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, 2002
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 Identification No.)
incorporation or organization)
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, 2003, the aggregate market value of
common stock held by non-affiliates of the registrant was $123,810,466.
The number of common shares outstanding of the registrant was 4,743,696 as of
March 1, 2003.
Documents Incorporated by Reference:
Portions of the Proxy Statement relating to the Annual Meeting of Shareholders
to be held April 17, 2003, are incorporated by reference into Part III of this
Report.
UNITIL CORPORATION
FORM 10-K
For the Fiscal Year Ended December 31, 2002
Table of Contents
Item Description Page
PART I
1. Business
Unitil Corporation................................................ 2
Utility Operations................................................ 3
March 14, 2003 New Hampshire Public Utilities Commission Order.... 4
Regulatory Matters................................................ 4
Electric Power Supply............................................. 6
Gas Supply........................................................ 8
Environmental Matters............................................. 9
Employees......................................................... 10
Executive Officers of the Registrant.............................. 11
2. Properties............................................................. 12
3. Legal Proceedings...................................................... 12
4. Submission of Matters to a Vote of Securities Holders.................. 12
PART II
5. Market for Registrant's Common Equity and Related Shareholder Matters.. 13
6. Selected Financial Data................................................ 14
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................. 15
7A. Quantitative and Qualitative Disclosures about Market Risk............. 27
8. Financial Statements and Supplementary Data............................ 28
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................... 53
PART III
10. Directors and Executive Officers of the Registrant..................... 54
11. Executive Compensation................................................. 54
12. Security Ownership of Certain Beneficial Owners and Management......... 54
13. Certain Relationships and Related Transactions......................... 54
PART IV
14. Controls and Procedures................................................ 55
15. Exhibits, Financial Statement Schedules and Reports on Form 8-K........ 55
Signatures............................................................. 59
Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002................................................................ 61
Schedule II Valuation and Qualifying Accounts and Reserves............. 64
Exhibit 4.1 Unitil Energy Systems, Inc. - Twelfth Supplemental Indenture
Exhibit 10.16 Restricted Stock Plan
Exhibit 10.17 Portfolio Sale and Assignment and Transition Service and Default
Service Supply Agreement By and Among Unitil Power Corp., Unitil
Energy Systems, Inc. and Mirant Americas Energy Marketing, LP
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 23.1 Consent of Independent Certified Public Accountants
Exhibit 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
1
PART I
Item 1. Business
UNITIL Corporation
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 companies. The following companies
are wholly-owned subsidiaries of Unitil:
State and
Unitil Corporation Year of Principal Type
Subsidiaries Organization of Business
- -------------------------------------------------- --------------- -------------------------------------------
Unitil Energy Systems, Inc. (UES) NH - 1901 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 Brokering and Advisory Services
Usource, Inc. NH - 2000 Energy Brokering and Advisory Services
Usource L.L.C. (Usource) NH - 2000 Energy Brokering and Advisory Services
Unitil'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 two wholly-owned retail
distribution utility subsidiaries (UES and FG&E, collectively referred to as the
Retail Distribution Utilities). The Company's wholesale electric power utility
subsidiary, Unitil Power Corp., currently provides all the electric power supply
requirements to UES for resale at retail.
In December 2002, Exeter & Hampton Electric Company (E&H), a wholly-owned
subsidiary of Until, was merged with and into Concord Electric Company (CECo),
also a wholly-owned subsidiary of Unitil. CECo changed its name to UES
immediately following the merger.
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 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. Usource, Inc. and Usource L.L.C. (Usource) are
wholly-owned subsidiaries of Usource, Inc. Usource provides energy brokering
services, as well as related energy consulting services.
2
UTILITY OPERATIONS
UES serves customers in two distinct geographical territories in New Hampshire -
one in the central region of the state and one in the seacoast region.
UES is engaged principally in the retail distribution and sale of electricity to
approximately 70,000 customers in New Hampshire in the cities of Concord, Exeter
and Hampton, as well as 12 towns surrounding Concord and all or part of 16 towns
surrounding Exeter and Hampton. UES's service area consists of approximately 408
square miles in the Merrimack River Valley of south central New Hampshire and in
southeastern New Hampshire.
The State of New Hampshire's government operations are located within UES's
service area, including the executive, legislative, judicial branches and
offices and facilities for all major state government services. In addition,
UES's service area is a retail trading center for the north central and
southeastern parts of the state. These areas serve diversified businesses
relating to insurance, printing, electronics, granite, belting, plastic yarns,
furniture, machinery, sportswear and lumber, 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
UES's service territory in southeastern New Hampshire, which includes several
popular resort areas and beaches along the Atlantic Ocean. Of UES's 2002 retail
electric revenues, approximately 42% were derived from residential sales, 34%
from commercial, government and nonmanufacturing sales, 23% from
industrial/manufacturing sales and 1% from other sales.
FG&E is engaged principally in the retail 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 27,000
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 2002 electric revenues,
approximately 35% were derived from residential sales, 23% from commercial and
nonmanufacturing sales, 25% from industrial/manufacturing sales and 17% from
other sales.
Natural gas is supplied and distributed by FG&E to approximately 15,000
customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner
and Westminster, all located in Massachusetts. Of FG&E's 2002 gas operating
revenues, approximately 51% were derived from residential sales, 11% from small
general customers, 18% from medium general customers, 9% from large general
customers, 8% from interruptible sales (which are sales to customers that have
agreed to discontinue use of the Company-supplied gas 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) and 3% from other sales. FG&E's industrial gas revenue is primarily
derived from firm sales to chemical manufacturers, paper manufacturing and paper
products companies, fabricated metal products manufacturers and plastics
manufacturers.
Natural gas sales in New England are seasonal, and the Company's results of
operations reflect this seasonal nature. 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. Unitil is not dependent on a single customer
or a few customers for its electric and gas sales.
(For details on Unitil's Results of Operations, see Part II, Item 7
herein.)
(For segment information, see Part II, Item 8, Footnote 14 herein.)
3
MARCH 14, 2003 New Hampshire Public Utilities Commission Order
On March 14, 2003 the New Hampshire Public Utilities Commission (NHPUC) approved
the agreement between Unitil Power, UES and Mirant Americas Energy Marketing,
LP. (Mirant), which was entered into on February 25, 2003, under which Mirant
will purchase the entitlements to Unitil Power's Supply portfolio and provide
Transition and Default Service to the customers of UES. The final amount of
Unitil Power's recoverable stranded costs, calculated on the basis of the
amounts agreed to be paid by the parties under such Agreement for the Unitil
Power power supply portfolio, was determined to be $108.7 million, with a
recovery period of 8 years. As of December 31, 2002, the Company had estimated
these recoverable stranded costs and accordingly recorded on its balance sheet
as of that date $94.5 million as Power Supply Buyout Obligations and Regulatory
Assets. The approval of the Agreement by the NHPUC is subject to an appeal
period of 30 days. The NHPUC Order completes the state approval process for
Unitil's restructuring plan under which UES will implement customer choice for
its customers on May 1, 2003.
REGULATORY MATTERS
The Unitil Companies are regulated by various federal and state agencies,
including the Securities and Exchange Commission (SEC), the Federal Energy
Regulatory Commission (FERC), and state regulatory authorities with jurisdiction
over public utilities, including the New Hampshire Public Utilities Commission
(NHPUC) and the Massachusetts Department of Telecommunications and Energy
(MDTE). In recent years, there has been significant legislative and regulatory
activity to restructure the utility industry in order to introduce greater
competition in the supply and sale of electricity and gas, while continuing to
regulate the distribution operations of Unitil's utility operating subsidiaries.
Unitil implemented the restructuring of its electric operations in Massachusetts
in 1998 and is implementing a restructuring settlement for its New Hampshire
electric operations on May 1, 2003.
Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E
implemented its Restructuring Plan under the Massachusetts Restructuring Act.
FG&E completed the divestiture of its entire regulated power supply business in
2000 in accordance with the Restructuring Plan. All FG&E distribution customers
must pay a transition charge that provides for the recovery of costs associated
with FG&E's power portfolio which were stranded as a result of the divestiture
of those assets. The plant and Regulatory Asset balances that will be recovered
through the transition charge have been approved by the MDTE as part of FG&E's
annual Reconciliation Filings. The Restructuring Act also requires FG&E to
obtain power for retail customers who choose not to buy energy from a
competitive supplier through either Standard Offer Service (SOS) or Default
Service. FG&E must provide SOS through February 2005 at rate levels which
guarantee rate reductions required by the Restructuring Act. New distribution
customers and customers no longer eligible for SOS are eligible to receive
Default Service at prices set periodically based on market solicitations as
approved by regulators. As of December 31, 2002, competitive suppliers were
serving approximately 20% of FG&E's load, mainly for large industrial customers.
As a result of the restructuring and divestiture of FG&E's entire generation and
purchased power portfolio, FG&E has accelerated the amortization of its stranded
electric generation assets and its abandoned investment in Seabrook Station, a
nuclear generating unit. FG&E earns an authorized rate of return on the
unamortized balance of these Regulatory Assets. In addition, as a result of the
rate reduction and rate cap requirements of the Restructuring Act, FG&E has been
authorized to defer the recovery of a portion of its transition costs and SOS
costs. These unrecovered amounts are also recorded as Regulatory Assets and earn
authorized carrying charges until their subsequent recovery in future periods.
In 2002, Unitil's earnings derived from these generation-related Regulatory
Assets, including carrying charges earned on deferred transition costs and SOS
costs, represented approximately 10% of net income. The value of FG&E's
Regulatory Assets is approximately $128 million at December 31, 2002, and is
expected to be amortized and recovered over the next three to nine years.
Earnings from this segment of FG&E's utility business will continue to decline
and ultimately cease.
FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002.
Rate adjustments were approved in each Filing for effect during the subsequent
year, subject to further investigation. In October 2001, the MDTE issued a final
Order on FG&E's 1999 Reconciliation Filing which determined the final treatment
of Regulatory Assets attributable to stranded generation costs, purchased power
costs, and related expenses for the 1999, and future, Reconciliation Filings.
FG&E's 2001 Reconciliation Filing, submitted on December 2, 2001, recast its
rates from 1998 through 2001 in compliance with the MDTE's final Order on its
1999 filing. On October 15, 2002, the MDTE issued an Order approving a
settlement agreement regarding the Company's 2001 filing. Under the approved
settlement, FG&E agreed to reduce the carrying charge on deferred transition
costs that will be
4
recovered from customers in future years. This change does not affect current
electric rates, but will reduce the total amount of transition costs, including
carrying costs, in future years. The MDTE's October 2002 Order and associated
settlement resolve many of the issues which otherwise might have been contested
in future FG&E Reconciliation Filings.
FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate
adjustments were approved for effect on January 1, 2003, subject to
investigation, resulting in a rate reduction of approximately 4.4% for
residential SOS customers. The reduction is due to a decrease in the SOS fuel
adjustment, which is not subject to the rate cap, and does not affect net
income.
Massachusetts Gas Operations Restructuring - Following a three year state-wide
collaborative process on the unbundling, or separation, of discrete services
offered by natural gas local distribution companies (LDCs), the MDTE approved
regulations and tariffs for FG&E and other LDCs to provide full customer choice
effective November 1, 2000. The MDTE ruled that LDCs would continue to have an
obligation to provide gas supply and delivery services for a five-year
transition period, with a review after three years. This review is expected to
be initiated in late 2003. The MDTE also required mandatory assignment of LDCs'
pipeline capacity to competitive marketers supplying customers during the
transition period. This mandatory capacity assignment protects LDCs from
exposure to certain stranded gas supply costs during the transition period.
New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire
electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive
restructuring proposal with the New Hampshire Public Utilities Commission
(NHPUC). This proposal included the introduction of customer choice consistent
with New Hampshire's electric utility industry restructuring law, the
divestiture of Unitil Power's power supply portfolio, the recovery of stranded
costs, the merger of CECo and E&H into one distribution company and new
distribution rates for the combined company. On October 25, 2002, the NHPUC
approved a multi-party settlement on all major issues in the proceeding,
including stranded cost recovery for purchased power contracts. At December 31,
2002, the Company estimated a range for these divestiture obligations and
recoverable stranded costs and recorded $94.5 million as Power Supply Buyout
Obligations and Regulatory Assets at December 31, 2002.
Under Unitil's restructuring plan, Unitil agreed to divest its existing power
supply portfolio and conduct a solicitation for new power supplies from which to
meet UES' ongoing Transition and Default Service obligations in 2003. On
February 26, 2003, Unitil filed for final NHPUC approval of the Agreement among
Unitil Power, UES and Mirant discussed above under the heading "March 14, 2003
NHPUC Oder," including final tariffs for UES for stranded cost recovery and
Transition and Default Service. On March 14, 2003 the NHPUC approved the
Agreement. The Agreement and Order of the NHPUC provide for stranded cost
recovery in the amount of $108.7 million over a recovery period of eight years.
The NHPUC Order is subject to a 30 day appeal period.
Unitil's restructuring plan is also designed to resolve the pending litigation
on this matter. In June 1997, Unitil and other New Hampshire utilities
intervened as plaintiffs in a suit filed in U.S. District Court by Northeast
Utilities' affiliate Public Service Company of New Hampshire for protection from
the NHPUC's Final Plan to restructure the New Hampshire electric utility
industry. Although the NHPUC found that CECo and E&H were entitled to full
interim stranded cost recovery, the NHPUC also made certain legal rulings, that,
if implemented, could affect UES's long-term ability to recover all of its
stranded costs. The Unitil Settlement, approved in October 2002, otherwise
resolves all of the issues in the federal court action. Upon the expiration of
all periods of appeal with respect to the regulatory approvals for Unitil's New
Hampshire restructuring, UES will implement retail choice and Unitil will
withdraw its intervention in this federal court action, with prejudice. Unitil
expects customer choice to be implemented on May 1, 2003.
Wholesale Power Market Restructuring - Unitil has also been a participant in the
restructuring of the wholesale power market and transmission system in New
England, which is subject to FERC jurisdiction. New wholesale markets structured
pursuant to FERC's Standard Market Design are expected to be implemented in the
New England Power Pool during the first half of 2003 under the general
supervision of an Independent System Operator (ISO) and the regulatory oversight
of the FERC.
Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated
by the Company to increase base rates for Unitil's retail electric operating
subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The
last distribution base rate increase request for FG&E's retail gas operations
occurred in 1998. In 2001, FG&E's electric base rates were investigated by the
MDTE, which resulted in an electric base rate decrease. A majority of the
Company's electric and gas operating revenues are collected under various
periodic rate adjustment mechanisms including fuel, purchased power, energy
efficiency, and restructuring-related cost
5
recovery mechanisms. Industry restructuring will continue to change the methods
of how certain costs are recovered through the Company's regulated rates and
tariffs.
On the gas side, FG&E continues to provide a multi-year refund through its Cost
of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding
that FG&E had over-collected fuel inventory finance charges. At December 31,
2002, the unamortized balance of this refund was $1.3 million. FG&E believes a
refund is not justified or warranted and has appealed the MDTE's ruling to the
Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single
justice of the SJC declined to stay the MDTE's Order based on a finding that
refunds made by FG&E may be recouped if FG&E prevails on the merits of its
claims. The review of the MDTE Order by the SJC is pending.
On October 25, 2002, as part of the electric restructuring settlement for
Unitil's New Hampshire utility operations described above, the Company received
approval from the NHPUC for an increase of approximately $2.0 million in annual
distribution revenues for UES, effective December 1, 2002.
On December 2, 2002, the MDTE issued an Order resulting in distribution rate
increases of $2.0 million for FG&E's electric operations and $3.0 million for
FG&E's gas operations. Increases for rising gas costs were incorporated into the
final gas rates. FG&E's new rates became effective on December 2, 2002.
On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the
MDTE for both electric and gas operations. PBR is a method of setting regulated
distribution rates that provides incentives to control costs while maintaining a
high level of service quality. Under PBR, a company's earnings are tied to
performance targets, and penalties can be imposed for deterioration of service
quality. FG&E's PBR Plans were filed in conjunction with FG&E's distribution
rate filings, consistent with MDTE policy to implement PBR in the context of
base rate cases. The MDTE did not initiate investigations of the filings. On
January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's
PBR plans have no scheduled date of implementation, and conventional cost-based
regulation continues to apply.
In December 2002, FG&E and UES filed requests with their respective state
regulatory commissions for approval of an accounting Order to mitigate certain
accounting requirements related to pension plan assets, which have been
triggered by the substantial decline in the capital markets. These requests were
granted by the respective state regulatory commissions in December 2002. These
approvals allow FG&E and UES to treat the additional minimum pension liability
and Prepaid Pension Costs as Regulatory Assets and avoid the reduction in equity
that would otherwise be required. These regulatory Orders do not pre-approve the
amount of pension expense to be recovered in future rates. Such recovery will be
subject to review and approval in future rate proceedings. Based on these
approvals, Unitil has included the amount of the additional minimum pension
liabilities and Prepaid Pension Costs of $12.0 million in Regulatory Assets on
its balance sheet.
ELECTRIC POWER SUPPLY
FG&E distributes electricity in the north central area of Massachusetts. UES
distributes electricity in the central and seacoast regions of New Hampshire.
FG&E contracts directly for its electric supply with various wholesale
suppliers. UES contracts for all of its needs from its affiliate Unitil Power,
which has acquired a portfolio of power contracts from other wholesale
suppliers. Following retail choice restructuring in 2003, UES will contract
directly with wholesale suppliers to meet the needs of its customers. The
wholesale power markets are conducted under the auspices of the New England
Power Pool (NEPOOL).
FG&E, Unitil Power, and UES are members of NEPOOL. NEPOOL was formed in 1971 to
assure reliable operation of the bulk power system in the most economic manner
for the region. Under the NEPOOL Agreement and the Open Access Transmission
Tariff (OATT), 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 and
the OATT 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 a supportive business environment for the development of a
competitive electric marketplace.
There are ongoing legislative and regulatory initiatives that are primarily
focused on the deregulation of the generation and supply of electricity and the
corresponding development of a competitive market place from which
6
customers could choose their electric energy supplier. As a result, the NEPOOL
Agreement continues to be 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 are traded in
open, competitive markets, with transmission access and pricing subject to a
regional OATT designed to promote competition among power suppliers. On May 1,
1999, ISO-NE began dispatching generating units using a bid-based system and
implemented bid-based markets for reserve products and automatic generation
control. On March 1, 2003, ISO-NE implemented a Standard Market Design (SMD)
that is intended to improve the ability to trade power between New England and
other regions throughout the northeast.
Energy Resources - Since April 1, 1998, each electric utility is required to
carry an allocated share of the NEPOOL capability responsibility under the
NEPOOL Agreement. These capacity requirements are determined each month based on
regional reliability criteria. Unitil Power, the full requirements supplier to
UES, had an annual peak capability responsibility in November 2002 of 309.33 MW
and a corresponding monthly peak demand of 220.02 MW. Beginning December 1,
2000, FG&E no longer had a direct capability responsibility because it's
Standard Offer Service supplier, Constellation Power Source, and its periodic
Default Service supplier are responsible for the capability responsibility under
the respective contracts. Effective December 1, 2000, FG&E began serving Default
Service load through six-month contracts wherein the Default Service supplier
had the load serving obligation, thus at the end of 2000, FG&E had no direct
capability responsibility. Under MDTE regulations, FG&E has continued to procure
Default Service through a bid process every six months.
To meet the needs of UES, Unitil Power 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
as well as purchases in the spot market. For the twelve months ended December
31,2002, Unitil Power's energy needs were provided by the following fuel
sources: nuclear (10%), oil (6%), gas (8%), coal (5%), refuse (4%), and system
(67%).
On March 14, 2003 the New Hampshire Public Utilities Commission (NHPUC) approved
the agreement between Unitil Power, UES and Mirant Americas Energy Marketing,
LP. (Mirant), which was entered into on February 25, 2003, under which Mirant
will purchase the entitlements to Unitil Power's Supply portfolio and provide
Transition and Default Service to the customers of UES. The final amount of
Unitil Power's recoverable stranded costs, calculated on the basis of the
amounts agreed to be paid by the parties under such Agreement for the Unitil
Power power supply portfolio, was determined to be $108.7 million, with a
recovery period of 8 years. As of December 31, 2002, the Company had estimated a
range for these recoverable stranded costs and accordingly recorded on its
balance sheet as of that date $94.5 million as Power Supply Buyout Obligations
and Regulatory Assets. The approval of the Agreement by the NHPUC is subject to
an appeal period of 30 days. The NHPUC Order completes the state approval
process for Unitil's restructuring plan under which UES will implement customer
choice for its customers on May 1, 2003.
Under Unitil's approved restructuring plan, Unitil agreed to divest its existing
power supply portfolio and conduct a solicitation for new power supplies from
which to meet UES' ongoing Transition and Default Service energy obligations. On
February 26, 2003, Unitil filed for final NHPUC approval of the executed
agreements resulting from these divestiture and solicitation processes,
including final tariffs for UES for stranded cost recovery and Transition and
Default Services. The filing proposed a recovery period of eight years for
stranded costs.
On January 25, 2002, the Company's New Hampshire electric utility subsidiaries,
CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with
the New Hampshire Public Utilities Commission (NHPUC). This proposal included
the introduction of customer choice consistent with New Hampshire's electric
utility industry restructuring law, the divestiture of Unitil Power's power
supply portfolio, the recovery of stranded costs, the merger of CECo and E&H
into one distribution company and new distribution rates for the combined
company. On October 25, 2002, the NHPUC approved a multi-party settlement on all
major issues in the proceeding, including stranded cost recovery for purchased
power contracts. At December 31, 2002, the Company estimated these divestiture
obligations and recoverable stranded costs and recorded $94.5 million as Power
Supply Buyout Obligations and Regulatory Assets at December 31, 2002.
7
In 2002, FG&E met its capacity requirements through an all requirements Standard
Offer contract with Constellation Power Source, and several all requirements
Default Service contracts. FG&E's power supply portfolio, including the joint
ownership generation output, was sold to Select Energy, Inc. effective February
1, 2000 as part of the power supply restructuring plan approved by the MDTE. For
the twelve months ended December 31, 2002, FG&E's energy needs were supplied by
system power from the Standard Offer and Default contracts.
Fuel - Oil: Approximately 6% of Unitil Power's electric power in 2002 was
provided by oil-fired units. 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 5% of Unitil Power's 2002 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.
Pursuant to the Nuclear Waste Policy Act of 1982, the participants in Millstone
Nuclear Generating Station Unit No. 3 (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. FG&E's
Millstone 3 ownership interest was sold in March 2001. The sales agreement and a
separate settlement agreement with Northeast Utilities indemnifies FG&E from
continuing liability associated with environmental, decommissioning and waste
disposal associated with its former Millstone 3 ownership.
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 2000 through 2002.
Sources of Gas Supply
(Expressed as percent of total MMBtu of gas purchased)
Natural Gas: 2002 2001 2000
------------------------------------
Domestic firm 73.9% 76.2% 78.6%
Canadian firm 8.4% 8.0% 6.3%
Domestic spot market 16.2% 14.5% 13.2%
------------------------------------
Total natural gas 98.5% 98.7% 98.1%
Supplemental gas 1.5% 1.3% 1.9%
------------------------------------
Total gas purchases 100.0% 100.0% 100.0%
Cost of Gas Sold
2002 2001 2000
--------------------------------
Cost of gas purchased and sold per MMBtu $ 4.49 $ 6.49 $ 5.19
Percent Increase (Decrease) from prior year (30.76%) 24.99% 52.01%
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.
8
ENVIRONMENTAL MATTERS
The Company's past and present operations include activities that are subject to
extensive federal and state environmental regulations.
Sawyer Passway MGP Site - The Company continues to work with environmental
regulatory agencies to identify and assess environmental issues at the former
manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg,
Massachusetts. FG&E proceeded with site remediation work as specified on the
Tier 1B permit issued by the Massachusetts Department of Environmental
Protection (DEP), which allows the Company to work towards temporary remediation
of the site. Work performed in 2002 was associated with the five-year review of
the Temporary Solution submittal (Class C Response Action Outcome) under the
Massachusetts Contingency Plan that was filed for the site in 1997. Completion
of this work has confirmed the Temporary Solution status of the site for an
additional five years. A status of temporary closure requires FG&E to monitor
the site until a feasible permanent remediation alternative can be developed and
completed.
Since 1991, FG&E has recovered the environmental response costs incurred at this
former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement).
The Agreement allows FG&E to amortize and recover from gas customers over
succeeding seven-year periods the environmental response costs incurred each
year. Environmental response costs are defined to include liabilities related to
manufactured gas sites, waste disposal sites or other sites onto which hazardous
material may have migrated as a result of the operation or decommissioning of
Massachusetts gas manufacturing facilities from 1882 through 1978. In addition,
any recovery that FG&E receives from insurance or third parties with respect to
environmental response costs, net of the unrecovered costs associated therewith,
are split equally between FG&E and its gas customers. The total annual charge
for such costs assessed to gas customers cannot exceed five percent of FG&E's
total revenue for firm gas sales during the preceding year. Costs in excess of
five percent will be deferred for recovery in subsequent years.
Former Electric Generating Station - The Company is remediating environmental
conditions at a former electric generating station located at Sawyer Passway,
which FG&E sold to WRW, a general partnership, in 1983. Rockware International
Corporation (Rockware), an affiliate of WRW, acquired rights to the electric
equipment in the building and intended to remove, recondition and sell this
equipment. During 1985, Rockware demolished several exterior walls of the
generating station in order to facilitate removal of certain equipment. The
demolition of the walls and the removal of generating equipment resulted in
damage to asbestos-containing insulation materials inside the building, which
had been intact and encapsulated at the time of the sale of the structure to
WRW.
When Rockware and WRW encountered financial difficulties and failed to respond
adequately to Orders of the environmental regulators to remedy the situation,
FG&E agreed to take steps at that time and obtained DEP approval to temporarily
enclose, secure and stabilize the facility. Based on that approval, between
September and December 1989, contractors retained by FG&E stabilized the
facility and secured the building. This work did not permanently resolve the
asbestos problems caused by Rockware, but was deemed sufficient for the then
foreseeable future.
Due to the continuing deterioration of this former electric generating station
and Rockware's continued lack of performance, FG&E, in concert with the DEP and
the U.S. Environmental Protection Agency (EPA), conducted further testing and
survey work during 2001 to ascertain the environmental status of the building.
Those surveys revealed continued deterioration of the asbestos-containing
insulation materials in the building.
By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially
Responsible Party for planned remedial activities at the site and invited FG&E
to perform or finance such activities. FG&E and the EPA have entered into an
Agreement of Consent, whereby FG&E, without an admission of liability, will
conduct environmental remedial action to abate and remove asbestos-containing
and other hazardous materials. FG&E has awarded contracts for all aspects of the
abatement work, which is presently ongoing. FG&E received significant coverage
from its insurance carrier. The Company believes that these funds will be
sufficient to complete this remediation and that resolution of this matter will
not have a material adverse impact on the Company's financial position.
The Company has recorded the estimated cost of the remediation action in Current
Liabilities and an offsetting asset reflecting insurance proceeds in Current
Assets. At the balance sheet date, net of amounts expended in 2002, the
remaining project cost was $3.7 million.
9
EMPLOYEES
As of December 31, 2002, the Company and its subsidiaries had 316 full-time and
part-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 approximately 100 employees represented by labor unions. In 2000, E&H
reached a new five-year pact with its employees covered by a collective
bargaining agreement, which will expire effective May 31, 2005. In 2000, CECo
reached a new five-year pact with its employees covered by a collective
bargaining agreement, which will expire effective May 31, 2005. In 2000, FG&E
reached a five-year pact with its employees covered by collective bargaining
agreements, which will expire effective May 31, 2005. 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.
10
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of the Company as
of March 1, 2003 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 elected. Officers of the Company also hold
various Director and Officer positions with subsidiary companies.
Name, Age Business Experience
and Position During Past 5 years
- ---------------------------------- ------------------------------------------
Robert G. Schoenberger, 52, Mr. Schoenberger has been Chairman of the
Chairman of the Board of Directors Board and Chief Executive Officer of
and Chief Executive Officer 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.
Michael J. Dalton, 62*, Mr. Dalton has been a Director, President
President and and Chief Operating Officer of the
Chief Operating Officer Company since its incorporation in 1984.
Mark H. Collin, 44, Mr. Collin was appointed Senior Vice
Senior Vice President and Chief President and Chief Financial Officer of
Financial Officer Unitil in February 2003. Mr. Collin has
been Treasurer of Unitil since January
1998. Mr. Collin has been Treasurer of
Unitil's principal subsidiaries and Vice
President of Unitil Service Corp. since
1992.
George R. Gantz, 51 Mr. Gantz has been Senior Vice President
Senior Vice President - Customer of Unitil Service since 1994.
Services and Communications
* Mr. Dalton has submitted his resignation from the Company, effective April 1,
2003.
11
Item 2. Properties
UES maintains Distribution Operations Centers in the city of Concord and the
town of Kensington. These properties are owned by UES in fee. UES's thirty
electric distribution substations, including a 5,000 kVA mobile substation,
constitute 214,270 kVA of capacity for the transformation of electric energy
from the 34.5 kV subtransmission voltage to other primary distribution voltage
levels. The electric substations are, with one exception, located on land owned
by UES in fee. The sole exception is located on land occupied pursuant to a
perpetual easement.
UES has a total of approximately 1,535 pole miles of overhead electric
distribution lines and a total of approximately 194 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 UES without objection by the owners. In the
case of certain distribution lines, UES 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, UES 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 UES (with certain exceptions) and its franchises are
subject to the lien of its Indenture of Mortgage and Deed of Trust under which
the respective series of First Mortgage Bonds of UES 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. FG&E is participating, on a
tenancy-in-common basis with other New England utilities, in the ownership of
the Wyman 4 generating unit. In accordance with Massachusetts Electric
Restructuring Law, and pursuant to the power supply divestiture discussed in
Note 10 of the Financial Statements, FG&E began selling the output from its
electric contracts and generation units on February 1, 2000. As of December 31,
2002, the electric properties of the Company consisted principally of 62 miles
of transmission lines, 480.8 miles of distribution lines, 14 distinct
transmission and distribution substations, and two mobile substations totaling
18.75 MVA. The in-service and spare capacity of these substations totals 561,900
kVA. 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.
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 its 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
12
PART II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters
The Registrant's Common Stock is traded on the American Stock Exchange. As of
December 31, 2002, there were 1,932 Common Shareholders of record.
Common Stock Data
Dividends per Common Share 2002 2001
------------------------------------------------------------------------------
1st Quarter $ 0.345 $ 0.345
2nd Quarter 0.345 0.345
3rd Quarter 0.345 0.345
4th Quarter 0.345 0.345
-------------------------------
Total for Year $ 1.38 $ 1.38
===============================
2002 2001
----------------------------------------------
Price Range of Common Stock High/Ask Low/Bid High/Ask Low/Bid
------------------------------- ----------------------------------------------
1st Quarter 26.80 22.82 27.00 24.90
2nd Quarter 31.40 26.10 27.50 24.75
3rd Quarter 29.22 25.31 25.45 23.00
4th Quarter 26.99 24.80 25.15 22.95
Information regarding Securities Authorized for Issuance Under Equity
Compensation Plans is set forth on pages 15 through 16 of the 2002 Proxy
Statement as filed with the Securities and Exchange Commission on March 12,
2003.
13
Item 6. Selected Financial Data
2002 2001 2000 1999 1998
------------------------------------------------------------
Consolidated Statements of Earnings (000's)
Operating Income $13,248 $14,394 $14,280 $15,408 $15,306
(Gain) Loss on Non-Utility Investments, net of tax (82) 2,400 ---- ---- ----
Other Non-operating Expense 185 170 244 51 156
------------------------------------------------------------
Income Before Interest Expense and Extraordinary Item 13,145 11,824 14,036 15,357 15,150
Interest Expense, net 7,057 6,797 6,820 6,919 6,901
------------------------------------------------------------
Income before Extraordinary Item 6,088 5,027 7,216 8,438 8,249
Extraordinary Item, net of tax --- 3,937 ---- ---- ----
------------------------------------------------------------
Net Income 6,088 1,090 7,216 8,438 8,249
Dividends on Preferred Stock 253 257 263 268 274
------------------------------------------------------------
Earnings Applicable to Common Shareholders 5,835 $833 $6,953 $8,170 $7,975
============================================================
Balance Sheet Data (000's)
Utility Plant (Original Cost) $271,179 $255,498 $238,023 $219,838 $209,462
Total Assets $480,783 $376,762 $382,967 $363,527 $376,835
Capitalization:
Common Stock Equity $74,350 $74,746 $79,935 $78,675 $75,351
Preferred Stock 3,322 3,609 3,690 3,757 3,843
Long-Term Debt 104,226 107,470 81,695 86,157 75,222
------------------------------------------------------------
Total Capitalization $181,898 $185,825 $165,320 $168,589 $154,416
============================================================
Short-term Debt $35,990 $13,800 $32,500 $10,500 $20,000
Capital Structure Ratios:
Common Stock Equity 34% 37% 40% 44% 43%
Preferred Stock 2% 2% 2% 2% 2%
Long-Term Debt 48% 54% 41% 48% 43%
Short-Term Debt 16% 7% 17% 6% 12%
Earnings Per-Share Data
Basic Earnings Per Average Share $1.23 $0.18 $1.47 $1.74 $1.77
Diluted Earnings Per Average Share $1.23 $0.18 $1.47 $1.74 $1.72
Common Stock Data
Shares of Common Stock (Year-End) (000's) 4,744 4,744 4,735 4,712 4,575
Shares of Common Stock (Average) (000's) 4,744 4,744 4,723 4,682 4,506
Dividends Paid Per Share (Year-End) $1.38 $1.38 $1.38 $1.38 $1.36
Book Value Per Share (Year-End) $15.67 $15.76 $16.88 $16.70 $16.47
Electric and Gas Statistics
Electric Distribution Sales (000's of kWh) 1,659,136 1,596,390 1,587,536 1,608,824 1,540,968
Electric Customers (Year-End) 96,985 95,116 94,050 92,505 91,729
Firm Gas Distribution Sales (000's of Therms) 22,480 23,067 23,992 22,136 22,027
Gas Customers (Year-End) 14,911 14,879 14,796 14,928 14,915
14
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
Unitil Corporation (Unitil or the Company) is nearing the completion of an
unprecedented restructuring process brought about by the deregulation of the
natural gas and electric industries in New Hampshire and Massachusetts. As a
result, by the middle of 2003, the Company expects to have divested its entire
generation and power supply portfolio, thus transforming the Company's
vertically integrated utility operations into principally a pipes-and-wires
business providing gas and electric delivery services. In the process, Unitil's
distribution subsidiaries secured regulatory approval for the recovery of
approximately a quarter billion dollars for all power supply related stranded
costs, implemented comprehensive customer and financial information systems to
accommodate the transition to competitive energy markets, and adjusted all
utility delivery rates to reflect the overall cost of service as a restructured
gas and electric energy delivery company.
During this restructuring process, management's focus has been to ensure fair
and reasonable treatment of the investments made to meet the needs of Unitil's
customers, while at the same time making sure that the Company is properly
structured from both a financial and an operational perspective to continue to
provide high-quality and competitively priced electric and gas delivery
services.
Highlights of Year 2002:
|_| On January 25, 2002, the Company's New Hampshire electric utility
subsidiaries Concord Electric Company (CECo), Exeter & Hampton Electric
Company (E&H) and Unitil Power Corp. (Unitil Power) filed a comprehensive
electric restructuring proposal with the New Hampshire Public Utilities
Commission (NHPUC). This proposal included the introduction of customer
choice, the divestiture of Unitil Power's power supply portfolio, the
recovery of stranded costs, the combination of CECo and E&H into a single
electric distribution utility, and new distribution rates for the combined
entity. On October 25, 2002, the NHPUC approved a multi-party settlement on
all the major issues in the proceeding.
A key result of the New Hampshire restructuring settlement was the
formation of Unitil Energy Systems, Inc. (UES) on December 2, 2002. UES is
the New Hampshire distribution electric utility formed by the combination
of CECo and E&H, and is a wholly-owned subsidiary of Unitil.
UES received an increase of approximately $2.0 million in annual
distribution revenue to cover current operating costs, depreciation and
amortization, and investments in utility plant. These rates became
effective December 1, 2002.
|_| On May 17, 2002, the Company's Massachusetts distribution utility
subsidiary, Fitchburg Gas and Electric Light Company (FG&E), filed revised
rates with the Massachusetts Department of Telecommunications and Energy
(MDTE) designed to increase annual base distribution revenues for both
electric and gas operations to cover increases in operating expenses,
depreciation and the cost of invested capital. On December 2, 2002, the
MDTE authorized base rate changes to increase annual distribution revenues
by $2.0 million for electric operations and $3.0 million for gas
operations. In addition, increases for rising gas supply costs were
incorporated into the final gas rates, effective December 2, 2002.
|_| On October 15, 2002, the MDTE issued an Order approving a settlement
agreement that resolved and secured the recovery of FG&E's
restructuring-related stranded costs. The settlement resolves issues
concerning FG&E's compliance with the Massachusetts Electric Restructuring
Act of 1997 and related MDTE Orders. Under the settlement, FG&E agreed to
reduce the carrying charge on deferred transition costs and to pass along
the benefit of lower interest costs to customers.
15
|_| Unitil eliminated a major environmental liability associated with a former
electric generating station in Fitchburg, Massachusetts. Under a consent
Order voluntarily initiated by Unitil with the U.S. Environmental
Protection Agency (EPA), a remedial project to clean up and remove asbestos
and related hazardous materials from a building formerly owned by the
Company is underway. Site remediation is expected to be completed at the
end of 2003. Funds from an insurance settlement related to this issue are
believed to be sufficient to complete the remediation work, such that this
matter will not have a material effect on the Company's financial position.
|_| In December 2002, FG&E and UES received regulatory approval to account for
certain pension obligations as regulatory assets, avoiding a reduction in
equity that would have been triggered by the substantial decline in the
capital markets. These regulatory Orders do not pre-approve the amount of
pension expense to be recovered in future rates. Such recovery will be
subject to review and approval in future rate proceedings.
|_| Unitil's non-regulated business, Usource, nearly doubled its revenues in
2002, as its electric and gas energy brokerage business continues to expand
into new regions where large commercial and industrial customers are able
to choose their energy suppliers.
|_| In December 2002, Unitil committed to a formal management transition and
reorganization plan to streamline its management structure and to improve
efficiency to meet ongoing business requirements. The Company estimates
this reorganization will result in an annual cash savings of approximately
$2.3 million in operating expenses and construction project overheads in
future periods.
Earnings per Share 2002 2001 2000
--------------------------------------------------------------------------
Earnings per Share $ 1.23 $ 0.18 $ 1.47
Non-recurring Items, net of tax:
Restructuring Charge (0.20) --- ---
Investment Write-down --- (0.50) ---
Extraordinary Item --- (0.83) ---
----------------------------------
Earnings Before Non-recurring Items $ 1.43 $ 1.51 $ 1.47
==================================
Earnings in 2002 were $5.8 million, or $1.23 per common share on a diluted
basis, compared to $0.8 million, or $0.18 in 2001. Results for both years
included significant non-recurring charges that affected earnings.
In the fourth quarter of 2002, Unitil recorded a non-recurring Restructuring
Charge of $1.6 million, or ($0.20) per share, associated with the reorganization
and reduction of 19 management and administrative positions. The Company
estimates that the result of this management restructuring process will be an
annual cash savings in future periods of approximately $2.3 million in operating
expenses and construction project overheads.
In 2001, as a result of industry restructuring-related regulatory Orders, Unitil
recognized an Extraordinary Item to reduce Regulatory Assets by $3.9 million
after tax, or ($0.83) per share. Unitil also recorded an Investment Write-down
of $2.4 million after-tax, or ($0.50) per share, to recognize a decrease in the
fair value of a non-utility energy technology investment. Unitil subsequently
sold its remaining interest in this non-utility investment in 2002 and realized
$1.5 million in cash. As a result of this sale, the Company will also realize
approximately $1.3 million in current tax refunds from the carryback of this
capital loss. This sale transaction did not have a material impact on Unitil's
2002 operating results.
Excluding the effect of these 2002 and 2001 non-recurring items, comparable
earnings per share were $1.43 in 2002 and $1.51 in 2001. This decrease in
earnings was mainly the result of increases in certain operating expenses,
including higher pension and health care costs, higher depreciation expense
associated with increased investments in Utility Plant, and accelerated
amortization of certain Regulatory Assets. These impacts were partially offset
by higher distribution base revenues.
16
A year-to-year comparison of Unitil's financial condition, changes in financial
condition and results of operations for the three-year period 2000 through 2002
follows.
RESULTS OF OPERATIONS
Operating Revenue -- Electric
Kilowatt-hour Sales - Unitil's total electric kilowatt-hour (kWh) sales
increased by 3.9% in 2002 compared to 2001. This increase reflects growth in
sales to residential and commercial and industrial customer classes driven by
hotter-than-normal summer weather.
Sales to residential customers increased by 3.9% in 2002 compared to 2001. The
increase in energy sales reflects an increase in the number of residential
customers as well as higher usage per customer, due to weather. Commercial and
industrial sales of electricity also increased by 3.9% in 2002 compared to 2001.
In addition, warmer summer weather in 2002 as compared to 2001 contributed to
the increase in energy sales.
Unitil's total electric kWh sales increased by 0.6% in 2001 compared to 2000.
This increase reflected growth in sales to residential and commercial customer
classes, offset by reductions in kWh sales to industrial customers, due to the
impact of the general economic downturn experienced in 2001.
The following table details total kWh sales for the last three years by major
customer class:
kWh Sales (000's)
------------------------------------------------------------------
2002 2001 2000
---------------------------------------
Residential 619,756 596,378 576,524
Commercial/Industrial 1,039,380 1,000,012 1,011,012
---------------------------------------
Total 1,659,136 1,596,390 1,587,536
=======================================
Electric Operating Revenue - Electric Operating Revenue decreased by $16.5
million, or 9.0%, in 2002 compared to 2001. This decrease in revenue is the
result of a reduction in wholesale commodity fuel prices overall and lower
distribution rates in the Massachusetts service territory, offset by the
increase in kWh sales. The energy component of Electric Operating Revenue
represents the recovery of energy supply costs, which are collected from
customers through periodic cost recovery adjustment mechanisms. Changes in
energy supply revenues do not affect net income, as they normally mirror
corresponding changes in energy supply costs.
In 2001, Electric Operating Revenue increased by $23.8 million, or 14.8%, as
compared to 2000. This increase in revenue was the result of increased wholesale
commodity fuel prices.
The following table details total Electric Operating Revenue for the last three
years by major customer class:
Electric Operating Revenue (000's)
------------------------------------------------------------------
2002 2001 2000
---------------------------------------
Residential $ 65,746 $ 71,960 $ 61,506
Commercial/Industrial 101,571 111,820 98,517
---------------------------------------
Total $ 167,317 $ 183,780 $ 160,023
=======================================
Operating Revenues - Gas
Therm Sales - Total firm therm sales decreased 2.5% in 2002 compared to 2001,
due to a warmer winter in early 2002 and the impact of the general economic
downturn, partially offset by colder weather in the latter stages of 2002
compared to the prior year.
17
In 2001, total firm therm sales decreased 3.9% compared to 2000, primarily due
to a warmer winter compared to the prior year and the impact of the general
economic downturn.
The following table details total firm therm sales for the last three years, by
major customer class:
Firm Therm Sales (000's)
------------------------------------------------------------------
2002 2001 2000
---------------------------------------
Residential 11,022 11,175 11,730
Commercial/Industrial 11,458 11,892 12,262
---------------------------------------
Total 22,480 23,067 23,992
=======================================
Gas Operating Revenue - Gas Operating Revenue, which represents approximately
11% of Unitil's total Operating Revenues, decreased by $2.5 million, or 11.1%,
in 2002 compared to 2001. This was attributable to lower unit sales and
decreased wholesale gas commodity prices. The energy commodity component of Gas
Operating Revenue represents the recovery of energy commodity supply costs,
which are collected from customers through periodic cost recovery adjustment
mechanisms. Changes in energy commodity supply revenues do not affect net
income, as they normally mirror corresponding changes in energy commodity supply
costs.
In 2001, total Gas Operating Revenue was flat, as compared to 2000. This was
attributable to lower unit sales, offset by higher gas supply prices.
The following table details total Gas Operating Revenue for the last three years
by major customer class:
Gas Operating Revenue (000's)
------------------------------------------------------------------
2002 2001 2000
---------------------------------------
Residential $ 10,871 $ 12,779 $ 11,540
Commercial/Industrial 8,007 9,505 8,745
---------------------------------------
Total Firm Gas Revenue 18,878 22,284 20,285
Interruptible Gas Revenue 1,405 544 2,471
---------------------------------------
Total $ 20,283 $ 22,828 $ 22,756
=======================================
Operating Revenue - Other
Total Other Revenue increased $0.4 million, or 89.9%, compared to 2001. This was
the result of growth in revenues from the Company's non-regulated energy
brokering business, Usource.
In 2001, total Other Revenue increased $0.3 million, compared to 2000. This was
also the result of increased Usource brokerage fees.
The following table details total Other Revenue for the last three years:
Other Revenue (000's)
------------------------------------------------------------------
2002 2001 2000
---------------------------------------
Usource $ 756 $ 384 $ 131
Other 30 30 31
---------------------------------------
Total $ 786 $ 414 $ 162
=======================================
18
Operating Expenses
Fuel and Purchased Power - Fuel and Purchased Power expense is the cost of
purchased power, including fuel used in electric generation and the cost of
wholesale energy and capacity purchased to meet Unitil's electric energy
requirements. Fuel and Purchased Power expenses, recoverable from customers
through periodic cost recovery adjustment mechanisms, decreased $18.3 million,
or 13.8%, in 2002 compared to 2001. The change was driven by a decrease in
wholesale power prices, compared to the volatile markets and rising energy
prices that the nation experienced in early 2001.
In 2001, Fuel and Purchased Power expenses increased $22.7 million, or 20.6%,
compared to 2000. This change was mainly due to increased wholesale power
prices.
Gas Purchased for Resale - 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. Gas Purchased for Resale decreased by $2.7 million, or 19.4% in 2002
compared to 2001, reflecting a decrease in wholesale gas prices.
In 2001, Gas Purchased for Resale increased by $0.3 million, or 2.5%, compared
to 2000, due to a decrease in therms purchased, offset by higher wholesale gas
prices in early 2001.
Operation and Maintenance (O&M) - O&M expense includes electric and gas utility
operating costs, and the operating cost of the Company's non-regulated business
activities. Total O&M expense increased $0.7 million, or 2.7%, in 2002 compared
to 2001, primarily due to higher employee and retiree health and pension costs.
In 2001, total O&M expense increased $0.5 million, or 1.9%, compared to 2000,
mainly due to higher utility system maintenance costs.
Depreciation, Amortization and Taxes
Depreciation and Amortization - Depreciation and Amortization expense increased
$2.1 million, or 16.8%, in 2002 compared to 2001, due to a higher level of
Utility Plant investments and the accelerated amortization of
restructuring-related Regulatory Assets.
In 2001, Depreciation and Amortization expense increased $0.8 million, or 6.7%,
compared to 2000, due to a higher level of Utility Plant investments.
Federal and State Income Taxes - Federal and State Income Taxes decreased $0.9
million, or 27.2%, in 2002 compared to 2001, due to lower pre-tax operating
income in 2002 and the amortization in 2002 of deferred tax liabilities related
to the accelerated write-off of Regulatory Assets.
In 2001, Federal and State Income Taxes remained level compared to 2000.
Local Property and Other Taxes -Local Property and Other Taxes increased $0.1
million, or 1.4%, in 2002 compared to 2001. This increase was related to a
higher level of Utility Plant and higher tax rates, partially offset by the
repeal of the State of New Hampshire Utility Franchise Tax.
In 2001, Local Property and Other Taxes decreased $0.3 million, or 6.1%,
compared to 2000. This decrease was related to the repeal of the State of New
Hampshire Utility Franchise Tax, partially offset by higher property taxes.
Interest Expense, net
Interest expense is presented in the financial statements net of interest
income. In 2002, Interest Expense, net, increased primarily due to the
refinancing of lower cost short-term debt with higher cost long-term debt and
additional borrowings to support the Company's capital requirements. Total
interest expense was $9.3 million, $9.1 million and $8.6 million in 2002, 2001
and 2000, respectively, due to higher debt outstanding in those years. Interest
income was $2.3 million, $2.3 million and $1.8 million in 2002, 2001 and 2000,
respectively, reflecting higher interest earned on recoverable deferred asset
balances related to industry restructuring.
19
Non-recurring Items
2002 Restructuring Charge - In the fourth quarter of 2002, the Company
recognized a pre-tax Restructuring Charge of $1.6 million. The after-tax effect
of the Restructuring Charge was a reduction of $0.20 in Earnings Per Common
Share, assuming full dilution.
In December 2002, the Company undertook a strategic review of its business
operations and committed to a formal transition and reorganization plan (the
Reorganization Plan) to streamline its management structure, in order to improve
operating efficiency and to align the organization to meet ongoing business
requirements. The Reorganization Plan resulted in the elimination of 19
management and administrative positions. As a result of the elimination of these
positions, and consistent with existing Company policy, certain benefits are
extended to the employees whose positions were eliminated. On January 8, 2003,
the Company implemented the remainder of the Reorganization Plan. The Company
estimates that the result of this management restructuring process will be an
annual cash savings of approximately $2.3 million in operating expenses and
construction project overheads.
The $1.6 million pre-tax Restructuring Charge established a liability at
December 31, 2002, to cover the disbursement of severance and employee benefits
and related costs committed to under the Reorganization Plan, substantially all
of which will be paid in fiscal 2003. At December 31, 2002, the Restructuring
Charge of $1.6 million is included in Other Current Liabilities.
2001 Investment Write-down, net of tax - Beginning in 1998, Unitil invested $5.5
million in Enermetrix, Inc. (Enermetrix), an energy technology start-up
enterprise. In accordance with Statement of Financial Accounting Standards
(SFAS) No. 115 "Accounting for Certain Investments in Debt and Equity
Securities," the Company recorded a non-cash charge of $3.7 million, or $2.4
million, net of tax, in the fourth quarter of 2001 to recognize the decrease in
fair value of its non-utility investment in Enermetrix.
On April 11, 2002, the Company sold its equity ownership in Enermetrix for $1.5
million in cash and improved commercial terms for use of the Enermetrix Software
Network. As a result of the sale, in 2002, the Company recognized the benefit of
approximately $1.3 million of this capital loss as a carryback against capital
gains in its 2002 tax return.
2001 Extraordinary Item, net of tax - In November 1997, the Massachusetts
Legislature enacted the Massachusetts Electric Restructuring Act of 1997 (the
Restructuring Act). The Restructuring Act required all electric utilities to
file a restructuring plan with the MDTE by December 31, 1997. Among other
things, the Restructuring Act required all Massachusetts electric utilities to
sell all of their electric generation assets and to restructure their utility
operations to provide direct retail access to their customers by all qualified
generation suppliers.
The MDTE conditionally approved FG&E's Restructuring Plan (the Plan) in February
1998, and started an investigation and evidentiary hearings into FG&E's proposed
recovery of Regulatory Assets related to stranded generation asset costs and
expenses related to the formulation and implementation of its Plan. In January
1999, the MDTE approved FG&E's Plan, which included provisions for the recovery
of stranded costs through a transition charge in FG&E's electric rates. In
September 1999, FG&E filed its first annual reconciliation of stranded
generation asset costs and expenses and associated transition charge revenues
and the MDTE initiated a lengthy investigation and hearing process.
On October 18 and 19, 2001, the MDTE issued a series of regulatory Orders in
several pending cases involving FG&E, including a final Order on FG&E's initial
reconciliation filing. Those Orders included the review and disposition of
issues related to FG&E's recovery of transition costs due to the restructuring
of the electric industry in Massachusetts, as well as certain costs associated
with gas industry restructuring and preparation and litigation of performance
based rate proceedings initiated by the MDTE. The Orders determined the final
treatment of Regulatory Assets that FG&E had sought to recover from its
Massachusetts electric customers over a multi-year transition period that began
in 1998.
As a result of the industry restructuring-related Orders, FG&E recorded a
non-cash adjustment to Regulatory Assets of $5.3 million, which resulted in the
recognition of an extraordinary charge of $3.9 million, net of taxes. The
Company recognized the extraordinary charge of $0.83 per share, as of September
30, 2001.
As a result of all of these Orders, the Company has been allowed recovery of its
Massachusetts industry restructuring transition costs, estimated at $150 million
after reconciliation, including the above-market or
20
stranded generation and power supply related costs via a non-bypassable uniform
transition charge. FG&E has been, and will continue to be, subject to annual
MDTE investigation and review in order to reconcile the costs and revenues
associated with the collection of transition charges from its customers over the
next eight to ten years.
Capital Requirements and Liquidity
Unitil requires capital to fund the addition of property, plant and equipment to
improve, protect, maintain and expand its electric and gas distribution systems
and for working capital and other timing differences related to the collection
of revenues in rates.
The capital necessary to meet these requirements is derived primarily from
internally-generated funds, which consist of cash flows from operating
activities, excluding payments of dividends. The Company supplements internally
generated funds, as needed, primarily through bank borrowings under unsecured
short-term bank lines. As of December 31, 2002, the Company had unsecured bank
lines for short-term debt in the aggregate amount of $38 million with three
banks. The amount of short-term borrowings that may be incurred by Unitil and
its subsidiaries is subject to periodic approval either by the Securities and
Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935
(1935 Act) or by state regulators. In 2001, the Company received SEC
authorization to allow Unitil to incur total short-term borrowings up to a
maximum of $45 million.
The Company periodically repays its short-term debt borrowings through the
issuance of permanent long-term debt financing. The Company expects to continue
to be able to satisfy its external financing needs by issuing additional
short-term and long-term debt. The continued availability of these methods of
financing will be dependent on many factors, including security market
conditions, economic conditions, regulatory approvals and the level of the
Company's income and cash flow.
In addition to the significant contractual obligations listed in the table
below, the Company also provides limited guarantees on certain energy contracts
entered into by its regulated subsidiary companies. The Company's policy is to
limit these guarantees to two years or less. As of December 31, 2002, there are
$1.8 million of guarantees outstanding and these guarantees extend through
October 15, 2004.
Significant Contractual Obligations (000's) Total 2003 2004- 2006- 2008 &
as of December 31, 2002 2005 2007 Beyond
- ---------------------------------------------------------------------------------------------------------
Long-term Debt $ 107,469 $ 3,244 $ 3,551 $ 646 $ 100,028
Capital Lease 4,534 1,131 1,464 584 1,355
Power Supply Buyout - MA 81,526 7,276 14,758 15,202 44,290
Purchased Power Contract 99,246 12,619 30,871 26,277 29,479
Gas Supply Contract 6,653 2,123 2,284 2,002 244
----------------------------------------------------------
Total Contractual Cash Obligations $ 299,428 $ 26,393 $ 52,928 $ 44,711 $ 175,396
==========================================================
Cash Flows from Operating Activities - Cash Flows from Operating Activities
decreased by $13.6 million in 2002, compared to 2001, mainly due to changes in
Accrued Revenues and Accounts Receivable and Accounts Payable related to energy
costs. There is an inherent ratemaking lag between the period when energy costs
increase and the period when the Company collects those higher energy costs from
customers. This timing difference is recorded as Accrued Revenue. During the
collection lag period, as occurred in 2002, the Company's cash flow is
negatively impacted and additional working capital-related short-term borrowings
are necessary. The balance of the decrease in 2002 was due to higher working
capital needs, principally resulting from year-end timing differences on energy
supply contract payments.
In 2001, Cash Flows from Operating Activities increased by $14.3 million
compared to 2000, mainly due to decreased Accrued Revenues and Accounts
Receivable related to energy costs. During 2001, the Company collected revenue
from rate reconciling mechanisms for higher energy costs incurred in 2000, and
used this cash, in part, to pay down short-term debt borrowings.
21
Operating Activities (000's)
---------------------------------------------------------------
2002 2001 2000
------------------------------------
$ 9,568 $ 23,178 $ 8,864
====================================
Cash Flows from Investing Activities - Cash Used in Investing Activities
decreased $0.3 million in 2002, compared to the prior year, primarily reflecting
a $0.9 million increase in capital expenditures on distribution system additions
and improvements, offset by the receipt of $1.5 million of proceeds from the
sale of the Company's ownership interest in its non-utility investment. In
addition, in 2001, Unitil received $0.3 million in proceeds from the sale of its
interest in Millstone Nuclear Generating Station Unit No. 3 (Millstone 3).
Cash Flows Used in Investing Activities decreased approximately $2.7 million in
2001, primarily reflecting a $1.2 million reduction in capital expenditures on
distribution system additions and improvements, the receipt of $0.3 million of
proceeds from the sale of the Company's ownership interest in Millstone 3, and
the reduction of unregulated investment activities.
Capital expenditures are projected to increase in 2003 to approximately $21.8
million, primarily reflecting increased expenditures for utility distribution
system improvements.
Investing Activities (000's)
---------------------------------------------------------------
2002 2001 2000
------------------------------------
$ (19,290) $ (19,548) $ (22,249)
====================================
Cash Flows from Financing Activities - Cash Flows from Financing Activities
increased by $11.4 million in 2002 compared to 2001. This increase primarily
reflects increased short-term borrowings used to fund a significant portion of
the Company's additions to gas and electric plant and equipment, as well as
increased working capital requirements associated with recoverable deferred
charges relating to industry restructuring.
Cash Flows from Financing Activities decreased by $14.2 million in 2001 compared
to 2000. This decrease primarily reflects repayment of short- and long-term
borrowings, offset by proceeds received from the issuance of long-term debt.
During 2001, three of the Company's utility subsidiaries issued long-term debt
totaling $29.0 million. The proceeds were used to reduce short-term debt
aggregating $18.7 million and to provide long-term funding for a portion of its
additions to gas and electric distribution plant and equipment.
As a result of rising and volatile wholesale gas and electric energy prices in
2000 and early 2001, the Company filed and obtained authorization from the SEC
under the 1935 Act to increase its maximum short-term borrowing level to $45
million. The Company also negotiated with its banks to increase its lines of
credit to meet its borrowing obligations. The Company periodically files rate
adjustments to its reconciling cost recovery mechanisms to reflect changes in
wholesale energy prices.
During 2001 the Company raised $0.3 million of additional common equity capital
through the issuance of 11,279 shares of Common Stock in connection with the
Dividend Reinvestment and Stock Purchase Plan (DRP). During 2001, the Company
moved to open-market purchases to meet its share issuance obligations under the
DRP. As a result, the Company did not issue new original shares of Common Stock
in connection with the DRP during 2002, and does not anticipate doing so in
2003. In conjunction with the SEC Emergency Orders of September 14 and 21, 2001,
which suspended the applicability of certain of the conditions contained in its
Rule 10b-18, the Company implemented an interim Common Stock repurchase program.
Under this program, in 2001, the Company repurchased, canceled and retired 2,500
shares of its outstanding Common Stock at a total cost of $58,500. The SEC has
since lifted its suspension of the aforementioned conditions and accordingly,
the Company's interim Common Stock repurchase program is no longer in effect.
Unitil's annual Common Stock dividend in 2002 was $1.38 per share. This annual
dividend resulted in a payout ratio of 97% for the year, before the
non-recurring Restructuring Charge. Excluding the loss from Non-regulated
Operations, the payout ratio was 88% based on Utility Operations, before the
Restructuring Charge. At its January 2003 meeting, the Unitil Board of Directors
declared a regular quarterly dividend on the Company's Common Stock of $0.345
per share. This quarterly dividend reflects the current annual dividend rate of
$1.38 per share.
22
Financing Activities (000's)
-------------------------------------------------------------------
2002 2001 2000
----------------------------------------
$ 10,806 $ (614) $ 13,598
========================================
Interest Rate Risk
As discussed above, the Company meets it external financing needs by issuing
short-term and long-term debt. The majority of the Company's debt outstanding
represents long-term notes bearing fixed rates of interest. Changes in market
interest rates do not affect interest expense resulting from these outstanding
long-term debt securities. However, the Company periodically repays its
short-term debt borrowings through the issuance of new long-term debt
securities. Changes in market interest rates may affect the interest rate and
corresponding interest expense on any new long-term debt securities issued by
the Company. In addition, the Company's short-term debt borrowings bear a
variable rate of interest. As a result, changes in short-term interest rates
will increase or decrease the Company's interest expense in future periods. For
example, if the Company had an average amount of short-term debt outstanding of
$25 million for the period of one year, a change in interest rates of 1% would
result in a change in annual interest expense of approximately $250,000. The
average interest rate on the Company's short-term borrowings was 2.18% and 4.78%
during 2002 and 2001, respectively.
Market Risk
Although Until'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 purchased power and
gas costs in rates. Consequently, there is limited commodity price risk after
consideration of the related rate-making.
Regulatory Matters
The Unitil Companies are regulated by various federal and state agencies,
including the SEC, the Federal Energy Regulatory Commission (FERC), and state
regulatory authorities with jurisdiction over public utilities, including the
NHPUC and the MDTE. In recent years, there has been significant legislative and
regulatory activity to restructure the utility industry in order to introduce
greater competition in the supply and sale of electricity and gas, while
continuing to regulate the distribution operations of Unitil's utility operating
subsidiaries. Unitil implemented the restructuring of its electric operations in
Massachusetts in 1998 and is implementing a restructuring settlement for its New
Hampshire electric operations that is expected to be on May 1, 2003.
Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E
implemented its Restructuring Plan under the Massachusetts Restructuring Act.
FG&E completed the divestiture of its entire regulated power supply business in
2000 in accordance with the Restructuring Plan. All FG&E distribution customers
must pay a transition charge that provides for the recovery of costs associated
with FG&E's power portfolio which were stranded as a result of the divestiture
of those assets. The plant and Regulatory Asset balances that will be recovered
through the transition charge have been approved by the MDTE as part of FG&E's
annual Reconciliation Filings. The Restructuring Act also requires FG&E to
obtain power for retail customers who choose not to buy energy from a
competitive supplier through either Standard Offer Service (SOS) or Default
Service. FG&E must provide SOS through February 2005 at rate levels which
guarantee rate reductions required by the Restructuring Act. New distribution
customers and customers no longer eligible for SOS are eligible to receive
Default Service at prices set periodically based on market solicitations as
approved by regulators. As of December 31, 2002, competitive suppliers were
serving approximately 20% of FG&E's load, mainly for large industrial customers.
As a result of the restructuring and divestiture of FG&E's entire generation and
purchased power portfolio, FG&E has accelerated the amortization of its stranded
electric generation assets and its abandoned investment in Seabrook Station, a
nuclear generating unit. FG&E earns an authorized rate of return on the
unamortized balance of these Regulatory Assets. In addition, as a result of the
rate reduction and rate cap requirements of the Restructuring Act, FG&E has been
authorized to defer the recovery of a portion of its transition costs and SOS
costs. These unrecovered amounts are also recorded as Regulatory Assets and earn
authorized carrying charges until their subsequent recovery in future periods.
In 2002, Unitil's earnings derived from these generation-related
23
Regulatory Assets, including carrying charges earned on deferred transition
costs and SOS costs, represented approximately 10% of net income. The value of
FG&E's Regulatory Assets is approximately $128 million at December 31, 2002, and
is expected to be amortized and recovered over the next three to nine years.
Earnings from this segment of FG&E's utility business will continue to decline
and ultimately cease.
FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002.
Rate adjustments were approved for effect during the subsequent year, subject to
further investigation. In October 2001, the MDTE issued a final Order on FG&E's
1999 Reconciliation Filing which determined the final treatment of Regulatory
Assets attributable to stranded generation costs, purchased power costs, and
related expenses for the 1999, and future, Reconciliation Filings. FG&E's 2001
Reconciliation Filing, submitted on December 2, 2001, recast its rates from 1998
through 2001 in compliance with the MDTE's final Order on its 1999 filing. On
October 15, 2002, the MDTE issued an Order approving a settlement agreement
regarding the Company's 2001 filing. Under the approved settlement, FG&E agreed
to reduce the carrying charge on deferred transition costs that will be
recovered from customers in future years. This change does not affect current
electric rates, but will reduce the total amount of transition costs, including
carrying costs, in future years. The MDTE's October 2002 Order and associated
settlement resolve many of the issues which otherwise might have been contested
in FG&E's future Reconciliation Filings.
FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate
adjustments were approved for effect on January 1, 2003, subject to
investigation, resulting in a rate reduction of approximately 4.4% for
residential SOS customers. The reduction is due to a decrease in the SOS fuel
adjustment, which is not subject to the rate cap, and does not affect net
income.
Massachusetts Gas Operations Restructuring - Following a three year state-wide
collaborative process on the unbundling, or separation, of discrete services
offered by natural gas local distribution companies (LDCs), the MDTE approved
regulations and tariffs for FG&E and other LDCs to provide full customer choice
effective November 1, 2000. The MDTE ruled that LDCs would continue to have an
obligation to provide gas supply and delivery services for a five-year
transition period, with a review after three years. This review is expected to
be initiated in late 2003. The MDTE also required mandatory assignment of LDCs'
pipeline capacity to competitive marketers supplying customers during the
transition period. This mandatory capacity assignment protects LDCs from
exposure to certain stranded gas supply costs during the transition period.
New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire
electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive
restructuring proposal with the NHPUC. This proposal included the introduction
of customer choice consistent with New Hampshire's electric utility industry
restructuring law, the divestiture of Unitil Power's power supply portfolio, the
recovery of stranded costs, the merger of CECo and E&H into one distribution
company and new distribution rates for the combined company. On October 25,
2002, the NHPUC approved a multi-party settlement on all major issues in the
proceeding, including stranded cost recovery for purchased power contracts. The
Company estimates that these recoverable stranded costs are approximately $94.5
million and these were recorded as Power Supply Buyout Obligations and
Regulatory Assets at December 31, 2002.
Under Unitil's approved restructuring plan, Unitil agreed to divest its existing
power supply portfolio and conduct a solicitation for new power supplies from
which to meet its ongoing Transition and Default Service energy obligations. On
February 26, 2003, Unitil filed for final NHPUC approval of the executed
agreements resulting from these divestiture and solicitation processes,
including final tariffs for stranded cost recovery and Transition and Default
Services. The filing proposed a recovery period of approximately eight years for
stranded costs. The implementation of customer choice for UES customers is
targeted for May 1, 2003.
Unitil's restructuring plan is also designed to resolve the pending litigation
on this matter. In June 1997, Unitil and other New Hampshire utilities
intervened as plaintiffs in a suit filed in U.S. District Court by Northeast
Utilities' affiliate Public Service Company of New Hampshire for protection from
the NHPUC's Final Plan to restructure the New Hampshire electric utility
industry. Although the NHPUC found that CECo and E&H were entitled to full
interim stranded cost recovery, the NHPUC also made certain legal rulings, that,
if implemented, could affect UES's long-term ability to recover all of its
stranded costs. The Unitil Settlement, approved in October 2002, otherwise
resolves all of the issues in the federal court action. Upon the expiration of
all periods of appeal with respect to the restructuring proceeding by the NHPUC
thereto, UES will implement retail choice and Unitil will withdraw its
intervention in this federal court action, with prejudice.
24
Wholesale Power Market Restructuring - Unitil has also been a participant in the
restructuring of the wholesale power market and transmission system in New
England, which is subject to FERC jurisdiction. New wholesale markets structured
pursuant to FERC's Standard Market Design are expected to be implemented in the
New England Power Pool during the first half of 2003 under the general
supervision of an Independent System Operator and the regulatory oversight of
the FERC.
Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated
by the Company to increase base rates for Unitil's retail electric operating
subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The
last distribution base rate increase request for FG&E's retail gas operations
occurred in 1998. In 2001, FG&E's electric base rates were investigated by the
MDTE, which resulted in an electric base rate decrease. A majority of the
Company's electric and gas operating revenues are collected under various
periodic rate adjustment mechanisms including fuel, purchased power, energy
efficiency, and restructuring-related cost recovery mechanisms. Industry
restructuring will continue to change the methods of how certain costs are
recovered through the Company's regulated rates and tariffs.
On the gas side, FG&E continues to provide a multi-year refund through its Cost
of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding
that FG&E had over-collected fuel inventory finance charges. At December 31,
2002, the unamortized balance of this refund was $1.3 million. FG&E believes a
refund is not justified or warranted and has appealed the MDTE's ruling to the
Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single
justice of the SJC declined to stay the MDTE's Order based on a finding that
refunds made by FG&E may be recouped if FG&E prevails on the merits of its
claims. The review of the MDTE Order by the SJC is pending.
On October 25, 2002, as part of the electric restructuring settlement for
Unitil's New Hampshire utility operations described above, the Company received
approval from the NHPUC for an increase of approximately $2.0 million in annual
distribution revenues for UES, effective December 1, 2002.
On December 2, 2002, the MDTE issued an Order resulting in distribution rate
increases of $2.0 million for FG&E's electric operations and $3.0 million for
FG&E's gas operations. Increases for rising gas costs were incorporated into the
final gas rates. FG&E's new rates became effective on December 2, 2002.
On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the
MDTE for both electric and gas operations. PBR is a method of setting regulated
distribution rates that provides incentives to control costs while maintaining a
high level of service quality. Under PBR, a company's earnings are tied to
performance targets, and penalties can be imposed for deterioration of service
quality. FG&E's PBR Plans were filed in conjunction with FG&E's distribution
rate filings, consistent with MDTE policy to implement PBR in the context of
base rate cases. The MDTE did not initiate investigations of the filings. On
January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's
PBR plans have no scheduled date of implementation, and conventional cost-based
regulation continues to apply.
In December 2002, FG&E and UES filed requests with their respective state
regulatory commissions for approval of an accounting Order to mitigate certain
accounting requirements related to pension plan assets, which have been
triggered by the substantial decline in the capital markets. These requests were
granted by the respective state regulatory commissions in December 2002. These
approvals allow FG&E and UES to treat the additional minimum pension liability
and Prepaid Pension Costs as Regulatory Assets and avoid the reduction in equity
that would otherwise be required. These regulatory Orders do not pre-approve the
amount of pension expense to be recovered in future rates. Such recovery will be
subject to review and approval in future rate proceedings. Based on these
approvals, Unitil has included the amount of the additional minimum pension
liabilities and Prepaid Pension Costs of $12.0 million in Regulatory Assets on
its balance sheet.
Environmental Matters
The Company's past and present operations include activities that are subject to
extensive federal and state environmental regulations.
Sawyer Passway MGP Site - The Company continues to work with environmental
regulatory agencies to identify and assess environmental issues at the former
manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg,
Massachusetts. FG&E proceeded with site remediation work as specified on the
Tier 1B permit issued by the Massachusetts Department of Environmental
Protection (DEP), which allows the Company to work towards temporary remediation
of the site. Work performed in 2002 was associated with the five-year review of
25
the Temporary Solution submittal (Class C Response Action Outcome) under the
Massachusetts Contingency Plan that was filed for the site in 1997. Completion
of this work has confirmed the Temporary Solution status of the site for an
additional five years. A status of temporary closure requires FG&E to monitor
the site until a feasible permanent remediation alternative can be developed and
completed.
Since 1991, FG&E has recovered the environmental response costs incurred at this
former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement).
The Agreement allows FG&E to amortize and recover from gas customers over
succeeding seven-year periods the environmental response costs incurred each
year. Environmental response costs are defined to include liabilities related to
manufactured gas sites, waste disposal sites or other sites onto which hazardous
material may have migrated as a result of the operation or decommissioning of
Massachusetts gas manufacturing facilities from 1882 through 1978. In addition,
any recovery that FG&E receives from insurance or third parties with respect to
environmental response costs, net of the unrecovered costs associated therewith,
are split equally between FG&E and its gas customers. The total annual charge
for such costs assessed to gas customers cannot exceed five percent of FG&E's
total revenue for firm gas sales during the preceding year. Costs in excess of
five percent will be deferred for recovery in subsequent years.
Former Electric Generating Station - The Company is remediating environmental
conditions at a former electric generating station located at Sawyer Passway,
which FG&E sold to WRW, a general partnership, in 1983. Rockware International
Corporation (Rockware), an affiliate of WRW, acquired rights to the electric
equipment in the building and intended to remove, recondition and sell this
equipment. During 1985, Rockware demolished several exterior walls of the
generating station in order to facilitate removal of certain equipment. The
demolition of the walls and the removal of generating equipment resulted in
damage to asbestos-containing insulation materials inside the building, which
had been intact and encapsulated at the time of the sale of the structure to
WRW.
When Rockware and WRW encountered financial difficulties and failed to respond
adequately to Orders of the environmental regulators to remedy the situation,
FG&E agreed to take steps at that time and obtained DEP approval to temporarily
enclose, secure and stabilize the facility. Based on that approval, between
September and December 1989, contractors retained by FG&E stabilized the
facility and secured the building. This work did not permanently resolve the
asbestos problems caused by Rockware, but was deemed sufficient for the then
foreseeable future.
Due to the continuing deterioration of this former electric generating station
and Rockware's continued lack of performance, FG&E, in concert with the DEP and
the EPA, conducted further testing and survey work during 2001 to ascertain the
environmental status of the building. Those surveys revealed continued
deterioration of the asbestos-containing insulation materials in the building.
By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially
Responsible Party for planned remedial activities at the site and invited FG&E
to perform or finance such activities. FG&E and the EPA have entered into an
Agreement of Consent, whereby FG&E, without an admission of liability, will
conduct environmental remedial action to abate and remove asbestos-containing
and other hazardous materials. FG&E has awarded contracts for all aspects of the
abatement work, which is presently ongoing. FG&E received significant coverage
from its insurance carrier. The Company believes that these funds will be
sufficient to complete this remediation and that resolution of this matter will
not have a material adverse impact on the Company's financial position.
The Company has recorded the estimated cost of the remediation action in Current
Liabilities and an offsetting asset reflecting insurance proceeds in Current
Assets. At the balance sheet date, net of amounts expended in 2002, the
remaining project cost was $3.7 million.
Critical Accounting Policies
The preparation of the Company's financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. The
following is a summary of the Company's most critical accounting policies, which
are defined as
26
those policies where judgments or uncertainties could materially affect the
application of those policies. For a complete discussion of the Company's
significant accounting policies, refer to the attached financial statements and
Note 1: Summary of Significant Accounting Policies.
Regulatory Accounting - The Company is a regulated utility and its principal
business is the distribution of electricity and natural gas. Accordingly, the
Company uses the provisions of SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation." In accordance with SFAS No. 71, the Company has
recorded Regulatory Assets and Regulatory Liabilities which will be recovered in
future electric and gas retail rates. The Company also has commitments under
long-term contracts for the purchase of electricity from various suppliers. The
annual costs under these contracts are included in Fuel and Purchased Power and
Gas Purchased for Resale in the Consolidated Statements of Earnings and these
costs are recoverable in current and future rates under various orders issued by
state and federal regulators. If the Company, or a portion of its assets or
operations, were to cease meeting the criteria for application of these
accounting rules, accounting standards for businesses in general would become
applicable and immediate recognition of any previously deferred costs, or a
portion of deferred costs, would be required in the year in which the criteria
are no longer met, if such deferred costs are not recoverable in the portion of
the business that continues to meet the criteria for application of SFAS No. 71.
Commitments and Contingencies - The Company's accounting policy is to record
and/or disclose commitments and contingencies in accordance with SFAS No. 5,
"Accounting for Contingencies." For example, in 2002 the Company resolved a long
standing contingency related to an environmental matter by entering into a fixed
price contract to remediate the site while also settling on the funding of the
project to be provided by the Company's insurance carrier. As a result,
management estimates that this matter will not have a material adverse effect on
the Company's financial position.
Forward-Looking Information
This report contains forward-looking statements which are subject to 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, interest rates, 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 7A. Quantitative and Qualitative Disclosures about Market Risk
Reference is made to the "Market Risk section of Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
(above).
27
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, 2002 and 2001, 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, 2002. 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 auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, 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, 2002 and 2001, and the consolidated results
of their operations and their consolidated cash flows for each of the three
years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
We have also audited Schedule II for each of the three years in the period ended
December 31, 2002. In our opinion, this schedule, when considered in relation to
the basic financial statements taken as a whole, presents fairly, in all
material respects, the information therein.
/s/ GRANT THORNTON LLP
Boston, Massachusetts
February 7, 2003
28
CONSOLIDATED STATEMENTS OF EARNINGS
(000's, except common shares and per share data)
-----------------------------------------
Year Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------
Operating Revenues:
Electric $ 167,317 $ 183,780 $ 160,023
Gas 20,283 22,828 22,756
Other 786 414 162
-------------------------------------------
Total Operating Revenues 188,386 207,022 182,941
-------------------------------------------
Operating Expenses:
Fuel and Purchased Power 114,598 132,947 110,280
Gas Purchased for Resale 11,143 13,827 13,492
Operation and Maintenance 25,667 25,000 24,545
Restructuring Charge 1,598 ---- ----
Depreciation and Amortization 14,911 12,767 11,964
Provisions for Taxes:
Local Property and Other 4,731 4,666 4,967
Federal and State Income 2,490 3,421 3,413
-----------------------------------------
Total Operating Expenses 175,138 192,628 168,661
-----------------------------------------
Operating Income 13,248 14,394 14,280
Non-Operating Expenses:
(Gain) Loss on Non-Utility Investments, (82) 2,400 ----
net of tax
Other Non-Operating Expenses 185 170 244
-----------------------------------------
Income Before Interest Expense
and Extraordinary Item 13,145 11,824 14,036
Interest Expense, net 7,057 6,797 6,820
-----------------------------------------
Income before Extraordinary Item 6,088 5,027 7,216
Extraordinary Item, net of tax ---- 3,937 ----
-----------------------------------------
Net Income 6,088 1,090 7,216
Less Dividends on Preferred Stock 253 257 263
-----------------------------------------
Earnings Applicable to Common Shareholders $ 5,835 $ 833 $ 6,953
=========================================
Average Common Shares Outstanding - Basic 4,743,696 4,743,576 4,723,171
Average Common Shares Outstanding - Diluted 4,762,166 4,759,822 4,742,745
Earnings per Common Share
- ------------------------------------------------------------------------------------------
Income before Extraordinary Item $ 1.23 $ 1.01 $ 1.47
Extraordinary Item, net of tax ---- (0.83) ----
-----------------------------------------
Net Income $ 1.23 $ 0.18 $ 1.47
=========================================
(The accompanying Notes are an integral part of these financial statements.)
29
CONSOLIDATED BALANCE SHEETS (000'S)
ASSETS
----------------------------
December 31, 2002 2001
- --------------------------------------------------------------------------------
Utility Plant:
Electric $ 193,152 $ 183,795
Gas 44,796 41,287
Common 27,573 28,529
Construction Work in Progress 5,658 1,887
----------------------------
Utility Plant 271,179 255,498
Less: Accumulated Depreciation 82,587 77,210
----------------------------
Net Utility Plant 188,592 178,288
----------------------------
Other Property and Investments 651 2,286
----------------------------
Current Assets:
Cash 7,160 6,076
Accounts Receivable - Net of Allowance for
Doubtful Accounts of $372 and $600 19,513 17,133
Refundable Taxes 4,851 2,432
Material and Supplies 2,323 2,804
Prepayments 1,735 1,889
Accrued Revenue 4,842 1,330
----------------------------
Total Current Assets 40,424 31,664
----------------------------
Noncurrent Assets:
Regulatory Assets 244,011 146,042
Prepaid Pension Costs ---- 10,712
Debt Issuance Costs, net 1,755 1,826
Other Noncurrent Assets 5,350 5,944
----------------------------
Total Noncurrent Assets 251,116 164,524
----------------------------
TOTAL $ 480,783 $ 376,762
============================
(The accompanying Notes are an integral part of these financial statements.)
30
CONSOLIDATED BALANCE SHEETS (Cont.) (000'S)
CAPITALIZATION AND LIABILITIES
----------------------------
December 31, 2002 2001
- --------------------------------------------------------------------------------
Capitalization:
Common Stock Equity $ 74,350 $ 74,746
Preferred Stock, Non-Redeemable,
Non-Cumulative 225 225
Preferred Stock, Redeemable, Cumulative 3,097 3,384
Long-Term Debt, Less Current Portion 104,226 107,470
----------------------------
Total Capitalization 181,898 185,825
----------------------------
Current Liabilities:
Long-Term Debt, Current Portion 3,243 3,224
Capitalized Leases, Current Portion 800 988
Accounts Payable 14,221 20,084
Short-Term Debt 35,990 13,800
Dividends Declared and Payable 77 109
Refundable Customer Deposits 1,336 1,393
Interest Payable 1,311 1,375
Other Current Liabilities 9,062 6,328
----------------------------
Total Current Liabilities 66,040 47,301
----------------------------
Deferred Income Taxes 47,332 47,113
Noncurrent Liabilities:
Power Supply Buyout Obligations 175,657 88,779
Capitalized Leases, Less Current Portion 2,534 2,945
Other Noncurrent Liabilities 7,322 4,799
----------------------------
Total Noncurrent Liabilities 185,513 96,523
----------------------------
TOTAL $ 480,783 $ 376,762
============================
(The accompanying Notes are an integral part of these financial statements.)
31
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(000's except number of shares and par value)
----------------------------
December 31, 2002 2001
- --------------------------------------------------------------------------------
Common Stock Equity
Common Stock, No Par Value $ 41,220 $ 41,220
(Authorized - 8,000,000 shares;
Outstanding - 4,743,696 and 4,743,696 shares)
Stock Options 990 669
Retained Earnings 32,140 32,857
----------------------------
Total Common Stock Equity 74,350 74,746
----------------------------
Preferred Stock
UES Preferred Stock, Non-Redeemable,
Non-Cumulative:
6.00% Series, $100 Par Value 225 225
UES Preferred Stock, Redeemable, Cumulative:
8.70% Series, $100 Par Value 215 215
5.00% Series, $100 Par Value --- 91
6.00% Series, $100 Par Value --- 168
8.75% Series, $100 Par Value 333 333
8.25% Series, $100 Par Value 385 385
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value 946 960
8.00% Series, $100 Par Value 1,218 1,232
----------------------------
Total Preferred Stock 3,322 3,609
----------------------------
Long-Term Debt
UES First Mortgage Bonds:
Series I, 8.49%, Due October 14, 2024 6,000 6,000
Series J, 6.96%, Due September 1, 2028 10,000 10,000
Series K, 8.00%, Due May 1, 2031 7,500 7,500
Series L, 8.49%, Due October 14, 2024 9,000 9,000
Series M, 6.96%, Due September 1, 2028 10,000 10,000
Series N, 8.00%, Due May 1, 2031 7,500 7,500
FG&E Long-Term Notes:
8.55% Notes, Due March 31, 2004 6,000 9,000
6.75% Notes, Due November 30, 2023 19,000 19,000
7.37% Notes, Due January 15, 2029 12,000 12,000
7.98% Notes, Due June 1, 2031 14,000 14,000
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017 6,469 6,694
----------------------------
Total Long-Term Debt 107,469 110,694
Less: Long-Term Debt, Current Portion 3,243 3,224
----------------------------
Total Long-Term Debt, Less Current Portion 104,226 107,470
----------------------------
Total Capitalization $ 181,898 $ 185,825
============================
(The accompanying Notes are an integral part of these financial statements.)
32
CONSOLIDATED STATEMENTS OF CASH FLOWS (000's)
-----------------------------------------
Year Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------
Cash Flows from Operating Activities:
Net Income $ 6,088 $ 1,090 $ 7,216
Adjustments to Reconcile Net Income to
Cash Provided by Operating Activities:
Depreciation and Amortization 14,911 12,767 11,964
Deferred Tax Provision 856 (607) 3,523
Noncash Stock Option Compensation Expenses 321 293 182
(Gain) Loss on Non-Utility Investments, net (82) 2,400 ----
Changes in Current Assets and Liabilities:
Accounts Receivable (2,380) 2,924 (3,427)
Prepayments and other Current Assets (960) (1,690) (2,393)
Accrued Revenue (3,512) 7,973 (6,340)
Accounts Payable (5,863) 1,545 2,024
Interest Payable and other Current
Liabilities 2,670 366 (145)
Other, net (2,481) (3,883) (3,740)
-----------------------------------------
Cash Provided by Operating Activities 9,568 23,178 8,864
-----------------------------------------
Cash Flows from Investing Activities:
Acquisitions of Property, Plant and Equipment (20,825) (19,890) (21,092)
Proceeds from Sale of Electric Generation
Assets ---- 342 ----
Proceeds (Acquisitions) on Investments, net 1,535 ---- (1,157)
-----------------------------------------
Cash Used in Investing Activities (19,290) (19,548) (22,249)
-----------------------------------------
Cash Flows from Financing Activities:
Proceeds from (Repayment of) Short-Term Debt,
net 22,190 (18,700) 22,000
Proceeds from Issuance of Long-Term Debt ---- 29,000 ----
Repayment of Long-Term Debt (3,225) (3,208) (1,255)
Dividends Paid (6,831) (6,902) (6,787)
Issuance of Common Stock, net ---- 229 639
Retirement of Preferred Stock (293) (81) (68)
Repayment of Capital Lease Obligations (1,035) (952) (931)
-----------------------------------------
Cash Provided by (Used In) Financing
Activities 10,806 (614) 13,598
-----------------------------------------
Net Increase in Cash 1,084 3,016 213
Cash at Beginning of Year 6,076 3,060 2,847
-----------------------------------------
Cash at End of Year $ 7,160 $ 6,076 $ 3,060
=========================================
Supplemental Cash Flow Information:
Interest Paid $ 9,356 $ 8,988 $ 8,640
Income Taxes Paid $ 2,351 $ 4,265 $ 827
Supplemental Schedule of Noncash Activities:
Capital Leases Incurred $ 436 $ 691 $ 363
(The accompanying Notes are an integral part of these financial statements.)
33
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
(000's except number of shares)
Common Stock Option Retained
Shares Plan Earnings Total
-----------------------------------------------------
Balance at January 1, 2000 $ 40,352 $ 194 $ 38,129 $ 78,675
Net Income for 2000 7,216 7,216
Dividends on Preferred Shares (263) (263)
Dividends on Common Shares -
at $1.38 per Share (6,514) (6,514)
Stock Option Plan 182 182
Issuance of 22,916 Common Shares (a) 639 639
-----------------------------------------------------
Balance at December 31, 2000 40,991 376 38,568 79,935
Net Income after Extraordinary Item for 2001 1,090 1,090
Dividends on Preferred Shares (257) (257)
Dividends on Common Shares -
at an Annual Rate of $1.38 per Share (6,544) (6,544)
Stock Option Plan 293 293
Issuance of 11,279 Common Shares (a) 287 287
Re-acquired and retired Common Shares (b) (58) (58)
-----------------------------------------------------
Balance at December 31, 2001 41,220 669 32,857 74,746
Net Income for 2002 6,088 6,088
Dividends on Preferred Shares (253) (253)
Dividends on Common Shares -
at $1.38 per Share (6,546) (6,546)
Stock Option Plan 321 321
Premium paid for redemption of Preferred
Shares (c) (6) (6)
-----------------------------------------------------
Balance at December 31, 2002 $ 41,220 $ 990 $ 32,140 $ 74,350
=====================================================
(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.
(b) Shares repurchased in conjunction with the Company's interim stock
repurchase program.
(c) Premium paid for the redemption of Exeter & Hampton Electric Company
Preferred Shares.
(The accompanying Notes are an integral part of these financial statements.)
34
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 (1935 Act). The
following companies are wholly-owned subsidiaries of Unitil: Unitil Energy
Systems, Inc. (UES) (formed in 2002 by the combination and merger of Unitil's
former utility subsidiaries Concord Electric Company (CECo) and Exeter & Hampton
Electric Company (E&H)), Fitchburg Gas and Electric Light Company (FG&E), Unitil
Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service
Corp. (Unitil Service) and its non-regulated business unit Unitil Resources,
Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are subsidiaries of
Unitil Resources.
Unitil'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 two wholly-owned retail
distribution utility subsidiaries. The Company's wholesale electric power
utility subsidiary, Unitil Power, principally provides all the electric power
supply requirements to UES for resale at retail.
Unitil Realty owns and manages the Company's corporate office building and
property located in Hampton, New Hampshire and leases this facility 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 its
affiliated Unitil companies. Unitil Resources is the Company's wholly-owned
non-utility subsidiary and has been authorized by the SEC, pursuant to the rules
and regulations of the 1935 Act, to engage in competitive business transactions
associated with 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. Usource, Inc. and Usource L.L.C.
(collectively, Usource) are wholly owned subsidiaries of Unitil Resources.
Usource provides competitive energy brokering services, as well as related
energy consulting services.
With respect to rates and other business and financial matters, UES is subject
to regulation by the New Hampshire Public Utilities Commission (NHPUC), FG&E is
regulated by the Massachusetts Department of Telecommunications & Energy (MDTE),
and Unitil Power, UES and FG&E are regulated by the Federal Energy Regulatory
Commission (FERC).
Basis of Presentation
Principles of Consolidation - The consolidated financial statements include the
accounts of Unitil and all of its wholly-owned subsidiaries. Intercompany
accounts and transactions have been eliminated in consolidation.
Regulatory Accounting - Generally Accepted Accounting Principles for regulated
entities in the United States allow Unitil to give accounting recognition to the
actions of regulatory authorities in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." In accordance with SFAS No. 71, the Company has
recognized future cash inflows that will result from the ratemaking process (a
Regulatory Asset) or has recognized obligations (a Regulatory Liability) if it
is probable that such costs will be recovered or obligations relieved in the
future through the ratemaking process. In addition to the Regulatory Assets and
Liabilities separately identified on the Consolidated Balance Sheet, there are
other regulatory assets and liabilities, such as accrued revenues associated
with reconciling cost recovery mechanisms and certain deferred tax liabilities
recovered through the ratemaking process. The Company also has obligations under
long-term power contracts, the recovery of which is subject to regulation. If
the Company, or a portion of its assets or operations, were to cease meeting the
criteria for application of these accounting rules, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met, if such deferred costs are not
recoverable in the portion of the business that continues to meet the criteria
for application of SFAS No. 71.
Massachusetts and New Hampshire have both passed utility industry restructuring
legislation and the Company has filed and implemented its restructuring plans in
both states. In Massachusetts, the Company is allowed to recover certain types
of costs through ongoing assessments to be included in future regulated service
rates. The Company is also deferring the recovery of certain restructuring
related costs in order to meet the retail rate cap imposed under the
Massachusetts restructuring legislation. Based on the recovery mechanism that
allows
35
recovery of all of its stranded costs and deferred costs related to
restructuring, the Company has recorded regulatory assets that it expects to
fully recover in future periods. The Company expects to continue to meet the
criteria for the application of SFAS No. 71 for the distribution portion of its
assets and operations for the foreseeable future. If a change in accounting were
to occur to the distribution portion of the Company's operations, it could have
a material adverse effect on the Company's earnings and retained earnings in
that year and could have a material adverse effect on the Company's ongoing
financial condition as well.
On January 25, 2002, the Company's New Hampshire electric utility subsidiaries,
CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with
the NHPUC. This proposal included the introduction of customer choice consistent
with the New Hampshire restructuring law, the divestiture of Unitil Power's
power supply portfolio, the recovery of stranded costs, the combination of CECo
and E&H into a planned successor, UES, and new distribution rates for UES. On
October 25, 2002, the NHPUC approved a multi-party settlement on all major
issues in the proceeding. Under Unitil's approved restructuring plan, Unitil
will divest its existing New Hampshire power supply portfolio and conduct a
solicitation for new power supplies from which to meet its ongoing transition
and default service energy obligations. In early 2003, Unitil will file for
final NHPUC approval of the executed agreements resulting from these divestiture
and solicitation processes, including final tariffs for stranded cost recovery
and transition and default services. The implementation of customer choice is
targeted for May 1, 2003.
Upon receipt of all requested approvals in the proceeding by the NHPUC, and the
expiration of all periods of appeal with respect thereto, UES will implement
retail choice and Unitil will withdraw its intervention in a pending federal
court action, with prejudice. In June 1997, Unitil and other utilities in NH
intervened as plaintiffs in a suit filed in U.S. District Court by Northeast
Utilities' affiliate Public Service Company of New Hampshire for protection from
the NHPUC Final Plan to restructure the New Hampshire electric utility industry.
Although the NHPUC found that CECo and E&H were entitled to full interim
stranded costs recovery, the NHPUC also made certain legal rulings, that, if
implemented, could affect the Company's long-term ability to recover all of
their stranded costs. The Unitil Settlement approved in October 2002, provides
for full stranded cost recovery by UES, and otherwise resolves all of the issues
in the federal court action.
Asset Balances at December 31,
Regulatory Assets consist of the
following (000's) 2002 2001
-----------------------------------------------------------------------
Power Supply Buyout Obligations $ 175,657 $ 88,779
Income Taxes 24,799 27,386
Recoverable Deferred Charges 22,253 18,103
Recoverable Generation-related Assets 9,327 11,774
Pension 11,975 ----
------------------------
Total Regulatory Assets $ 244,011 $ 146,042
========================
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 - Unitil'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. Usource, Unitil's
competitive energy brokering subsidiary, records energy brokering revenues based
upon the estimated amount of electricity and gas delivered to customers through
the end of the accounting period.
Utility Plant - The cost of additions to Utility Plant and the cost of renewals
and betterments are capitalized. Cost consists of labor, materials, services and
certain indirect construction costs, including an allowance for funds used
during construction (AFUDC). The costs of current repairs and minor replacements
are charged to appropriate operating expense accounts. The original cost of
utility plant retired or otherwise disposed of and the cost of removal, less
salvage, are charged to the accumulated provision for depreciation.
Depreciation and Amortization - Depreciation provisions for Unitil's utility
operating subsidiaries are determined on a group straight-line basis. Provisions
for depreciation were equivalent to the following composite rates, based
36
on the average depreciable property balances at the beginning and end of each
year: 2002 - 3.79%, 2001 - 3.75% and 2000 - 3.74%.
Amortization provisions include the recovery of a portion of FG&E's former
investment in Seabrook Station, a nuclear generating unit, in rates to its
customers through the Seabrook Amortization Surcharge as ordered by the MDTE. In
addition, FG&E is amortizing the balance of its unrecovered electric generating
related assets, which are recorded as Regulatory Assets, in accordance with its
electric restructuring plan approved by the MDTE (See Note 15).
Stock-based Employee Compensation - Unitil accounts for stock-based employee
compensation currently using the fair value based method (See Note 5).
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.
Newly Issued Pronouncements - On June 29, 2001, the Financial Accounting
Standards Board (FASB) approved for issuance SFAS No. 141, "Business
Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets."
Significant provisions of these statements are as follows: all business
combinations initiated after June 30, 2001, must use the purchase method of
accounting; goodwill and intangible assets with indefinite lives are not
amortized but are tested for impairment annually using a fair value approach;
other intangible assets will continue to be valued and amortized over their
estimated lives. The Company has no goodwill recorded at December 31, 2002 and
2001. As a result, the adoption of these statements did not have any impact on
the Company's financial position or results of operations. The merger of the
Company's two New Hampshire utility subsidiaries, CECo and E&H, into UES in
December 2002 was the combination of entities under the common control of Unitil
Corporation and therefore all of the accounts of these businesses were combined
at their historical cost.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which establishes new accounting and reporting standards for legal
obligations associated with retiring tangible long-lived assets. The fair value
of a liability for an asset retirement obligation must be recorded in the period
in which it is incurred, with the cost capitalized as part of the related
long-lived asset and depreciated over the asset's useful life. SFAS No.143 must
be adopted by 2003. The Company currently accounts for all of the costs of its
long lived-assets, including the cost of removal to replace these assets, in
accordance with Generally Accepted Accounting Principles and guidelines
published by the FERC for Utility plant accounting. The Company has no ownership
interest in nuclear power plants, and no decommissioning obligations. The
Company has determined that the adoption of this statement will not have a
material adverse impact on the Company's financial position or results of
operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS No. 144 requires that an impairment loss
should be recognized if the carrying value of the asset is not recoverable from
its undiscounted cash flows. The statement is effective for fiscal years
beginning after December 15, 2001, with early adoption permitted. The Company
has determined that the adoption of this statement will not have a material
adverse impact on the Company's financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." The provisions of SFAS No. 146 are effective
for exit or disposal activities that are initiated after December 31, 2002. The
Company initiated a reorganization of management and administrative positions in
the fourth quarter of 2002 and recognized a Restructuring Charge, discussed
below, under the provisions of Emerging Issues Task Force (EITF) Issue No. 94-3,
the predecessor standard to SFAS 146.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123,
"Accounting for Stock-Based Compensation" to provide alternative methods of
transition for a voluntary change to the fair value-based method of accounting
for stock-based employee compensation. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method on reported
results. The Company recognizes compensation cost at fair value at the date of
grant.
37
Also in 2002, the FASB issued Interpretation 45 (FIN 45), "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." Under FIN 45 guarantors are required to
measure and recognize the fair value of guarantees at inception and provide new
disclosures regarding the nature of any guarantees. FIN 45 is effective for
financial statements of reporting periods ending after December 15, 2002. The
Company has adopted the provisions of FIN 45.
Reclassifications - Certain amounts previously reported have been reclassified
to conform to current year presentation.
Note 2: Restructuring Charge - 2002
In the fourth quarter of 2002, Unitil recognized a pre-tax Restructuring Charge
of $1.6 million. The after-tax effect of the Restructuring Charge was a
reduction of $0.20 in Earnings per Common Share, assuming full dilution.
In December 2002, the Company undertook a strategic review of its business
operations and committed to a formal transition and reorganization plan (the
Reorganization Plan) to streamline its management structure, in order to improve
operating efficiency and to align the organization to meet ongoing business
requirements. The Reorganization Plan resulted in the elimination of 19
management and administrative positions. As a result of the elimination of these
positions, and consistent with existing Company policy, certain benefits are
extended to the employees whose positions were eliminated. On January 8, 2003,
the Company implemented the Reorganization Plan.
The $1.6 million pre-tax Restructuring Charge established a liability at
December 31, 2002, to cover the disbursement of severance and employee benefits
and related costs committed to under the Reorganization Plan, substantially all
of which will be paid in fiscal 2003. At December 31, 2002, the Restructuring
Charge of $1.6 million is included in Other Current Liabilities.
Note 3: Extraordinary Item - 2001
In November 1997, the Massachusetts Legislature enacted the Massachusetts
Electric Restructuring Act of 1997 (the Restructuring Act). The Restructuring
Act required all electric utilities to file a restructuring plan with the MDTE
by December 31, 1997. Among other things, the Restructuring Act required all
Massachusetts electric utilities to sell all of their electric generation assets
and to restructure their utility operations to provide direct retail access to
their customers by all qualified generation suppliers.
The MDTE conditionally approved FG&E's Restructuring Plan (the Plan) in February
1998, and started an investigation and evidentiary hearings into FG&E's proposed
recovery of Regulatory Assets related to stranded generation asset costs and
expenses related to the formulation and implementation of its Plan. In January
1999, the MDTE approved FG&E's Plan, which included provisions for the recovery
of stranded costs through a transition charge in FG&E's electric rates. In
September 1999, FG&E filed its first annual reconciliation of stranded
generation asset costs and expenses and associated transition charge revenues
and the MDTE initiated a lengthy investigation and hearing process.
On October 18 and 19, 2001, the MDTE issued a series of regulatory Orders in
several pending cases involving FG&E, including a final Order on FG&E's initial
reconciliation filing. Those Orders included the review and disposition of
issues related to FG&E's recovery of transition costs due to the restructuring
of the electric industry in Massachusetts, as well as certain costs associated
with gas industry restructuring and preparation and litigation of performance
based rate proceedings initiated by the MDTE. The Orders determined the final
treatment of Regulatory Assets that FG&E had sought to recover from its
Massachusetts electric customers over a multi-year transition period that began
in 1998.
As a result of the industry restructuring-related Orders, FG&E recorded a
non-cash adjustment to Regulatory Assets of $5.3 million, which resulted in the
recognition of an extraordinary charge of $3.9 million, net of taxes. The
Company recognized the extraordinary charge of $0.83 per share, as of September
30, 2001.
38
As a result of all of these Orders, the Company has been allowed recovery of its
Massachusetts industry restructuring transition costs, estimated at $150
million, after reconciliation, including the above-market or stranded generation
and power supply related costs via a non-bypassable uniform transition charge.
FG&E has been and will continue to be subject to annual MDTE investigation and
review in order to reconcile the costs and revenues associated with the
collection of transition charges from its customers over the next eight to ten
years.
Note 4: Investment Write-down and Sale of Equity Stake in Enermetrix - 2001
Beginning in 1998, Unitil invested $5.5 million in Enermetrix, Inc.
(Enermetrix), an energy technology start-up enterprise. In accordance with SFAS
No. 115, "Accounting for Certain Investments in Debt and Equity Securities," the
Company recorded a non-cash charge of $3.7 million, or $2.4 million, net of tax,
in the fourth quarter of 2001 to recognize the decrease in fair value of its
non-utility investment in Enermetrix.
On April 11, 2002, the Company sold its equity ownership in Enermetrix for $1.5
million in cash and improved commercial terms for use of the Enermetrix Software
Network. As a result of the sale, in 2002, the Company recognized the benefit of
approximately $1.3 million of this capital loss as a carryback against capital
gains in its 2002 tax return.
Note 5: Common Stock
New Shares Issued - During 2002, Unitil did not issue any additional shares of
its common stock. The Company raised $287,142 and $639,000 of additional common
equity capital through the issuance of 11,279 and 22,916 shares of common stock
in connection with the Dividend Reinvestment and Stock Purchase Plan (DRP)
during 2001 and 2000, respectively. The DRP 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.
Shares Repurchased, Cancelled and Retired - During 2002, Unitil did not
repurchase, cancel and retire any of its common stock. During 2001, in
conjunction with the SEC's Emergency Orders of September 14 and 21, 2001, which
suspended the applicability of certain of the conditions contained in its Rule
10b-18, the Company implemented an interim Common Stock repurchase program.
Under this program, the Company used its cash on hand to repurchase, cancel and
retire 2,500 shares of its outstanding Common Stock at a total cost of $58,500.
The SEC has since lifted its suspension of the aforementioned conditions and
accordingly, the Company's interim Common Stock repurchase program is no longer
in effect.
Stock-Based Compensation Plans - Unitil maintains two stock option plans, which
provide for the granting of options to key employees. Details of the plan are as
follows:
Unitil Corporation Key Employee Stock Option Plan - The "Unitil Corporation Key
Employee Stock Option Plan" was a 10-year plan which began in March 1989. The
number of shares granted under this plan, as well as the terms and conditions of
each grant, were determined by the Key Employee Stock Option Plan Committee of
the Board of Directors, subject to plan limitations. All options granted under
this plan vested upon grant. The 10-year period in which options could be
granted under this plan expired in March 1999. The expiration date of the
remaining outstanding options is November 3, 2007. The plan provides 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 $43,000, $42,000 and $38,000 for the years ended December 31,
2002, 2001 and 2000, respectively.
39
Share Option Activity of the "Unitil Corporation Key Employee Stock Option Plan"
is presented in the following table:
2002 2001 2000
------------------------------------------------
Beginning Options Outstanding and Exercisable 30,996 29,358 27,976
Dividend Equivalents Earned 1,649 1,638 1,382
Options Exercised ---- ---- ----
------------------------------------------------
Ending Options Outstanding and Exercisable 32,645 30,996 29,358
================================================
Range of Option Exercise Price per Share $12.11-$18.28 $12.11-$18.28 $12.11-$18.28
Weighted Average Remaining Contractual Life 4.9 years 5.9 years 6.9 years
Unitil Corporation 1998 Stock Option Plan - The "Unitil Corporation 1998 Stock
Option Plan" became effective on December 11, 1998. The number of shares granted
under this plan, as well as the terms and conditions of each grant, are
determined by the Compensation Committee of the Board of Directors, subject to
plan limitations. All options granted under this plan vest over a three-year
period from the date of the grant, with 25% vesting on the first anniversary of
the grant, 25% vesting on the second anniversary, and 50% vesting on the third
anniversary. Under the terms of this plan, key employees may be granted options
to purchase the Company's Common Stock at no less than 100% of the market price
on the date the option is granted. All options must be exercised no later than
10 years after the date on which they were granted. The total compensation
expenses recorded by the Company with respect to this plan were $278,000,
$251,000 and $144,000 for the years ended December 31, 2002, 2001 and 2000,
respectively.
2002 2001 2000
-------------------------------------------------------------------------
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Shares Price Shares Price Shares Price
-------------------------------------------------------------------------
Beginning Options Outstanding 172,500 $ 26.99 113,500 $ 27.64 62,000 $ 23.38
Options Granted ---- ---- 60,000 $ 25.88 55,000 $ 32.18
Options Forfeited ---- ---- (1,000) $ 33.56 (3,500) $ 23.38
-------------------------------------------------------------------------
Ending Options Outstanding 172,500 $ 26.99 172,500 $ 26.99 113,500 $ 27.64
=========================================================================
Options Vested and Exercisable-
end of year 100,500 $ 26.11
The Company has adopted SFAS No. 123, "Accounting for Stock Based Compensation,"
and recognizes compensation costs at fair value at the date of grant.
The following summarizes certain data for options outstanding at December 31,
2002:
Weighted Options Weighted
Range of Options Average Vested and Average Remaining
Exercise Prices Outstanding Exercise Price Exercisable Exercise Price Contractual Life
$20.00-$24.99 58,500 $23.38 58,500 $23.38 6.2 years
$25.00-$29.99 60,000 $25.88 15,000 $25.88 8.1 years
$30.00-$34.99 54,000 $32.15 27,000 $32.15 7.1 years
------------- -----------
172,500 100,500
============= ===========
40
There were no options granted during 2002. The weighted average fair value per
share of options granted during 2001 and 2000 was $4.66 and $7.13, respectively.
The fair value of options at the date of grant was estimated using the
Black-Scholes model with the following weighted average assumptions:
2002 2001 2000
-------------------------------------
Expected Life (years) N/A 10.0 10.0
Interest Rate N/A 5.8% 6.0%
Volatility N/A 23.6% 22.3%
Dividend Yield N/A 5.3% 4.3%
Restrictions on Retained Earnings - Unitil Corporation has no restriction on the
payment of common dividends from retained earnings.
Its two retail distribution subsidiaries, UES and FG&E, do have restrictions.
Under the terms of the First Mortgage Bond Indentures, UES had $9,313,000
available for the payment of cash dividends on its Common Stock at December 31,
2002. Under the terms of long-term debt purchase agreements, FG&E had $5,144,000
of retained earnings available for the payment of cash dividends on its Common
Stock at December 31, 2002.
In addition, under the terms of the NHPUC's Order in Docket DE 01-247, UES'
ability to issue dividends on its common stock is restricted to an annual
maximum of $1,794,000. This restriction will remain in place until UES files its
next base rate case with the NHPUC, which UES is required to file within the
next five years.
Note 6: Preferred Stock
Unitil's two distribution operating subsidiaries, UES and FG&E, have redeemable
Cumulative Preferred Stock outstanding and one subsidiary, UES, has a
Non-Redeemable, Non-Cumulative Preferred Stock issue outstanding. These
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 2002,
2001 and 2000 related to the annual redemption offer were $34,500, $81,000 and
$67,500, respectively. The aggregate amount of sinking fund requirements of the
Redeemable Cumulative Preferred Stock for each of the five years following 2002
are $192,000 per year.
Also, during 2002, in conjunction with the merger of E&H into CECo to form UES,
the 5% and 6% series of Redeemable Cumulative Preferred Stock were
fully-redeemed at par plus premiums of 2% and 3%, respectively. These
redemptions and related premiums resulted in an aggregate expenditure of
$258,720.
Note 7: Long-Term Debt and Interest Expense
Substantially all the property and franchises of Unitil's utility operating
subsidiaries are subject to liens of indenture under which First Mortgage bonds
have been issued. Certain of the Company's long-term debt agreements contain
provisions which, among other things, limit the incursion of additional
long-term debt.
Total aggregate amount of sinking fund payments relating to bond issues and
normal scheduled long-term debt repayments amounted to $3,225,444, $3,208,000
and $1,254,946 in 2002, 2001 and 2000, respectively.
The aggregate amount of bond sinking fund requirements and normal scheduled
long-term debt repayments for each of the five years following 2002 is: 2003 -
$3,244,156, 2004 - $3,264,421, 2005 - $286,368, 2006 - $310,136 and 2007 -
$335,877.
41
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, 2002
and 2001.
The Company also provides limited guarantees on certain energy contracts entered
into by its regulated subsidiary companies. The Company's policy is to limit
these guarantees to two years or less. As of December 31, 2002, there are $1.8
million of guarantees outstanding and these guarantees extend through October
15, 2004.
Interest Expense, net - Interest expense is presented in the financial
statements, net of Interest Income. In 2002, Interest Expense, net, increased
primarily due to the refinancing of lower cost short-term debt with higher cost
long-term debt and additional borrowings to support the Company's capital
requirements. Total interest expense was $9.3 million, $9.1 million and $8.6
million in 2002, 2001 and 2000, respectively, and increased due to higher debt
outstanding in each of those years. Interest income was $2.3 million, $2.3
million and $1.8 million in 2002, 2001 and 2000, respectively, primarily
reflecting interest earned on recoverable deferred charge balances related to
industry restructuring.
Note 8: Credit Arrangements
At December 31, 2002, Unitil had unsecured committed bank lines for short-term
debt in the aggregate amount of $38.0 million with three banks for which it pays
commitment fees. The weighted average interest rates on all short-term
borrowings were 2.18%, 4.78% and 6.57% during 2002, 2001 and 2000, respectively.
Note 9: Leases
Unitil's subsidiaries conduct a portion of their operations in leased facilities
and also lease some of their machinery and office equipment. FG&E had a 22-year
facility lease in which the Primary Term was scheduled to end on January 31,
2003. On February 1, 2002, a 10-year Extended Term commenced extending the lease
term through February 2012. Furthermore, the amended lease agreement allows for
three additional five-year renewal periods at the option of FG&E. 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) 2002 2001
--------------------------------------------------------------------
Common Plant $ 7,095 $ 7,146
Less: Accumulated Depreciation 3,761 3,213
----------------------------
Net Plant $ 3,334 $ 3,933
============================
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, 2002:
Year Ending December 31, (000's)
--------------------------------------------------------------------
2003 $ 1,130
2004 862
2005 602
2006 310
2007 274
2008 - 2012 1,356
------------
Total Minimum Lease Payments $ 4,534
Less: Amount Representing Interest 1,200
------------
Present Value of Net Minimum Lease Payments $ 3,334
============
Total rental expense charged to operations for the years ended December 31,
2002, 2001 and 2000 amounted to $4,000, $12,000 and $21,000, respectively. There
are no material future operating lease payment obligations at December 31, 2002.
42
Note 10: Income Taxes
Federal Income Taxes were provided for the following items for the years ended
December 31, 2002 2001and 2000, respectively:
2002 2001 2000
---------------------------------------
Current Federal Tax Provision (Benefit) (000's):
Operating Income $ 1,960 $ 3,566 $ (9)
Amortization of Investment Tax Credits (51) (153) (256)
---------------------------------------
Total Current Federal Tax Provision (Benefit) 1,909 3,413 (265)
---------------------------------------
Deferred Federal Tax Provision (Benefit) (000's)
Accelerated Tax Depreciation 68 (401) 183
Abandoned Properties (705) (767) (863)
Accrued Revenue 1,118 691 3,604
Allowance for Funds Used During Construction (32) (42) (48)
Post Retirement Benefits Other Than Pensions (38) (34) (29)
Deferred Pensions 86 89 275
Regulatory Assets and Liabilities 70 37 (186)
Deferred Gain on Sale of New Haven Harbor ---- ---- 125
Contributions in Aid of Construction (231) (251) (106)
Difference in Prior Year Taxes as Filed 72 312 149
Other (119) (197) (38)
---------------------------------------
Total Deferred Federal Tax Provision (Benefit) 289 563 3,066
---------------------------------------
Total Federal Tax Provision $ 2,198 $ 2,850 $ 2,801
=======================================
The components of the Federal and State income tax provisions reflected as
operating expenses in the accompanying consolidated statements of earnings for
the years ended December 31, 2002, 2001 and 2000 were as follows:
Federal and State Tax Provisions (000's) 2002 2001 2000
- ---------------------------------------------------------------------------------------------
Federal
Current $ 1,960 $ 3,566 $ (9)
Deferred 289 (563) 3,066
Amortization of Investment Tax Credits (51) (153) (256)
---------------------------------------
Total Federal Tax Provision 2,198 2,850 2,801
---------------------------------------
State
Current (275) 615 155
Deferred 567 (44) 457
---------------------------------------
Total State Tax Provision 292 571 612
---------------------------------------
Federal and State Income Taxes - Operating Expenses $ 2,490 $ 3,421 $ 3,413
=======================================
In 2001, the Company provided for a deferred tax benefit of $1.3 million on the
capital loss from the write-down of its investment in Enermetrix. The Company
recognized the benefit in 2002 of this capital loss as a carryback against
capital gains in its tax return. Also in the third quarter of 2001, the Company
recorded a deferred tax benefit of $1.4 million as adjustments to deferred taxes
recognized when the Company recorded the extraordinary item.
43
The differences between the Company's provisions for Income Taxes and the
provisions calculated at the statutory federal tax rate, expressed in
percentages, are shown below:
2002 2001 2000
-----------------------------------
Statutory Federal Income Tax Rate 34% 34% 34%
Income Tax Effects of:
State Income Taxes, Net 2 4 4
Investment Tax Credits (1) (1) (2)
Abandoned Property (8) (6) (6)
Other, Net 2 (1) 2
-----------------------------------
Effective Income Tax Rate 29% 30% 32%
===================================
Temporary differences which gave rise to deferred tax assets and liabilities are
shown below:
Deferred Income Taxes (000's) 2002 2001
---------------------------------------------------------------------
Accelerated Depreciation $ 24,140 $ 24,020
Abandoned Property 2,547 4,845
Contributions in Aid of Construction (3,654) (3,360)
Percentage Repair Allowance 2,038 2,165
Retirement Loss - Plant Assets 2,924 3,177
Employee Benefit Plans 3,624 3,551
Regulatory Assets and Liabilities 7,087 7,828
Deferred Charges 7,820 5,954
Investment Write-down ---- (1,236)
Other 806 169
--------------------------
Total Deferred Income Tax $ 47,332 $ 47,113
==========================
Due to a change in New Hampshire State tax regulations and in accordance with
SFAS No. 109, "Accounting for Income Taxes," the Company recorded an adjustment
to Deferred Income Taxes and an offsetting adjustment to Regulatory Assets of
$6.1 million in 2001.
Note 11: 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 one generating unit. Wyman Unit
No. 4 is an oil-fired station that has been in commercial operation since
December 1978. FG&E's 0.217% interest in Millstone Nuclear Generating Station
Unit No. 3 (Millstone 3), which has been in commercial operation since April
1986, was sold to Dominion Resources, Inc. effective April 1, 2001.
Kilowatt-hour generation and operating expenses of the joint ownership unit is
divided on the same basis as ownership. FG&E's proportionate costs are reflected
in the Consolidated Statements of Earnings. In accordance with the Massachusetts
Restructuring Act, and pursuant to the power supply divestiture discussed below,
FG&E began selling the entire output from its joint ownership generating units
on February 1, 2000. Revenues from this sale reflect collection of the costs
associated with FG&E's ownership interest in these generation units.
Accordingly, these expenses do not have an impact on net income. Information
with respect to FG&E's ownership in Wyman Unit No. 4, at December 31, 2002, is
shown below:
Company's
Proportionate Share of Net Book
Joint Ownership Unit State Ownership % Total MW Value (000's)
- ---------------------------------------------------------------------------------------
Wyman Unit No. 4 ME 0.1822 1.13 $ 71
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 annual costs under these contracts are included in
Fuel and
44
Purchased Power and Gas Purchased for Resale in the Consolidated Statements of
Earnings. These costs are recoverable in revenues under various cost recovery
mechanisms. In accordance with the Restructuring Act, and pursuant to the power
supply divestiture discussed below, FG&E began selling the entire output from
its power supply contracts on February 1, 2000.
Under the Restructuring Act, customers not purchasing electric power from
competitive suppliers are eligible either for Standard Offer Service (SOS) or
for Default Service. Many of FG&E's customers are currently eligible for SOS
service. On March 1, 1999, FG&E entered into a contract with Constellation Power
Source to procure power needed to serve the SOS load. The contract will continue
through February 28, 2005. The power required to meet Default Service is
currently being procured through six-month contracts that expire May 31, 2003.
In accordance with MDTE regulations, FG&E will conduct periodic Request for
Proposals (RFP) to procure Default Service at market prices. The next RFP will
be used to procure Default Service effective June 1, 2003.
Power Supply Divestiture - In January 2000, the MDTE approved FG&E's agreement
to sell the output from its remaining electric power supply portfolio to Select
Energy Inc., a subsidiary of Northeast Utilities. FG&E initiated its electric
restructuring process, including the divestiture and sale of its power supply
portfolio, in 1998, in response to the Restructuring Act. Under the Select
Energy contract, which went into effect February 1, 2000, FG&E began selling the
entire output from its remaining power contracts and the output of its two joint
ownership units to Select Energy. Upon the sale of FG&E's share of Millstone 3,
this portion of the contract sale ceased.
FG&E has been allowed recovery of its transition costs, including the
above-market or stranded generation and power-supply related costs, via a
non-bypassable uniform transition charge. The recoverable transition costs,
which have been recorded on FG&E's balance sheet at December 31,2002, as
Regulatory Assets, include $81.1 million of purchased power contracts and $12.3
million of recoverable generation-related assets.
New Hampshire:
Purchased Power Contracts - Unitil Power 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
Fuel and Purchased Power in the Consolidated Statements of Earnings and are
normally recoverable in revenues under various cost recovery mechanisms.
UES, upon the implementation of customer choice, will be required to acquire and
provide transition service power supply to its customers for up to three years.
All existing and new customers will be eligible to receive transition service.
To the extent that UES customers choose a third party supplier for their power
supply and then subsequently return to UES for service, UES will be obligated to
provide default service power supply to these customers.
Power Supply Divestiture - On January 25, 2002, Unitil Power, along with CECo
and E&H, filed a comprehensive electric restructuring proposal under which its
long-term power supply contracts would be sold and/or assigned through a
competitive auction process to a third party and the remaining financial
obligations recovered in their entirety through a retail stranded cost charge.
This proposal included the introduction of customer choice consistent with the
New Hampshire restructuring law, the divestiture of Unitil Power's power supply
portfolio, the recovery of stranded costs, the combination of CECo and E&H into
a planned successor and new distribution rates for the combined company. On
October 25, 2002, the NHPUC approved a multi-party settlement on all major
issues in the proceeding. Under Unitil's approved restructuring plan, Unitil
will divest its existing power supply portfolio and conduct a solicitation for
new power supplies from which to meet its ongoing transition and default service
energy obligations. On February 26, 2003, Unitil filed for final NHPUC approval
of the executed agreements resulting from these divestiture and solicitation
processes, including final tariffs for stranded cost recovery and transition and
default services. The filing proposed a recovery period of approximately eight
years for stranded costs. The implementation of customer choice is targeted for
May 1, 2003.
The Unitil Settlement approved in October 2002, provides for full stranded cost
recovery by UES, and otherwise resolves all of the issues in the federal court
action. The Company has estimated its recoverable stranded costs at $94.5
million, which have been recorded on UES' balance sheet as Regulatory Assets and
Power Supply Buyout Obligations.
45
Note 12: Benefit Plans
Pension Plans - Unitil has a defined benefit pension plan covering substantially
all its employees. The retirement benefits are based upon the employee's level
of compensation and length of service. The Company records annual expense and
accounts for its pension plan in accordance with SFAS No. 87, "Employers'
Accounting for Pensions."
The following table provides the components of net periodic expense (income) for
the plan for years 2002, 2001 and 2000:
Net Periodic Expense (Income) (000's) 2002 2001 2000
- ---------------------------------------------------------------------------------------------
Service Cost $ 1,116 $ 914 $ 850
Interest Cost 2,797 2,639 2,552
Expected Return on Plan Assets (4,181) (4,439) (4,356)
Amortization of Transition Obligation ---- 84 85
Amortization of Prior-Service Cost 102 96 98
Recognized Net Actuarial (Gain) ---- (10) (105)
----------------------------------------------
Net Periodic Benefit Income $ (166) $ (716) $ (876)
----------------------------------------------
Reconciliation of Projected Benefit
Obligations (000's):
- ---------------------------------------------------------------------------------------------
Beginning of Year $ 38,922 $ 35,348 $ 33,371
Service Cost 1,116 914 850
Interest Cost 2,797 2,639 2,552
Amendments 78 ---- (80)
Actuarial (Gain) Loss 1,997 2,173 749
Benefit Payments (2,165) (2,152) (2,094)
----------------------------------------------
End of Year $ 42,745 $ 38,922 $ 35,348
----------------------------------------------
Reconciliation of Fair Value of Plan
Assets (000's):
- ---------------------------------------------------------------------------------------------
Beginning of Year $ 40,943 $ 45,422 $ 45,783
Actual Return of Plan Assets (4,534) (2,327) 1,733
Benefit Payments (2,165) (2,152) (2,094)
----------------------------------------------
End of Year $ 34,244 $ 40,943 $ 45,422
----------------------------------------------
Funded Status (000's):
- ---------------------------------------------------------------------------------------------
Funded Status at December 31 $ (8,501) $ 2,021 $ 10,074
Unrecognized Transition Obligation ---- ---- 84
Unrecognized Prior-Service Cost 919 942 1,038
Unrecognized Loss (Gain) 18,461 7,749 (1,200)
----------------------------------------------
Subtotal 10,879 10,712 9,996
Effect of Regulatory Order (10,879) ---- ----
----------------------------------------------
Prepaid Pension Cost $ ---- $ 10,712 $ 9,996
----------------------------------------------
Unitil had an Accumulated Benefit Obligation (ABO) of $35.3 million, $31.3
million and $29.5 million at December 31, 2002, 2001 and 2000, respectively.
The Effect of Regulatory Order, noted in the table above, is discussed below.
In December 2002, FG&E and UES filed requests with their respective state
regulatory commissions for approval of an accounting order to mitigate certain
accounting requirements related to pension plan assets which have been triggered
by the substantial decline in the capital markets. Due to this decline, at
December 31, 2002, the Company's ABO of $35.3 million exceeded its Fair Value of
Plan Assets of $34.2 million, which created an additional minimum liability of
$1.1 million to be recognized for pension accounting purposes under SFAS No. 87.
The respective state regulatory commissions approved these requests in December
2002. These approvals allow FG&E and UES to treat its additional minimum pension
liability and Prepaid Pension Costs as Regulatory Assets
46
under SFAS No. 71 and avoid the reduction in equity through comprehensive income
that would otherwise be required by SFAS No. 87. These regulatory Orders do not
pre-approve the amount of pension expense to be recovered in future rates. Such
recovery will be subject to review and approval in future rate proceedings.
Based on these approvals, the Company included the additional minimum pension
liabilities of $1.1 million plus Prepaid Pension Costs of $10.9 million, or a
total of $12.0 million, in Regulatory Assets on its balance sheet.
Plan assets are primarily made up of 60% equity and 40% fixed income
investments. Fluctuations in actual equity market returns as well as changes in
general interest rates may result in increased or decreased pension benefit
costs and cash funding requirements in future periods. Likewise, changes in
assumptions regarding discount rates and expected rates of return on plan assets
could also increase or decrease pension benefit costs and cash funding
requirements in future periods. The weighted average discount rates used in
determining the Projected Benefit Obligation in 2002, 2001 and 2000 were 7.00%,
7.25% and 7.75%, respectively. The rate of increase in future compensation
levels was 4.00% and the expected long-term rate of return on assets was 9.25%
in 2002, 2001 and 2000.
Unitil Service 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 $137,000, $136,000 and $112,000 for the years ended December 31,
2002, 2001 and 2000, respectively.
Employee 401(k) Tax Deferred Savings Plan - Unitil 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
current compensation by contributing to the plan. The Company matches
contributions, with a maximum matching contribution of 3% of current
compensation. Employees may direct, at their sole discretion, the investment of
their savings plan balances both the employer and employee portions 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 $483,000, $446,000 and $425,000 for the years ended December 31,
2002, 2001 and 2000, respectively.
Post-Retirement Benefits - Unitil's subsidiaries provide health care benefits to
retirees for a 12-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,
2002, 2001 and 2000, the accumulated post-retirement benefit obligation
(transition obligation) was approximately $214,000, $235,000 and $257,000,
respectively, and the period cost associated with these benefits for 2002, 2001
and 2000 was approximately $119,000, $107,000 and $90,000, 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.
In addition, the Company made payments of $1.2 million, $1.0 million and $0.9
million in 2002, 2001 and 2000 respectively, to the Unitil Retiree Trust (URT)
in return for certain advisory services rendered to the Company in those years.
URT is an organization of retirees, incorporated in 1993, to advise Unitil
Corporation regarding customer service and retirement issues and to provide
social, health and welfare benefits to its members, who are eligible former
employees of the Company. URT is under the direction of an independent Board of
Trustees whose voting members are comprised of former employees of the Company,
elected by and from the membership of URT. URT is not a subsidiary of Unitil
Corporation.
47
Note 13: Earnings Per Share
The following table reconciles basic and diluted earnings per share, assuming
all outstanding stock options were converted to common shares per SFAS No. 128,
"Earnings per Share."
(000's except share and per share data) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------
Income before Extraordinary Item $ 5,835 $ 4,770 $ 6,953
Extraordinary Item, net of tax ---- (3,937) ----
---------------------------------------------
Earnings Available to Common Shareholders $ 5,835 $ 833 $ 6,953
=============================================
Weighted Average Common Shares Outstanding - Basic 4,743,696 4,743,576 4,723,171
Plus: Diluted Effect of Incremental Shares -
from Assumed Conversion 18,470 16,246 19,574
Weighted Average Common Shares Outstanding - Diluted 4,762,166 4,759,822 4,742,745
Earnings per Share:
Income before Extraordinary Item $ 1.23 $ 1.01 $ 1.47
Extraordinary Item, net of tax --- $ (0.83) $ ---
---------------------------------------------
Earnings Available to Common Shareholders $ 1.23 $ 0.18 $ 1.47
=============================================
Weighted average options to purchase 54,000, 114,000 and 55,000 shares of Common
Stock were outstanding during 2002, 2001 and 2000, respectively, but were not
included in the computation of Weighted Average Common Shares Outstanding for
purposes of computing diluted earnings per share, because the effect would have
been antidilutive.
Note 14: Segment Information
Unitil reported four segments: utility electric operations, utility gas
operations, other, and non-regulated. 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
UES and FG&E. The Company's wholesale electric power subsidiary, Unitil Power,
principally provides all the electric power supply requirements to UES for
resale at retail. Unitil Resources provides an energy brokering service, through
Usource, as well as various energy consulting activities. Unitil Realty and
Unitil Service provide centralized facilities, operations and administrative
services to support the affiliated Unitil companies.
Unitil Realty and Unitil Service are included in the "Other" column of the table
below. Unitil Service provides centralized management and administrative
services, including information systems management and financial record keeping.
Unitil Realty owns certain real estate, principally the Company's corporate
headquarters. Unitil Resources and Usource are included in the Non-Regulated
column below.
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 based
on factors under the 1935 Act rules and 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.
48
The following table provides significant segment financial data for the years
ended December 31, 2002, 2001 and 2000:
Year Ended December 31, 2002 (000's) Non-
Electric Gas Other Regulated Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------
Revenues $ 167,317 $ 20,283 $ 30 $ 756 $ 188,386
Depreciation and Amortization 10,793 1,998 1,922 198 14,911
Interest, net 4,693 1,692 654 18 7,057
Income Taxes 3,519 (458) (46) (525) 2,490
Segment Profit 6,249 (206) 456 (664) 5,835
Identifiable Segment Assets 384,862 85,366 24,500 1,958 (15,903) 480,783
Capital Expenditures 16,676 3,859 290 ---- 20,825
Year Ended December 31, 2001 (000's)
- -----------------------------------------------------------------------------------------------------------------------
Revenues $ 183,780 $ 22,828 $ 30 $ 384 $ 207,022
Depreciation and Amortization 9,025 1,760 1,753 229 12,767
Interest, net 4,388 1,576 829 4 6,797
Income Taxes 4,527 (457) 2 (651) 3,421
Segment Profit 8,771 (771) 172 (1,002) 7,170
Investment Write-down, net of tax ---- ---- (2,400) ---- (2,400)
Extraordinary Item, net of tax (3,937) ---- ---- ---- (3,937)
Identifiable Segment Assets 288,013 87,851 23,679 834 (23,615) 376,762
Capital Expenditures 14,328 4,817 745 ---- 19,890
Year Ended December 31, 2000 (000's)
- -----------------------------------------------------------------------------------------------------------------------
Revenues $ 160,023 $ 22,756 $ 31 $ 131 $ 182,941
Depreciation and Amortization 8,815 1,575 1,344 230 11,964
Interest, net 4,797 1,370 627 26 6,820
Income Taxes 4,051 199 14 (851) 3,413
Segment Profit 7,923 662 46 (1,678) 6,953
Identifiable Segment Assets 286,437 89,917 24,079 994 (18,460) 382,967
Capital Expenditures 14,066 3,821 3,205 ---- 21,092
Note 15: Commitments and Contingencies
Regulatory Matters -
The Unitil Companies are regulated by various federal and state agencies,
including the SEC, the FERC and state regulatory authorities with jurisdiction
over public utilities, including the NHPUC and the MDTE. In recent years, there
has been significant legislative and regulatory activity to restructure the
utility industry in order to introduce greater competition in the supply and
sale of electricity and gas, while continuing to regulate the distribution
operations of Unitil's utility operating subsidiaries. Unitil implemented the
restructuring of its electric operations in Massachusetts in 1998 and is
implementing a restructuring settlement for its New Hampshire electric
operations that is expected to be on May 1, 2003.
Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E
implemented its Restructuring Plan under the Massachusetts Restructuring Act.
FG&E completed the divestiture of its entire regulated power supply business in
2000 in accordance with the Restructuring Plan. All FG&E distribution customers
must pay a transition charge that provides for the recovery of costs associated
with FG&E's power portfolio which were stranded as a result of the divestiture
of those assets. The plant and Regulatory Asset balances that will be recovered
through the transition charge have been approved by the MDTE as part of FG&E's
annual Reconciliation Filings. The Restructuring Act also requires FG&E to
obtain power for retail customers who choose not to buy energy from a
competitive supplier through either SOS or Default Service. FG&E must provide
SOS through February 2005 at rate levels which guarantee rate reductions
required by the Restructuring Act. New distribution customers and customers no
longer eligible for SOS are eligible to receive Default Service at prices set
periodically based on market solicitations as approved by regulators. As of
December 31, 2002, competitive suppliers were serving approximately 20% of
FG&E's load, mainly for large industrial customers.
49
As a result of the restructuring and divestiture of FG&E's entire generation and
purchased power portfolio, FG&E has accelerated the amortization of its stranded
electric generation assets and its abandoned investment in Seabrook Station, a
nuclear generating unit. FG&E earns an authorized rate of return on the
unamortized balance of these Regulatory Assets. In addition, as a result of the
rate reduction and rate cap requirements of the Restructuring Act, FG&E has been
authorized to defer the recovery of a portion of its transition costs and SOS
costs. These unrecovered amounts are also recorded as Regulatory Assets and earn
authorized carrying charges until their subsequent recovery in future periods.
In 2002, Unitil's earnings derived from these generation-related Regulatory
Assets, including carrying charges earned on deferred transition costs and SOS
costs, represented approximately 10% of net income. The value of FG&E's
Regulatory Assets is approximately $128 million at December 31, 2002, and is
expected to be amortized and recovered over the next three to nine years.
Earnings from this segment of FG&E's utility business will continue to decline
and ultimately cease.
FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002.
Rate adjustments were approved for effect during the subsequent year, subject to
further investigation. In October 2001, the MDTE issued a final Order on FG&E's
1999 Reconciliation Filing which determined the final treatment of Regulatory
Assets attributable to stranded generation costs, purchased power costs, and
related expenses for the 1999, and future, Reconciliation Filings. FG&E's 2001
Reconciliation Filing, submitted on December 2, 2001, recast its rates from 1998
through 2001 in compliance with the MDTE's final Order on its 1999 filing. On
October 15, 2002, the MDTE issued an Order approving a settlement agreement
regarding the Company's 2001 filing. Under the approved settlement, FG&E agreed
to reduce the carrying charge on deferred transition costs that will be
recovered from customers in future years. This change does not affect current
electric rates. The MDTE's October 2002 Order and associated settlement resolve
many of the issues which otherwise might have been contested in FG&E's future
Reconciliation Filings.
FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate
adjustments were approved for effect on January 1, 2003, subject to
investigation, resulting in a rate reduction of approximately 4.4% for
residential SOS customers. The reduction is due to a decrease in the SOS fuel
adjustment, which is not subject to the rate cap, and does not affect net
income.
Massachusetts Gas Operations Restructuring - Following a three year state-wide
collaborative process on the unbundling, or separation, of discrete services
offered by natural gas local distribution companies (LDCs), the MDTE approved
regulations and tariffs for FG&E and other LDCs to provide full customer choice
effective November 1, 2000. The MDTE ruled that LDCs would continue to have an
obligation to provide gas supply and delivery services for a five-year
transition period, with a review after three years. This review is expected to
be initiated in late 2003. The MDTE also required mandatory assignment of LDCs'
pipeline capacity to competitive marketers supplying customers during the
transition period. This mandatory capacity assignment protects LDCs from
exposure to certain stranded gas supply costs during the transition period.
New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire
electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive
restructuring proposal with the NHPUC. This proposal included the introduction
of customer choice consistent with New Hampshire's electric utility industry
restructuring law, the divestiture of Unitil Power's power supply portfolio, the
recovery of stranded costs, the merger of CECo and E&H into one distribution
company and new distribution rates for the combined company. On October 25,
2002, the NHPUC approved a multi-party settlement on all major issues in the
proceeding, including stranded cost recovery for purchased power contracts. The
Company estimates that these recoverable stranded costs are approximately $94.5
million and these were recorded as Power Supply Buyout Obligations and
Regulatory Assets at December 31, 2002.
Under Unitil's approved restructuring plan, Unitil also agreed to divest its
existing power supply portfolio and conduct a solicitation for new power
supplies from which to meet its ongoing Transition and Default Service energy
obligations. On February 26, 2003, Unitil filed for final NHPUC approval of the
executed agreements resulting from these divestiture and solicitation processes,
including final tariffs for stranded cost recovery and Transition and Default
Services. The filing proposed a recovery period of approximately eight years for
stranded costs. The implementation of customer choice for UES customers is
targeted to begin May 1, 2003.
Unitil's restructuring plan is also designed to resolve the pending litigation
on this matter. In June 1997, Unitil and other New Hampshire utilities
intervened as plaintiffs in a suit filed in U.S. District Court by Northeast
Utilities' affiliate Public Service Company of New Hampshire for protection from
the NHPUC's Final Plan to restructure the New Hampshire electric utility
industry. Although the NHPUC found that CECo and E&H were entitled to full
50
interim stranded cost recovery, the NHPUC also made certain legal rulings, that,
if implemented, could affect UES's long-term ability to recover all of its
stranded costs. The Unitil Settlement, approved in October 2002, otherwise
resolves all of the issues in the federal court action. Upon receipt the
expiration of all periods of appeal with respect to the restructuring proceeding
by the NHPUC thereto, UES will implement retail choice and Unitil will withdraw
its intervention in this federal court action, with prejudice.
Wholesale Power Market Restructuring - Unitil has also been a participant in the
restructuring of the wholesale power market and transmission system in New
England, which is subject to FERC jurisdiction. New wholesale markets structured
pursuant to FERC's Standard Market Design are expected to be implemented in the
New England Power Pool during the first half of 2003 under the general
supervision of an Independent System Operator and the regulatory oversight of
the FERC.
Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated
by the Company to increase base rates for Unitil's retail electric operating
subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The
last distribution base rate increase request for FG&E's retail gas operations
occurred in 1998. In 2001, FG&E's electric base rates were investigated by the
MDTE, which resulted in an electric base rate decrease. A majority of the
Company's electric and gas operating revenues are collected under various
periodic rate adjustment mechanisms including fuel, purchased power, energy
efficiency and restructuring-related cost recovery mechanisms. Industry
restructuring will continue to change the methods of how certain costs are
recovered through the Company's regulated rates and tariffs.
On the gas side, FG&E continues to provide a multi-year refund through its Cost
of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding
that FG&E had over-collected fuel inventory finance charges. At December 31,
2002, the unamortized balance of this refund was $1.3 million. FG&E believes a
refund is not justified or warranted and has appealed the MDTE's ruling to the
Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single
justice of the SJC declined to stay the MDTE's Order based on a finding that
refunds made by FG&E may be recouped if FG&E prevails on the merits of its
claims. The review of the MDTE Order by the SJC is pending.
On October 25, 2002, as part of the electric restructuring settlement for
Unitil's New Hampshire utility operations described above, the Company received
approval from the NHPUC for an increase of approximately $2.0 million in annual
distribution revenues for UES, effective December 1, 2002.
On December 2, 2002, the MDTE issued an Order resulting in distribution rate
increases of $2.0 million for FG&E's electric operations and $3.0 million for
FG&E's gas operations. Increases for rising gas costs were incorporated into the
final gas rates. FG&E's new rates became effective on December 2, 2002.
On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the
MDTE for both electric and gas operations. PBR is a method of setting regulated
distribution rates that provides incentives to control costs while maintaining a
high level of service quality. Under PBR, a company's earnings are tied to
performance targets, and penalties can be imposed for deterioration of service
quality. FG&E's PBR Plans were filed in conjunction with FG&E's distribution
rate filings, consistent with MDTE policy to implement PBR in the context of
base rate cases. The MDTE did not initiate investigations of the filings. On
January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's
PBR plans have no scheduled date of implementation, and conventional cost-based
regulation continues to apply.
In December 2002, FG&E and UES filed requests with their respective state
regulatory commissions for approval of an accounting Order to mitigate certain
accounting requirements related to pension plan assets, which have been
triggered by the substantial decline in the capital markets. These requests were
granted by the respective state regulatory commissions in December 2002. These
approvals allow FG&E and UES to treat the additional minimum pension liability
and Prepaid Pension Costs as Regulatory Assets under SFAS No. 71 and avoid the
reduction in equity that would otherwise be required by SFAS No. 87. These
regulatory Orders do not pre-approve the amount of pension expense to be
recovered in future rates. Such recovery will be subject to review and approval
in future rate proceedings. Based on these approvals, Unitil has included the
amount of the additional minimum pension liabilities and Prepaid Pension Costs
of $12.0 million in Regulatory Assets on its balance sheet.
51
Environmental Matters -
The Company's past and present operations include activities that are subject to
extensive federal and state environmental regulations.
Sawyer Passway MGP Site - The Company continues to work with environmental
regulatory agencies to identify and assess environmental issues at the former
manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg,
Massachusetts. FG&E proceeded with site remediation work as specified on the
Tier 1B permit issued by the Massachusetts Department of Environmental
Protection (DEP), which allows the Company to work towards temporary remediation
of the site. Work performed in 2002 was associated with the five-year review of
the Temporary Solution submittal (Class C Response Action Outcome) under the
Massachusetts Contingency Plan that was filed for the site in 1997. Completion
of this work has confirmed the Temporary Solution status of the site for an
additional five years. A status of temporary closure requires FG&E to monitor
the site until a feasible permanent remediation alternative can be developed and
completed.
Since 1991, FG&E has recovered the environmental response costs incurred at this
former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement).
The Agreement allows FG&E to amortize and recover from gas customers over
succeeding seven-year periods the environmental response costs incurred each
year. Environmental response costs are defined to include liabilities related to
manufactured gas sites, waste disposal sites or other sites onto which hazardous
material may have migrated as a result of the operation or decommissioning of
Massachusetts gas manufacturing facilities from 1882 through 1978. In addition,
any recovery that FG&E receives from insurance or third parties with respect to
environmental response costs, net of the unrecovered costs associated therewith,
are split equally between FG&E and its gas customers. The total annual charge
for such costs assessed to gas customers cannot exceed five percent of FG&E's
total revenue for firm gas sales during the preceding year. Costs in excess of
five percent will be deferred for recovery in subsequent years.
Former Electric Generating Station - The Company is remediating environmental
conditions at a former electric generating station located at Sawyer Passway,
which FG&E sold to WRW, a general partnership, in 1983. Rockware International
Corporation (Rockware), an affiliate of WRW, acquired rights to the electric
equipment in the building and intended to remove, recondition and sell this
equipment. During 1985, Rockware demolished several exterior walls of the
generating station in order to facilitate removal of certain equipment. The
demolition of the walls and the removal of generating equipment resulted in
damage to asbestos-containing insulation materials inside the building, which
had been intact and encapsulated at the time of the sale of the structure to
WRW.
When Rockware and WRW encountered financial difficulties and failed to respond
adequately to Orders of the environmental regulators to remedy the situation,
FG&E agreed to take steps at that time and obtained DEP approval to temporarily
enclose, secure and stabilize the facility. Based on that approval, between
September and December 1989, contractors retained by FG&E stabilized the
facility and secured the building. This work did not permanently resolve the
asbestos problems caused by Rockware, but was deemed sufficient for the then
foreseeable future.
Due to the continuing deterioration of this former electric generating station
and Rockware's continued lack of performance, FG&E, in concert with the DEP and
the U.S. Environmental Protection Agency (EPA), conducted further testing and
survey work during 2001 to ascertain the environmental status of the building.
Those surveys revealed continued deterioration of the asbestos-containing
insulation materials in the building.
By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially
Responsible Party for planned remedial activities at the site and invited FG&E
to perform or finance such activities. FG&E and the EPA have entered into an
Agreement on Consent, whereby FG&E, without an admission of liability, will
conduct environmental remedial action to abate and remove asbestos-containing
and other hazardous materials. FG&E has awarded contracts for all aspects of the
abatement work, which is presently ongoing. FG&E received significant coverage
from its insurance carrier. The Company believes that these funds will be
sufficient to complete this remediation and that resolution of this matter will
not have a material adverse impact on the Company's financial position.
52
The Company has recorded the estimated cost of the remediation action in Current
Liabilities and an offsetting asset reflecting insurance proceeds in Current
Assets. At the balance sheet date, net of amounts expended in 2002, the
remaining project cost was $3.7 million.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
53
PART III
Item 10. Directors and Executive Officers of the Registrant
Information required by this Item is set forth on pages 3 through 7 of the 2002
Proxy Statement as filed with the Securities and Exchange Commission on March
12, 2003.
Item 11. Executive Compensation
Information required by this Item is set forth on pages 12 through 23 of the
2002 Proxy Statement as filed with the Securities and Exchange Commission on
March 12, 2003.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this Item is set forth on pages 4 through 7 and pages 16
through 18 of the 2002 Proxy Statement as filed with the Securities and Exchange
Commission on March 12, 2003.
Item 13. Certain Relationships and Related Transactions
None
54
PART IV
Item 14. Controls and Procedures
Within the 90 days prior to the date of this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Company's Chief Executive Officer, Chief Financial
Officer and Controller, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Rule 13a-14 under the
Securities Exchange Act of 1934, as amended. Based upon that evaluation, the
Chief Executive Officer, Chief Financial Officer and Controller concluded that
the Company's disclosure controls and procedures are effective in timely
alerting them to material information relating to the Company required to be
included in the Company's periodic SEC filings.
There have been no significant changes in the Company's internal controls or in
other factors, which could significantly affect internal controls subsequent to
the date the Company carried out its evaluation.
Item 15. 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:
o Report of Independent Certified Public Accountants
o Consolidated Balance Sheets - December 31, 2002 and 2001
o Consolidated Statements of Earnings for the years ended December 31,
2002, 2001, and 2000
o Consolidated Statements of Capitalization - December 31, 2002 and 2001
o Consolidated Statements of Cash Flows for the years ended December 31,
2002, 2001, and 2000
o Consolidated Statements of Changes in Common Stock Equity for the
years ended December 31, 2002, 2001, and 2000
o Notes to Consolidated Financial Statements
The following consolidated financial statement schedule of the Company and
subsidiaries is included in Item 15(d):
o Schedule II Valuation and Qualifying Accounts for December 31, 2002,
2001, and 2000
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 not applicable, or information required is included in
the financial statements or notes thereto and, therefore, have been omitted.
55
(3) - List of Exhibits
Exhibit Number 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 Exhibit 3.2 to Form
Filed on March 4, 1992 and 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), Exhibit 3.3 to
Exeter & Hampton Electric Company (E&H) and the Company. 10-K for 1984
3.5 Articles of Exchange of CECo, E&H, and the Company - Stipulation of Exhibit 3.4 to
the Parties Relative to Recordation and Effective Date. Form 10-K 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 Light Company (FG&E) and UMC Form 8-K dated March 1,
Electric Co., Inc. (UMC). 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 and UMC. Form 8-K dated December
14, 1989
4.1 Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., Filed herewith
successor to Concord Electric Company, dated as of December 2,
2002, amending and restating the Concord Electric Company Indenture
of Mortgage and Deed of Trust dated as of July 15, 1958.
4.2 FG&E Purchase Agreement dated March 20, 1992 for the 8.55% Senior Exhibit 4.18 to
Notes due March 31, 2004 Form 10-K for 1993
4.3 FG&E Note Agreement dated November 30, 1993 for the 6.75% Notes due Exhibit 4.18 to
November 23, 2023. Form 10-K for 1993
4.4 FG&E Note Agreement dated January 26, 1999 for the 7.37% Notes due Exhibit 4.25 to
January 15, 2028. Form 10-K for 1999
4.5 FG&E Note Agreement dated June 1, 2001 for the 7.98% Notes due June Exhibit 4.6 to
1, 2031. Form 10-Q for
June 30, 2001
4.6 Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for Exhibit 4.22 to
the 8.00% Senior Secured Notes due August 1, 2017. Form 10-K for 1997
10.1 Unitil System Agreement dated June 19, 1986 providing that Unitil Exhibit 10.9 to
Power will supply wholesale requirements electric service to CECo Form 10-K for 1986
and E&H.
56
Exhibit Number Description of Exhibit Reference*
- -------------- ---------------------- ----------
10.2 Supplement No. 1 to Unitil System Agreement providing that Unitil Exhibit 10.8 to
Power will supply wholesale requirements electric service to CECo Form 10-K for 1987
and E&H.
10.3 Transmission Agreement between Unitil Power Corp. and Public Exhibit 10.6 to
Service Company of New Hampshire, effective November 11, 1992. Form 10-K for 1993
10.4 Form of Severance Agreement dated February 21, 1989, between the Exhibit 10.55 to
Company and the persons named in the schedule attached thereto. Form 8 dated
April 12, 1989
10.5 Key Employee Stock Option Plan effective January 17, 1989. Exhibit 10.56 to
Form 8 dated
April 12, 1989
10.6 Unitil Corporation Key Employee Stock Option Plan Award Agreement. Exhibit 10.63 to
Form 10-K for 1989
10.7 Unitil Corporation Management Performance Compensation Plan. Exhibit 10.94 to
Form 10-K/A for 1993
10.8 Unitil Corporation Supplemental Executive Retirement Plan effective Exhibit 10.95 to
as of January 1, 1987. Form 10-K/A for 1993
10.9 Unitil Corporation 1998 Stock Option Plan. Exhibit 10.12 to
Form 10-K for 1998
10.10 Unitil Corporation Management Incentive Plan. Exhibit 10.13 to
Form 10-K for 1998
10.11 Entitlement Sale and Administrative Service Agreement with Select Exhibit 10.14 to
Energy. Form 10-K for 1999
10.12 Purchase and Sale Agreement For New Haven Harbor. Exhibit 10.15 to
Form 10-K for 1999
10.13 Labor Agreement effective June 1, 2000 between CECo and The Exhibit 10.13 to
International Brotherhood of Electrical Workers, Local Union No. Form 10-K for 2000
1837.
10.14 Labor Agreement effective June 1, 2000 between E&H and The Exhibit 10.14 to
International Brotherhood of Electrical Workers, Local Union No. Form 10-K for 2000
1837.
10.15 Labor Agreement effective June 1, 2000 between FG&E and The Utility Exhibit 10.15 to
Workers of America, AFL-CIO., Local Union No. B340, The Brotherhood Form 10-K for 2000
of Utility Workers Council.
10.16 Unitil Corporation 2003 Restricted Stock Plan Filed herewith
10.17 Portfolio Sale and Assignment and Transition Service and Default Filed herewith
Service Supply Agreement By and Among Unitil Power Corp., Unitil
Energy Systems, Inc. and Mirant Americas Energy Marketing, LP
11.1 Statement Re: Computation in Support of Earnings per Share For the Filed herewith
Company.
57
Exhibit Number Description of Exhibit Reference*
- -------------- ---------------------- ----------
12.1 Statement Re: Computation in Support of Ratio of Earnings to Fixed Filed herewith
Charges for the Company.
21.1 Statement Re: Subsidiaries of Registrant. Filed herewith
23.1 Consent of Independent Certified Public Accountants Filed herewith
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Filed herewith
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* 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, 2002.
58
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 25, 2003 By /s/ Robert G. Schoenberger
-------------------------------
Robert G. Schoenberger
Chairman of the Board 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
--------- -------- ----
/s/ Robert G. Schoenberger Principal Executive March 25, 2003
- ------------------------------ Officer; Director
Robert G. Schoenberger
/s/ Michael J. Dalton Principal Operating March 25, 2003
- ------------------------------ Officer; Director
Michael J. Dalton
/s/ Mark H. Collin Principal Financial March 25, 2003
- ------------------------------ Officer
Mark H. Collin
/s/ Albert H. Elfner, III Director March 25, 2003
- ------------------------------
Albert H. Elfner, III
/s/ Ross B. George Director March 25, 2003
- ------------------------------
Ross B. George
/s/ M. Brian O'Shaughnessy Director March 25, 2003
- ------------------------------
M. Brian O'Shaughnessy
/s/ Charles H. Tenney III Director March 25, 2003
- ------------------------------
Charles H. Tenney III
/s/ Dr. Sarah P. Voll Director March 25, 2003
- ------------------------------
Dr. Sarah P. Voll
/s/ Eben S. Moulton Director March 25, 2003
- ------------------------------
Eben S. Moulton
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/s/ David P. Brownell Director March 25, 2003
- ------------------------------
David P. Brownell
/s/ Edward F. Godfrey Director March 25, 2003
- ------------------------------
Edward F. Godfrey
/s/ Michael B. Green Director March 25, 2003
- ------------------------------
Michael B. Green
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CERTIFICATIONS UNDER SECTION 302 OF THE SARBANES-OXLEY ACT
I, Robert G. Schoenberger, certify that:
1) I have reviewed this annual report on Form 10-K of Unitil Corporation;
2) Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3) Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ Robert G. Schoenberger
--------------------------
Robert G. Schoenberger
Chief Executive Officer
61
I, Mark H. Collin, certify that:
1) I have reviewed this annual report on Form 10-K of Unitil Corporation;
2) Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3) Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ Mark H. Collin
------------------
Mark H. Collin
Chief Financial Officer
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I, Laurence M. Brock, certify that:
1) I have reviewed this annual report on Form 10-K of Unitil Corporation;
2) Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3) Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6) The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ Laurence M. Brock
---------------------
Laurence M. Brock
Controller, Unitil Service Corp.
63
SCHEDULE II
UNITIL CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Additions
--------------------------
Balance at Charged to Charged to Deductions Balance at
Beginning Costs and Other from End of
Description of Period Expenses Accounts Reserves Period
(A) (B)
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Reserves Deducted from A/R
Electric $ 457,657 $ 323,401 $ 138,010 $ 646,869 $ 272,199
Gas 142,842 294,051 64,571 401,164 100,300
---------------------------------------------------------------------
$ 600,499 $ 617,452 $ 202,581 $ 1,048,033 $ 372,499
=====================================================================
Year Ended December 31, 2001
Reserves Deducted from A/R
Electric $ 452,872 $ 940,590 $ 86,161 $ 1,021,080 $ 457,657
Gas 142,810 54,162 656,952 711,082 142,842
---------------------------------------------------------------------
$ 595,682 $ 994,752 $ 743,113 $ 1,732,162 $ 600,499
=====================================================================
Year Ended December 31, 2000
Reserves Deducted from A/R
Electric $ 464,797 $ 455,353 $ 81,286 $ 548,564 $ 452,872
Gas 133,803 48,202 413,277 452,472 142,810
---------------------------------------------------------------------
$ 598,600 $ 503,555 $ 494,563 $ 1,001,036 $ 595,682
=====================================================================
$ 646,084 $ 807,059 $ 178,881 $ 1,033,424 $ 598,600
=====================================================================
(A) Collections on Accounts Previously Charged Off
(B) Bad Debts Charged Off
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