
Oil/Gas 10 17,820 2008 None
Oil 4 8,472 1999 None
Oil 11 52,598 2005 None
Coal 25 137,183 2005 None
Nuclear 29 197,146 2005 None
Nuclear 10 86,408 2010 None
Nuclear 2 13,458 2013 None
Hydro 5 --- 2001 $989 [2]
Refuse 6 47,113 2003 None
System 18 1,242 2002 None
System 30 11,317 Variable None
Various 5 4,236 1999 None
Various 178,055 Short-term None
Notes:
[1] Total estimated 1998 annualized capacity payments, including debt
service requirements.
[2] Total support charges including debt service requirements.
In New Hampshire, Electric Industry Restructuring is not yet
complete. The Company expects that, upon completion of industry
restructuring, the above-market portion of the contracts listed above would
be classified as stranded costs.
Note 9: Benefit Plans
Pension Plans --- Prior to May 1, 1998 four of the Company's
subsidiaries had defined benefit Retirement and Pension plans and related
Trust Agreements to provide retirement annuities for participating employees
at age 65. On May 1, 1998, the plans of each employer were merged into one
plan with uniform plan provisions to be known as the "Unitil Corporation
Retirement Plan." The entire cost of the plan is borne by the respective
subsidiaries.
The following table provides the components of net periodic expense
(income) for the plans for years 1998, 1997, and 1996:
(000's) 1998 1997 1996
Service Cost $827 $767 $703
Interest Cost 2,207 2,023 1,921
Expected Return on Plan Assets (3,562) (3,094) (2,817)
Amortization of Transition Obligation (16) (16) (16)
Amortization of Prior-service Cost 74 13 13
Net Periodic Benefit Income $(470) $(307) $(196)
Reconciliation of Projected Benefit Obligation
(000's): 1998 1997 1996
Beginning of Year $29,853 $26,907 $28,236
Service Cost 827 767 703
Interest Cost 2,207 2,023 1,921
Amendments (Note A) 1,292 --- ---
Actuarial Loss/(Gain) 4,290 1,836 (2,373)
Benefit Payments (1,848) (1,680) (1,580)
End of Year $36,621 $29,853 $26,907
Reconciliation of Fair Value of Plan Assets (000's):
Beginning of Year $42,304 $36,547 $32,858
Actual Return on Plan Assets 8,171 6,971 4,807
Employer Contributions --- 466 462
Benefit Payments (1,848) (1,680) (1,580)
End of Year $48,627 $42,304 $36,547
Funded Status (000's)
Funded Status at December 31 (Note B) $12,006 $12,451 $9,640
Unrecognized Transition Obligation 254 238 222
Unrecognized Prior-service Cost 1,317 98 111
Unrecognized Net Actuarial (Gain)/Loss (4,986) (4,667) (2,625)
Prepaid Pension Cost $8,591 $8,120 $7,348
(A)Generally effective May 1, 1998, the plans of each employer were merged
into one plan with uniform plan provisions to be known as the "Unitil
Corporation Retirement Plan."
(B)From Fair Value of Plan Assets less End of Year Projected Benefit
Obligation
Plan assets are invested in common stock, short-term investments and
various other fixed income security funds. The weighted-average discount
rates used in determining the projected benefit obligation in 1998, 1997 and
1996 were 7.00%, 7.25%, and 7.75%, respectively, while the rate of increase
in future compensation levels for 1998, 1997 and 1996 were 4.00%, 4.50% and
4.50%, respectively. The expected long-term rates of return on assets in 1998,
1997 and 1996 were 9.25% in each year.
Unitil Service Corp. has a Supplemental Executive Retirement Plan
(SERP). The SERP is an unfunded retirement plan with participation limited
to executives selected by the Board of Directors. The cost associated with
the SERP amounted to approximately $114,000; $112,000; and $71,000 for the
years ended December 31, 1998, 1997 and 1996, respectively.
Employee 401(k) Tax Deferred Savings Plan --- The Company sponsors a
defined contribution plan (under Section 401 (k) of the Internal Revenue
Code) covering substantially all of the Company's employees. Participants may
elect to defer from 1% to 15% of current compensation to the plan. The
Company matches contributions, with a maximum matching contribution of 3% of
current compensation. Employees may direct the investment of their savings
plan balances into a variety of investment options, including a Company
common stock fund. Participants are 100% vested in contributions made on
their behalf, once they have completed three years of service. The Company's
share of contributions to the plan were $384,142; $389,888; and $356,574 for
the years ended December 31, 1998, 1997 and 1996, respectively.
Post-Retirement Benefits --- The Company's subsidiaries provide
health care benefits to retirees for a twelve-month period following their
retirement. The Company's subsidiaries continue to provide life insurance
coverage to retirees. Life insurance and limited health care post-retirement
benefits require the Company to accrue post-retirement benefits during the
employee's years of service with the Company and the recognition of the
actuarially determined total post retirement benefit obligation earned by
existing retirees. At December 31, 1998, 1997 and 1996, the accumulated post
retirement benefit obligation (transition obligation) was approximately
$299,000, $321,000 and $342,000, respectively, and the period cost associated
with these benefits for 1998, 1997 and 1996 was approximately $76,000,
$75,000 and $132,000, respectively. This obligation is being recognized on a
delayed basis over the average remaining service period of active
participants and such period will not exceed 20 years. The Company has
omitted certain disclosures relating to SFAS No.132, as the accumulated
post-retirement benefit obligation (transition obligation) is not material.
Note 10: Earnings Per Share
The following table reconciles basic and diluted earnings per share
assuming all stock options were converted to common shares per SFAS 128.
(000's except share and per share data) 1998 1997 1996
Basic Income Available to Common Stock $7,975 $7,959 $8,451
Weighted Average Common Shares
Outstanding-Basic 4,505,784 4,412,869 4,354,297
Plus: Diluted Effect of Incremental
Shares from Assumed
Conversion 128,324 107,512 106,366
Weighted Average Common
Shares Outstanding-Diluted 4,634,108 4,520,381 4,460,663
Basic Earnings per Share $1.77 $1.80 $1.94
Diluted Earnings per Share $1.72 $1.76 $1.89
Note 11: Segment Information
The Company has two reportable segments: Electric (CECo, E&H, UPC,
URI, and the electric portion of FG&E's business) and Gas (the gas portion
of FG&E's business). Unitil is engaged principally in the retail sale and
distribution of electricity in New Hampshire and both electric and gas
service in Massachusetts through its retail distribution subsidiaries CECo,
E&H, and FG&E. The Company's wholesale electric power subsidiary, UPC,
provides all the electric power supply requirements to CECo and E&H for
resale at retail, and also engages in various other wholesale electric power
services with affiliates and non-affiliates throughout the New England
Region. URI is engaged in business transactions as a competitive marketer of
electricity. URC and USC provide centralized operations to support the
Unitil System.
URC and USC are included in the "Other" column of the table below.
USC provides centralized management and admininstrative services, including
information systems management and financial record-keeping. URC owns certain
real estate, principally the Company's corporate headquarters.
The segments follow the same accounting policies as described in the
Summary of Significant Accounting Policies. Intersegment sales take place at
cost and the effects of all intersegment and/or intercompany transactions are
eliminated in the consolidated financial statements. Segment profit or loss
is based on profit or loss from operations after income taxes. Expenses used
to determine operating income before taxes are charged directly to each
segment or are allocated in accordance with factors contained in cost of
service studies which were included in rate applications approved by the
NHPUC and MDTE. Assets allocated to each segment are based upon specific
identification of such assets provided by Company records.
The table below provides significant segment financial
data for the years ended December 31, 1998, 1997 and 1996:
Year Ended
December 31, 1998 (000's) Electric Gas Other Eliminations Total
Revenues
External Customers $149,639 $17,009 $30 $166,678
Intersegment --- --- 18,483 (18,483) ---
Depreciation and Amortization 7,917 893 1,197 10,007
Interest, net 4,842 1,097 962 6,901
Income Taxes 3,609 (145) 246 3,710
Segment Profit 7,428 176 371 7,975
Identifiable Segment Assets 316,568 36,354 44,932 (21,019) 376,835
Regulatory Assets 163,034 --- --- 163,034
Capital Expenditures 10,644 3,171 648 14,463
Year Ended
December 31, 1997 (000's)
Revenues
External Customers $149,973 $19,729 $36 $169,738
Intersegment --- --- 14,295 (14,295) ---
Depreciation and Amortization 7,246 892 1,040 9,178
Interest, net 5,715 1,034 418 7,167
Income Taxes 3,563 414 189 4,166
Segment Profit 6,772 916 271 7,959
Identifiable Segment Assets 177,684 36,045 47,488 (22,686) 238,531
Regulatory Assets 23,885 --- --- 23,885
Capital Expenditures 10,475 2,182 1,230 13,887
Year Ended
December 31, 1996 (000's)
Revenues
External Customers $149,696 $21,105 $45 $170,846
Intersegment --- --- 10,738 (10,738) ---
Depreciation and Amortization 7,243 856 677 8,776
Interest, net 5,206 979 (14) 6,171
Income Taxes 3,831 417 365 4,613
Segment Profit 6,982 900 569 8,451
Identifiable Segment Assets 175,178 33,473 41,952 (18,495) 232,108
Regulatory Assets 25,432 --- --- 25,432
Capital Expenditures 10,834 1,915 6,610 19,359
Note 12: Commitments and Contingencies
Environmental Matters
In September 1998, the FG&E signed a memorandum of understanding with
the Massachusetts Highway Department and the Massachusetts Department of
Environmental Protection that accommodates the construction of a new highway
bridge across Sawyer Passway, the Company's former manufactured gas plant
(MGP) site. This memorandum satisfies the requirements of the Massachusetts
Contingency Plan for temporary closure at this last remaining portion of the
site. Specifically, this agreement allows for current FG&E efforts to
perform remediation work required as result of bridge construction. Upon
completion of site remediation associated with the bridge construction, this
last remaining portion of the Sawyer Passway MGP site is expected be closed
out and attain the status of temporary closure in late 1999. This temporary
closure allows FG&E to monitor the site every five years to determine if a
more feasible remediation alternative can be developed and achieved.
The costs of remedial action at this site are initially funded from
traditional sources of capital and recovered from customers under a rate
recovery mechanism approved by the MDTE. The Company also has a number of
liability insurance policies that may provide coverage for environmental
remediation at this site.
Regulatory Matters
Restructuring and Competition -Regulatory activity surrounding
restructuring and competition continues in both Massachusetts and New
Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition
for all electric consumers in Massachusetts, while New Hampshire's "Choice
Date" slipped past both the proposed date of January 1, 1998, and the
legislature's mandated July 1, 1998. Currently, approximately 10% of New
Hampshire electric consumers can choose their electric supplier. The ability
to choose for the remaining 90% is currently the subject of a federal court
preliminary injunction (see below).
Massachusetts gas industry restructuring plans continue to be under
development. The MDTE, gas utilities and other stakeholders began a
collaborative effort in late 1997 to develop solutions to the many issues
that surround restructuring the local natural gas distribution business.
Unitil has been preparing for electric and gas industry restructuring
by developing transition plans that will move its utility subsidiaries into
this new market structure in a way that will ensure fairness in the treatment
of the Company's assets and obligations that are dedicated to the current
regulated franchises and, at the same time, provide choice for all customers.
Massachusetts (Electric)- On January 15, 1999, the MDTE gave final
approval to FG&E's restructuring plan with certain modifications. The Plan
provides customers with: a) a choice of energy supplier; b) an option to
purchase Standard Offer Service (i.e. state-mandated energy service) provided
by FG&E at regulated rates for up to seven years; and c) a cumulative 15%
rate reduction. The Plan also provides for FG&E to divest generation assets
and its portfolio of purchased power contracts. The Company will be afforded
full recovery of any transition costs through a non-bypassable retail
Transition Charge.
Pursuant to the Plan, on October 30, 1998, the Company filed with the
MDTE a proposed contract with Constellation Power Services Inc. for provision
of Standard Offer Service. The MDTE's January 15, 1999 Order approves the
FG&E/Constellation contract, and service thereunder is scheduled to commence
on March 1, 1999, and is scheduled to continue through February 28, 2005.
This contract is the result of the first successful Standard Offer auction
conducted in Massachusetts.
The January 15 Order also approved the Company's power supply
divestiture plan for its interest in three generating units and four
long-term power supply contracts. A contract for the sale of FG&E's interest
in the New Haven Harbor plant was filed with the MDTE on November 20, 1998.
The MDTE's decision is pending. Contracts for the sale of the Company's
remaining generating assets and purchased power contracts are expected to be
filed with the MDTE in the near future. All such contracts are subject to
MDTE approval.
Massachusetts (Gas) -In mid-1997, the MDTE directed all Massachusetts
natural gas Local Distribution Companies (LDCs) to form a collaborative with
other stakeholders to develop common principles and appropriate regulations
for the unbundling of gas service, and directed FG&E and four other LDCs to
file unbundled gas rates for its review. FG&E's unbundled gas rates were
approved by the MDTE and implemented in November of 1998.
On July 2, 1998 the MDTE established April 1, 1999 as the date by
which unbundled gas service would begin to be implemented by all LDCs. On
February 1, 1999, the MDTE issued an order in which it determined that the
LDCs would continue to have an obligation to provide gas supply and delivery
services for another five years, with a review after three years. That
order also set forth the MDTE's decision regarding release by LDCs of their
pipeline capacity contracts to competitive marketers. In January of 1999,
the LDCs reported to the MDTE that they were continuing to work to develop
systems and practices to implement unbundling. The MDTE has not yet responded
to the LDCs' report, and it appears unlikely that full implementation will
be achieved by the April 1, 1999 target date.
New Hampshire - On February 28, 1997, the New Hampshire Public
Utilities Commission (NHPUC) issued its Final Plan for transition to a
competitive electric market in New Hampshire. The order allowed CECo and E&H,
Unitil's New Hampshire retail distribution utilities, to recover 100% of
"stranded" costs for a two-year period, but excluded recovery of certain
administrative-related charges.
Northeast Utilities' affiliate, Public Service Company of New
Hampshire, appealed the NHPUC order in Federal District Court. A temporary
restraining order was issued on March 10, 1997. In June 1997, Unitil was
admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June
9, 1998, the Federal Court issued an injunction continuing the freeze on
NHPUC efforts to implement restructuring. Several parties have filed
interlocutory appeals, and no date has been scheduled for a trial in the
federal court. The Company will vigorously pursue its action in the federal
court and simultaneously look for ways to resolve issues and bring forth
choice to its retail customers.
In September of 1998, the Company reached a comprehensive
restructuring settlement with key parties and filed this voluntary Agreement
with the NHPUC. The Agreement was modified on October 20, 1998. In oral
deliberations on November 2 and November 18, 1998, the NHPUC imposed
conditions to approval of the Settlement which were unacceptable to the
Company, and the Settlement was subsequently withdrawn. The component of the
Agreement dealing with wholesale rates was filed with the FERC in September
1998, and approved by the FERC in early November. However, implementation
will not occur, as the changes were conditioned upon approval by the NHPUC.
Unitil continues to participate actively in all proceedings and in several
NHPUC-established working groups which will define details of the transition
to competition and customer choice.
Rate Cases -The last formal regulatory hearings to increase base
electric rates for Unitil's three retail operating subsidiaries occurred in
1985 for Concord Electric Company, 1984 for Fitchburg Gas and Electric Light
Company and 1981 for Exeter & Hampton Electric Company.
On May 15, 1998, FG&E filed a gas base rate case with the MDTE.
After evidentiary hearings, the MDTE issued an Order allowing FG&E to
establish new rates, effective November 30, 1998, that would produce an
annual increase of approximately $1.0 million in gas revenues. However, as
part of the proceeding, the Attorney General of the Commonwealth of
Massachusetts alleged that FG&E had double-collected fuel inventory finance
charges, since 1987, and requested that the MDTE require FG&E to refund
approximately $1.6 million to its customers. The Company believes that the
Attorney General's claim is without merit and that a refund is not justified
or warranted. The MDTE stated its intent to open a separate proceeding to
investigate the Attorney General's claim.
A majority of the Company's operating revenues are collected under
various periodic rate adjustment mechanisms including fuel, purchased power,
cost of gas and energy efficiency program cost recovery mechanisms.
Restructuring will continue to change the methods of how certain costs are
recovered from customers and from suppliers. Transition costs, Standard Offer
Service and Default Service power supply costs, internal and external
transmission service costs and energy efficiency and renewable energy
program costs for FG&E are being recovered via fully reconciling rate
adjustment mechanisms in Massachusetts.
Millstone Unit No. - FG&E has a 0.217% nonoperating ownership in the
Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it
with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear
Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which
calls for increased NRC inspection attention. On March 30, 1996, as a result
of an engineering evaluation completed by the operator, Northeast Utilities,
Millstone 3 was taken out of service. NRC authorization for restart was given
on June 29, 1998. Millstone 3 began producing electric power in early July,
1998 and reached full output on July 15, 1998. The unit remains on the
NRC's Watch List.
During the period that Millstone 3 was out of service, FG&E continued
to incur its proportionate share of the unit's ongoing Operations and
Maintenance (O&M) costs, and may incur additional O&M costs and capital
expenditures to meet NRC requirements. FG&E also incurred costs to replace
the power that was expected to be generated by the unit. During the outage,
FG&E had been incurring approximately $35,000 per month in replacement power
costs, and had been recovering those costs through its fuel adjustment
clause, which will be subject to review and approval by the MDTE.
In August 1997, FG&E, in concert with other non-operating joint
owners, filed a demand for arbitration in Connecticut and a lawsuit in
Massachusetts, in an effort to recover costs associated with the extended
unplanned shutdown. The arbitration and legal cases are proceeding.
Item 9. Changes In And Disagreements With Accountants On Accounting
And Financial Disclosure
None
PART III
Item 10. Directors and Executive Officers of the Registrant
Information required by this Item is set forth in Exhibit 99.1 on
pages 2 through 8 of the 1998 Proxy Statement.
Item 11. Executive Compensation
Information required by this Item is set forth in Exhibit 99.1 on
pages 9 through 13 of the 1998 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this Item is set forth in
Exhibit 99.1 on pages 3 through 5 of the 1998 Proxy
Statement and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
None
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) and (2) -
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following financial statements are included herein under Part II,
Item 8, Financial Statements and Supplementary Data.
Report of Independent Certified Public Accountants
Consolidated Balance Sheets - December 31, 1998 and 1997
Consolidated Statements of Earnings - for the years ended
December 31, 1998, 1997 and 1996
Consolidated Statements of Capitalization - December 31, 1998 and 1997
Consolidated Statements of Cash Flows
for the years ended December 31, 1998, 1997 and 1996
Consolidated Statements of Changes in Common Stock Equity -
for the years ended December 31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements
The following consolidated financial statement schedules of the
Company and subsidiaries are included in Item 14(d):
Report of Independent Certified Public Accountants
Schedule VIII Valuation and Qualifying Accounts for December 31,
1998, 1997 and 1996
All other schedules for which provision is made in the
applicable accounting regulation of the Securities and Exchange
Commission are not required under the related instructions, are
inappropriate, or information required is included in the financial
statements or notes thereto and, therefore, have been omitted.
(3) - List of Exhibits
Exhibit No. Description of Exhibit Reference*
3.1 Articles of Incorporation Exhibit 3.1 to Form
of the Company. S-14 Registration
Statement 2-93769
3.2 Articles of Amendment to the
Articles of Incorporation
filed on March 4, 1992 and Exhibit 3.2 to Form
April 30, 1992. 10-K for 1992
3.3 By-Laws of the Company. Exhibit 3.2 to
Form S-14 Registration
Statement 2-93769
3.4 Articles of Exchange of Concord
Electric Company (CECo),
Exeter & Hampton Exhibit 3.3 to
Electric Company (E&H) 10-K
and the Company for 1984
3.5 Articles of Exchange of CECo,
E&H, and the Company -
Stipulation of the Parties Exhibit 3.4 to
Relative to Recordation and Form 10-K
Effective Date. for 1984
3.6 The Agreement and Plan of Merger
dated March 1, 1989 among the Exhibit 25(b) to
Company, Fitchburg Gas and Electric Form 8-K
Light Company (FG&E) and dated
UMC Electric Co., Inc. (UMC). March 1, 1989
3.7 Amendment No. 1 to The Agreement
and Plan of Merger dated March 1, Exhibit 28(b) to
1989 among the Company, FG&E Form 8-K, dated
and UMC December 14, 1989
4.1 Indenture of Mortgage and Deed of
Trust dated July 15, 1958 of
CECo relating to First
Mortgage Bonds, Series B, 4 3/8%
due September 15, 1988 and all
series unless supplemented. **
4.2 First Supplemental Indenture
dated January 15, 1968 relating
to CECo's First Mortgage
Bonds, Series C, 6 3/4% due January
5, 1998 and all additional series
unless supplemented. **
Exhibit No. Description of Exhibit Reference*
4.3 Second Supplemental Indenture
dated November 15, 1971 relating
to CECo's First Mortgage
Bonds, Series D, 8.70% due November
15, 2001 and all additional series
unless supplemented. **
4.4 Fourth Supplemental Indenture
dated March 28, 1984 amending
CECo's Original First Mortgage
Bonds Indenture, and First, Second and
Third Supplemental Indentures
and all additional series unless supplemented. **
4.5 Fifth Supplemental Indenture
dated June 1, 1984 relating
to CECo's First Mortgage
Bonds, Series F, 14 7/8% due June 1,
1999 and all additional series
unless supplemented. **
4.6 Sixth Supplemental Indenture
dated October 29, 1987 relating
to CECo's First Mortgage
Bonds, Series G, 9.85% due October Exhibit 4.6 to
15, 1997 and all additional series unless Form 10-K
supplemented. for 1987
4.7 Seventh Supplemental Indenture
dated August 29, 1991 relating
to CECo's First Mortgage
Bonds, Series H, 9.43% due September Exhibit 4.7 to
1, 2003 and all additional series Form 10-K
unless supplemented. for 1991
4.8 Eighth Supplemental Indenture
dated October 14, 1994 relating
to CECo's First Mortgage Bonds, Exhibit 4.8 to
Series I, 8.49% due October 14, 2024 Form 10-K
and all additional series unless for 1994
supplemented.
4.9 Indenture of Mortgage and Deed
of Trust dated December 1, Exhibit 4.5 to
1952 of E&H relating to all series unless Registration
supplemented. Statement 2-49218
4.10 Third Supplemental Indenture
dated June 1, 1964 relating
to E&H's First Mortgage Bonds, Series D, Exhibit 4.5 to
4 3/4% due June 1, 1994 and all Registration
additional series unless supplemented. Statement 2-49218
Exhibit No. Description of Exhibit Reference*
4.11 Fourth Supplemental Indenture
dated January 15, 1968 relating to
E&H's First Mortgage Bonds, Series E, Exhibit 4.6 to
6 3/4% due January 15, 1998 and Registration
all additional series unless supplemented. Statement 2-49218
4.12 Fifth Supplemental Indenture
dated November 15, 1971 relating
to E&H's First Mortgage Bonds, Series F, Exhibit 4.7 to
8.70% due November 15, 2001 and Registration
all additional series unless supplemented. Statement 2-49218
4.13 Sixth Supplemental Indenture
dated April 1, 1974 relating to
E&H's First Mortgage Bonds, Series G, 8 7/8%
due April 1, 2004 and all additional
series unless supplemented. **
4.14 Seventh Supplemental Indenture
dated December 15, 1977 relating
to E&H's Exhibit 4 to
First Mortgage Bonds, Series H, Form 10-K
8.50% due December 15, 2002 and for 1977
all additional series unless supplemented. (File No. 0-7751)
4.15 Eighth Supplemental Indenture
dated October 29, 1987 relating
to E&H's First Mortgage Bonds, Series I, Exhibit 4.15 to
9.85% due October 15, 1997 and Form 10-K
all additional series unless supplemented. for 1987
4.16 Ninth Supplemental Indenture
dated August 29, 1991 relating
to E&H's
First Mortgage Bonds, Series J, Exhibit 4.18 to
9.43% due September 1, 2003 and Form 10-K
all additional series unless supplemented. for 1991
4.17 Tenth Supplemental Indenture
dated October 14, 1994 relating
to E&H's First Mortgage Bonds, Series K Exhibit 4.17 to
8.49% due October 14, 2024 and all Form 10-K
additional series unless supplemented. for 1994
4.18 Bond Purchase Agreement dated
August 29, 1991 relating to
E&H's Exhibit 4.19 to
First Mortgage Bonds, Series J Form 10-K
9.43% due September 1, 2003 for 1991
Exhibit No. Description of Exhibit Reference*
4.19 Purchase Agreement dated March 20,
1992 for the 8.55% Senior Notes Exhibit 4.18 to Form
due March 31, 2004 10-K for 1993
4.20 Note Agreement dated November 30,
1993 for the 6.75% Notes due Exhibit 4.18 to Form
November 30, 2023 10-K for 1993
4.21 First Mortgage Loan Agreement dated October 24,
1988 with an Institutional Investor in
connection Exhibit 4.16 to
with Unitil Realty Corp.'s Form 10-K
acquisition of the Company's facilities in for 1998
Exeter, New Hampshire.
4.22 Note Purchase Agreement dated July 1, 1997 Exhibit 4.22 to
for the 8.00% Senior Secured Notes Form 10-K
due August 1, 2017 for 1997
4.23 Eleventh Supplemental Indenture dated Filed Herewith
September 1, 1998 relating to E&H's First
Mortgage Bonds Series L 6.96% due September 1,
2028.
4.24 Ninth Supplemental Indenture dated Filed Herewith
September 1, 1998 relating to CECo's First
Mortgage Bonds Series J 6.96% due September 1,
2028.
10.1 Labor Agreement effective June 1, 1997 Exhibit 10.1 to
between CECo and The Form 10-K
International Brotherhood of Electrical for 1997
Workers, Local Union No. 1837
10.2 Labor Agreement effective May 31, Filed herewith
1998 between E&H and The International
Brotherhood of Electrical Workers, Local Union
No. 1837, Unit 1.
10.3 Labor Agreement effective May 1, Filed herewith
1998 between FG&E and The
Brotherhood of Utility Workers of
New England, Inc., Local Union No. 340.
10.4 Unitil System Agreement dated
June 19, 1986 providing that Unitil Power Exhibit 10.9 to
will supply wholesale requirements electric Form 10-K
service to CECo and E&H for 1986
Exhibit No. Description of Exhibit Reference*
10.5 Supplement No. 1 to Unitil System
Agreement providing that Unitil Power Exhibit 10.8 to
will supply wholesale requirements Form 10-K
electric service to CECo and E&H. for 1987
CECo and E&H.
10.6 Transmission Agreement Between
Unitil Power Corp. and Public Exhibit 10.6 to
Service Company of New Hampshire, Form 10-K
Effective November 11, 1992 for 1993
10.7 Form of Severance Agreement dated Exhibit 10.55 to
February 21, 1989, between the Company Form 8
and the persons named in the schedule dated
attached thereto. April 12, 1989
10.8 Key Employee Stock Option Exhibit 10.56 to
Plan effective as of January 17, 1989. Form 8 dated
April 12, 1989
10.9 Unitil Corporation Key Employee Exhibit 10.63 to
Stock Option Plan Award Form 10-K
Agreement. for 1989
10.10 Unitil Corporation Management Exhibit 10.94 to
Performance Compensation Program. Form 10-K/A for 1993
10.11 Unitil Corporation Supplemental
Executive Retirement Plan Exhibit 10.95 to
effective as of January 1, 1987. Form 10-K/A for 1993
10.12 Unitil Corporation 1998 Stock Option Plan Filed herewith
10.13 Unitil Corporation Management Filed herewith
Incentive Plan
11.1 Statement Re Computation in Support
of Earnings Per Share for the Company Filed herewith
12.1 Statement Re Computation in
Support of Ratio of Earnings
to Fixed Charges for the Company. Filed herewith
21.1 Statement Re Subsidiaries of Registrant Filed herewith
27 Financial Data Schedule Filed herewith
99.1 1998 Proxy Statement Filed herewith
* The exhibits referred to in this column by specific designations and
dates have heretofore been filed with the Securities and Exchange Commission
under such designations and are hereby incorporated by reference.
** Copies of these debt instruments will be furnished to the Securities
and Exchange Commission upon request.
(b) Report on Form 8-K
No reports on Form 8-K were filed during the fourth quarter
of the year ended December 31, 1998.
On January 29, 1999 Unitil Corporation filed Form 8-K
related to the approval of Fitchburg Gas and Electric Light
Compay's Electric Restructuring Plan (the Plan) by the
Massachusetts Department of Telecommunications and Energy.
See Item 7 - Management's Discussion and Analysis for
further discussion of the Plan.
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our report dated February 9, 1999, accompanying the
consolidated financial statements and schedule included in the Annual Report
of Unitil Corporation and subsidiaries on Form 10-K for the year ended
December 31, 1998. We hereby consent to the incorporation by reference of
said report in the Registration Statements of Unitil Corporation and
subsidiaries on Form S-3 and on Form S-8.
GRANT THORNTON LLP
Boston, Massachusetts
March 23, 1999
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, the Registrant has duly caused this report
to be signed on its behalf by the undersigned thereunto duly authorized.
Unitil Corporation
Date March 31, 1999 By Robert G. Schoenberger
Robert G. Schoenberger
Chairman of the Board of Directors,
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
as amended, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates indicated.
Signature Capacity Date
Robert G. Schoenberger Principal Executive March 31, 1999
Robert G. Schoenberger Officer; Director
(Chairman of the Board of Directors
and Chief Executive Officer)
Michael J. Dalton Principal Operating March 31, 1999
Michael J. Dalton Officer; Director
(President and Chief
Operating Officer)
Anthony J. Baratta, Jr. Principal Financial March 31, 1999
Anthony J. Baratta, Jr. Officer
(Executive Vice President
and Chief Financial Officer)
Bruce W. Keough Director March 31, 1999
Bruce W. Keough
Douglas K. Macdonald Director March 31, 1999
Douglas K. Macdonald
M. Brian O'Shaughnessy Director March 31, 1999
M. Brian O'Shaughnessy
J. Parker Rice, Jr. Director March 31, 1999
J. Parker Rice, Jr.
Charles H. Tenney II Director March 31, 1999
Charles H. Tenney II
Charles H. Tenney III Director March 31, 1999
Charles H. Tenney III
William W. Treat Director March 31, 1999
William W. Treat
W. William VanderWolk, Jr. Director March 31, 1999
W. William VanderWolk, Jr.
Joan D. Wheeler Director March 31, 1999
Joan D. Wheeler
Franklin Wyman, Jr. Director March 31, 1999
Franklin Wyman, Jr.
SCHEDULE VIII
UNITIL CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Deductions Balance at
Beginning Costs and Other from End of
Description of Period Expenses Accounts(A) Reserves(B)Period
Year Ended
December 31, 1998
Reserves Deducted from A/R
Electric 544,224 459,942 146,387 582,528 568,025
Gas 108,899 288,214 31,189 350,243 78,059
653,123 748,156 177,576 932,771 646,084
Year Ended
December 31, 1997
Reserves Deducted from A/R
Electric 518,606 670,548 262,523 907,453 544,224
Gas 141,508 177,733 41,284 251,626 108,899
660,114 848,281 303,807 1,159,079 653,123
Year Ended
December 31, 1996
Reserves Deducted from A/R
Electric 490,272 691,880 155,853 819,399 518,606
Gas 132,324 213,258 44,949 249,023 141,508
622,596 905,138 200,802 1,068,422 660,114
(A) Collections on Accounts Previously Charged Off
(B) Bad Debts Charged Off
Exhibit 11.1
UNITIL CORPORATION
Computation in Support of Earnings per Share
Year Ended December 31,
1998 1997 1996
(000's Omitted)
BASIC EARNINGS PER SHARE
Net Income $8,249 $8,235 $8,729
Less: Dividend Requirements
on Preferred Stock 274 276
Net Income Applicable to Common Stock $7,959 $7,959 $8,451
Average Number of Common Shares Outstanding 4,506 4,413 4,354
Basic Earnings per Average
Common Share Outstanding $1.77 $1.80 $1.94
DILUTED EARNINGS PER SHARE
Net Income $8,249 $8,235 $8,729
Less: Dividend Requirements
on Preferred Stock 274 276 278
Net Income Applicable to Common Stock $7,959 $7,959 $8,451
Average Number of Common Shares
Outstanding plus
Assumed Options converted* 4,634 4,520 4,461
Diluted Earnings per Average
Common Share Outstanding $1.72 $1.76 $1.89
* Assumes all options were converted to common shares per SFAS 128.
Exhibit 12.1
UNITIL CORPORATION
Computation in Support of Ratio of Earnings to Fixed Charges
Year Ended December 31,
1998 1997 1996 1995 1994
(000's Omitted Except Ratio)
Earnings:
Net Income, per Consolidated
Statements of Earnings $8,249 $8,235 $8,729 $8,369 $8,038
Federal Income Tax 2,191 3,025 3,699 3,924 3,480
Deferred Federal Income Tax 1,225 573 321 (298) (186)
State Income Tax 368 682 688 690 610
Deferred State Income Tax 289 87 137 (16) 72
Amortization of Tax Credit (402) (172) (194) (202) (211)
Interest on Long-term Debt 5,412 5,242 5,142 5,193 4,825
Amortization of Debt
Discount and Expense 61 60 57 72 64
Rents (annual interest component) 671 667 595 572 561
Other Interest 1,787 1,889 1,049 799 909
Total $19,851 $20,288 $20,223 $19,103 $18,162
Fixed Charges:
Interest on Long-term Debt $5,412 $5,242 $5,142 $5,193 $4,825
Amortization of Debt
Discount and Expense 61 60 57 72 64
Rents (annual interest component) 671 667 595 572 561
Other Interest 1,889 1,889 1,049 799 909
Total $8,033 $7,858 $6,843 $6,636 $6,359
Ratio of Earnings to Fixed Charges 2.47 2.58 2.96 2.88 2.86
Exhibit 21.1
Subsidiaries of Registrant
The Company or the registrant has seven wholly-owned subsidiaries,
six of which are corporations organized under the laws of The State of New
Hampshire: Concord Electric Company, Exeter & Hampton Electric Company,
Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc., and Unitil
Service Corp. The seventh, Fitchburg Gas and Electric Light Company, is
organized under the laws of The State of Massachusetts.
Exhibit 27