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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------------
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 19972002
Commission file number 1-1398
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)(Exact name of registrant as specified in its charter)
Pennsylvania
(State or other jurisdiction of 23-1174060
(STATE OR OTHER JURISDICTIONincorporation or organization) (I.R.S. EMPLOYER IDENTIFICATION NO.Employer Identification No.)
OF INCORPORATION OR ORGANIZATION)
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)(Address of principal offices) (Zip Code)
(610) 796-3400
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NoneNONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NoneNONE
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___.|X| NO | |.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]|X|
At December 1, 1997November 29, 2002, there were 26,781,785, shares of UGI Utilities Common
Stock, par value $2.25 per share, outstanding, all of which were held,
beneficially and of record, by UGI Corporation.Corporation
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No | |
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TABLE OF CONTENTS
Page
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PART II: BUSINESS PAGE1
Items 1 and 2And 2. Business and Properties...................................................Properties................................................. 1
General.................................................................General............................................................... 1
Gas Utility Operations..................................................Operations................................................ 1
Electric Utility Operations............................................. 4
Item 33. Legal Proceedings......................................................... 10Proceedings....................................................... 9
Item 44. Submission of Matters to a Vote of Security Holders........................................................ 14Holders..................... 11
PART IIII: SECURITIES AND FINANCIAL INFORMATION 12
Item 55. Market for Registrant's Common Equity and Related Stockholder Matters......................................... 14Matters... 12
Item 66. Selected Financial Data................................................... 15Data................................................. 13
Item 77. Management's Discussion and Analysis of Financial Condition and Results
of Operations..................................... 16Operations........................................................... 14
Item 87a. Quantitative and Qualitative Disclosures About Market Risk.............. 25
Item 8. Financial Statements and Supplementary Data...............................Data............................. 25
Item 99. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..................................Disclosure.................................................... 25
PART IIIIII: UGI UTILITIES INC. MANAGEMENT AND SECURITY HOLDERS 26
Item 1010. Directors and Executive Officers of the Registrant........................ 25Registrant...................... 26
Item 1111. Executive Compensation.................................................... 30Compensation.................................................. 31
Item 1212. Security Ownership of Certain Beneficial Owners and Management................................................... 39Management and
Related Stockholder Matters............................................. 38
(i)
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Item 1313. Certain Relationships and Related Transactions............................................................Transactions.......................... 40
Item 14. Controls and Procedures................................................. 40
PART IVIV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS 41
Item 1415. Exhibits, Financial Statement SchedulesSchedule, and Reports on Form 8-K.................................................8-K......... 41
Signatures................................................................ 48Signatures............................................................ 47
Certifications........................................................ 50
Index to Financial Statements and Financial Statement Schedule..............................................Schedule........ F-2
(i)(ii)
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PART I: BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities", "UGI Utilities" or the "Company") is a
public utility company that owns and operates (i) a natural gas distribution
utility serving 14 counties in eastern and southeastern Pennsylvania ("Gas
Utility"), and (ii) an electric utility serving parts of Luzerne and Wyoming
Countiescounties in northeastern Pennsylvania ("Electric Utility"). Utilities isIn response to state
deregulation legislation, effective October 1, 1999 we transferred our electric
generation assets to our non-utility subsidiary, UGI Development Company
("UGID"). UGID contributed certain of its generation assets to a joint venture
with a subsidiary of Allegheny Energy, Inc. in December 2000. We are a wholly
owned subsidiary of UGI Corporation ("UGI").
Utilities (formerly, UGI Corporation) was incorporated in Pennsylvania in 1925 as the successor to a
business founded in 1882. The Company isWe are subject to regulation by the Pennsylvania
Public Utility Commission ("PUC"). ItsOur executive offices are located at 100
Kachel Boulevard, Suite 400, Green Hills Corporate Center, Reading, Pennsylvania
19607, and itsour telephone number is (610) 796-3400. ReferencesIn this report, the terms
"Company" and "Utilities," as well as the terms, "our," "we," and "its," are
sometimes used to the "Company" includerefer to UGI Utilities, Inc. or, collectively, UGI Utilities,
Inc. and its consolidated subsidiaries unless the context indicates otherwise.subsidiaries.
GAS UTILITY OPERATIONS
Service Area; Revenue Analysis.NATURAL GAS CHOICE AND COMPETITION ACT
On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act
("Gas Competition Act") was signed into law. The purpose of the Gas Competition
Act was to provide all natural gas consumers in Pennsylvania with the ability to
purchase their gas supplies from the supplier of their choice. Under the Gas
Competition Act, local distribution companies ("LDCs") like Gas Utility may
continue to sell gas to customers, and such sales of gas, as well as
distribution services provided by LDCs, continue to be subject to price
regulation by the PUC.
Generally, Pennsylvania LDCs will serve as the supplier of last resort for
all residential and small commercial and industrial customers unless the PUC
approves another supplier of last resort. The Gas Competition Act requires
energy marketers seeking to serve customers of LDCs to accept assignment of a
portion of the LDC's interstate pipeline capacity and storage contracts at
contract rates, thus avoiding the creation of stranded costs.
On October 1, 1999, Gas Utility filed its restructuring plan with the PUC
pursuant to the Gas Competition Act. On June 29, 2000, the PUC entered its order
("Gas Restructuring Order") approving Gas Utility's restructuring plan
substantially as filed. Gas Utility designed its restructuring plan to ensure
reliability of gas supply deliveries to Gas Utility on behalf of
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residential and small commercial and industrial customers. In addition, the plan
changed Gas Utility's base rates for firm customers. It also changed the
calculation of purchased gas cost rates. See "Utility Regulation and Rates."
Since October 1, 2000, all of Gas Utility's customers have had the option
to purchase their gas supplies from an alternative gas supplier. Large
commercial and industrial customers of Gas Utility have been able to purchase
their gas from other suppliers since 1982. During fiscal year 2002, two
third-party suppliers qualified to serve residential or small commercial and
industrial customers in Gas Utility's service territory. Together, they are
serving approximately 2,400 customers. Management believes none of the Gas
Competition Act, the Gas Restructuring Order, or commodity sales to core-market
customers by third party suppliers will have a material adverse impact on the
Company's financial condition or results of operations.
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 252,000286,000 customers in
portions of 14 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,2004,700 miles of gas mains. The service area
consists of approximately 3,000 square miles and includes the cities of
Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon and
Reading, Pennsylvania. Located in Gas Utility's service area are major
production centers for basic industries such as steel
fabrication. For the fiscal years ended September 30, 1997, 1996specialty metals, aluminum and
1995,
revenues of Gas Utility accounted for approximately 84%, 85% and 82%,
respectively, of Utilities' total consolidated revenues.glass.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 19972002 fiscal year was
approximately 80.270.5 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 46%41% of system throughput, while gas transported for residential,
commercial and industrial customers (who buybought their gas from others) accounted
for approximately 54%59% of system throughput. Based on industry data for 1996,2000,
residential customers account for approximately 38%31% of total system throughput
by local gas
distribution companiesLDCs in the United States. By contrast, for the 19972002 fiscal year, Gas
Utility's residential customers represented 23%24% of its total system throughput.
Sources of Supply and Pipeline Capacity.SOURCES OF SUPPLY AND PIPELINE CAPACITY
Gas Utility meets its service requirements by utilizing a diverse mix of
natural gas purchase contracts with producers and marketers, and storage and
transportation services from pipeline
companies, and its own propane-air and liquefied natural
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gas peak-shaving facilities. Purchases of natural gas in the spot market are
also made to reduce costs and manage storage inventory levels.service contracts. These arrangements enable Gas Utility to
purchase gas from Gulf Coast, mid-continent,Mid-Continent, Appalachian and Canadian sources.
For the transportation and storage function, Utilities has agreements with a
number of pipeline companies, including Texas Eastern Transmission Corporation,
Columbia Gas Transmission Corporation ("Columbia"), ANR Pipeline Company, Columbia Gulf Transmission Company, CNG
Transmission Corporation, National Fuel Gas Supply Corporation,and Transcontinental Gas Pipeline
Corporation, Trunkline Gas Company, Texas Gas Transmission
Corporation and Panhandle Eastern Pipe Line Company.
Gas Supply Contracts.Corporation.
GAS SUPPLY CONTRACTS
During the 1997 fiscal year 2002, Gas Utility purchased approximately 37.528 bcf of
natural gas and sold approximately 36.8 bcf
to customers. Gas not sold to customers was used by Gas Utility principally for
storage for later sale to customers. Approximately 31 bcf or 83%90% of the volumes purchased
were supplied under
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agreements with six major suppliers of natural
gas.suppliers. The remaining 6.5 bcf or 17%10% of
gas purchased was supplied by over 30 producers and marketers under other arrangements, including multi-month agreements at spot
prices. Certain gasmarketers. Gas supply
contracts require minimum gas purchases. Each of
these agreements, however, either terminates inare generally no longer than one year.
In fiscal year 1998, or includes
provisions which entitle2002, as a result of changing market conditions following
the bankruptcy of Enron Corp., a number of suppliers that Utilities formerly did
business with exited the wholesale trading market. This development did not
significantly impact Utilities' ability to terminate in the event the agreement is
not market responsive.
Storage and Peak Shaving. Gas Utility contracts for 10.8 bcf of
seasonal storage with several interstate pipelines. Gas is injected in storage
during the summer and delivered during the winter at combined peak day
capacities of approximately .14 bcf. In Harrisburg, Reading and Bethlehem,
Pennsylvania, Gas Utility operates peak-shaving facilities capable of producing
.06 bcf ofsecure gas per day from propane-air and liquefied natural gas facilities.
These facilities are used to meet winter peak service requirements.
Seasonal Variation. Approximately 58% of Gas Utility's system
throughput for the 1997 fiscal year occurred during the winter season from
November 1, 1996 through March 31, 1997, becausesupplies.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes.
Competition.purposes, Gas Utility's
sales are seasonal. Approximately 57% of fiscal year 2002 throughput and
approximately 68% of earnings before interest expense, income taxes,
depreciation and amortization occurred during the winter season from November
through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
aggressively seeking new load, primarily in the new construction market. Competition with fuelFuel oil dealers
is focused oncompete for customers in all categories, including industrial customers. Gas
Utility responds to this competition with marketing efforts designed to retain
and grow its customer base.
In substantially all of its service territory, Gas Utility is the only
regulated gas distribution utility having the right, granted by the PUC or by
law, to provide transportationgas distribution services. While unregulatedUnder the Gas Competition Act, retail
customers may purchase their natural gas marketers have
been selling gas to commercialfrom a supplier other than Gas Utility.
Commercial and industrial customers in Gas Utility's service territory for over 12 years,have been
able to do this since 1982. As of October 2002, two marketers have qualified to
serve residential and small commercial and industrial customers. Together they
serve approximately 2,400 customers. Gas Utility provides transportation
services for those sales.
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Customers representing approximately 25%residential and small commercial and industrial customers who
purchase natural gas from others.
Many of the Company's
non-residential system throughput (11% of non-residential revenues)Gas Utility's commercial and industrial customers have the ability
to switch to an alternate fuel at any time and, therefore, are served on an
interruptible basis under flexible, interruptible rates which are competitively priced with respect to
their alternate fuel. Gas Utility's marginsprofitability from these customers,
therefore, areis affected by the spreaddifference, or "spread," between the customers'
delivered cost of gas and the customers' delivered alternate fuel cost. In addition, otherSee
"Utility Regulation and Rates - Gas Utility Rates." Commercial and industrial
customers representing 30%17% of non-residentialtotal system throughput (8% of non-residential
revenues) have locations which
afford them the option, although none has exercised it, of seeking
transportation service directly from interstate pipelines, thereby bypassing Gas
Utility,
although none have done so.Utility. The majority of these customers in this group are served under transportation
contracts having three- to ten-yeartwenty-year terms. Included in these two groups are
theUtilities' ten Utilities'largest customers with the highest volumein terms of system
throughput. Threeannual volume. All of the top fivethese
customers have executed ten-year agreementscontracts with Utilities.Utilities, eight of which extend into
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fiscal year 2004. No single customer represents, or is anticipated to represent,
more than 5% of the total revenues of Gas Utility.
Outlook for Gas Service and Supply.OUTLOOK FOR GAS SERVICE AND SUPPLY
Gas Utility anticipates having adequate pipeline capacity and sources of
supply available to it to meet the full requirements of all firm customers on
its system at least through fiscal year 1998.2003. Supply mix is diversified, market priced,
and delivered pursuant to a number of longlong- and short-term firm transportation
and storage arrangements.arrangements, including transportation contracts held by some of
Utilities' larger customers.
During the 1997 fiscal year 2002, Gas Utility supplied transportation service to
threetwo major cogeneration installations.installations and three electric generation facilities.
Gas Utility continues to pursue opportunities to supply natural gas to electric
generation projects located in its service territory. Gas Utility also continues
to seek new residential, commercial and industrial customers for both firm and
interruptible service. In the residential market sector, Gas Utility connected
6,882
additionalapproximately 9,200 residential heating customers during the 1997 fiscal year an
increase of 8% from the previous year. Approximately 63% of the additions
represent gas2002, which
represented a record annual increase. Of those new customers, from the new home
construction market. The remaining 37%
represent customersaccounted for over 7,100 heating customers. Customers converting
from other energy sources, primarily oil and electric, and existing non-heating
gas customers who have added gas heating systems to replace other energy
sources.sources, accounted for the balance of the additions. The total number of new
commercial and industrial customers was 1,068, down slightly from 1,122 in fiscal year 1996.over 1,100.
Utilities continues to monitor and participate extensively in third-partyrulemaking
and individual rate and tariff proceedings before the Federal Energy Regulatory
Commission ("FERC") affecting the rates and the terms and conditions under which
Gas Utility transports and stores natural gas. Among these proceedings are those
arising out of certain FERC orders and/or pipeline filings which relate to (i)
the relative
pricing of pipeline services in a competitive energy marketplace; (ii) the
flexibility of the terms and conditions of pipeline service tariffs and
contracts; and (iii) pipelines' requests to increase their base rates, or change
the terms and conditions of their storage and transportation services.
Gas Utility continues to take the measures it believes necessary,Utility's objective in negotiations with interstate pipeline and
natural gas suppliers, and in caseslitigation before regulatory agencies, is to
assure availability of supply, transportation and storage alternatives to serve
market requirements at the lowest cost consistent
withpossible, taking into account the need
for security of supply considerations. Those measures include negotiating
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6supply. Consistent with that objective, Gas Utility negotiates
the terms of firm transportation capacity from production areas on all pipelines serving Gas Utility,
arrangingarranges for appropriate storage and peak-shaving resources, negotiatingnegotiates with
producers for competitively priced secure gas purchases and aggressively participatingparticipates
in regulatory proceedings related to transportation rights and costs of service and gas costs.service.
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ELECTRIC UTILITY OPERATIONS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, Pennsylvania's Electricity Generation Customer Choice
and Competition Act (Customer Choice Act)("ECC Act") became effective. The Customer
ChoiceECC Act permits all
Pennsylvania retail electric customers to choose their electric generation
supplier over a three-year phase-in period commencing
January 1, 1999. The Customer Choicesupplier. Pursuant to the Act, requires all electric utilities were required to file
restructuring plans with the PUC which, among other things, includeincluded unbundled
prices for electric generation, transmission and distribution and a competitive
transition charge (CTC) for the recovery of "stranded costs" which would be paid
by all customers receiving distribution service and certain customers that
increase their own generation of electricity. "Stranded costs"service. Stranded costs generally are
electric generation-related costs that traditionally would be recoverable in a
regulated environment but may not be recoverable in a competitive electric
generation market. Under the Customer ChoiceECC Act, Electric Utility's rates for
transmission and distribution services provided through June 30, 2001 are capped
at levels in effect on January 1, 1997. In addition, Electric Utility generally may not
increase theprices for electric generation component of prices as long as stranded costs are being
recovered through the CTC. In accordance with the restructuring proceedings
discussed below, Utilities collected a CTC from commercial and industrial
customers until September 2002 and expects to collect from all other
distribution customers until May 2003. Under the ECC Act, Electric Utility is
obligated to provide energy at the capped rates to customers who do not choose
alternate suppliers. Electric Utility will continue to be the only regulated
electric utility having the right, granted by the PUC or by law, to distribute
electric energy in its service territory.
On June 19, 1998, the PUC entered its Opinion and Order (the
"Restructuring Order") in Electric Utility's restructuring proceeding under the
ECC Act. The Electric Restructuring Order authorized Electric Utility has filedto recover
from its restructuring plan with the PUC
("Restructuring Plan"). The Restructuring Plan includes a claim for the recovery
of $34.4customers approximately $32.5 million forin stranded costs during the(on a full
revenue requirements basis, which includes all income and gross receipts taxes)
over a four-year period which commenced January 1, 1999 through a CTC, together
with carrying charges on unrecovered balances of 7.94%.
The PUC approved a settlement establishing rules for Electric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively, the "POLR
Settlement") under which Electric Utility terminated stranded cost recovery
through its CTC from commercial and industrial ("C&I") customers on July 31,
2002, and from residential customers on October 31, 2002, and is no longer
subject to the statutory rate caps as of August 1, 2002 for C&I customers and as
of November 1, 2002 for residential customers. Charges for generation service
will (1) initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 31, 2002. The major components of this claim are: (1) plant investments
in excess of competitive market value and electric generation facility
retirement costs; (2) potential costs associated with existing power purchase
agreements;2004; and
(3) regulatory assets (principally income taxes) recoverable
from ratepayers under current regulatory practice. Itmay be set at market rates thereafter. Electric Utility may also seeksoffer
multiple year POLR contracts to establishits customers. The POLR Settlement provides for
annual shopping periods during which customers may elect to remain on POLR
service or choose an alternate supplier. Customers who do not select an
alternate supplier will be obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service at a recovery mechanism that would permittime
other than during the recovery of up to an additional $28
million of costs associated withannual shopping period must remain on POLR service until
the buyout or implementation of a December 1993
agreement with Foster Wheeler Penn Resources, Inc. to purchase power from a
wood-fired generator to be constructed by Foster Wheeler. The PUC is expected to
take action on Electric Utility's filing in May 1998.
The Customer Choice Act also authorized the PUC to implement pilot
customer choice programs for up to five percentdate of the noncoincident peak load
of industrial, commercialsecond open shopping period after returning. C&I customers who
return to POLR service at a time other than during the annual shopping period
must remain on POLR service until the next
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open shopping period, and residential customers. In accordance with PUC
directives, Electric Utility implemented such a pilot program effective November
1, 1997. It is anticipated that a full five percent of the
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noncoincident peak load of Electric Utility's industrial, commercial and
residential customers will participatemay, in the pilot.
Given the changing regulatory environment in the electric utility
industry, the Company continuescertain circumstances, be subject to
evaluate its ability to apply the provisions
of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), as it relates to its electric generation operation. SFAS 71 permits
the recording of costs (regulatory assets) that have been, or are expected to
be, allowed in the ratesetting process in a period different from the period in
which such costs would be charged to expense by an unregulated enterprise. The
Company believes its electric generation assets and related regulatory assets
continue to satisfy the criteria of SFAS 71. If such electric generation assets
no longer meet the criteria of SFAS 71, then any related regulatory assets would
be written-off unless some form of transition cost recovery is established by
the PUC which would meet the requirements under generally accepted accounting
principles for continued accounting as regulatory assets during such recovery
period. Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Based upon an evaluation of the various factors and conditions
affecting future cost recovery, the Company does not expect the Customer Choice
Act to have a material adverse effect on its financial condition or results of
operations.
Service Area; Revenue Analysis.rate surcharges.
SERVICE AREA; SALES ANALYSIS
Electric Utility supplies electric service to approximately 61,00061,500
customers in portions of Luzerne and Wyoming Counties in northeastern
Pennsylvania through a system consisting of approximately 2,100 miles of
transmission and distribution lines and 14 transmission substations. For the 1997 fiscal
year 2002, about 53%52% of sales volume came from residential customers, 34%36% from
commercial customers and 13%12% from industrial customers. Electricity transported
for customers and others. Forwho purchased their power from others pursuant to the 1997, 1996 and 1995ECC Act
represented approximately 1% of fiscal years,
revenues of Electric Utility accounted for approximately 16%, 15% and 18%,
respectively,year 2002 sales volume.
SOURCES OF SUPPLY
Effective October 1, 1999, Utilities transferred its electric generation
assets to its non-utility subsidiary, UGI Development Company ("UGID"). These
generation assets consisted principally of Utilities' total consolidated revenues.
Sources of Supply. Electric Utility distributes electricity which it
generates or purchases from others. As the provisions of the Customer Choice Act
are implemented, it will also distribute electric power acquired and transmitted
by others. Utilities owns and operates Hunlock generating station
("Hunlock Station"), located near Kingston, Pennsylvania ("Hunlock Station"), and has aits 1.11% ownership interest
in the Conemaugh generating station located near Johnstown, Pennsylvania
("Conemaugh Station"), which is operated by another utility. These two
coal-fired stations can generate uplocated near
Johnstown, Pennsylvania. Effective December 8, 2000, UGID entered into a
partnership ("Energy Ventures") with a subsidiary of Allegheny Energy, Inc. for
the purpose of owning and operating electric generation facilities. UGID
contributed Hunlock Station, coal inventory and $6 million to 69 megawattsthe partnership
and Allegheny contributed a 44 megawatt gas combustion electric generator. UGID
has the right to purchase half the output of electric power forEnergy Ventures' generation at
cost. During fiscal year 2002, Electric Utility and providedpurchased approximately 47%28% of
its energy requirements during the 1997from UGID. Effective October 1, 2002, Electric Utility
has generation supply contracts in place for substantially all of its expected
on-peak energy requirements through fiscal year.
Utilities has a long-term power supply agreement with Pennsylvania
Power & Light Company ("PP&L"). Under this agreement, PP&L supplies allyear 2004. UGID plans to market the
electric power required bygeneration it controls to third parties.
Electric Utility abovedistributes both electricity that providedit purchases from
certainothers (including UGID) and electricity that customers purchase from other
sources, including Hunlock Station. The costsuppliers. At September 30, 2002, alternate suppliers served customers
representing less than 1% of electricity supplied by
PP&L is based on PP&L's actual system costs. Utilities estimates thatload. Electric Utility expects to continue
to provide energy to the cost
of electricity supplied by Hunlock is higher than projected market rates, but
lower
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than the cost of electricity purchased under the PP&L contract. As a result of
the availability and projected cost of alternative supplies, Utilities has
provided PP&L with noticegreat majority of its intent to stop purchasing power underdistribution customers for the
power
supply agreement as of March 2001. In addition, if certain conditions occur
(i.e., Electric Utilities' demand falls to zero in any particular billing
month), the power supply agreement may terminate at an earlier date. There
currently is a dispute between Utilities and PP&L over the effect of customer
choice on Utilities' obligations under the PP&L power supply agreement.
Utilities has filed an action in the Court of Common Pleas of Luzerne County,
Pennsylvania seeking a declaration of the rights and responsibilities of the
parties to the agreement.
In a regulated utility environment, Hunlock Station could be expected
to operate until the end of its useful life in 2004. As a result of electric
deregulation, however, Hunlock may cease operations as early as January 1, 1999,
depending on a number of factors, including customer load, contract purchase
obligations and the availability and cost of replacement power. Until
restructuring proceedings under the Customer Choice Act are completed, Utilities
will be unable to predict how long Hunlock Station will operate.
Environmental Factors. Theforeseeable future.
ENVIRONMENTAL FACTORS
Energy Ventures' operation of Hunlock Station complies with the air
quality standards of the Pennsylvania Department of Environmental Resources
("DER") with respect to stack emissions. Under the Federal Water Pollution
Control Act, UtilitiesUGID has a permit from the DER to discharge water from Hunlock
Station into the North Branch of the Susquehanna River. The Federal Clean Air
Act Amendments of 1990 (the "Clean Air Act Amendments") impose emissions
limitations for certain compounds, including sulfur dioxide and nitrous oxides.
TheBoth
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the Conemaugh Station is in compliance with
these standards, and the Hunlock Station is required to meetare in material compliance with
these emission standards by 1999.
In compliance with the Clean Air Act Amendments, the DER issued final
Reasonably Available Control Technology ("RACT") regulations for nitrous oxides
in January 1994. These regulations are applicable to Hunlockstandards.
SEASONALITY
Sales and Conemaugh
Stations. Utilities' compliance plans for Hunlock Station and Conemaugh Station
have been approved by the DER. Capital expenditures associated with the RACT
regulations are not expected to be material.
More stringent regulation of nitrous oxide emissions at both Hunlock
and Conemaugh Stations may be required due to the actions of the Northeast Ozone
Transport Commission. The Commission was created by the Clean Air Act Amendments
to provide a plan to reduce ground level ozone in the Northeast to a level
acceptable to the U.S. Environmental Protection Agency (the "EPA"). Future
actions of the Commission may cause the DER to modify its nitrous oxide RACT
plans and thereby affect the compliance plans of Hunlock and Conemaugh Stations.
Seasonality. Salesdistribution of electricity for residential heating purposes
accounted for approximately 23%19% of the total sales of Electric Utility during
the 1997 fiscal year.year 2002. Electricity competes with natural gas, oil, propane and other
heating fuels in this use. Approximately 54%51% of -6-
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salesvolume occurred induring the six
coldest months of the 1997 fiscal year 2002 (November through April), demonstrating
modest seasonality favoring winter due to the use of electricity for residential
heating purposes.
PROPERTIES
Utilities' Mortgage and Deed of Trust constitutes a first lien on
substantially all real and personal property of Utilities.
UTILITY REGULATION AND RATES
Recent Regulatory Environment. Since December 1982, Utilities has
provided transportationPENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION
Utilities' gas and electric utility operations, which exclude electric
generation, are subject to regulation by the PUC as to rates, terms and
conditions of service, for commercialaccounting matters, issuance of securities, contracts and
industrial customers who
purchase their gas from others.other arrangements with affiliated entities, and various other matters. As previously reported, this unbundled service
accounted for approximately 54% of Utilities' system throughput in fiscal year
1997. Certain states, including Pennsylvania, are considering whether
transportation service options should be extended to residential and small
commercial customers. On March 27, 1997, proposed customer choice legislation
was introduced in the Pennsylvania General Assembly that would, among other
things, extend the availability of gas transportation service to residential and
small commercial customers of local gas distribution companies. It would permit
all customers of natural gas distribution utilities to transport their natural
gas supplies through the distribution systems of Pennsylvania gas utilities by
Aprilnoted
earlier, effective October 1, 1999, and would also require Pennsylvania gas utilitiesUtilities contributed its electric
generation assets to stop selling
natural gas. Legislative committees have conducted public hearings onUGID. UGID has FERC authority to sell power at market-based
rates. Generally, UGID is not subject to regulation by the proposed legislation and Utilities has provided testimony on such issues as the
need for standards to assure reliability of future gas supplies and the recovery
of costs associated with existing gas supply assets. Utilities is considering a
number of options for addressing the provision of unbundled transportation
services to residential and small commercial customers, including the
termination of bundled retail sales services. The Company will continue to
monitor the proposed legislation.PUC.
FERC OrdersORDERS 888 and 889.AND 889
In April 1996, FERC issued Orders No. 888 and 889, which established rules
for the use of electric transmission facilities for wholesale transactions. FERC
has also asserted jurisdiction over the transmission component of electric
retail choice transactions. In compliance with these orders, the PJM
Interconnection, LLC ("PJM"), of which UGIUtilities is a member, has filed an open
access transmission tariff with the FERC establishing transmission rates and
procedures for transmission within the PJM control area. Under the PJM tariff
and associated agreements, Electric Utility is entitled to receive certain
revenues when Utilities'its transmission facilities are used by third parties.
Pennsylvania PublicGAS UTILITY RATES
The Gas Restructuring Order included an increase in firm, core-market base
rates, effective October 1, 2000. The increase, calculated in accordance with
the Gas Competition Act, was designed to generate approximately $16.7 million in
additional annual revenues. The Order also provided that Gas Utility Commission Jurisdiction. Utilities'reduce its
purchased gas and
electric utility operations are subjectcost rates by an annualized amount of $16.7 million for the first
14 months following the base rate increase.
Effective December 1, 2001, Gas Utility was required to regulationreduce its
purchased gas cost rates to core market customers by an amount equal to the
PUC as to rates,
terms and conditions of service, accounting matters, issuance of securities,
contracts and other arrangements with affiliated entities, and various other
matters.margin it receives from customers
-7-
10
Purchasedserved under interruptible rates to the extent they use capacity contracted for
by Gas Cost Rates.Utility for core-market customers. As a result of these changes in its
regulated rates, since December 1, 2001, Gas Utility's operating results have
been more sensitive to heating season weather and less sensitive to the market
prices of alternative fuel than in the past.
BASE RATES
As stated above, Gas Utility's current base rates went into effect October
1, 2000 pursuant to The Gas Restructuring Order. See Note 4 to the Company's
Consolidated Financial Statements.
PURCHASED GAS COST RATES
Gas Utility's gas service tariff contains Purchased Gas Cost ("PGC") rates
which provide for annual increases or decreases in the rate per thousand cubic
feet ("mcf") which Gas Utility charges for natural gas sold by it, to reflect
Utilities' projected cost of purchased gas. In accordance with regulations adopted by the PUC on June 14, 1995, PGC rates may also be adjusted
quarterly, or monthly, to reflect purchased gas costs. Each proposed annual PGC
rate is required to be filed with the PUC six months prior to its effective
date. During this period the PUC holds hearings to determine whether the
proposed rate reflects a least-cost fuel procurement policy consistent with the
obligation to provide safe, adequate and reliable service. After completion of
these hearings, the PUC issues an order permitting the collection of gas costs
at levels which meet that standard. The PGC mechanism also provides for an
annual reconciliation. Utilities has two PGC rates. PGC (1) is applicable to
small, firm, core marketcore-market customers consisting of the residential and small
commercial and industrial classes; PGC (2) is applicable to firm, contractual,
high-load factor customers served on three specific rates (Rates BD, BD-L and
N/CIAC).separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC(2)PGC (2)
rate. In accordance withAs described above, the schedule established by law and PUC
regulations, Gas Utility will file a newRestructuring Order provided for ongoing
adjustments to Gas Utilities' PGC tariff on June 1, 1998, to be
effectiverates, commencing December 1, 1998. When filed, the proposed tariff will2001, to reflect
estimated PGC over-collectionsmargins, if any, from interruptible rate customers who do not obtain their own
pipeline capacity.
ELECTRIC UTILITY RATES
Electric Utility's rates for electric generation are frozen through
approximately July 2003 for commercial and under-collectionsindustrial customers and
approximately May 2004 for residential customers. After these dates and through
November 30, 1998.
Energy Cost Rates. In accordance with provisionsDecember 2004, Electric Utility can increase generation rates by up to 5% of the
total rate for distribution, transmission and generation. See "Electricity
Generation Customer Choice and Competition Act." The ECC Act the PUC approved Electric Utility's application to roll its energy costs
rate ("ECR") into its base rates effective as of May 2, 1997, at a combined
level not to exceed the rate cap established as of January 1, 1997. Before
January 1, 1997, the ECR permittedobligates Electric
Utility to adjust customers' monthly
chargesact as "provider of last resort" to reflect annual changes in the cost of purchased power, fuel,
interchange power and the cost of transmitting power purchased from external
sources. Although Electric Utility may no longer adjust customer charges to
reflect changes in the cost of purchased power, it will continue to account for
such changes in order to reconcile costs as part of its Restructuring Plan.
Gas Rate Case. On January 27, 1995, Gas Utility filed with the PUC for
a $41.3 million increase in base rates. The PUC approved a $19.5 million
settlement of this proceeding, effective August 31, 1995.
Electric Rate Case. On January 26, 1996 Electric Utility filed with the
PUC for a $6.2 million increase in its base rates, to be effective March 26,
1996. On July 18, 1996, the PUC approved a settlement of this proceeding
authorizing a $3.1 million increase in annual revenues. This increase in base
rates became effective on July 19, 1996.
Deferred Fuel Adjustments. Gas Utility defers and until January 1, 1997
Electric Utility deferred the difference between the amount of revenue
recognized, and the applicable purchased gas costs and purchased power costs
incurred, until subsequently billed or refunded to customers.
State Tax Surcharge Clauses.customers who do not choose
alternate generation suppliers.
STATE TAX SURCHARGE CLAUSES
Utilities' gas and electric service tariffs contain state tax surcharge
clauses. The surcharges are recomputed whenever any of the tax rates included in
their -8-
11
calculation are changed. These clauses protect Utilities from the effect
of increases in most of the Pennsylvania taxes to which it is subject.
-8-
UTILITY FRANCHISES
Utilities holds certificates of public convenience issued by the PUC and
certain "grandfather rights" predating the adoption of the Pennsylvania Public
Utility Code and its predecessor statutes which it believes are adequate to
authorize it to carry on its business in substantially all the territory to
which it now renders gas and electric service. Under applicable Pennsylvania
law, Utilities also has certain rights of eminent domain as well as the right to
maintain its facilities in streets and highways in its territories.
OTHER GOVERNMENT REGULATION
In addition to regulation by the PUC, the gas and electric utility
operations of Utilities are subject to various federal, state and local laws
governing environmental matters, occupational health and safety, pipeline safety
and other matters. Certain of Utilities' activities involving the interstate
movement of natural gas, the transmission of electricity, transactions with
non-utility generators of electricity, like UGID, and other matters, are also
subject to the jurisdiction of FERC.
Utilities is subject to the requirements of the federal Resource
Conservation and Recovery Act, CERCLA and comparable state statutes with respect
to the release of hazardous substances on property owned or operated by
Utilities. See ITEM 3. "LEGAL PROCEEDINGS-Environmental Matters.PROCEEDINGS - Environmental Matters-Manufactured
Gas Plants." The electric generation activities of Utilities are also subject to
the Clean Air Act Amendments, the Federal Water Pollution Control Act and
comparable state statutes and regulations. See "UTILITY OPERATIONS - GenerationElectric
Operations - Environmental Factors."
EMPLOYEES
At September 30, 2002, Utilities and Distribution
of Electricity-Environmental Factors."
-9-
12its subsidiaries had approximately
1,100 employees.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' industryoperating segments for the 1997,
19962002,
2001 and 19952000 fiscal years appears in Note 1110 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
EMPLOYEES
At September 30, 1997, Utilities and its subsidiaries had 1,226
employees.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal
proceedings are pending involving Utilities, any of its subsidiaries or any of
their properties, and no such proceedings are known to be contemplated by
governmental authorities.
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ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
PriorIn the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas, in the 1800s through
the mid-1900s, manufactured gas was a chief source of gas for lighting and
heating nationwide. The process involved heating certain combustibles such as
coal, oil and coke in a low-oxygen atmosphere. Methods of production included
coal carbonization, carbureted water gas and catalytic cracking. These methods
were employed at many different sites throughout the country. The residue from
gas manufacturing, including coal tar, was typically stored on site, burned in
the gas plant, or sold for commercial use.gas. Some constituents of coal tars
produced fromand other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law.
The gas distribution business has been oneLaw and may be present on the sites of
Utilities' principal
lines of business since its inception in 1882. One of the waysformer MGPs. Between 1882 and 1953, UGI Utilities initially expanded its business in its early years was by entering into
agreements with other gas companies to operate their businesses. After 1888, the
principal means by which Utilities expanded its gas business was to acquire all
or a portion ofowned the stock of companies engaged in this business. Utilities also
provided management and administrative services to some of these companies.
Utilities grew rapidly by means of stock acquisitions and became one of the
largest public utility holdingsubsidiary
gas companies in Pennsylvania and elsewhere and also operated the country.business of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, by 1953, UGI Utilities had divested all of
its utility operations other than those which now constitute the
Gas Utility and
the Electric Utility.
The manufactured gas process was once used byUGI Utilities in connection
with providing gas servicedoes not expect its costs for investigation and remediation
of hazardous substances at Pennsylvania MGP sites to be material to its customers. In addition, virtually allresults
of the
gas companies thatoperations because UGI Utilities operated oris currently permitted to -10-
13
which it provided services, orinclude in which Utilities held stock, utilized a
manufactured gas process.rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. UGI Utilities has been notified of several sites
outside Pennsylvania on which (i) gas plants(1) MGPs were formerly operated by it or owned or
operated by its former subsidiaries and (ii)(2) either environmental agencies or
private parties are investigating the extent of environmental contamination and
the necessity ofor
performing environmental remediation. UGI Utilities is currently litigating a
claimtwo
claims against it relating to an out-of-state site. If Utilities were found
liable as a "responsible party" as defined in the Superfund Law (or comparable
state statutes) with respect to this site, it would have joint and several
liability with other responsible parties for the full amount of the cleanup
costs. A "responsible party" under that statute includes (i) the current owner
of the affected property and (ii) each owner or operator of a facility during
the time when hazardous substances were released on the property.
Management believes that Utilities should not have significant
liability in those instances in which a former subsidiary operated a
manufactured gas plant because Utilities generally is not legally liable for the
obligations of its subsidiaries. Under certain circumstances, however, courts
have found parent companies liable for environmental damage caused by subsidiary
companies when the parent company exercised such substantial control over the
subsidiary that the court concluded that the parent company either (i) itself
operated the facility causing the environmental damage or (ii) otherwise so
controlled the subsidiary that the subsidiary's separate corporate form should
be disregarded. There could be, therefore, significant future costs of an
uncertain amount associated with environmental damage caused by manufactured gas
plants that Utilities owned or directly operated, or that were owned or operated
by former subsidiaries of Utilities, if a court were to conclude that the level
of control exercised by Utilities over the subsidiary satisfies the standard
described above.
Utilities believes that there are approximately 40 manufactured gas
plant sites in Pennsylvania where either (i) Utilities formerly operated the
plant or (ii) Utilities owns or at one time owned the site. Most of the sites
are no longer owned by Utilities and the gas plants formerly operated at these
40 sites have all been out of operation since at least the early 1950s.
Utilities or other parties are currently conducting investigative or remedial
activities at nine of the 40 sites.
Based on the 1995 settlement agreement with
the PUC relating to Gas Utilities' 1995 base rate increase filing, rate relief
will be permitted for certain remediation expenditures on environmentally
contaminated sites located in Pennsylvania. Because of this, Utilities does not
expect its costs for Pennsylvania sites to be material to its results of
operations.
The following is a short description of the status of certain matters
involving Utilities related to manufactured gas plants located in other states.
See also Note 8 to the Company's Consolidated Financial Statements.
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14
OUT OF STATE GAS PLANT SITES
1. Halladay Street, Jersey City, New Jersey. By letter dated April 12,Fishbein Family Partnership v. PPG Industries, Inc., et al. In July 1993,
Public Service Electric and Gas Company ("PSE&G") informedjoined Utilities that
PSE&G had been named as a
third-party defendant in a civil action pending in the United States District Court offor
the District of New Jersey, seeking damages as a result of contamination
relating to the former manufactured gas plant operations at Halladay Street in
Jersey City, New Jersey. The Halladay Street gas plant
operated from approximately 1884 until 1950. PSE&G asserted that Utilities is
liable for that portion ofcase principally involved claims by the costs associated with operations of the plant
between 1886 and 1899.Fishbein
Family Partnership against PPG Industries, Inc. has also been named as a defendant
in the action for costsdamages associated with
chemical contamination at the site unrelated to gas plant operations. In July 1993,November 2001, the
parties agreed voluntarily to dismiss all claims by and against PSE&G servedwithout
prejudice. All claims against Utilities with a
complaint naming Utilities as a third-party defendant in this civil action.
PSE&G subsequently amended the complaint to allege additional theories of
liability for the period from 1899 to 1940. To date, that action has focused on
the chemical contamination allegedly associated with PPG Industries' activities
and there have been no developments concerning liability for gas plant related
contamination. Management is currently investigating Utilities' involvementdismissed, although they could
be re-instituted in operations of the site and evaluating its defenses. Investigations of the site
conducted to date are insufficient to establish the extent of environmental
remediation necessary, if any. Hence, Utilities is unable to estimate the total
cost of cleanup associated with manufactured gas plant wastes at this site.
2. Burlington, Vermont. By letter dated November 24, 1992, the EPA
notified Utilities of potential liability with respect to contamination at the
Pine Street Canal Superfund Site, Burlington, Vermont. The EPA has also
identified eighteen other "potentially responsible parties." Utilities has
responded to the EPA letter and denied liability for any contamination caused by
the former operator of the gas plant. Management believes that Utilities has
substantial defenses to any claim that may be made for investigative or remedial
costs because, among other things, the plant was operated by a subsidiary of a
predecessor company.
The site is the location of a former manufactured gas plant owned and
operated by Burlington Gas Light Company ("BGLC") and Burlington Light and Power
Company ("BLPC"). The EPA contends that Utilities is potentially liable because
it assumed the liabilities of American Gasfuture.
Consolidated Edison Company of New Jersey, a one-time
parent of BGLC and BLPC. In 1985, the EPA removed approximately 15,000 tons of
coal tar contaminated material from a portion of the site. From 1986 through
1992, the EPA conducted investigations and developed potential remedial actions
at the site. The results of EPA's investigations show that coal gasification
wastes, particularly polynuclear aromatic hydrocarbons and coal tar, are present
in surface and subsurface soils as well as groundwater. The contamination also
extends to wetlands adjacent to the site.
In November 1992, the EPA proposed a cleanup of the site that, among
other actions, would consist of on-site containment, dredging and excavation,
dewatering and consolidation of contaminated soils, treatment of groundwater and
restoration of wetlands. The estimated cost of the proposed plan would have been
approximately $50 million. In May 1993, after reviewing extensive public comment
concerning the proposed plan of remediation, the EPA withdrew the
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15
proposed plan and announced that it would work with a coordinating council
consisting of community groups, potentially responsible parties ("PRPs") and
others to develop an alternative plan.
In September 1997, the coordinating council proposed a remedial plan
calling for capping of the site at an estimated cost of $6 million to $10
million. In addition, the coordinating council and EPA may have spent an
additional $10 million in studying the site. In December 1997, Green Mountain
Power Company, the lead PRP, agreed in principle to indemnify and release
Utilities from any further liability at the site on terms and conditions which
are not material to the results of operations of Utilities.
3. Savannah, Georgia. On March 2, 1992, Atlanta Gas Light Company
("AGL") informed Utilities that it was investigating contamination that appears
to be related to manufactured gas plant operations at a site owned by AGL in
Savannah, Georgia. AGL believes that Utilities may be liable for investigative
and remedial costs as a result of having operated the gas plant through a
subsidiary company in the early 1900s. AGL has stated its intention to bring
suit against Utilities. AGL estimates that total costs to remediate the site may
exceed $5 million. Management believes that Utilities has substantial defenses
to any action that may arise out of the activities of its former subsidiary at
this site.
4. Concord, New Hampshire. By letter dated October 18, 1993,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") informed Utilities that the New
Hampshire Department of Environmental Services ("NHDES") has alleged that there
is environmental contamination on property in Concord, N.H., where a
manufactured gas plant was once located. EnergyNorth requested that Utilities,
as a former operator of the plant, participate in investigation of the site.
Because this gas plant appears to have been operated almost exclusively by
former subsidiary companies of Utilities, Utilities declined to participate. On
September 17, 1995 EnergyNorth filed suit against Utilities alone in federal
District Court in New Hampshire, seeking Utilities' allocable share of response
costs associated with remediating gas plant related contamination at that site.
The complaint alleges that EnergyNorth has spent $3.5 million to remove
contaminants from a gas holder at the site and will be required to spend an
unknown amount in the future. As a result of investigations of gas plant related
contamination in a nearby pond completed in 1996, EnergyNorth recommended to
NHDES a remedial plan that would cost approximately $4 million. In November
1997, Utilities settled this litigation on terms which are not material to the
results of operations of Utilities.
OTHER MATTERS
Foster Wheeler Penn Resources, Inc.York v. UGI Utilities, Inc. Civil Action
No. 97CV4592. On
July 14, 1997, Foster Wheeler Penn Resources, Inc.September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit
against UGI Utilities, Inc. in the United States District Court for the EasternSouthern
District of Pennsylvania alleging, amongNew York, seeking contribution from Utilities for an allocated share
of response costs associated with investigating and assessing gas plant related
contamination at former manufactured gas plant sites in eleven communities in
Westchester County, New York. The complaint alleges that Utilities "owned and
operated" the plants prior to 1904. The complaint also seeks a declaration that
Utilities is responsible for an allocated percentage of future investigative and
remedial costs at the sites. ConEd has stated that the cost of remediation at
two of the sites, Tarrytown and White Plains, could exceed $20 million and $10
million respectively. ConEd has not provided specific estimates of costs at the
remainder of the sites and Utilities has no other things,information on which to base
estimates. Utilities continues to investigate its involvement at these sites and
is defending the claim.
-10-
EnergyNorth Natural Gas, Inc. v. UGI Utilities, Inc. By letter dated
October 26, 2000, EnergyNorth Natural Gas, Inc. ("EnergyNorth") notified
Utilities that it has filed suit in the United States District Court for the
District of New Hampshire, seeking contribution from Utilities for response and
remediation costs associated with contamination on the site of a former
manufactured gas plant allegedly operated by former subsidiaries of Utilities.
EnergyNorth has not stated the amount of the costs and has provided no
information on which Utilities could make an estimate. Utilities is actively
defending the suit.
Management believes that under applicable law UGI Utilities should not be
liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
breached an Agreement for the Sale and Purchasedirectly operated, or that were owned or operated by former subsidiaries of Net Electrical Energy under
which UGI
Utilities, had agreedif a court were to purchase electricity from a generating
facility yet to be
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16
built by Foster Wheeler. In its suit Foster Wheeler seeks, among other things, a
declarationconclude that the Sale and Purchase Agreement remains in effect orsubsidiary's separate corporate
form should be disregarded.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et. al. On February
11, 1999, UGI Utilities, Inc. filed suit in the alternativeCourt of Common Pleas of
Montgomery County, Pennsylvania against more than fifty insurance companies,
including Associated Electric and Gas Insurance Services, Ltd. (AEGIS). The
complaint alleges that Foster Wheeler be awarded damages in excessthe defendants breached contracts of $20 million.
Management believes that itinsurance by failing
to indemnify Utilities for certain environmental costs. To date, Utilities has
defenses to Foster Wheeler's claims.recovered a significant portion of its claims through settlements with most of
the defendants, including AEGIS. The court has not yet set a date for trial of
the claims against the remaining defendants.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the last
fiscal quarter of the 1997 fiscal year.year 2002.
-11-
PART II: SECURITIES AND FINANCIAL INFORMATION
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
All of the outstanding shares of the Company's Common Stock are owned by
UGI and are not publicly traded.
DIVIDENDS
DividendsCash dividends declared on the Company's Common Stock during the 1997totaled $37.9
million in fiscal year totaled $25.1 million, including a $1 million intercompany receivable.
Dividends declared on the Company's Common Stock during the 1996 and 1995 fiscal
years totaled $32.9 million and $15.5 million (including $1.02002, $35.3 million in net
assets of its former GASMARK operation), respectively.
The information concerning restrictions on dividends required by Item 5
is includedfiscal year 2001 and $44.0 million
in Note 3 to the Company's Consolidated Financial Statements
included in this Report and is incorporated herein by reference.
-14-fiscal year 2000.
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17
ITEM 6. SELECTED FINANCIAL DATA (a)
Nine
Months
Year Ended Ended
September 30,
September 30,
------------------------------------------------- ----------------------
1997 1996 1995 1994 1993 1992------------------------------------------------------------------------
2002 2001 2000 1999 1998
--------- --------- --------- --------- --------- ---------
(unaudited)
(Thousands of dollars)
FOR THE PERIOD ENDED:
Income statement data:PERIOD:
INCOME STATEMENT DATA:
Revenues $ 461,208490,552 $ 460,496584,762 $ 357,364436,942 $ 395,061420,647 $ 251,210 $ 246,677422,283
========= ========= ========= ========= =========
=========
Income from:
Continuing operations $ 38,711 $ 38,348 $ 28,018 $ 23,555 $ 16,031 $ 15,782
Discontinued operations (a) -- -- -- 6,918 -- 13,471
--------- --------- --------- --------- --------- ---------
Income before accounting change 38,711 38,348 28,018 30,473 16,031 29,253
Change in accounting for
postemployment benefits -- -- (1,028) -- -- --
--------- --------- --------- --------- --------- ---------
Net income 38,711 38,348 26,990 30,473 16,031 29,253$ 44,095 $ 48,137 $ 50,476 $ 38,868 $ 35,551
Dividends on preferred stock 2,764 2,765 2,778 1,356 2,124 1,905
---------1,550 1,550 1,550 1,550 2,160
--------- --------- --------- --------- ---------
Net income after dividends
on preferred stock $ 35,94742,545 $ 35,58346,587 $ 24,21248,926 $ 29,11737,318 $ 13,907 $ 27,348
=========33,391
========= ========= ========= ========= =========
AT PERIOD END:
Balance sheet data:BALANCE SHEET DATA:
Total assets $ 681,378798,123 $ 649,899784,409 $ 661,480751,137 $ 581,426717,169 $ 561,306 $ 560,672
=========690,317
========= ========= ========= ========= =========
Capitalization:
Debt:
Bank loans $ 67,00037,200 $ 50,50057,800 $ 42,000100,400 $ 17,00087,400 $ -- $ --68,400
Long-term debt including
current maturities: 169,294 176,654 208,162 177,444 200,421 198,273
---------maturities 248,369 208,477 172,924 180,047 187,170
--------- --------- --------- --------- ---------
Total debt 236,294 227,154 250,162 194,444 200,421 198,273
--------- --------- --------- --------- --------- ---------285,569 266,277 273,324 267,447 255,570
Preferred stock subject to
mandatory redemption 35,187 35,187 35,202 35,202 33,222 35,22320,000 20,000 20,000 20,000 20,000
Common equity 200,494 189,441 186,803 178,071 169,077 161,971
---------237,854 235,757 224,473 219,560 211,242
--------- --------- --------- --------- ---------
Total capitalization $ 471,975543,423 $ 451,782522,034 $ 472,167517,797 $ 407,717507,007 $ 402,720 $ 395,467486,812
========= ========= ========= ========= =========
=========
Ratio of capitalization:RATIO OF CAPITALIZATION:
Total debt 50.0% 50.3% 53.0% 47.7% 49.8% 50.1%52.6% 51.0% 52.8% 52.8% 52.5%
UGI Utilities preferred stock 7.5% 7.8% 7.4% 8.6% 8.2% 8.9%3.7% 3.8% 3.9% 3.9% 4.1%
Common equity 42.5% 41.9% 39.6% 43.7% 42.0% 41.0%
---------45.2% 43.3% 43.3% 43.4%
--------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0%
100.0%
========= ========= ========= ========= ========= =========
(a) Includes results of AmeriGasArthur Andersen LLP audited our consolidated financial statements for
2001, 2000, 1999 and Ashtola prior to April 10, 1992. Also
includes the Company's oil field activities discontinued in 1986.1998. See Item 15 - Notice Regarding Arthur Andersen
LLP.
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18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
1997In the following Management's Discussion and Analysis ("MD&A") of
Financial Condition and Results of Operations, Electric Utility and UGID's
electric generation business are collectively referred to as "Electric
Operations." The MD&A should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the business segment information in Note 10.
FISCAL 2002 COMPARED WITH 1996FISCAL 2001
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1997 19962002 2001 (Decrease)
- ----------------------------------------------------------------------------------------------------------- ---- ---- ----------
(Millions of dollars)
(Millions of dollars)
GAS UTILITY:
Natural gas systemRevenues $404.5 $ 500.8 $ (96.3) (19.2)%
Total margin (a) $162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
System throughput - bcf 80.2 85.4 (5.2) (6.1)70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal (4.8) 4.2(17.4)% 2.0% -- --
ELECTRIC OPERATIONS:
Revenues $389.1 $391.0 $ (1.9) (.5)%86.0 $ 83.9 $ 2.1 2.5%
Total margin $168.7 $169.7(a) $ (1.0) (.6)%32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 74.813.2 $ 72.910.7 $ 1.9 2.6 %
ELECTRIC UTILITY:
Electric2.5 23.4%
Distribution sales - gwh 868.5 884.7 (16.2) (1.8)933.6 945.5 (11.9) (1.3)%
Revenues $ 72.1 $ 69.5 $ 2.6 3.7 %
Total margin $ 35.2 $ 33.0 $ 2.2 6.7 %
Operating income $ 10.7 $ 8.6 $ 2.1 24.4 %
CORPORATE GENERAL AND OTHER:
Corporate general expenses $ (5.6) $ (3.9) $ 1.7 43.6 %
Other operating income $ .2 $ .1 $ .1 100.0 %
- -----------------------------------------------------------------------------------
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
Total(a) Gas Utility's total margin represents total revenues less cost of sales.
Electric Operation's total margin represents total revenues less cost of
sales and revenue-related taxes, i.e. Electric Utility gross receipts
taxes. For financial statement purposes, revenue-related taxes are
included in "taxes other than income taxes" on the Consolidated Statements
of Income.
GAS UTILITY.
Weather in Gas Utility's service territory during Fiscal 2002 based upon
heating degree days was 4.8%17.4% warmer than normal in 1997 compared to 4.2%weather that was
2.0% colder than normal in 1996.Fiscal 2001. As a result of the significantly warmer
weather and the effects of a weak economy on commercial and industrial natural
gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in total system throughput principally reflects the warmer weather's effect on core
market sales as well as a decrease in low-margin interruptible delivery service
volumes associated with the shut-down of a gas-fired cogeneration facility.Fiscal 2002 Gas Utility revenues were $1.9 millionreflects
the impact of lower in 1997 as a $27.2 million increase
in core market revenues principally due to higher average PGC rates, was offset
by a $21.2 million decrease in core market revenuesresulting from the pass through of lower salesnatural
gas costs to firm- residential, commercial and an $8.1
million decrease in revenues from off-system sales. Costindustrial (collectively,
"core-market") customers, and the lower distribution system throughput. Gas
Utility cost of gas sold by Gas
Utility decreased $1.1was $241.7 million in Fiscal 2002 compared to $205.2$322.9
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million in Fiscal 2001 reflecting lower natural gas costs and the lower off-system
and core market sales offset by higher average PGC rates.
-16-
19decline in
core-market throughput in Fiscal 2002.
The decreasedecline in Gas Utility total margin principally reflects a $6.3$6.0 million
decreasedecline in core-market margin due to the lower sales; a $6.6 million decline in
interruptible margin due principally to the flowback of certain interruptible
customer margin to core-market customers beginning December 1, 2001 pursuant to
the Gas Restructuring Order; and lower firm delivery service total margin from core marketdue to
lower sales. Interruptible customers resulting fromare those who have the warmer
weather partially offset by a $5.5 million increase in total margin from
interruptible customers.
Although total margin was slightly lower in 1997,ability to switch to
alternate fuels.
Gas Utility operating income increased $1.9declined $10.7 million principallyin Fiscal 2002
reflecting the previously mentioned decline in total margin and a decrease in
pension income partially offset by lower operating expenses. Operating expenses
declined $4.1 million primarily as a result of a $1.5 million decrease in
operating and administrative expenses and higher miscellaneous income. Operating
and administrative expenses during 1997 decreased principally as a result of a
decrease in distribution system expenses, lower accrualscharges for uncollectible
accounts and lower general and administrative expensesdistribution system expenses. Depreciation expense declined
$1.2 million due to a change effective April 1, 2002 in the estimated useful
lives of Gas Utility's natural gas distribution assets resulting from an asset
life study required by the PUC.
ELECTRIC OPERATIONS. The decline in kilowatt-hour sales in Fiscal 2002
reflects the effects on heating-related sales of significantly warmer winter
weather partially offset by higher costs associated with environmental matters.
ELECTRIC UTILITY. Electric Utilitythe effects on air conditioning sales decreasedof warmer
summer weather. Notwithstanding the decrease in 1997 reflecting weather
which was 5.6% warmer than in the prior-year period. Electric Utility base ratetotal kilowatt-hour sales,
revenues increased $1.7$2.1 million principally due to an increase in state tax
surcharge revenue and greater third-party sales of electricity produced by our
Pennsylvania-based electric generation facilities. Electric Operations cost of
sales was $48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001
principally reflecting the impact of the lower sales and lower purchased power
unit costs partially offset by the full-period increase to cost of sales
resulting from the transfer of our Hunlock Creek electricity generation assets
to Hunlock Creek Energy Ventures ("Energy Ventures") in December 2000. Energy
Ventures is an electricity generation joint-venture with a subsidiary of
Allegheny Energy, Inc. Subsequent to the formation of Energy Ventures, our
electric generating business purchases its share of the power produced by Energy
Ventures rather than producing this electricity itself. As a result, the cost of
this power is reflected in cost of sales whereas prior to the formation of
Energy Ventures such costs were reflected as operating and administrative
expenses.
Electric Operations total margin increased $4.2 million in Fiscal 2002 as
a $2.8result of lower purchased power unit costs partially offset by the
weather-driven decline in sales. Operating income increased $2.5 million
increase resulting from higher
base rates wasreflecting the greater total margin and lower operating costs subsequent to the
formation of Energy Ventures partially offset by a $1.1 million decrease resulting from thedecline in other income.
INTEREST EXPENSE. The lower sales. In addition, Electric Utility revenues include a $.9 million
increase in energy cost recoveries. Cost of sales increased to $33.8 million in
1997 from $33.4 million in 1996 as a result of the higher energy cost recoveries
partially offset by the lower sales.
Electric Utility total margin and operating income increased in 1997 principally
as a result of the higher base rates. Electric Utility operating and
administrative expenses in 1997 were essentially unchanged from the prior year.
CORPORATE GENERAL AND OTHER. Corporate general expenses, which represent an
allocated share of corporate headquarters' expenses incurred by UGI, were $5.6
million in 1997 compared with $3.9 million in 1996. The 1996 corporate general
expenses were lower as a result of adjustments to incentive compensation
accruals.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.9 million in 1997
compared with $16.1 million in 1996. The increase in interest expense reflects
higher averagein Fiscal 2002 resulted
primarily from lower levels of long-term debt and lower bank loans outstanding partially offset by lower average
long-term debt outstanding.
The effective income tax rate for 1997 was 38.8%
compared with a rate of 37.9% for 1996.
-17--15-
20
1996FISCAL 2001 COMPARED WITH 1995FISCAL 2000
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1996 19952001 2000 (Decrease)
- ------------------------ ---- ---- ----------
(Millions of dollars)
- -----------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Natural gas systemRevenues $ 500.8 $ 359.0 $ 141.8 39.5 %
Total margin $ 177.9 $ 170.8 $ 7.1 4.2 %
Operating income $ 87.8 $ 86.2 $ 1.6 1.9 %
System throughput - bcf 85.4 82.4 3.0 3.6%77.3 79.7 (2.4) (3.0)%
Degree days - % colder (warmer)
than normal 4.2 (5.4)2.0% (9.9)% -- --
ELECTRIC OPERATIONS:
Revenues $391.0 $291.3 $ 99.7 34.2%83.9 $ 77.9 $ 6.0 7.7 %
Total margin $169.7 $140.9 $ 28.8 20.4%28.6 $ 40.8 $ (12.2) (29.9)%
Operating income $ 72.910.7 $ 51.915.1 $ 21.0 40.5%
ELECTRIC UTILITY:
Electric(4.4) (29.1)%
Distribution sales - gwh 884.7 860.9 23.8 2.8%
Revenues $ 69.5 $ 66.1 $ 3.4 5.1%
Total margin $ 33.0 $ 32.1 $ .9 2.8%
Operating income $ 8.6 $ 9.1 $ (.5) (5.5)945.5 907.2 38.3 4.2 %
CORPORATE GENERAL AND OTHER:
Corporate general expenses $ (3.9) $ (6.6) $ (2.7) (40.9)%
Other operating income $ .1 $ 2.1 $ (2.0) (95.2)%
- -----------------------------------------------------------------------------------
bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin
represents revenues less cost of sales and revenue-related taxes.
GAS UTILITY. WeatherAlthough temperatures based upon heating degree days were
colder in Gas Utility's service territory in 1996 was colder than
normal and also colder than in 1995. The increase inFiscal 2001, total system throughput includes a 5.4 bcf increase in sales to core market customersdeclined 3.0% as the impact of
the colder weather was more than offset by lower interruptible and a .7 bcf
increase in throughput to interruptible customers. Partially offsetting these
increases was a decrease in firm delivery
service volumes, asthe impact of price-induced customer conservation, and the
effects of a resultslowing economy. Natural gas prices were significantly higher in
Fiscal 2001 than in the prior year. The higher prices resulted in fuel switching
by many of customer switchingour interruptible customers, who have the ability to interruptible delivery service.switch to
alternate fuels, and encouraged price-induced conservation by many of our firm
customers. Throughput to our core-market customers increased 3.3 bcf (10.6%)
reflecting the impact of the colder Fiscal 2001 weather.
The significant increase in Gas Utility total revenues reflectsis primarily a $68.4 million increase inresult of
higher core-market revenues reflecting greater PGC rates and higher revenues
from core marketsales to customers (reflectingnot on our distribution system ("off-system sales"). Gas
Utility's tariffs permit it to pass through prudently incurred gas costs to its
core-market customers through higher sales and the full-year
effect of higher base rates), greater off-system sales, and lower refunds of
producer settlement charges. CostPGC rates. Gas Utility cost of gas sold was $206.3totaled
$322.9 million during 1996, an
increase of $67.7in Fiscal 2001 compared with $184.2 million from 1995,in Fiscal 2000
principally reflecting principally the greater saleshigher average PGC rates and, to core market customers,a lesser extent,
higher core-market and off-system sales, and lower refunds of producer
settlement charges.
The increase insales.
Gas Utility total margin increased $7.1 million reflecting a $12.1 million
increase in 1996core-market margin partially offset by lower total margin from
interruptible customers. The decline in interruptible margin reflects lower
average interruptible unit margins due to a $34.5decline in the spread between oil
and natural gas prices and the lower interruptible throughput.
Gas Utility operating income increased $1.6 million as the previously
mentioned increase in total margin from core market customers as a result of the colder
weather and higher base rates. However, partially offsetting thean increase in core market margin was a decrease in total margin from interruptible customers,
principally as a result of higher 1996 gas costs, and a decrease in total margin
from firm delivery service customers due in large part to the lower volumes.
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21
Gas Utility operatingpension income in 1996 benefitted from the increase in total
margin. However, the benefit was
partially offset by higher operating and administrative expenses and higher charges for depreciation.
ELECTRIC UTILITY. Electric Utility sales increased during 1996 principally from
colder heating-season weather. The $3.4 million increase in Electric Utility
revenues reflects a $1.7 million increase in base rate revenues and a $1.7
million increase in energy cost recoveries. Electric Utility cost of sales was
$33.4 million, an increase of $2.3 million from the prior year.expenses. The increase
in the cost of sales resultedoperating and administrative expenses includes, among
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other things, greater allowances for uncollectible accounts, reflecting
significantly higher Fiscal 2001 customer bills, and lower income from
higher sales and higher energy cost recoveries.environmental insurance litigation settlements. Such settlements totaled $0.9
million in Fiscal 2001 compared with $4.5 million in Fiscal 2000. Depreciation
expense increased $1.1 million reflecting greater depreciation associated with
distribution system capital expenditures.
ELECTRIC OPERATIONS. Electric Utility total margindistribution system sales in Fiscal
2001 increased 4.2% on favorable weather. Revenues increased as a result of the
increased sales and
higher base rates effective in July. However, operating income declined as the
increase in Electric Utility total margin was more than offset by higher distribution system maintenance expenses, general and administrative expenses,
and depreciation.
CORPORATE GENERAL AND OTHER. Corporate general expenses were $3.9sales as well as off-system sales of electricity
generated by Energy Ventures. Cost of sales totaled $51.9 million in 1996Fiscal 2001
compared with $6.6to $34.2 million in 1995.the prior year. The allocated UGI corporate expenses in
1996 were lowerincrease reflects higher
per-unit purchased power costs, the impact on cost of sales resulting from the
formation of Energy Ventures, and the higher Fiscal 2001 sales.
Electric Operations total margin decreased $12.2 million as a result of
adjustmentsthe higher purchased power costs. Operating income declined less than the
decline in total margin reflecting lower power production and depreciation
expenses subsequent to incentive compensation accruals.
Other operating income in 1995 principally reflects income from the gas
marketing activitiesformation of GASMARK, a former division of UGI Utilities' wholly
owned subsidiary, UGI Development Company (UGIDC). Effective August 1, 1995, the
business assets of GASMARK, which totaled $1.0 million, were dividended to UGI.Energy Ventures and lower utility realty
taxes.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.1 million in 1996
compared with $16.8 million in 1995.EXPENSE. The decrease ingreater interest expense principally reflects a decrease in interest on bank loans and purchased gas cost
overcollections. The effective income tax rate was 37.9% in 1996 compared with
an effective tax rate of 29.5% in 1995. The lower income tax rate in 1995
reflects the benefit of a $4.3 million adjustment to deferred state income taxes
recorded in September 1995 (see Note 4 to Consolidated Financial Statements).
Income taxes in 1996 reflect a reduction in the Pennsylvania corporate income
tax rate to 9.99%Fiscal 2001 resulted
primarily from 11.99%.
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22greater long-term debt outstanding.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities'Utilities debt outstanding at September 30, 1997 totaled $236.3 million
compared with $227.2$285.6 million at September 30, 1996. The increase principally
reflects an increase2002.
Included in borrowingsthis amount is $37.2 million under revolving credit agreements.
Utilities may borrow up to a total of $97 million under its revolving
credit facilities.
Utilities hasagreements. The revolving credit agreements providing for borrowingscontain financial covenants
including interest coverage ratios, debt service, and minimum tangible net
worth. In September 2002, Utilities issued $40 million face value of its Series
C Medium-Term Notes under a shelf registration statement with the U.S.
Securities and Exchange Commission ("SEC"). The proceeds of the issuance were
used after the end of Fiscal 2002 principally to repay debt maturing in October
2002. Utilities may issue up to $82an additional $85 million of debt securities
under committed lines through June 30, 2000. At September 30, 1997,the shelf registration statement.
Based upon cash expected to be generated from operations, the expected
ability to refinance all or a portion of long-term debt maturing in Fiscal 2003,
and borrowings available under its revolving credit agreements, totaled $67 million.management believes
that Utilities also haswill be able to meet its anticipated contractual and projected
cash commitments in Fiscal 2003. For a shelf registration for issuance from timemore detailed discussion of Utilities'
debt and credit facilities, see Note 3 to time of upConsolidated Financial Statements.
-17-
CASH FLOWS
OPERATING ACTIVITIES. Cash provided by operating activities was $55.1
million in Fiscal 2002 compared to $75$76.1 million in Fiscal 2001. Changes in
working capital required $23.3 million of debt securities.
Dividend paymentsoperating cash flow in Fiscal 2002
compared to UGI totaled $24.1$3.8 million of operating cash flow provided in Fiscal 2001. Cash
flow before working capital changes increased to $78.4 million in 1997Fiscal 2002
compared with $32.9to $72.3 million in 1996. The Company intendsFiscal 2001, notwithstanding the decrease in Fiscal
2002 net income, reflecting in large part higher noncash charges for deferred
income taxes.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment
totaled $35.9 million during Fiscal 2002 compared to declare and pay$36.8 million during Fiscal
2001. Cash used for investing activities in Fiscal 2001 included a $6 million
cash contribution relating to the formation of Energy Ventures in December 2000.
FINANCING ACTIVITIES. We paid cash dividends to UGI subjecttotaling $37.9 million
in Fiscal 2002 compared to $35.3 million in Fiscal 2001. We also paid dividends
of $1.6 million on our preferred stock. In September 2002, we issued $40 million
face amount of Medium-Term Notes and used the availabilityproceeds after the end of earningsFiscal
2002 principally to repay debt maturing in October 2002. During Fiscal 2001, we
issued $50 million face amount of Medium-Term Notes and used the cash needsproceeds for
working capital purposes, to repay $15 million of its businesses. In
addition,maturing Medium-Term Notes,
and to reduce borrowings under our revolving credit agreements.
UTILITIES PENSION PLAN
Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI, Utilities, and certain of Utilities' debt agreements contain limitations with respect
to incurring additional debt, requireUGI's other subsidiaries. During
Fiscal 2002 and 2001, the maintenancemarket value of consolidated tangible
net worth, as defined,plan assets was negatively affected by
persistent declines in the equity markets. Notwithstanding the significant
decline in the market value of at least $125 million, and restrict the amounts of
payments for investments, redemptions of capital stock, prepayment of
subordinated debt and dividends. Under the most restrictive ofplan assets during these provisions,
permitted future payments aggregate $149.4 millionyears, at September 30,
1997.
Management believes that2002 the Pension Plan's assets exceeded its accumulated benefit obligations by
approximately $7.2 million. Utilities is in full compliance with regulations
governing defined benefit pension plans, including ERISA rules and regulations,
and does not anticipate it will be required to make a contribution to the
Pension Plan in Fiscal 2003. Pretax pension income reflected in Fiscal 2002,
2001 and 2000 results was $3.9 million, $5.7 million, and $2.9 million,
respectively. Pension income in Fiscal 2003 is expected to decline to
approximately $1.0 million principally as a result of the impact of recent
declines in the market value of Pension Plan assets.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business
segment for Fiscal 2002, 2001 and 2000. We also provide amounts we expect to
spend in Fiscal 2003. We expect to finance a substantial portion of Fiscal 2003
capital expenditures from cash flow from the Company'sgenerated by operations and funds
available under its credit facilities will be sufficient to meet its liquidity
needs for the foreseeable future.
CAPITAL EXPENDITURES
The following table presents capital expenditures of Gas Utility and Electric
Utility for the years ended September 30, 1997, 1996 and 1995, as well as
expected amounts for fiscal 1998. Utilities expects to finance 1998 capital
expenditures through internally generated cash andremainder from
borrowings under itsour credit facilities.
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- --------------------------------------------------------------------------------
Year Ended September 30, 1998 1997 1996 19952003 2002 2001 2000
- -------------------------------------------------------------------------------------------------------- ---- ---- ---- ----
(Millions of dollars) (estimate)
Gas Utility $ 37.339.6 $ 36.731.0 $ 34.631.8 $ 45.331.7
Electric Utility 5.95.3 4.9 5.0 5.0 5.9
- --------------------------------------------------------------------------------4.7
------ ------ ------ ------
$ 43.244.9 $ 41.735.9 $ 39.636.8 $ 51.2
- --------------------------------------------------------------------------------36.4
====== ====== ====== ======
YEAR 2000 MATTERSCONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The Company is currently in the processfollowing table presents significant contractual cash obligations
under agreements existing as of modifying certain of its computer
software systems so that they will function properly in the year 2000. The
Company does not expect the costs necessary to modify these systems, which costs
are and will be expensed as incurred, to have a material effect on the Company's
results of operations.
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23
CASH FLOWS
OPERATING ACTIVITIES. Utilities' operating cash flows are seasonal and are
generally greatest during the winter and spring when customers pay heating bills
incurred during the heating season. Accordingly, the actual amount of cash
generated during such period is dependent in large part upon the severity of
heating-season weather. Cash flow from operating activities was $69.5 million in
1997 compared with $57.0 million in 1996. Cash flows from operating activities
before changes in operating working capital were $64.1 million in 1997 compared
with $71.7 million in 1996. The decrease reflects in large part the effects of
lower noncash deferred tax expense in 1997. Changes in operating working capital
in 1997 provided $5.4 million of operating cash flow principally from an
increase in accounts payable and purchased gas overcollections partially offset
by an increase in accounts receivable. In 1996, changes in operating working
capital required $14.6 million of operating cash flow principally from increases
in inventories and accounts receivable and net refunds of Gas Utility fuel costs
partially offset by an increase in accounts payable.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment increased
to $41.7 million in 1997 from $39.6 million in 1996. The increase is a result of
higher Gas Utility capital expenditures.
FINANCING ACTIVITIES. During 1997, Utilities paid $24.1 million in dividends to
UGI and $2.8 million to holders of preferred stock. Utilities made debt
repayments of $27.4 million including scheduled repayments of $8.4 million of
its 7.85% Series First Mortgage Bonds, $10.0 million of 8.70% Notes, and $7.1
million of 9.71% Notes. In addition, Utilities issued $20 million of ten year
notes under its Series B Medium-Term Note program. Net borrowings under
Utilities' revolving credit facilities totaled $16.5 million in 1997 compared
with net borrowings of $8.5 million in 1996.
UTILITY BASE RATES
During the three-year period ended September 30, 1997, the following Gas and
Electric utility base rate increases became effective:2002 (in millions).
Fiscal Fiscal
2003 - ------------------------------------------------------------------------------------
Increase in Annual Revenues
Division Effective Date Requested Granted2004 2005 - ------------------------------------------------------------------------------------
(Millions of dollars)2006 Thereafter Total
----------- ----------- ---------- -----
Long-term debt $ 76.0 $ 70.0 $ 102.0 $ 248.0
UGI Utilities redeemable preferred stock -- 2.0 18.0 20.0
Operating leases 5.4 3.9 5.6 14.9
Gas and Electric Utility 7/19/96utility supply agreements 202.9 80.2 107.3 390.4
------- ------- ------- -------
Total $ 6.2284.3 $ 3.1
Gas Utility 8/31/95 41.3 19.5
- ------------------------------------------------------------------------------------156.1 $ 232.9 $ 673.3
======= ======= ======= =======
CUSTOMER CHOICE ACT
On January 1, 1997, the Customer Choice Act became effective.REGULATORY MATTERS
The Customer
Choice Act permits all Pennsylvania retail electric customers to choose their
electric generation supplier overPUC approved a three-year phase-in period commencing
January 1, 1999. The Customer Choice Act requires all
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24
electric utilities to file restructuring plans with the PUC which, among other
things, include unbundled pricessettlement establishing rules for electric generation, transmission and
distributionElectric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a competitive transition charge (CTC)separate
settlement that modified these rules on June 13, 2002 (collectively the "POLR
Settlement"). Under the terms of the POLR Settlement, Electric Utility
terminated stranded cost recovery through its CTC from commercial and industrial
("C&I") customers on July 31, 2002, and from residential customers on October
31, 2002, and is no longer subject to the statutory rate caps as of August 1,
2002 for the recoveryC&I customers and as of "stranded costs" which would be paid by all customers receiving transmission and
distribution service. "Stranded costs" generallyNovember 1, 2002 for residential customers.
Stranded costs are electric generation-related costs that traditionally would be
recoverable in a regulated environment but may not be recoverable in a
competitive electric generation market. UnderCharges for generation service will (1)
initially be set at a level equal to the Customer Choice Act, Electric Utility's rates for transmission and distribution
services provided through June 30, 2001 are capped at levels in effect on
January 1, 1997. In addition,paid by Electric Utility
generallycustomers for POLR service under the statutory rate caps; (2) may not increase the
generation component of prices as long as stranded costs are being recoveredbe raised at
certain designated times up to certain specified caps through the CTC.December 2004; and
(3) may be set at market rates thereafter. Electric Utility may also offer
multiple year POLR contracts to its customers. The POLR Settlement provides for
annual shopping periods during which customers may elect to remain on POLR
service or choose an alternate supplier. Customers who do not select an
alternate supplier will continuebe obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service at a time
other than during the annual shopping period must remain on POLR service until
the date of the second open shopping period after returning.
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C&I customers who return to POLR service at a time other than during the annual
shopping period must remain on POLR service until the next open shopping period,
and may, in certain circumstances, be the only regulated
electric utility having the right, granted bysubject to generation rate surcharges.
On June 29, 2000, the PUC orissued its order ("Gas Restructuring Order")
approving Gas Utility's restructuring plan filed by law,Gas Utility pursuant to
distribute
electric energyPennsylvania's Natural Gas Choice and Competition Act. Among other things, the
implementation of the Gas Restructuring Order resulted in its service territory.
On August 7, 1997, Electric Utility filed its Restructuring Planan increase in Gas
Utility's core-market base rates effective October 1, 2000. This base rate
increase was designed to generate approximately $16.7 million in additional net
annual revenues. In accordance with the PUC.
TheGas Restructuring Plan includes a claim for the recoveryOrder, Gas Utility
reduced its core-market PGC rates by an annualized amount of $34.4$16.7 million for
stranded costs during the period January 1, 1999 through December 31, 2002. The
claim is primarily for the recovery of: (1) plant investments in excess of
competitive market value and electric generation facility retirement costs; (2)
potential costs associated with existing power purchase agreements; and (3)
regulatory assets (principally income taxes) recoverable from ratepayers under
current regulatory practice. The claim also seeks to establish a recovery
mechanism that would permit the recovery of up to an additional $28 million of
costs associated with the buyout or implementation of a December 1993 agreement
to purchase power from an independent power producer. The PUC is expected to
take action on Electric Utility's filing in May 1998.
Given the changing regulatory environment in
the electric utility industry,first 14 months following the Company continuesOctober 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to evaluatereduce its ability to apply the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71) as it relates to its electric generation
operations. SFAS 71 permits the recording of costs (regulatory assets) that have
been, or are expected to be, allowed in the ratesetting process in a period
different from the period in which such costs would be charged to expensePGC
rates by an
unregulated enterprise. The Company believes its electric generation assets and
related regulatory assets continue to satisfy the criteria of SFAS 71. If such
electric generation assets no longer meet the criteria of SFAS 71, any related
regulatory assets would be written-off unless some form of transition cost
recovery is established by the PUC which would meet the requirements under
generally accepted accounting principles for continued accounting as regulatory
assets. Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Based upon an evaluation of the various factors and conditions affecting future
cost recovery, the Company does not expect the Customer Choice Act to have a
material adverse effect on its financial condition or results of operations.
On March 27, 1997, proposed gas customer choice legislation was introduced in
the Pennsylvania General Assembly that would, among other things, extend the
availability of gas transportation
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25
service to residential and small commercial customers of local gas distribution
companies. It would permit all customers of natural gas distribution utilities
to transport their natural gas supplies through the distribution systems of
Pennsylvania gas utilities by April 1, 1999 and would also require Pennsylvania
gas utilities to exit the merchant function of selling natural gas. Legislative
committees have conducted public hearings on the proposed legislation and the
Company has provided testimony on such issues as the recovery of costs
associated with its existing gas supply assets and the need for standards to
assure reliability of future gas supplies. The Company will continue to monitor
developments with regardamounts equal to the proposed legislation.margin it receives from interruptible customers
using pipeline capacity contracted by Gas Utility for core-market customers. As
a result, Gas Utility operating results are more sensitive to the effects of
heating-season weather and less sensitive to the market prices of alternative
fuels.
MANUFACTURED GAS PLANTS
The gas distribution business has been oneFrom the late 1800s through the mid-1900s, Utilities and its former
subsidiaries owned and operated a number of Utilities' principal lines of
business since its inception in 1882. Prior to the construction of major natural
gas pipelines in the 1950s, gas for lighting and heating was produced at manufactured gas plants (MGPs) from processes involving coal, coke or oil.("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
produced fromand other residues of the manufactured gas process are today considered
hazardous substances under the Comprehensive Environmental Response,
Compensation and Liability Act (Superfund Law)Superfund Law and may be located at those
sites.
Onepresent on the sites of
the waysformer MGPs. Between 1882 and 1953, UGI Utilities initially expanded its business was by entering into
agreements with other gas companies to operate their businesses. After 1888, the
principal means by which Utilities expanded its gas business was to acquire all
or a portion ofowned the stock of companies engaged in this business. Utilities also
provided management and administrative services to some of these companies.
Utilities grew to become one of the largest public utility holdingsubsidiary
gas companies in Pennsylvania and elsewhere and also operated the U.S.businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, by 1954 Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
The CompanyUtilities does not expect its costs for investigation and remediation of
hazardous substances at Pennsylvania MGP sites to be material to its results of
operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. Utilities has been notified of several sites outside
Pennsylvania whereon which (1) MGPs were formerly operated by Utilitiesit or owned or operated
by its former subsidiaries and (2) either environmental agencies or private
parties are investigating the extent of environmental contamination and the necessity ofor
performing environmental remediation. If
Utilities were found liable as a "responsible party" as defined in the Superfund
Law (or comparable state statutes) with respectis currently litigating two
claims against it relating to any of these sites, it would
have joint and several liability with other responsible parties for the full
amount of the cleanup costs. A "responsible party" under that statute includes
the current owner of the affected property and each owner or operator of a
facility during the time when hazardous substances were released on the
property.out-of-state sites.
Management believes that under applicable law Utilities should not have significant liabilitybe
liable in those instances in which a former subsidiary operated a MGP because Utilities
generally is not legally liable for the obligations of its subsidiaries. Under
certain circumstances, however, courts have found parent companies liable for
environmental damage caused by subsidiary companies when the parent company
exercised substantial control over the subsidiary.an MGP. There
could be, therefore,however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that Utilities owned or
directly operated, or that were owned or operated by former
-20-
subsidiaries of
-23-
26 Utilities, if a court were to conclude that the subsidiary's
separate corporate form should be disregarded.
Utilities exercised substantial
control overhas filed suit against more than fifty insurance companies
alleging that the defendants breached contracts of insurance by failing to
indemnify Utilities for certain environmental costs. The suit seeks to recover
more than $11 million in such subsidiaries.
Management believes, after consultationcosts. During 2002, 2001 and 2000, Utilities
entered into settlement agreements with counsel,several of the insurers and recorded
pre-tax income of $0.4 million, $0.9 million and $4.5 million, respectively,
which amounts are included in operating and administrative expenses in the
Consolidated Statements of Income.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding
Disclosure About Critical Accounting Policies," the Company has identified the
following critical accounting policies that future costsare most important to the portrayal
of
investigation and remediation, if any, will not have a material adverse effect
on the Company's financial position but couldcondition and results of operations. The following
accounting policies require management's most subjective or complex judgments,
as a result of the need to make estimates regarding matters that are inherently
uncertain.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are
involved in litigation regarding pending claims and legal actions that arise in
the normal course of our businesses. In addition, Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be material to operating resultspresent. In accordance with accounting
principles generally accepted in the United States, we establish reserves for
pending claims and cash flows dependinglegal actions or environmental remediation obligations when
it is probable that a liability exists and the amount or range of amounts can be
reasonably estimated. Reasonable estimates involve management judgments based on
the naturea broad range of information and timing of future developmentsprior experience. These judgments are reviewed
quarterly as more information is received and the amounts reserved are updated
as necessary. Such estimated reserves may differ materially from the actual
liability, and such reserves may change materially as more information becomes
available and estimated reserves are adjusted.
DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT. We compute depreciation on
Utilities property, plant and equipment on a straight-line basis over the
average remaining lives of future operating results and cash flows. For a more detailed
discussionits various classes of environmental matters related to MGP sites, see Note 8 to
Consolidated Financial Statements.
IMPACT OF INFLATION
Inflation impacts the Company's gas and electric utility operations primarilydepreciable property. Changes
in the prices they pay for labor, materialsestimated useful lives of property, plant and services. Because Electric
Utility's base rates are capped and Gas Utility's base rates can be adjusted
only through general rate filings with the PUC, increased costs, absent timely
rate relief, can have a significant impact on Utilities' results. Under current
tariffs, Gas Utility is permitted, after annual PUC review, to recover certain
costs of purchased gas, fuel and power which comprise a substantial portion of
Gas Utility's costs and expenses.
The Company attempts to limit the effects of inflation on its results of
operations through cost control efforts, productivity improvements and, with
respect to Gas Utility, timely rate relief.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In October 1996, the American Institute of Certified Public Accountants issued
Statement of Position No. 96-1, "Environmental Remediation Liabilities" (SOP
96-1). SOP 96-1 provides guidance on the recognition, measurement, display and
disclosure of environmental remediation liabilities. SOP 96-1, is effective for
fiscal years beginning after December 15, 1996. The adoption of SOP 96-1 in
fiscal 1998 is not expected toequipment could have a
material effect on our results of operations.
REGULATORY ASSETS AND LIABILITIES. Gas Utility, and Electric Utility's
distribution business, are subject to regulation by the Company'sPennsylvania Public
Utility Commission. In accordance with SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," we record the effects of rate regulation in our
financial statements as regulatory assets or regulatory liabilities. We
continually assess whether the regulatory assets are probable of future recovery
by evaluating the
-21-
regulatory environment, recent rate orders and public statements issued by the
PUC and the status of any pending deregulation legislation. If future recovery
of regulatory assets ceases to be probable, the elimination of those regulatory
assets would adversely impact our results of operations. As of September 30,
2002, our regulatory assets totaled $62.0 million.
MARKET RISK DISCLOSURES
Gas Utility's tariffs contain clauses that permit recovery of
substantially all of the prudently incurred cost of natural gas it sells to its
customers. The recovery clauses provide for a periodic adjustment for the
difference between the total amount actually collected from customers and the
recoverable costs incurred. Because of this ratemaking mechanism, there is
limited commodity price risk associated with our Gas Utility operations.
During Fiscal 2002, 2001 and 2000, Electric Utility purchased all of its
electric power needs, in excess of the electric power it obtained from its
interests in electric generating facilities, under power supply arrangements of
various lengths and on the spot market. Beginning September 2002, Electric
Utility began purchasing its power needs from electricity suppliers under
fixed-price energy and capacity contracts and, to a much lesser extent, on the
spot market, and our electricity generation businesses began selling on the spot
market electric power produced from its interests in electricity generating
facilities to third parties. Prices for electricity can be volatile especially
during periods of high demand or tight supply. Although the generation component
of Electric Utility's rates is subject to various rate cap provisions as a
result of the Electricity Restructuring Order and the POLR Settlement, Electric
Utility's fixed-price contracts with electricity suppliers mitigate most risks
associated with offering customers a fixed price during the contract periods.
However, should any of the suppliers under these contracts fail to provide
electric power under the terms of the power and capacity contracts, increases,
if any, in the cost of replacement power or capacity would negatively impact
Electric Utility results. In order to reduce this non-performance risk, Electric
Utility has diversified its purchases across several suppliers and entered into
bilateral collateral arrangements with certain of them.
We have both fixed-rate and variable-rate debt. Changes in interest rates
impact the cash flows of variable-rate debt but generally do not impact its fair
value. Conversely, changes in interest rates impact the fair value of fixed-rate
debt but do not impact their cash flows.
Our variable-rate debt includes borrowings under our revolving credit
agreements. These agreements provide for interest rates on borrowings that are
indexed to short-term market interest rates. Based upon the average level of
borrowings outstanding under these agreements in Fiscal 2002 and Fiscal 2001, an
increase in short-term interest rates of 100 basis points (1%) would have
increased annual interest expense by $0.5 million and $0.7 million,
respectively.
-22-
The remainder of our debt outstanding is subject to fixed rates of
interest. A 100 basis point increase in market interest rates would result in
decreases in the fair value of this fixed-rate debt of $11.0 million and $8.5
million at September 30, 2002 and 2001, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $12.0 million and $9.2 million at September 30, 2002 and
2001, respectively.
In order to reduce interest rate risk associated with near-term issuances
of fixed-rate debt, we may enter into interest rate protection agreements. The
fair value of our interest rate protection agreements, which have been
designated and qualify as cash flow hedges, was $(1.2) million at September 30,
2002. An adverse change in interest rates on ten-year U.S. treasury notes of 100
basis points would result in a $2.2 million decrease in the fair value of these
interest rate protection agreements.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No.
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144");
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146").
SFAS 143 addresses financial accounting and reporting for legal
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred with a corresponding increase in the carrying value of the
related asset. Entities shall subsequently charge the retirement cost to expense
using a systematic and rational method over the related asset's useful life and
adjust the fair value of the liability resulting from the passage of time
through charges to operating expense. We adopted SFAS 143 effective October 1,
2002. The adoption of SFAS 143 did not have a material effect on our financial
position or results of operations.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121") and
the accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" as it relates to the disposal of a segment of a business. SFAS 144
establishes a single accounting model for long-lived assets to be disposed of
based upon the framework of SFAS 121, and resolves significant implementation
issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption
of SFAS 144 did not affect our financial position or results of operations.
-23-
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"),
effective May 15, 2002. SFAS 4 had required that material gains and losses on
extinguishment of debt be classified as an extraordinary item. Under SFAS 145,
it is less likely that a gain or loss on extinguishment of debt would be
classified as an extraordinary item in our Consolidated Statement of Income.
Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases,"
to require that certain lease modifications that have economic effects similar
to sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. The provisions of SFAS 145 relating to leases
became effective for transactions occurring after May 15, 2002. The adoption of
SFAS 145 did not affect our financial position or results of operations.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force ("EITF") No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity." Generally, SFAS 146 requires that a liability for costs
associated with an exit or disposal activity, including contract termination
costs, employee termination benefits and other associated costs, be recognized
when the liability is incurred. Under EITF No. 94-3, a liability was recognized
at the date of an entity's commitment to an exit plan. SFAS 146 will be
effective for disposal activities initiated after December 31, 2002.
FORWARD-LOOKING STATEMENTS
This AnnualInformation contained above in this Management's Discussion and Analysis
of Financial Condition and Results of Operations and elsewhere in this Report on
Form 10-K containsmay contain forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Such statements use forward-looking words such as "believe," "plan,"
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss plans, strategies, events or developments that
we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or
bases underlying the forward-looking statement. We believe that we have chosen
these assumptions or bases in good faith and that they are subjectreasonable. However,
we caution you that actual results almost always vary from assumed facts or
bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking
statements, you should keep in mind the following important factors which could
affect our future results and could cause those results to differ materially
from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) price volatility and availability of
oil, electricity and natural gas and the capacity to transport to market areas;
(3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) liability for environmental claims; (6) customer conservation measures and
improvements in energy efficiency and technology resulting in reduced demand;
(7) adverse labor relations; (8)
-24-
large customer, counterparty or supplier defaults; (9) liability for personal
injury and property damage arising from explosions and other catastrophic
events, including acts of terrorism, resulting from operating hazards and risks
incidental to generating and uncertainties. Thedistributing electricity and transporting, storing
and distributing natural gas, including liability in excess of insurance
coverage; (10) political, regulatory and economic conditions in the United
States; and (11) interest rate fluctuations and other capital market conditions.
These factors are not necessarily all of the important factors that could
cause actual results to differ materially includefrom those discussed herein as well as those listedexpressed in Exhibit 99. Readers are cautioned not to place undue relianceany of our
forward-looking statements. Other unknown or unpredictable factors could also
have material adverse effects on these
forward-looking statements, which speak only as of the date of this Annual
Report on Form 10-K. The Company undertakesfuture results. We undertake no obligation to
update publicly release
any revision to these forward-looking statements to reflect eventsstatement whether as a result of new
information or circumstances afterfuture events.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
"Quantitative and Qualitative Disclosures About Market Risk" are contained
in Management's Discussion and Analysis of Financial Condition and Results of
Operations under the date of this Annual Report on Form 10-K.
-24-
27caption "Market Risk Disclosures" and are incorporated here
by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule set forth on
pages F-1 to F-28F-27 and page S-1 of this Reportreport are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During fiscal year 1997, Utilities2002, the Company engaged a new independent auditor,
Arthur AndersenPricewaterhouseCoopers LLP. The information required by Item 9 is incorporated
in this Report by reference to Utilities' Amendment No. 1 on Form 8-K/A to itsthe Company's Current Report on Form 8-K dated
July 11, 1997.May 21, 2002.
-25-
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Lon R. Greenberg 47 1994 Chairman of the Company (since August
1996)
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Lon R. Greenberg 52 1994 Mr. Greenberg has been Chairman of the Board of Directors of
UGI Utilities, Inc. since August 1996. He was formerly Vice
Chairman of the Board from 1995 to 1996, and Senior Vice
President - Legal and Corporate Development from 1989 to
1994.
James W. Stratton 66 1979 Mr. Stratton is the Chairman, Chief Executive Officer, and a
director of Stratton Management Company (an investment
advisory and financial consulting firm) (since 1972). Mr.
Stratton also serves as a director of AmeriGas Propane,
Inc.; Stratton Growth Fund, Inc.; Stratton Monthly Dividend
REIT Shares, Inc.; Stratton Small-Cap Value Fund; Teleflex,
Inc.; and BE&K, Inc.
Richard C. Gozon 64 1989 Mr. Gozon retired as Executive Vice President of
Weyerhaeuser Company in April of 2002 (an integrated forest
products company) and Chairman of Norpac (North Pacific
Paper Company, a joint venture with Nippon Paper Industries
headquartered in Tokyo, Japan) positions he has held since
1994. Mr. Gozon was formerly a director (1984 to 1993),
President and Chief Operating Officer of Alco Standard
Corporation (a provider of paper and office products) (1988
to 1993); Executive Vice President and Chief Operating
Officer (1988), President (1985 to 1987) of Paper
Corporation of America. He also serves as a director of
AmeriSource Bergen Corp.; Chief Executive Officer, (since
August 1995) Director and President
(since 1994) of UGI; formerly, Vice
Chairman of the Company (1994 to 1996)
and Senior Vice President-Legal and
Corporate Development of UGI (1989 to
July 1994). Mr. Greenberg is also a
director on the Mellon PSFS Advisory
Board.
James W. Stratton 61 1979 President of Stratton Management Company
since 1972 (investment advisory and
financial consulting firm); Chairman and
Chief Executive Officer of FinDaTex
(financial services firm). Director:
AmeriGas Propane, Inc.; Stratton Growth
Fund; Stratton Monthly Dividend Shares,
Inc.; Stratton Small-Cap Yield Fund;
Unisource Worldwide, Inc.; Teleflex, Inc.
-25-
28
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Robert C. Forney 70 1988 Retired; formerly Executive Vice
President (1981 to 1989) and Director
(1979 to 1989) of E. I. duPont de
Nemours & Co., Inc. (chemicals and
petroleum products). Director: AmeriGas
Propane, Inc.; Wilmington Trust
Corporation; Wilmington Trust Company;
Wilmington Trust of Pennsylvania.
David I. J. Wang 65 1988 Retired; formerly Executive Vice
President-Timber and Specialty Products
and a Director of International Paper
Company (1987 to 1991). Director:
AmeriGas Propane, Inc.; Weirton Steel
Corp.
Richard C. Gozon 59 1989 Executive Vice President of Weyerhaeuser
Company (integrated forest products
company) (since 1994). Formerly
Director (1984 to 1993), President and
Chief Operating Officer of Alco Standard
Corporation (provider of paper and
office products) (1988 to 1993);
Executive Vice President and Chief
Operating Officer (1987); Vice President
(1982 to 1988); President (1979 to 1987)
of Paper Corporation of America.
Director: AmeriSource Health Corporation and Triumph Group, Inc.
Quentin I. Smith, Jr. 70 1990 Retired; formerly Chairman and Chief
Executive Officer of Towers Perrin
(management consulting services) (1957
to 1987). Director: Omnicom Group Inc.;
The Guardian Life Insurance Company
of America.
-26-
29
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Stephen D. Ban 57 1991 President and Chief Executive Officer of
Gas Research Institute (gas industry
research and development) (since 1987);
formerly Executive Vice President of Gas
Research Institute (1986); formerly
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Stephen D. Ban 62 1991 Dr. Ban is currently serving as the Director of the
Technology Transfer Division of the Argonne National
Laboratory (science-based Department of Energy laboratory
dedicated to advancing the frontiers of science in energy,
environment, biosciences and materials. He previously served
as President and Chief Executive Officer of the Gas Research
Institute (GRI), a gas industry research and development
organization funded by distributors, transporters, and
producers of natural gas (1987 through 1999). He also served
as Executive Vice President. Prior to coming to GRI in 1981,
he was Vice President, Research and Development and Quality
Control of Bituminous Materials, Inc. Dr. Ban also serves as
a director of Energen Corporation.
Robert J. Chaney 60 1999 Mr. Chaney has been President and Chief Executive Officer of
UGI Utilities, Inc. (since March 1999). He previously served
as Executive Vice President - Utilities (1998 to 1999) and
Vice President and General Manager-Gas Utility Division of
the Company (1991 to 1998).
Marvin O. Schlanger 54 1998 Mr. Schlanger is a Principal in the firm of Cherry Hill
Chemical Investments, L.L.C. (management services and
capital for chemical and allied industries) (October 1998 to
present) and Chairman and Chief Executive Officer of
Resolution Performance Products, Inc. (a producer and
marketer of specialty and intermediate chemicals) (November
2000 to present). Mr. Schlanger was previously President and
Chief Executive Officer (May 1998 to October 1998),
Executive Vice President and Chief Operating Officer (1994
to May 1998) and a director (1994 to 1998) of ARCO Chemical
Company. Mr. Schlanger also serves as a director of Wellman,
Inc.
(1981).
Director: Energen Corporation.
Richard L. Bunn 61 1992 President and Chief Executive Officer of
the Company (since May 1992). Mr. Bunn
joined the Company in 1958
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Thomas F. Donovan 69 1998 Mr. Donovan retired as Vice Chairman of Mellon Bank on
January 31, 1997, a position he had held since 1988. He
continues to serve as a director of AmeriGas Propane, Inc.
and Nuclear Electric Insurance Ltd.
Anne Pol 55 1999 (and Mrs. Pol is President and Chief Operating Officer of Trex
1993-1997) Enterprises Corporation (a high technology research and
development company), a position she has held since
October 15, 2001. She previously served as Senior Vice
President, Thermo Electron Corporation (environmental
monitoring, analytical instruments and a major producer of
recycling equipment, biomedical products and alternative
energy systems) (1998 to 2001); and Vice President (1996
to 1998). Mrs. Pol also served as an
engineer in the Electric Division.
Director: Paoli Travel Services, Inc.
Anne Pol 49 1993 Vice President of Thermo Electron
Corporation (environmental technology
products and services) (since 1996);
formerly President, Pitney Bowes
Shipping and Weighing Systems Division, a business unit of
Pitney Bowes Inc. (mailing and related business equipment)
(1993 to 1996); Vice President, New Product Programs in
the Mailing Systems Division of Pitney Bowes Inc. (1991 to
1993); and Vice President, Manufacturing Operations in the
Mailing Systems Division of Pitney Bowes Inc. (1990 to 1991).
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Ernest E. Jones 58 2002 Mr. Jones is President and Chief Executive Officer of
Philadelphia Workforce Development Corporation (an agency
which funds, coordinates and implements employment and
training activities in Philadelphia), a position he has
held since 1998. He formerly served as President and
Executive Director of the Greater Philadelphia Urban
Affairs Coalition (1983 to 1998). Mr. Jones also served
as Executive Director of Community Legal Services, Inc.
(1977 to 1983). Mr. Jones also serves as a director of
the African American Museum in Philadelphia; First Union
Regional Foundation; Thomas Jefferson University; United
Way of Southeastern Pennsylvania; and the William Penn
Foundation.
(1) With the exception of Mr. Bunn, allAll of the directors except Mr. Chaney also serve as directors of UGI.UGI
Corporation. In addition, Messrs. Greenberg, Forney,Donovan, Gozon, and Stratton and Wang also serve
as directors of AmeriGas Propane, Inc., the General Partner of AmeriGas
Partners, L.P.
-27-
30
EXECUTIVE OFFICERS
Name Age Position
- ---- --- --------
Lon R. Greenberg 47 Chairman of the Board of Directors
Richard L. Bunn 61 President and Chief Executive Officer
Brendan P. Bovaird 49 Vice President and General Counsel
Robert J. Chaney 55 Vice President and General Manager-Gas
Utility Division
Mark R. Dingman 48 Vice President and General
Manager-Electric Utility Division
John C. Barney 49 Vice President-Finance and Accounting
Name Age Position
- ---- --- --------
Lon R. Greenberg 52 Chairman of the Board of Directors
Robert J. Chaney 60 President and Chief Executive Officer
Peter G. Terranova 50 Vice President -Operations
John C. Barney 54 Senior Vice President-Finance
Brendan P. Bovaird 54 Vice President and General Counsel
Vicki O. Ebner 43 Vice President -Marketing and Gas Supply
Directors are elected annually. All officers are elected for a one-year
term at the organizational meeting of the Board of Directors held each year.
-29-
There are no family relationships between any of the directors or any of
the officers or between any of the officers and any of the directors.
-28-
31
The following is a summary of the business experience of the executive
officers listed above during at least the last five years:
Lon R. Greenberg
Mr. Greenberg is Chairman of the Board of the Company (since August 1996),
having served as a Director since 1994; he is also Chairman (since 1996), Chief
Executive Officer (since August 1995) and President (since 1994) of UGI. In
addition, he is Chairman of AmeriGas Propane, Inc. (since August 1996),. Mr.
Greenberg previously served as President and Chief Executive Officer of AmeriGas
Propane, Inc. (since July 1996)(1996 to 2000).
Robert J. Chaney
Mr. Greenberg previously
served as Senior Vice President-Legal and Corporate Development of UGI (1989 to
1994).
Richard L. Bunn
Mr. BunnChaney is President and Chief Executive Officer of the Company (since
May 1992)March 1999). Mr. Bunn began his career with the CompanyHe previously served as an engineer in the
Electric Utility Division in 1958,Executive Vice President - Utilities (1998
to 1999) and successively held various operating and
staff positions.
Robert J. Chaney
Mr. Chaney is Vice President and General Manager-Gas Utility Division of the
Company (since 1991). He previously served as Vice President-Rates and
Energy Utilization of the Company's Gas Utility Division (1981(1991 to August 1991).
Mark R. Dingman
Mr. Dingman is Vice President and General Manager-Electric Utility
Division of the Company (since 1990). Previously, he was Manager-Power
Production of the Electric Division (1986 to April 1990)1998).
John C. Barney
Mr. Barney is Senior Vice President-Finance and Accounting of Utilities (since April 1992)March
1999). Previously, Mr. Barney served as Vice President-Finance of the
Company's Gas Utility Division (1987and Accounting
(1992 to April 1992)1999).
Brendan P. Bovaird
Mr. Bovaird is Vice President and General Counsel of the Company (since
April 1995). He is also Vice President and General Counsel of UGI Corporation
and AmeriGas Propane, Inc. (since April 1995). Mr. Bovaird previously served as
Division Counsel and Member of the Executive and Operations Committees of
Wyeth-Ayerst International Inc. (1992 to 1995) and Senior.
Peter G. Terranova
Mr. Terranova is Vice President General Counsel- Operations (since 1999). He previously
served as Vice President - Marketing and Secretary of Orion Pictures Corporation (1990 to 1991)Rates (1994-2000).
-29-Vicki O. Ebner
Mrs. Ebner is Vice President - Marketing, Rates and Gas Supply (since
1999). She previously served as Vice President - Gas Supply (1998-1999),
Customer Relations Manager - Harrisburg (1996-1998) and Manager - Gas Supply
Services and Regulatory Affairs (1991-1995).
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32
ITEM 11. EXECUTIVE COMPENSATION
The following table shows cash and other compensation paid or accrued to
the Company's Chief Executive Officer and each of theits four other most highly
compensated executive officers, (collectively, the "Named Executives") for the
last three fiscal years.
Summary Compensation Table
===================================================================================================================================
SUMMARY COMPENSATION TABLE
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Compensation
- -----------------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long Term Compensation
------------------------------- ------------------------------------
Awards Payouts
- -------------------------------------------------------------------------------------------------------------------------------------------------------------- -------
Other
Annual Restricted Securities
Other Underlying Long-Term All Other
Annual Options/SARs Incentive Compensation
Name and Principal Fiscal Compen- Stock underlying LTIP Compensation
Position Year Salary ($) Bonus Compensation Granted(1) sation(2) Awards (3) Options / SARs Payouts ($) (3)
Principal Position ($) (1) ($) (2) (#) ($)
===================================================================================================================================(4)
-------- ---- ------ --------- --------- ---------- -------------- ------- ---
Robert J. Chaney 2002 $294,415 $105,754 $6,814 $120,800 18,000 $0 $9,867
President and Chief $120,800
Executive Officer(6) $120,800
2001 $285,500 $144,144 $7,511 $64,688 0 $0 $9,609
$133,450
2000 $264,307 $141,570 $7,679 $0 45,000 $0 $7,569
Lon R. Greenberg, (4) (5) 1997 $509,827 $425,000 $7,671 200,000 2002 $705,015 $521,092 $15,342 $785,200 120,000 $0 $28,033
Chairman(5)(6) $0 $ 14,233
Chairman 1996 $465,000 $122,760 $7,359$785,200
$785,200
2001 $667,799 $595,010 $14,849 $323,438 0 $0 $ 10,462
1995 $381,923 $ 0 $7,365 14,167 (7)$20,939
$1,000,875
2000 $640,662 $262,836 $13,092 $0 $ 11,439
- -----------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn (5) 1997 $318,089 $139,073 $7,696 75,000 (6)225,000 $0 $ 10,254$20,417
Brendan P. Bovaird, 2002 $232,683 $95,459 $5,449 $90,600 14,500 $0 $7,411
Vice President and
Chief 1996 $305,900 $137,655 $5,855General Counsel $90,600
(5)(6) $90,600
2001 $222,283 $96,708 $5,012 $38,813 0 $0 $ 10,579
Executive Officer 1995 $305,900 $164,268 $6,684$6,112
$120,105
2000 $210,392 $49,349 $7,264 $0 28,000 $0 $5,927
John C. Barney 2002 $176,033 $64,262 $6,340 $60,400 8,000 $0 $5,124
Senior Vice President $60,400
- -Finance $60,400
2001 $170,826 $51,710 $3,827 $31,050 0 $0 $ 9,732
- -----------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney
Vice President & 1997 $164,396 $ 51,457 $4,272 35,000 (6)$5,167
$68,059
2000 $164,848 $58,806 $2,145 $0 $ 4,921
General Manager, 1996 $156,601 $ 54,321 $4,019 015,000 $0 $ 5,074
Gas Utility Division 1995 $156,429 $ 68,904 $2,757 0 $0 $ 4,579
- -----------------------------------------------------------------------------------------------------------------------------------$4,453
Mark R. Dingman, Vice President & 1997 $125,298 $ 26,322 $6,410 35,000 (6)2002 $156,003 $35,161 $7,335 $60,400 8,000 $0 $ 3,649
General Manager, 1996 $120,000 $ 33,600 $5,730 0 $0 $ 3,375
Electric Utility Division 1995 $119,912 $ 23,640 $4,036 0 $0 $ 3,493
- -----------------------------------------------------------------------------------------------------------------------------------
Brendan P. Bovaird (4)(5) 1997 $164,653 $ 64,449 $3,769 30,000 (6) $0 $ 4,196$3,510
Vice President and 1996 $149,999 $ 21,853 $1,299$60,400
General Manager - $60,400
Electric Utility 2001 $152,882 $0 $6,862 $38,813 0 $0 $ 1,363
General Counsel 1995 $ 66,346 $ 8,663 $ 0 10,000 (7)$4,258
$88,077
2000 $149,583 $36,383 $6,907 $0 $ 0
===================================================================================================================================28,000 $0 $4,385
(1) Bonuses earned under the UGI Corporation and UGI Utilities, Inc. Annual Bonus PlansPlan are for the year reported,
regardless of the year paid. The Company's Annual Bonus Plans arePlan is based on
the achievement of pre-determined business and/or financial performance objectives, which
support business plans and goals. Bonus opportunities vary by position and
for fiscal year 1997Fiscal 2002 ranged from 0% to 148%86% of base salary for Mr. Chaney, 0% to
184% of base salary for Mr. Greenberg, 0% to 52%104% of base salary for Mr.
Bunn,
fromBovaird, 0% up to 38%60% of base salary for Mr. Chaney, fromBarney and 0% to 30%52% of base
salary for Mr. Dingman, and from
0% to 65% for Mr. Bovaird.Dingman.
(2) Amounts represent tax payment reimbursements for certain benefits.benefits and, for
Messrs. Barney and Bovaird, above-market interest on deferred
compensation.
(3) Effective January 1, 2002, the Board of Directors of UGI Corporation,
approved three phantom performance-contingent
-31-
restricted stock awards ("Restricted Shares") to the Named Executives
under the UGI Corporation 2000 Stock Incentive Plan. The restriction
period for all three awards will end on December 31, 2004 provided that
certain performance criteria are met for each performance period. Each
award has a separate performance period as follows: January 1, 2002
through December 31, 2002, January 1, 2002 through December 31, 2003, and
January 1, 2002 through December 31, 2004. The performance requirement is
that UGI's Total Shareholder Return (TSR) during the relevant performance
period equals the median of a peer group. The peer group is the group of
companies that comprises the S&P Utilities Index. The actual amount of the
award may be higher or lower than the original grant, or even zero, based
on UGI's TSR percentile rank relative to the companies in the S&P
Utilities Index. The maximum payout potential is 200% of the original
award. The share price used for determining the TSR at the beginning and
the end of each performance period will be the average price for the
90-day period preceding each December 31st.
The dollar values shown in the restricted stock awards column of the table
above represent the aggregate value of each award on the date of grant,
determined by multiplying the number of shares awarded by the closing
price of UGI Common Stock on the New York Stock Exchange on the effective
dates of the respective grants.
Based on the closing stock price of UGI Common Stock on the New York Stock
Exchange on September 30, 2002, Mr. Greenberg's 128,000 Restricted Shares
had a market value of $4,652,800; Mr. Chaney's 19,500 Restricted Shares
had a market value of $708,825; Mr. Bovaird's 15,000 Restricted Shares had
a market value of $545,250; Mr. Barney's 9,750 Restricted Shares had a
market value of $354,413 and Mr. Dingman's 10,800 Restricted Shares had a
market value of $392,580.
(4) Amounts represent matching contributions by the Company or UGI in
accordance with the provisions of the UGI Utilities, Inc. Employee Savings
Plan and/or allocations under the Executive Retirement Plan. During 1997,
19962002,
2001 and 1995,2000, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: Forfor each of Messrs.
Greenberg, Bunn, Chaney, Bovaird and Dingman, $3,375, $3,375Barney $3,825, $3,825, and $3,375;$3,825; and Mr.
Bovaird,
-30-
33
$3,375, $1,363Dingman $3,510, $3,825, and $0; and$3,825; (ii) under the Supplemental Executive
Retirement Plan: Mr. Greenberg, $10,858, $7,087$24,208, $17,114, and $8,064;$16,592; Mr. Bunn, $6,879, $7,204Chaney,
$6,042, $5,784, and, $6,357;$3,744; Mr. Bovaird, $821, $0$3,586, $2,287, and $0;$2,102; Mr.
Chaney, $1,546, $1,699Barney, $1,299, $1,342, and $1,204;$628; and Mr. Dingman, $274, $0, $433, and $118.
(4) Mr. Greenberg was elected Chairman, UGI Utilities, Inc. effective August 1,
1996.$560.
(5) Compensation for Mr. Greenberg is attributable to his employment as
Chairman, President and Chief Executive Officer of UGI Corporation.
Compensation for Mr. Bovaird is attributable to his employment as Vice
President and General Counsel of UGI Corporation. Mr. Greenberg and Mr.
Bovaird receive no compensation from UGI Utilities, Inc.
(5)(6) Compensation reported for Messrs. Greenberg, Bovaird and BunnChaney is also
reported in the Proxy Statement for UGI's 19982002 Annual Meeting of
Shareholders and is not additive.
(6) Non-qualified-32-
Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values
The following table shows information for fiscal year 2002 concerning
exercised and unexercised stock options grantedfor shares of UGI Common Stock for each
of the Named Executives.
Option Exercises in Fiscal 2002
And Fiscal Year-End Option Values
Value of
Number of Securities Unexercised
Underlying Unexercised In-The-Money
Number of Options at Options at
Shares Fiscal Year End Fiscal Year End (2)
Acquired on Value -------------------------- ------------------------------
Name Exercise Realized (1) Exercisable Unexercisable Exercisable Unexercisable
---- -------- ------------ ----------- ------------- ----------- -------------
Robert J. Chaney 13,639 $135,697 78,889 33,000 $1,152,475 $339,375
Lon R. Greenberg 123,959 $1,661,893 468,750 251,250 $7,113,281 $2,767,969
Brendan P. Bovaird 0 $0 48,667 14,500 $705,289 $83,375
John C. Barney 0 $0 20,000 13,000 $294,500 $124,625
Mark R. Dingman 18,666 $220,176 0 17,334 $0 $192,777
(1) Value realized is calculated on December 10, 1996 under the UGI 1997
Stock Option and Dividend Equivalent Plan (the "1997 Plan"). The 1997 Plan
consists of non- qualified stockdifference between the option grantsexercise
price and the opportunity for
participants to earn an amount equivalent to the dividends paid on shares
covered by options, subject to a comparison of the total return realizable
on a shareclosing market price of UGI's Common Stock ("on the date
of exercise multiplied by the number of shares to which the exercise
relates.
(2) The closing price of UGI's Return") withCommon Stock as reported on the total return
achieved by each memberNew York
Stock Exchange Composite tape on September 30, 2002 was $36.35 and is used
in calculating the value of a group of comparable peer companies (the "SODEP
Peer Group") over a three-year period beginning January 1, 1997 and ending
December 31, 1999. Total return encompasses both changesunexercised options.
-33-
Option Grants in the per share
market price and dividends paid on a share of common stock.
(7) Non-qualified stock options granted under the UGI 1992 Stock Option and
Dividend Equivalent Plan (the "1992 Plan").
-31-
34
OPTION GRANTS IN LAST FISCAL YEARLast Fiscal Year
The following table shows information on grants of stock options for UGI
Corporation Common Stock during fiscal year 19972002 to each of the Named
Executives.
- -------------------------------------------------------------------------------------------------------------------------------
OPTION GRANTS IN LAST FISCAL YEAR
- -------------------------------------------------------------------------------------------------------------------------------
INDIVIDUAL GRANTS GRANT DATE
VALUE
- -------------------------------------------------------------------------------------------------------------------------------
NUMBER OF
Grant Date
Individual Grants Value
----------------- -----
Number of
Securities % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO EXERCISE
OPTIONS EMPLOYEES IN OR BASE EXPIRATION GRANT DATE
NAME GRANTEDof Total
Underlying Options Granted Grant Date
Options to Employees in Exercise Present
Name Granted Fiscal Year (1) FISCAL YEARor Base Price Expiration Date Value (2)
PRICE DATE PRESENT VALUE (3)
- ----------------------------------------------------------------------------------------------------------------------------------- ------- --------------- ------------- --------------- ---------
Robert J. Chaney 18,000 4.02% $30.600 12/31/2011 $92,093
Lon R. Greenberg 200,000 45% $22.625120,000 26.77% $30.600 12/09/06 $ 486,000
- -------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn 75,000 17% $22.62531/2011 $613,953
Brendan P. Bovaird 14,500 3.23% $30.600 12/09/06 $ 182,250
- -------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney 35,000 8% $22.62531/2011 $74,186
John C. Barney 8,000 1.78% $30.600 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------31/2011 $40,930
Mark R. Dingman 35,000 8% $22.6258,000 1.78% $30.600 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------
Brendan P. Bovaird 30,000 7% $22.625 12/09/06 $ 72,900
===============================================================================================================================31/2011 $40,930
(1) Non-qualified stock options granted on December 10, 1996 under the 1997
SODEP. This grant also includes the opportunity to earn an amount
equivalent to the dividends paid during the performance period on shares
covered by options. The option exercise price is not less than 100% of the
fair market value of UGI's Common Stock determined on the date of the
grant. These options were fully vested on the date of grant. Options
granted under the Plan are nontransferable and are generally exercisable
only while the optionee is employed by the Company or an affiliate. Options
are subject to adjustment in the event of recapitalizations, stock splits,
mergers, and other similar corporate transactions affecting UGI's Common
Stock.
(2) A total of 445,000448,250 options were granted to employees and executive
officers of the Company during fiscal year 19972002 under the 1997 SODEP and the 1992
Non-Qualified Stock Option Plan. UnderPlan, the 19922000 Stock Incentive Plan and the
2002 Non-Qualified Stock Option Plan. Under each Plan, the option exercise
price is not less than 100% of the fair market value of UGI's Common Stock
on the date of grant. Options granted on
and after December 10, 1996 are fully vestedAll options will vest at the rate of 33% per year on
the dateanniversary of grant.the grant date. Options
under the 1992 Plan are nontransferable and
generally exercisable only while the optionee is employed by the Company
or an affiliate. Options are subject to adjustment in the event of
recapitalizations, stock splits, mergers, and other similar corporate
transactions affecting UGI's Common Stock.
-32-
35
(3)(2) Based on the Black-Scholes options pricing model. The assumptions used in
calculating the grant date present value are as follows:
- - Three years of closing monthly stock price and dividend observations
were used to calculate the stock volatility and dividend yield
assumptions
- - Stock volatility - .1676
- - Stock's dividend yield - 6.54%
- - Length of option term - 10 years
- - Annualized risk-free interest rate - 6.36%assumptions.
- Stock volatility 29.10%
- Stock's dividend yield 6.70%
- Length of option term 10 years
- Annualized risk-free interest rate 5.54%
- Discount of risk of forfeiture - 0% per year
All options were granted at fair market value. The actual value, if any, the
executive may realize will depend on the excess of the stock price on the date
the option is exercised over the exercise price. There is no assurance that the
value realized by the executive will be at or near the value estimated by the
Black-Scholes model.
-33-
36
OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION VALUES
The following table shows information for the 1997 fiscal year
concerning exercised and unexercised stock options for shares of UGI Common
Stock for each of the Named Executives.
====================================================================================================================================
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUE
====================================================================================================================================
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED IN-THE-
OPTIONS/SARS MONEY OPTIONS/
AT FISCAL YEAR END (#) SARs AT FISCAL YEAR END ($)
- ------------------------------------------------------------------------------------------------------------------------------------
SHARES
ACQUIRED VALUE
ON REALIZED
NAME EXERCISE (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
====================================================================================================================================
143,959 (2) -0- $1,079,693(4) $0
Lon R. Greenberg (1) -0- $0 200,000 (3) -0- $1,000,000(5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
87,500 (2) -0- $ 656,250 (4) $0
Richard L. Bunn (1) -0- $0 75,000 (3) -0- $ 375,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
45,000 (2) -0- $ 337,500 (4) $0
Robert J. Chaney -0- $0 35,000 (3) -0- $ 175,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
2,950 (2) -0- $ 22,125 (4) $0
Mark R. Dingman 42,050 $291,225 35,000 (3) -0- $ 175,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
10,000 (2) -0- $ 75,000 (4) $0
Brendan P. Bovaird -0- $0 30,000 (3) -0- $ 150,000 (5) $0
====================================================================================================================================
(1) Information reported for Messrs. Greenberg and Bunn is also reported in the
Proxy Statement for UGI's 1998 Annual Meeting of Shareholders and is not
additive.
(2) Options granted under the 1992 Stock Option and Dividend Equivalent Plan.
(3) Options granted under the 1997 Stock Option and Dividend Equivalent Plan.
(4) Value based on comparison of price per share at September 30, 1997 (fair
market value $27.625) to the 1992 Plan option price ($20.125).
(5) Value based on comparison of price per share at September 30, 1997 (fair
market value $27.625) to the 1997 Plan option price ($22.625).
-34-
37
RETIREMENT BENEFITS
The following table shows the annual benefits payable upon retirement at age 65
in 1997 applicable for various combinations of final average earnings and length
of service which may be payableto
the Named Executive Officers under the Retirement Income Plan for Employees of
UGI Utilities, Inc. and participating employers (the "Retirement Plan") and the
UGI Supplemental Executive Retirement Plan.
=============================================================================================================================The amounts shown assume the
executive retires in 2002 at age 65, and that the aggregate benefits are not
subject to statutory maximums.
PENSION PLAN BENEFITS TABLE
ANNUAL PLAN BENEFITS
- -----------------------------------------------------------------------------------------------------------------------------
FINAL 5-
YEAR
AVERAGE ANNUAL BENEFIT FOR YEARS OF CREDITED SERVICE SHOWN (1)
FINAL 5-YEAR
AVERAGE ANNUAL 5 10 15 20 25 30 35 40
EARNINGS (2) ----------------------------------------------------------------------------------------------------------
15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS 40 YEARS =============================================================================================================================YEARS YEARS
------------ ----- ----- ----- ----- ----- ----- ----- -----
$100,000 $28,500 $38,000 $47,500 $57,000 $66,500 $68,400
$ 200,000 $ 19,000 $ 38,000 $ 57,000 $ 76,000 $ 95,000 $ 114,000 $ 133,000 $ 136,800 (3)
$200,000 $57,000 $76,000 $95,000 $114,000 $133,000 $136,800 (3)
$300,000 $85,500 $114,000 $142,500 $171,000 $199,500 $205,200 (3)
$400,000$ 400,000 $ 38,000 $ 76,000 $114,000 $152,000 $190,000 $228,000 $266,000 $273,600$ 228,000 $ 266,000 $ 273,600 (3)
$500,000 $142,500 $190,000 $237,500 $285,000 $332,500 $342,000 (3)
$600,000$ 600,000 $ 57,000 $114,000 $171,000 $228,000 $285,000 $342,000 $399,000 $410,400$ 342,000 $ 399,000 $ 410,400 (3)
$700,000 $199,500 $266,000 $332,500 $399,000 $465,500 $478,800 (3)
$800,000$ 800,000 $ 76,000 $152,000 $228,000 $304,000 $380,000 $456,000 $532,000 $547,200$ 456,000 $ 532,000 $ 547,200 (3)
$900,000 $256,500 $342,000 $427,500 $513,000 $598,500 $615,600 (3)
$1,000,000 $ 95,000 $190,000 $285,000 $380,000 $475,000 $570,000 $665,000 $684,000$ 570,000 $ 665,000 $ 684,000 (3)
$1,200,000 $114,000 $228,000 $342,000 $456,000 $570,000 $684,000 $798,000 $820,800$ 684,000 $ 798,000 $ 820,800 (3)
$1,400,000 $133,000 $266,000 $399,000 $532,000 $665,000 $798,000 $931,000 $957,600$ 798,000 $ 931,000 $ 957,600 (3)
=============================================================================================================================$1,600,000 $152,000 $304,000 $456,000 $608,000 $760,000 $ 912,000 $1,064,000 $1,094,400 (3)
$1,800,000 $171,000 $342,000 $513,000 $684,000 $855,000 $1,026,000 $1,197,000 $1,231,200 (3)
$2,000,000 $190,000 $380,000 $570,000 $760,000 $950,000 $1,140,000 $1,330,000 $1,368,000 (3)
(1) Annual benefits are computed on the basis of straight life annuity
amounts. These amounts include pension benefits, if any, to which a
participant may be entitled as a result of participation in a pension plan
of a subsidiary during previous periods of employment. The amounts shown
do not take into account exclusion of up to 35% of the estimated primary
Social Security benefit. The Retirement Plan provides a minimum benefit
equal to 25% of a participant's final 12 months' earnings, reduced
proportionately for less than 15 years of credited service at retirement.
The minimum Retirement Plan Benefit is not subject to Social Security
offset. Messrs. Greenberg, Bunn,Barney, Chaney, Dingman and Bovaird had,
respectively, 1722 years, 3930 years, 3338 years, 2429 years and 27 years of
estimated credited service at September 30, 1997.
-35-
382002.
(2) Consists of (i) base salary, commissions and cash payments under the UGI
and Utilities Annual Bonus Plans, and (ii) deferrals thereof permitted
under the Internal Revenue Code.
(3) The maximum benefit under the Retirement Plan and the Supplemental
Executive Retirement Plan is equal to 60% of a participant's highest
consecutive 12 months' earnings during the last 120 months.
-35-
SEVERANCE PAY PLAN FOR SENIOR EXECUTIVE EMPLOYEES
The UGI Corporation Senior Executive Employee Severance Pay Plan (the "UGI
Severance Plan") assists certain senior level employees of Utilities, including
Messrs. Greenberg, Bovaird, Chaney, DingmanBarney and LadnerDingman in the event their
employment is terminated without fault on their part. Specified benefits are
payable to a senior executive covered by the UGI Severance Plan if the senior
executive's employment is involuntarily terminated for any reason other than for
cause or as a result of the senior executive's death or disability.
Benefits payable include a lump sumThe UGI Severance Plan provides for cash payment in an amount
approximatelypayments equal to the suma participant's
compensation for a period of (i) threetime ranging from 3 months of compensation (18to 15 months (30 months
in the case of Mr. Greenberg), (ii)depending on length of service. In addition, a
pro rata portionparticipant receives the cash equivalent of the senior executive's
annualhis or her target bonus under the
Annual Bonus Plan, pro-rated for the current year, provided
that the employment termination date occurs during the first tennumber of months ofserved in the fiscal year, or,year.
However, if the employment termination date occurs duringin the last two months of the fiscal year,
and the Chief Executive Officer determines not to use
hishas the discretion to paydetermine whether the
participant will receive a pro-rata portion of the executive's annualpro-rated target bonus, or the fullactual annual bonus
payablewhich would have been paid after the end of the fiscal year, assuming that (x) the
weighting to be applied toparticipant's entire bonus was contingent on meeting the business/applicable financial
performance goals is 100%, and
(y) the employee served the entire fiscal year, and (iii) separation pay
determined in a manner consistent with that payable to employees generally, not
exceeding 12 months of compensation.goal. Certain employee benefits are continued under the Plan for a
specified period (the "Employee Benefit Period") not exceedingof up to 15 months (30 months in the case of Mr. Greenberg) after termination, or. Utilities
has the senior executive
may be paidoption to pay a lump sum equal toparticipant the present valuecash equivalent of suchthose employee
benefits.
In order to receive benefits under the UGI Severance Plan, a senior
executive is required to execute a release which discharges Utilities and its
affiliates from liability for any claims the senior executive may have against
any of them, other than claims for amounts or benefits due to the executive
under any plan, program or contract provided by or entered into with Utilities
or its affiliates. The senior executive is also required to cooperate in
attending to matters pending at the time of his or her termination of
employment.
-36-
39
CHANGE OF CONTROL ARRANGEMENTS
The Named Executives Employed by UGI Corporation. Messrs. Greenberg and
Bovaird each have an agreement with UGI Corporation (the "Agreement") which
provides certain benefits in the event of a change of control of UGI. The
Agreements operate independently of the UGI Severance Plan, continue through
July 2002,2004, and are automatically extended in one-year increments thereafter
unless, prior to a change of control, UGI terminates an Agreement. In the
absence of a change of control, each Agreement will terminate when, for any
reason, the executive terminates his employment with UGI or its subsidiaries.
A change of control is generally deemed to occur if: (i) any person (other
than the executive, his affiliates and associates, UGI or any of its
subsidiaries, any employee benefit plan of UGI or any of its subsidiaries, or
any person or entity organized, appointed, or established by UGI or its
subsidiaries for or pursuant to the terms of any such employee benefit plan),
together with all affiliates and associates of such person, acquires securities
representing 20% or more of either (x) the then outstanding shares of common
stock of UGI or (y) the combined voting power
-36-
of UGI's then outstanding voting securities, in either case unless the members of the Executive Committee of the
Board of Directors in office immediately prior to such acquisition (the
"Executive Committee") determine that the circumstances do not warrant the
implementation of the provisions of the Agreement;securities; (ii) individuals who at the
beginning of any 24-month period constitute the Board of Directors (the
"Incumbent Board") and any new director whose election by the Board, or
nomination for election by UGI's shareholders, was approved by a vote of at
least a majority of the Incumbent Board, cease for any reason to constitute a
majority thereof; (iii) UGI is reorganized, merged or consolidated with or into,
or sells all or substantially all of its assets to, another corporation in a
transaction in which former shareholders of UGI do not own more than 50% of the
outstanding common stock and the combined voting power, respectively, of the
then outstanding voting securities of the surviving or acquiring corporation
after the transaction, in any such case, unless the Executive Committee
determines at the time of such transaction that the circumstances do not warrant
the implementation of the provisions of the Agreement;transaction; or (iv) UGI is liquidated or dissolved.
Upon a change of control, the Agreement provides for an immediate cash
payment equal to the market value of any pending target award under UGI's
long-term compensation plan.
Severance benefits are payable under the Agreements if there is a
termination of the executive's employment without cause at any time within three
years after a change of control. In addition, following a change of control, the
executive may elect to terminate his or her employment without loss of severance
benefits in certain specified contingencies, including termination of officer
status; a significant adverse change in authority, duties, responsibilities or
compensation; the failure of UGI to comply with and satisfy any of the terms of
the Agreement; or a substantial relocation or excessive travel requirements.
An executive who is terminated with rights to severance compensation under
an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 (2.5 in
the case of Mr. Greenberg) times his average total cash remuneration for the
preceding five calendar years. If the severance compensation payable under the
Agreement, either alone or together with other payments to an executive, would
constitute "excess parachute payments," as defined in Section 280G of the
Internal Revenue Code of 1986, as amended (the "Code"), the executive will also
receive an amount to satisfy the executive's additional tax burden.
Named Executives Employed by UGI Utilities, Inc. Messrs. Chaney, Barney
and Dingman each have an agreement with UGI Utilities (the "Agreement") which
provides certain benefits in the event of a change of control of Utilities or of
UGI. The Agreements operate independently of the UGI Severance Plan, continue
through July 2004, and are automatically extended in one-year increments
thereafter unless, prior to a change of control, the Company terminates an
Agreement. In the absence of a change of control, each Agreement will terminate
when, for any reason, the executive terminates his employment with Utilities or
its subsidiaries.
A change of control is generally deemed to occur if a change of control of
UGI, as defined above, occurs or if: (i) UGI and its subsidiaries fail to own
more than fifty percent of the combined voting power of the Company's then
outstanding voting securities, (ii) the Company is reorganized, merged or
consolidated with or into, or sells all or substantially all of its assets to,
another corporation in a transaction in which former shareholders of the Company
do not own more than 50% of the outstanding common stock and the combined voting
power, respectively, of the then outstanding voting securities of the surviving
or acquiring corporation after the transaction, or (iii) the Company is
liquidated or dissolved.
-37-
40Upon a change of control, the Agreement provides for an additional amount, such that the net amount retained afterimmediate cash
payment of
applicable taxes is equal to the market value of any pending target award under Utilities'
long-term compensation plan.
Severance benefits are payable under the Agreements if there is a
termination of the executive's employment without cause at any time within three
years after a change of control. In addition, following a change of control, the
executive may elect to terminate his or her employment without loss of severance
benefits in certain specified contingencies, including termination of officer
status; a significant adverse change in authority, duties, responsibilities or
compensation; the failure of the Company to comply with and satisfy any of the
terms of the Agreement; or a substantial relocation or excessive travel
requirements.
An executive who is terminated with rights to severance compensation under
an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 times his
average total cash remuneration for the preceding five calendar years. If the
severance compensation payable.
BOARDpayable under the Agreement, either alone or together
with other payments to an executive, would constitute "excess parachute
payments," as defined in Section 280G of the Internal Revenue Code of 1986, as
amended (the "Code"), the executive will also receive an amount to satisfy the
executive's additional tax burden.
COMPENSATION OF DIRECTORS
Messrs. BunnChaney and Greenberg who are officers of either the Company or
its parent, UGI, are not compensated for service on the Board
of Directors or on any Committee of the Board. The other members of the
Company's Board of Directors also serve on the UGI Board and receive no
additional compensation for service on the Company's Board. The Company
reimburses UGI for 50% of the attendance fees and expenses incurred by the
non-employee directors of UGI.
COMPENSATION COMMITTEE
The members of the UGI Utilities, Inc. Compensation and Management
Development Committee are Robert C. Forney (Chairman), Richard C. Gozon Quentin
I. Smith, Jr.(Chairman), Thomas F. Donovan and
David I. J. Wang.
-38-
41Anne Pol.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
At December 9, 1997,2, 2002, UGI Corporation held 100% of the Company's Common
Stock. UGI is located at 460 N.North Gulph Road, King of Prussia, PA 19406.
The following table sets forth, as of December 9, 1997,October 31, 2002, the number of
shares of Common Stock of UGI beneficially owned by each director of the Company
and each of the Named Executives, as well as all directors and executive
officers as a group. Mr. Greenberg is the beneficial owner of approximately 1.2%2%
of UGI's Common Stock. All other directors, Named Executives and executive
officers own less than 1% of UGI's outstanding shares. The total
-38-
number of shares beneficially owned by theall directors and executive officers as a
group (including 630,859726,739 shares subject to options exercisable within 60 days),options) represents
approximately 2.7%4% of UGI's outstanding shares.
SECURITY OWNERSHIP OF MANAGEMENT
NUMBER OF SHARES
AND NATURE OF
BENEFICIAL
OWNERSHIP NUMBER
OWNERSHIP OF
EXCLUDING OPTIONS EXERCISABLE STOCK
NAME OF BENEFICIAL OWNER OPTIONS (1)(2) OPTIONS TOTAL
- ------------------------ ----------------- ------- -----
Stephen D. Ban 8,70515,470 (2) 14,100 29,570
John C. Barney (3) 3,400 12,1058,343 20,000 28,343
Brendan P. Bovaird 8,147 (4) 40,000 48,147
Richard L. Bunn 62,600 (5) 75,000 137,60022,965 48,667 71,632
Robert J. Chaney 9,72038,450 (5) 78,889 117,339
Thomas F. Donovan 5,629 (2) 12,800 18,429
Richard C. Gozon 25,964 (2) 16,800 42,764
Lon R. Greenberg (6) 149,500 159,220112,040 468,750 580,790
Anne Pol 11,752 (2) 12,800 24,552
Marvin O. Schlanger 9,433 (2) 12,800 22,233
James W. Stratton (7) 16,427 (2) 16,800 33,227
Peter G. Terranova (8) 4,871 20,333 25,204
Mark R. Dingman 358 35,000 35,358
Robert C. Forney 12,18617,000 0 17,000
Ernest E. Jones 1,084 (2) 4,000 16,186
Richard C. Gozon 11,768 5,000 16,768
Lon R. Greenberg 90,360 (7) 293,959 384,319
Anne Pol 4,276 0 4,276
Quentin I. Smith, Jr. 8,071 5,000 13,071
James W. Stratton 8,779 5,000 13,779
David I. J. Wang 20,894 5,000 25,8945,084
All directors and executive
officers as a group (13) 210,019 630,859 879,363
- --------------------(13 total) 314,761 726,739 1,041,500
(1) This column shows shares held in the individual's name,
individuallyThe director or jointly with others, or in the name of a bank, broker or nominee
for the individual's account. It includes 2,000 shares held directly by Mr.
Bunn's spouse.
-39-
42officer has sole voting and investment power unless
otherwise specified.
(2) Included in theThe number of sharesShares shown above areincludes Deferred Units ("Units")
acquired through the 1997 Amended and Restated Directors' Equity
Compensation Plan. Units are neither actual shares nor other
securities, but each Unit will be converted to one share of Common
Stock and paid out to directors upon their retirement or termination
of service. The number of Units included for each director is as
follows: Messrs. Donovan (3,546), Stratton (7,351 Units)(13,316), Forney (7,358
Units), Wang (6,466 Units)Schlanger
(6,950), Gozon (5,340 Units), Smith (5,643 Units)(18,853), Ban (3,424 Units) and(9,653), Mrs. Pol (2,923 Units)(9,879) and Mr. Jones
(970).
(3) Shares are held jointly with Dr. Ban's spouse.
(4) Includes the number ofMr. Barney holds 236 shares represented by units held in the UGI
Stock Fund of the 401(k) Employee Savings Plan.
(5) Includes 45,092Plan, based on September
30, 2002 Savings Plan statements. Mr. Barney disclaims beneficial
ownership of 200 Shares owned by an adult son.
-39-
(4) Mr. Bovaird holds 19,993 shares held jointly with Mr. Bunn'shis spouse and 2,0002,972
Shares represented by units held in the UGI Stock Fund of the 401(k)
Employee Savings Plan, based on September 30, 2002 Saving Plan
statements.
(5) Mr. Chaney is trustee of a trust that holds 13,650 shares.
(6) Mr. Greenberg holds 88,220 shares jointly with his spouse and 6,105
Shares represented by units held directly byin the UGI Stock Fund of the 401(k)
Employee Savings Plan, based on September 30, 2002 Saving Plan
statements.
(7) Mr. Stratton holds 3,111 shares jointly with his spouse.
(6) Includes 2,561(8) Mr. Terranova holds 820 shares represented by units held jointly with Mr. Chaney's spouse.
(7) Includes 72,759in the UGI
Stock Fund of the 401(k) Employee Savings Plan, based on September
30, 2002 Savings Plan statements.
(9) The total number of shares held jointly with Mr. Greenberg's spouse.beneficially owned by the directors and
officers as a group represents approximately 4% of UGI's outstanding
Shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 19972002 UGI allocated $5,554,727, representing 42%49%, or approximately $6.7 million, of
its general corporate expenses to Utilities.
ITEM 14. CONTROLS AND PROCEDURES
An evaluation of the effectiveness of the design and operation of the
Company's disclosure controls and procedures as of December 20, 2002 was carried
out by the Company under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the Company's disclosure controls and
procedures have been designed and are being operated in a manner that provides
reasonable assurance that the information required to be disclosed by the
Company in reports filed under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms. A controls system, no matter how well designed and
operated, cannot provide absolute assurance that the objectives of the controls
system are met, and no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within a company have
been detected. Subsequent to the date of the most recent evaluation of the
Company's internal controls, there were no significant changes in the Company's
internal controls or in other factors that could significantly affect the
internal controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.
-40-
43
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 14.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(a) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTSSTATEMENTS:
Included under Item 8 are the following financial statements
and supplementary data:
Reports of Independent Public Accountants
Consolidated Balance Sheets as of September 30, 19972002 and
19962001
Consolidated Statements of Income for the fiscal years
ended September 30, 1997, 19962002, 2001 and 19952000
Consolidated Statements of Cash Flows for the fiscal
years ended September 30, 1997, 19962002, 2001 and 19952000
Consolidated Statements of Stockholders' Equity for the
fiscal years ended September 30, 1997, 19962002, 2001 and 19952000
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULES
II-ValuationSCHEDULE:
For the years ended September 30, 2002, 2001 and 2000
II- Valuation and Qualifying Accounts
AllWe have omitted all other financial statement schedules are omitted
because the required information is (1) not present orpresent; (2) not
present in amounts sufficient to require submission of the
scheduleschedule; or because the information required is(3) included elsewhere in the respective financial
statements or notes thereto contained herein.in this report.
NOTICE REGARDING ARTHUR ANDERSEN LLP
Arthur Anderson LLP audited our consolidated financial
statements for the three years in the period ended September
30, 2001 and issued a report thereon dated November 16, 2001.
Arthur Anderson LLP has not reissued its report or consented
to the incorporation by reference of such report into the
Company's prospectuses relating to offering and sale of our
debt
-41-
44securities. On June 15, 2002, Arthur Andersen LLP was
convicted of obstruction of justice by a federal jury in
Houston, Texas in connection with Arthur Andersen LLP's work
for Enron Corp. On September 15, 2002, a federal judge upheld
this conviction. Arthur Andersen LLP ceased its audit practice
before the SEC on August 31, 2002. Effective May 21, 2002, we
terminated the engagement of Arthur Andersen LLP as our
independent accountants and engaged PricewaterhouseCoopers LLP
to serve as our independent accountants for the fiscal year
ending September 30, 2002. Because of the circumstances
currently affecting Arthur Andersen LLP, as a practical matter
it may not be able to satisfy any claims arising from the
provision of auditing services to us, including claims
available to security holders under federal and state
securities laws.
(3) LIST OF EXHIBITS:
The exhibits filed as part of this Reportreport are as follows
(exhibits incorporated by reference are set forth with the
name of the registrant, the type of report and registration
number or last date of the period for which it was filed, and
the exhibit number in such filing):
===============================================================================================================================
INCORPORATION BY REFERENCE
===============================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
===============================================================================================================================----------- ------- ---------- ------ -------
3.1 Utilities' Articles of Incorporation Utilities Form 8-K 4(a)
(9/22/94)
3.2Registration 3
Statement
No. 333-72540
*3.2 Bylaws of UGI Utilities as in effect since
Utilities Form 10-K 3.2
September 26, 1995 (9/30/95)
- -------------------------------------------------------------------------------------------------------------------------------24, 2002
4 Instruments defining the rights of security holders,
including indentures. (The Company agrees to furnish
to the Commission upon request a copy of any
instrument defining the rights of holders of its
long-term debt not required to be filed pursuant to
the description of Exhibit 4 contained in Item 601 of
Regulation S-K)
- -------------------------------------------------------------------------------------------------------------------------------
-42-
45
====================================================================================================================================
INCORPORATION BY REFERENCE
====================================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
====================================================================================================================================
4.1 Utilities' Articles of Incorporation and Bylaws
referred to in Exhibit Nos. 3.1 and 3.2
4.2 Indenture between Utilities and First Union National UGI Form 10-K (4)e
Union National Bank (formerly, First (9/30/93)
Fidelity Bank, N.A. (9/30/93)
Pennsylvania,) Trustee, dated as of August 1, 1993 and
related 6.5% Note due 2003.2003
-42-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
4.3 Form of Fixed Rate Medium-Term Note Utilities Form 8-K (4)i
(8/26/94)
4.4 Form of Fixed Rate Series B Medium-Term Note Utilities Form 8-K 4(i)
Medium-Term Note
(8/1/96)
4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii)
Medium-Term Note (8/1/96)
4.6 (Intentionally left blank)Service Agreement for comprehensive delivery service UGI Form 10-K 10.40
(Rate CDS) dated February 23, 1998 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv)
series (8/26/94)
4.9 Form of Officer's Certificate establishing Series B Utilities Form 8-K 4(iv)
Medium-Term Notes seriesunder the Indenture (8/26/94)
4.8 Calculation Agent Agreement dated1/96)
4.10 Forms of Floating Rate and Fixed Rate Series C Utilities Form 8-K 4(iii)
August 1, 1996 between UGI Utilities, (8/1/96)
Inc. and First Union National Bank
4.94.1
Medium-Term Notes (5/21/02)
4.11 Form of Officer'sOfficers' Certificate establishing Series C Utilities Form 8-K 4(iv)
Series B4.2
Medium-Term Notes under the (8/1/96)
Indenture - -----------------------------------------------------------------------------------------------------------------------------------
-43-
46
==================================================================================================================================
Incorporation by Reference
==================================================================================================================================
Exhibit No. Exhibit Registrant Filing Exhibit
==================================================================================================================================
(5/21/02)
10.1 Service Agreement (Rate FSS) dated as of November 1, UGI Form 10-K 10.5
as of November 1, 1989 between (9/30/95) Utilities and Columbia, as modified (9/30/95)
pursuant to the orders of the Federal Energy
Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Paragraph 61,060 (1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities Form 10-K (10)o.
June 1, 1987 between Utilities and (12/31/90) Columbia, as modified by (12/31/90)
Supplement No. 1 dated October 1, 1988; Supplement No.
2 dated November 1, 1989; Supplement No. 3 dated
November 1, 1990; Supplement No. 4 dated November 1,
1990; and Supplement No. 5 dated January 1, 1991, as
further modified pursuant to the orders of the Federal
Energy Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Paragraph 61,060 (1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
10.3 Transportation Service Agreement (Rate FTS-1) dated Utilities Form 10-K (10)p.
(Rate FTS-1) dated November 1, (12/31/90) 1989 between Utilities and Columbia Gulf (12/31/90)
Transmission Company, as modified pursuant to the
orders of the Federal Energy Regulatory Commission in
Docket No. RP93-6-000 reported at Columbia Gulf
Transmission Co., 64 FERC Paragraph 61,060 (1993),
order on rehearing, 64 FERC Paragraph 61,06061,365 (1993), order on rehearing,
64 FERC Paragraph 61,365 (1993)
- ----------------------------------------------------------------------------------------------------------------------------------
-44--43-
47
==============================================================================================================================
INCORPORATION BY REFERENCE
==============================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
==============================================================================================================================----------- ------- ---------- ------ -------
10.4** UGI Corporation 1992 Directors' Stock Plan UGI Form 10-Q (10)ff
Stock Plan
(6/30/92)
10.5** UGI Corporation DirectorsDirectors' Deferred UGICompensation Plan Form 10-K 10.39
Compensation Plan dated August 26,10.6
Amended and Restated as of January 1, 2000 UGI (9/30/94)
199300)
10.6** UGI Corporation Directors' Equity UGI Form 10-Q 10.1
Compensation Plan (3/31/97)Form 10-K 10.9
Amended and Restated as of January 1, 2000 UGI (9/30/00)
10.7** UGI Corporation 1992 Stock Option UGIand Dividend Form 10-Q (10)ee
and Dividend Equivalent Plan, as (6/30/92) amended May 19, 1992 UGI (6/30/92)
10.8** UGI Corporation Annual Bonus Plan dated March 8, 1996 UGI Form 10-Q 10.4
dated March 8, 1996
(6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Utilities Form 10-Q 10.4
Plan dated March 8, 1996Form 10-Q 10.4
1996` Utilities (6/30/96)
`
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive UGIEmployee Severance Form 10-K 10.12
Employee Severance Pay Plan (9/30/97) effective January 1, 1997 UGI (9/30/97)
10.12** Change of Control AgreementUGI Corporation 1992 Non-Qualified Stock Option Plan, Form 10-K 10.39
as amended UGI (9/30/00)
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-K 10.13
(9/30/99)
10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-Q 10.1
(6/30/00)
10.15** Service Agreement for comprehensive delivery service
(Rate CDS) dated February 23, 1999 between UGI
Utilities, Inc. and Texas Eastern Transmission Form 10-K 10.41
Corporation UGI (9/30/00)
10.16** UGI Corporation 1997 Stock Option and Lon (9/30/Dividend Form 10-Q 10.2
Equivalent Plan UGI (3/31/97)
R. Greenberg
10.13*10.17** UGI Corporation Supplemental Executive Retirement Plan Form 10-Q 10
Amended and Restated effective October 1, 1996 UGI (6/30/98)
10.18 ** Summary of Terms of UGI Corporation 1999 Restricted Form 10-Q 10
Stock Awards UGI (6/30/99)
10.20** Description of Change of Control Agreementarrangements for UGI Form 10-K 10.1410.33
Messrs. Greenberg and Bovaird (9/30/99)
10.21** Description of Change of Control arrangements for UGI Form 10-K 10.34
Messrs. Chaney, Barney and Dingman (9/30/99)
10.22** Consulting Services Agreement dated as of August 1, UGI Form 10-K 10.38
2000 between Stephen D. Ban and UGI Corporation and Mr. Bunn (9/30/97)
- --------------------------------------------------------------------------------------------------------------------------------00)
-45--44-
48
===================================================================================================================================
INCORPORATION BY REFERENCE
===================================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
===================================================================================================================================----------- ------- ---------- ------ -------
10.14** Form of Change of Control10.23 Power Sales Agreement between UGI Utilities, Inc. and Utilities Form 10-K 10.1510.23
UGI Development Company dated as of November 30, 2001 (9/30/01)
10.24 Partnership Agreement of Hunlock Creek Energy Ventures Utilities Form 10-K 10.24
dated December 8, 2001 by and between UGI CorporationHunlock (9/30/01)
Development Company and eachAllegheny Energy Supply
Hunlock Creek LLC
*10.25 Storage Transportation Service Agreement (Rate
Schedule SST) between Utilities and Columbia dated
November 1, 1993, as modified pursuant to orders of
Corporation (9/30/97)
Messrs. Chaney, Dingmanthe Federal Energy Regulatory Commission
*10.26 No-Notice Transportation Service Agreement (Rate
Schedule NTS) between Utilities and Bovaird
10.15*Columbia dated
November 1, 1993, as modified pursuant to orders of
the Federal Energy Regulatory Commission
*10.27 No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas Eastern
Transmission dated February 23, 1999, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*10.28 No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas Eastern
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*10.29 Firm Transportation Service Agreement (Rate Schedule
FT-1) between Utilities and Texas Eastern Transmission
dated June 15, 1999, as modified pursuant to various
orders of the Federal Energy Regulatory Commission
*10.30 Firm Transportation Service Agreement (Rate Schedule
FT-1) between Utilities and Texas Eastern Transmission
dated October 31, 2000, as modified pursuant to
various orders of the Federal Energy Regulatory
Commission
*10.31 Firm Transportation Service Agreement (Rate Schedule
FT) between Utilities and Transcontinental Gas Pipe
Line dated October 1, 1996, as modified pursuant to
various orders of the Federal Energy Regulatory
Commission
10.32** 2002 UGI Corporation 1992 Non-Qualified AmeriGas Form 10-K 10.19
Stock Option Plan Partners, L.P. (9/30/95)
10.16** Amendment No. 1 to UGI Corporation UGI Utilities Form 10-Q 10
1992 Non-Qualified Stock Option Plan (6/30/97)
10.17** UGI Corporation 1997 Stock Option UGI Form 10-Q 10.2
and Dividend Equivalent Plan (3/31/97)
- -----------------------------------------------------------------------------------------------------------------------------------10-K 10.38
(9/30/02)
*12.1 Computation of Ratio of Earnings to Fixed Charges
*12.2 Computation of Ratio of Earnings to Combined Fixed
*12.2 Charges and Preferred Stock Dividends
-45-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
21 Subsidiaries of the Registrant Utilities Form 10-K 21
(9/30/00)
*23 Consent of PricewaterhouseCoopers LLP
*99 Certification by the Chief Executive Officer and Preferred
Stock Dividends
- -----------------------------------------------------------------------------------------------------------------------------------
*13 Amendment No. 1the
Chief Financial Officer relating to the Registrant's
Report on Form 8-K/A to
Form 8-K dated July 11, 1997
- -----------------------------------------------------------------------------------------------------------------------------------
*23.1 Consent of Arthur Andersen LLP
*23.2 Consent of Coopers & Lybrand L.L.P.
*27 Financial Data Schedule
*99 Cautionary Statements Affecting
Forward-looking Information
===================================================================================================================================10-K for the fiscal year ended
September 30, 2002
* Filed herewith.
** As required by Item 14(a)(3), this exhibit is identified as a compensatory
plan or arrangement.
b.(b) REPORTS ON FORM 8-K.
During the last quarter of the 1997 fiscal year, the8-K:
The Company filed athe following Current ReportReports on Form 8-K dated July 11, 1997, consistingduring the
fourth quarter of Items 4
and 7; and Amendment No. 1 onfiscal year 2002:
Date Item Number(s) Content
---- -------------- -------
09/16/02 5 Other Events - Standard & Poor's Ratings
Services Press Release dated September 11, 2002
re: Corporate Credit and Unsecured Debt Ratings
-46-
49
Form 8-K/A to the Current Report on Form 8-K dated July 11, 1997,
consisting of Items 4 and 7.
-47-
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UGI UTILITIES, INC.
Date: December 16, 199717, 2002 By: John C. Barney
---------------------------------------------
John C. Barney
Senior Vice President - Finance and Accounting
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 16, 199717, 2002 by the following persons on
behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Richard L. BunnRobert J. Chaney President and Chief
- -------------------------------------------------- Executive Officer
Richard L. BunnRobert J. Chaney (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- --------------------------------------------------
Lon R. Greenberg
John C. Barney Senior Vice President -
- -------------------------------------------------- Finance and Accounting
John C. Barney (Principal Financial
Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- --------------------------------------------------
Stephen D. Ban
Robert C. ForneyThomas F. Donovan Director
- -----------------------
Robert C. Forney
-48----------------------------
Thomas F. Donovan
-47-
51Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 17, 2002 by the following persons on
behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Ernest E. Jones Director
- -------------------------------
Ernest E. Jones
Richard C. Gozon Director
- ----------------------------------------------------
Richard C. Gozon
Anne Pol Director
- ----------------------------------------------------
Anne Pol
Quentin I. Smith, Jr.Marvin O. Schlanger Director
- ---------------------
Quentin I. Smith, Jr.-------------------------------
Marvin O. Schlanger
James W. Stratton Director
- ----------------------------------------------------
James W. Stratton
David I. J. Wang Director
- ---------------------
David I. J. Wang-48-
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT:
No annual report or proxy material was sent to security holders in fiscal year
2002.
-49-
52
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
12.1 Computation of Ratio of Earnings to Fixed Charges
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
13 Amendment No. 1CERTIFICATIONS
I, Robert J. Chaney, certify that:
1. I have reviewed this annual report on Form 8-K/A10-K of UGI Utilities, Inc.;
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 officer 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 we
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 officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the 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 officer 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: December 20, 2002
Robert J. Chaney
-------------------------------------
Robert J. Chaney
President and Chief Executive Officer
-50-
I, John C. Barney, certify that:
1. I have reviewed this annual report on Form 8-K dated
July 11, 1997
23.1 Consent10-K of Arthur Andersen LLP
23.2 ConsentUGI Utilities, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of Coopers & Lybrand L.L.P.
27a 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 officer 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 we
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 officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the 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 officer 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: December 20, 2002
John C. Barney
--------------------------------------------
John C. Barney
Senior Vice President - Finance and Chief
Financial Data Schedule
99 Cautionary Statements Affecting Forward-looking
InformationOfficer
-51-
53
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 19972002
F-1
54
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
Pages
-----
Financial Statements:
Reports of Independent Public Accountants F-3 andto F-4
Consolidated Balance Sheets as of September 30,
19972002 and 19962001 F-5 andto F-6
Consolidated Statements of Income for the years
ended September 30, 1997, 19962002, 2001 and 19952000 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 1997, 19962002, 2001 and 19952000 F-8
Consolidated Statements of Stockholders'Stockholder's Equity
for the years ended September 30, 1997, 19962002, 2001 and 19952000 F-9
Notes to Consolidated Financial Statements F-10 to F-28F-27
Financial Statement Schedule:
For the years ended September 30, 1997, 19962002, 2001 and 1995:2000:
II - Valuation and Qualifying Accounts S-1
AllWe have omitted all other financial statement schedules are omitted because the
required information is either (1) not present orpresent; (2) not present in
amounts sufficient to require submission of the scheduleschedule; or because the information required is(3) included
elsewhere in the respective financial statements or notes thereto contained
herein.related notes.
F-2
55REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
In our opinion, the consolidated financial statements as of and for the year
ended September 30, 2002 listed in the index appearing under Item 15a(1) and (2)
present fairly, in all material respects, the financial position of UGI
Utilities, Inc. and its subsidiaries at September 30, 2002 and the results of
their operations and their cash flows for the year ended September 30, 2002 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule as of and
for the year ended September 30, 2002 listed in the Index to Financial
Statements and Financial Statement Schedule present fairly, in all material
respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and
financial statement schedule are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion. The financial statements of
UGI Utilities, Inc. and its subsidiaries as of September 30, 2001, and for each
of the two years in the period ended September 30, 2001 were audited by other
independent accountants who have ceased operations. Those independent
accountants expressed an unqualified opinion on those financial statements in
their report dated November 16, 2001.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 15, 2002
F-3
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S
REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY
ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
We have audited the accompanying consolidated balance sheetsheets of UGI Utilities,
Inc. and subsidiaries as of September 30, 19972001 and 2000, and the related
consolidated statements of income, cash flows and stockholder's equity and cash flows for each
of the year then
ended.three years in the period ended September 30, 2001. These financial
statements and the schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audit.audits.
We conducted our auditaudits in accordance with auditing standards generally accepted
auditing standards.in the United States. 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 audit providesaudits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of UGI
Utilities, Inc. and subsidiaries as of September 30, 19972001 and 2000, and the
results of their operations and their cash flows for each of the year thenthree years in
the period ended September 30, 2001 in conformity with accounting principles
generally accepted accounting principles.in the United States.
Our audit wasaudits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The information for the year ended September 30,
1997 included on the schedule listed in the Index to
Financial Statements and Financial Statement Schedule is presented for purposes
of complying with the Securities and Exchange Commission's rules and is not part
of the basic financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects, the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
November 14, 1997
F-3
56
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder
UGI Utilities, Inc.
We have audited the accompanying consolidated balance sheet of UGI Utilities,
Inc. and subsidiaries as of September 30, 1996 and the related consolidated
statements of income, stockholder's equity, and cash flows for the years ended
September 30, 1996 and 1995. We have also audited the related financial
statement schedule for the years ended September 30, 1996 and 1995 listed in the
index on page F-2 of this Form 10-K. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits 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 UGI Utilities,
Inc. and subsidiaries as of September 30, 1996, and the consolidated results of
their operations and cash flows for the years ended September 30, 1996 and 1995
in conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
As discussed in Note 5 to the consolidated financial statements, the Company
changed its method of accounting for postemployment benefits in 1995.
COOPERS & LYBRAND L.L.P.
Philadelphia, Pennsylvania
November 22, 199616, 2001
F-4
57
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
September 30,
1997 1996
-------- --------2002 2001
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents (note 1) $ 12,8136,090 $ 3,1007,711
Accounts receivable (less allowances for doubtful
accounts of $3,333$1,972 and $3,976,$3,151, respectively) 25,309 26,28838,554 39,152
Accrued utility revenues (note 1) 7,688 8,6128,069 11,110
Inventories (notes 1 and 6) 30,645 30,03538,654 48,074
Deferred income taxes (notes 1 and 4) 7,179 6,3162,610 5,527
Income taxes recoverable 6,892 -
Deferred fuel costs 4,304 -
Prepaid expenses and other current assets 4,653 1,920
-------- --------3,151 2,178
--------- ---------
Total current assets 88,287 76,271108,324 113,752
Property, plant and equipment
(notes 1 and 3):
Gas utility 637,943 605,150760,161 734,661
Electric utility 118,808 114,915operations 111,265 108,423
General 8,897 9,794
-------- --------
765,648 729,85911,909 12,113
--------- ---------
883,335 855,197
Less accumulated depreciation and amortization 237,293 222,559
-------- --------(290,194) (276,429)
--------- ---------
Net property, plant and equipment 528,355 507,300593,141 578,768
Regulatory income tax asset (notes 1 and 4) 44,438 42,908assets 57,685 56,155
Other assets 20,298 23,420
-------- --------38,973 35,734
--------- ---------
Total assets $681,378 $649,899
======== ========$ 798,123 $ 784,409
========= =========
TheSee accompanying notes are an integral part of theseto consolidated financial statements.
F-5
58
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
September 30,
1997 1996
-------- --------2002 2001
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt (note 3) $ 17,14376,000 $ 25,543
Current portion of preferred stock (note 7) 3,000 ---
Bank loans (note 3) 67,000 50,50037,200 57,800
Accounts payable 45,367 39,51757,499 67,456
Employee compensation and benefits accrued 8,207 8,2108,984 8,356
Dividends and interest accrued 3,692 4,9755,443 5,392
Income taxes accrued 5,071 5,302- 11,138
Customer deposits and refunds 8,745 6,032
Other current liabilities 26,621 22,882
-------- --------22,346 21,264
--------- ---------
Total current liabilities 176,101 156,929216,217 177,438
Long-term debt (note 3) 152,151 151,111172,369 208,477
Deferred income taxes (notes 1 and 4) 99,868 95,452131,483 121,890
Deferred investment tax credits (notes 1 and 4) 10,376 10,7758,385 8,783
Other noncurrent liabilities 10,201 11,00411,815 12,064
Commitments and contingencies (note 8)
Preferred stock subject to mandatory redemption,
without par value (note 7) 32,187 35,18720,000 20,000
Common stockholder's equity:
Common Stock, $2.25 par value (authorized - 40,000,000 shares;
issued and outstanding - 26,781,785 shares) 60,259 60,259
Additional paid-in capital 68,249 68,05273,057 72,792
Retained earnings 71,986 61,130
-------- --------107,312 102,706
Accumulated other comprehensive loss (2,774) -
--------- ---------
Total common stockholder's equity 200,494 189,441
-------- --------237,854 235,757
--------- ---------
Total liabilities and stockholders' equity $681,378 $649,899
======== ========$ 798,123 $ 784,409
========= =========
TheSee accompanying notes are an integral part of theseto consolidated financial statements.
F-6
59
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------
1997 1996 1995-----------------------------------------------
2002 2001 2000
--------- --------- ---------
Revenues (note 1) $ 461,208490,552 $ 460,496584,762 $ 357,364436,942
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power (note 1) 238,978 239,643 169,694290,282 374,781 218,119
Operating and administrative expenses 117,874 119,432 108,51480,910 88,310 85,425
Operating and administrative expenses - related parties (note 13) 5,555 3,850 6,5856,664 5,277 4,159
Taxes other than income taxes 11,930 9,182 17,052
Depreciation and amortization (note 1) 21,431 21,602 19,754
Miscellaneous22,172 23,767 23,612
Other income, net (note 10) (2,777) (1,842) (3,780)(11,723) (15,111) (12,660)
--------- --------- ---------
381,061 382,685 300,767400,235 486,206 335,707
--------- --------- ---------
Operating income 80,147 77,811 56,59790,317 98,556 101,235
Interest expense 16,872 16,094 16,83816,652 18,988 18,353
--------- --------- ---------
Income before income taxes 63,275 61,717 39,75973,665 79,568 82,882
Income taxes (notes 1 and 4) 24,564 23,369 11,741
--------- --------- ---------
Income before accounting change 38,711 38,348 28,018
Change in accounting for postemployment
benefits (note 5) -- -- (1,028)29,570 31,431 32,406
--------- --------- ---------
Net income 38,711 38,348 26,99044,095 48,137 50,476
Dividends on preferred stock 2,764 2,765 2,7781,550 1,550 1,550
--------- --------- ---------
Net income after dividends on preferred stock $ 35,94742,545 $ 35,58346,587 $ 24,21248,926
========= ========= =========
TheSee accompanying notes are an integral part of theseto consolidated financial statements.
F-7
60
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended
September 30,
--------------------------------
1997 1996 1995
-------- -------- -------------------------------------------------------
2002 2001 2000
--------- --------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,71144,095 $ 38,34848,137 $ 26,99050,476
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 21,431 21,602 19,75422,172 23,767 23,612
Deferred income taxes, net 549 7,481 2,36911,114 (2,016) 2,866
Provision for uncollectible accounts 4,272 4,933 3,3765,270 8,269 4,386
Pension income (3,857) (5,671) (2,930)
Other (850) (704) 541
-------- -------- --------
64,113 71,660 53,030(391) (177) 4,892
Net change in:
Accounts receivable and accrued utility revenues (2,401) (9,444) (9,805)(1,631) (14,704) (14,823)
Inventories (610) (6,608) 2,8239,420 (14,508) (8,831)
Deferred fuel adjustments 4,639 (10,731) (138)
Pipeline transition and producer settlement
recoveries (costs), net (1,769) 1,074 (7,591)costs (7,056) 9,948 (3,751)
Accounts payable 5,850 5,894 7,803(9,957) 13,318 16,257
Other current assets and liabilities (338) 5,184 (3,454)
-------- -------- --------(14,123) 9,769 9,293
--------- --------- ---------
Net cash provided by operating activities 69,484 57,029 42,668
-------- -------- --------55,056 76,132 81,447
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (41,684) (39,659) (51,221)(35,884) (36,783) (36,391)
Net costs of property, plant and equipment disposals (884) (1,189) (973)
Other, net 500 740 1,225
-------- -------- --------(704) (1,407) (838)
Cash contribution to partnership - (6,000) -
--------- --------- ---------
Net cash used by investing activities (42,068) (40,108) (50,969)
-------- -------- --------(36,588) (44,190) (37,229)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (26,823) (35,649) (16,897)(39,489) (36,809) (45,563)
Issuance of long-term debt 20,000 20,000 48,00040,000 50,603 -
Repayment of long-term debt (27,380) (54,828) (17,236)- (15,000) (7,143)
Bank loans increase 16,500 8,500 25,000
Redemption of Series Preferred Stock -- (15) --
-------- -------- --------(decrease) (20,600) (42,600) 13,000
Capital contribution from UGI Corporation - 4,000 -
--------- --------- ---------
Net cash provided (used)used by financing activities (17,703) (61,992) 38,867
-------- -------- --------(20,089) (39,806) (39,706)
--------- --------- ---------
Cash and cash equivalents increase (decrease) $ 9,713 $(45,071)(1,621) $ 30,566
======== ======== ========(7,864) $ 4,512
========= ========= =========
CASH AND CASH EQUIVALENTS:
End of periodyear $ 12,8136,090 $ 3,1007,711 $ 48,17115,575
Beginning of period 3,100 48,171 17,605
-------- -------- --------year 7,711 15,575 11,063
--------- --------- ---------
Increase (decrease) $ 9,713 $(45,071)(1,621) $ 30,566
======== ======== ========(7,864) $ 4,512
========= ========= =========
TheSee accompanying notes are an integral part of theseto consolidated financial statements.
F-8
61
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
Accumulated Total
Additional Other Common
Common Paid-in Retained Comprehensive Stockholder's
Stock Capital Earnings -------- -------- --------Loss Equity
---------- ---------- ------------ --------------- --------------
Balance September 30, 19941999 $ 60,259 $ 68,05268,559 $ 49,76090,742 $ - $ 219,560
Net income 26,99050,476 50,476
Cash dividends - common stock (14,507)(44,013) (44,013)
Cash dividends - preferred stock (2,778)
Dividend of subsidiary net assets (973)(1,550) (1,550)
---------- ---------- --------- -------- -------- ------------------
Balance September 30, 19952000 60,259 68,052 58,49268,559 95,655 - 224,473
Net income 38,34848,137 48,137
Capital contribution by UGI Corporation 4,000 4,000
Cash dividends - common stock (32,884)(35,259) (35,259)
Cash dividends - preferred stock (2,765)(1,550) (1,550)
Dividends of net assets (4,277) (4,277)
Other (61)233 233
---------- ---------- --------- -------- -------- ------------------
Balance September 30, 19962001 60,259 68,052 61,13072,792 102,706 - 235,757
Net income 38,71144,095 44,095
Net change in fair value of interest rate
protection agreements (net of tax of $1,968) (2,774) (2,774)
--------- -------- ----------
Comprehensive income 44,095 (2,774) 41,321
Cash dividends - common stock (24,060)(37,939) (37,939)
Cash dividends - preferred stock (2,764)
Dividend of subsidiary assets (1,031)(1,550) (1,550)
Other 197265 265
---------- ---------- --------- -------- -------- ------------------
Balance September 30, 19972002 $ 60,259 $ 68,24973,057 $ 71,986107,312 $ (2,774) $ 237,854
========== ========== ========= ======== ======== ==================
TheSee accompanying notes are an integral part of theseto consolidated financial statements.
F-9
62
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
UGI Utilities, Inc. (UGI Utilities) is("UGI Utilities"), a wholly owned subsidiary of UGI
Corporation (UGI) and("UGI"), owns and operates (1) a natural gas distribution utility
(Gas Utility)("Gas Utility") in parts of eastern and southeastern Pennsylvania and (2) an
electricelectricity distribution utility (Electric Utility)("Electric Utility") and electricity generation
business (which together with Electric Utility are referred to herein as
"Electric Operations") in northeastern Pennsylvania. The Company's interests in
electric generation assets are owned by our non-utility subsidiary, UGI
Development Company ("UGID") and its 50%-owned joint-venture partnership Hunlock
Creek Energy Ventures ("Energy Ventures") which is accounted for under the
equity method. We refer to UGI Utilities and its subsidiaries collectively as
"the Company" or "we." Our consolidated financial statements include the
accounts of UGI Utilities and its subsidiaries (collectively, the Company). Allmajority-owned subsidiaries. We eliminate all
significant intercompany accounts and transactions havewhen we consolidate. UGID
has been eliminated
in consolidation. Revenues of Gas Utility comprise more than four-fifths
ofgranted "Exempt Wholesale Generator" status by the Company's consolidated revenues.Federal Energy
Regulatory Commission.
USE OF ESTIMATES
The preparation ofWe make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted accounting principles requires management to makein the United States.
These estimates and assumptions that affect the reported amounts of assets and
liabilities, revenues and expenses, as well as the disclosure of contingent
assets and liabilities at the date of the
financial statements, and revenues and expenses during the reporting
period.liabilities. Actual results could differ from these estimates.
REGULATED UTILITY OPERATIONS
Gas Utility and Electric Utility (collectively, "Utilities") are subject to
regulation by the Pennsylvania Public Utility Commission (PUC)("PUC"). We account for
Gas Utility and Electric Utility account for their regulated operations in accordance with Statement of Financial
Accounting Standards (SFAS)("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71), as amended
and supplemented by subsequently issued standards.("SFAS 71"). SFAS 71 as amended
and supplemented, requires among other things, thatus to record the effects of
rate regulation in the financial statementsstatements. If a separable portion of a regulated enterprise reflectGas
Utility or Electric Utility no longer meets the actionsprovisions of regulators,
where appropriate. The economicSFAS 71, we are
required to eliminate the financial statement effects of regulation can resultfor that
portion of our operations.
On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in regulated enterprises recording costs that have been or are expectedGas
Utility's restructuring plan filed by Gas Utility pursuant to be allowed inPennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
ratesetting process in a period different fromprovisions of the period in whichGas Restructuring Order and the costs would be charged to expense by an unregulated
enterprise. When this occurs, costs are deferred as assets in the
balance sheet (regulatory assets) and recorded as expenses as those
amounts are reflected in rates. Additionally, regulators can impose
liabilities upon a regulated enterprise for amounts previously collected
from customers and for recovery of costs that are expected to be
incurred in the future (regulatory liabilities). The Company continually
monitors the regulatory and competitive environments in which it
operates to determine that itsGas Competition Act, we
believe Gas Utility's regulatory assets are probablecontinue to satisfy the criteria of recovery.SFAS
71. For further information on the impact of the Gas Competition Act and
Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see
Note 2.
F-10
63
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Given the changing regulatory environment in the electric utility
industry (see Note 2), the Company continues to evaluate its ability to
apply the provisions of SFAS 71 as it relates to its electric generation
operations. The Company believes its electric generation assets and
related regulatory assets continue to satisfy the criteria of SFAS 71.
If such electric generation assets no longer meet the criteria of SFAS
71, any related regulatory assets would be written off unless some form
of transition cost recovery is established by the PUC which would meet
the requirements under generally accepted accounting principles for
continued accounting as regulatory assets during such recovery period.
Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of."
CONSOLIDATED STATEMENTS OF CASH FLOWS
CashWe define cash equivalents includeas all highly liquid investments with maturities of
three months or less when purchased and are recordedpurchased. We record cash equivalents at cost plus
accrued interest, which approximates market value.
InterestWe paid during 1997, 1996interest totaling $16,348 in 2002, $17,543 in 2001 and 1995, was $17,507, $16,100$17,941 in 2000.
We paid income taxes totaling $36,282 in 2002, $29,000 in 2001 and $15,530, respectively. Income taxes paid during 1997, 1996 and 1995 were
$24,246, $15,736, and $11,535, respectively.$23,108 in
2000.
REVENUE RECOGNITION
Gas Utility and Electric Utility record regulated revenues are recorded for servicesservice provided
to the end of each month but not yet billed. Ratewhich includes an accrual for certain unbilled amounts
based upon estimated usage. We reflect the impact of Gas Utility and Electric
Utility rate increases or decreases at the time they become effective.
Nonregulated revenues are reflected in revenues from effective dates permitted by
the PUC.recognized as services are performed.
INVENTORIES
InventoriesOur inventories are stated at the lower of cost or market. Cost is
determinedWe determine cost
principally on an average or first-in, first-out (FIFO)cost method except for appliances for which we use the
specific identification method is used.method.
INCOME TAXES
DeferredGas Utility and Electric Utility record deferred income tax provisionstaxes in the
Consolidated Statements of UGI UtilitiesIncome resulting from the use of accelerated
depreciation methods are recorded in the Consolidated
Statements of Income based upon amounts recognized for ratemaking purposes. UGI UtilitiesThey
also recognizesrecord a deferred tax liability for tax benefits that are flowed through to
ratepayers when temporary differences originate and establishesrecord a corresponding regulatory asset
(regulatory income
tax asset)asset for the probable increase in future revenues that will result when the
temporary differences reverse.
F-11
64
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
InvestmentWe are amortizing deferred investment tax credits related to UGI Utilities' plant
additions have
been deferred and are being amortized over the service lives of the related property. UGI Utilities reduces its
deferred income tax liability for the future tax benefits that will occur when
the deferred investment tax credits, which are not taxable, are amortized, andamortized. We
also reducesreduce the regulatory income tax asset for the probable reduction in future
revenues that will result when such deferred investment tax credits amortize.
The Company joinsWe join with UGI Corporation and its subsidiaries in filing a consolidated federal income
tax return. The Company is allocated tax
assets, liabilities, expense, benefits and creditsWe are charged or credited for our share of current taxes resulting
from the effects of itsour transactions in the UGI consolidated federal income tax
provision,return including giving effect to all intercompany transactions. The result of this
allocation is not materially different fromgenerally consistent with income taxes calculated on a separate
return basis.
F-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
Property,We record property, plant and equipment is stated at cost. TheWe charge to accumulated
depreciation the original cost of UGI Utilities' retired plant and equipment,
together with the net cost of removal, is
charged to accumulated depreciation for financial accounting purposes.
Removal costs of UGIWe record depreciation expense for Utilities' plant and equipment are deducted
currently for income tax purposes.
Depreciation of Gas Utility's and Electric Utility's plant and equipment
is computed using theon a
straight-line method over the estimated average remaining lives of the various
classes of its depreciable property. Depreciation expense as a percentage of the
related average depreciable base for 1997, 1996 and 1995 was 2.7%, 2.9% and 2.8%; and 3.6%, 3.6% and 3.4% for
Gas Utility was 2.5% in 2002 and Electric Utility, respectively.2.6% in
each of 2001 and 2000. Depreciation expense during 1997, 1996as a percentage of the related
average depreciable base for Electric Operations was 3.0% in each of 2002 and
19952001, and 3.5% in 2000. Depreciation expense was $20,899, $20,848$21,649 in 2002, $22,701 in
2001 and $18,983,
respectively.$23,000 in 2000.
We evaluate the impairment of long-lived assets whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable. We evaluate recoverability based upon undiscounted future cash
flows expected to be generated by such assets.
COMPUTER SOFTWARE COSTS
We include in property, plant and equipment costs associated with computer
software we develop or obtain for use in our businesses. We amortize computer
software costs on a straight-line basis over expected periods of benefit not
exceeding ten years once the installed software is ready for its intended use.
DEFERRED FUEL ADJUSTMENTSCOSTS
Gas Utility's tariffs contain and prior to January 1, 1997, Electric
Utility's tariffs contained, clauses which permit recovery of certain purchased
gas fuel andcosts through the application of purchased power costs in excess of the level of such costs
included in basegas cost ("PGC") rates. The
clauses provide for a periodic adjustmentadjustments to PGC rates for the difference between
the total amount of purchased gas costs collected under each clausefrom customers and the
recoverable costs incurred. Accordingly,In accordance with SFAS 71, we defer the difference
between amounts recognized in revenues and the applicable gas fuel and
purchased power costs incurred
is deferred until they are subsequently billed or refunded to customers.
In accordance withENVIRONMENTAL LIABILITIES
We accrue environmental investigation and cleanup costs when it is probable that
a liability exists and the provisionsamount or range of amounts can be reasonably
estimated. Our estimated liability for environmental contamination is reduced to
reflect anticipated participation of other responsible parties but is not
reduced for possible recovery from insurance carriers. We do not discount to
present value the Customer Choice Act (see Note
2), the rates Electric Utility can charge its customers, including
amounts pertainingcosts of future expenditures for environmental liabilities. We
intend to thepursue recovery of fuelany incurred costs through all appropriate means,
including regulatory relief. Gas Utility is permitted to amortize as removal
costs site-specific environmental investigation and purchased powerremediation costs, were capped effective January 1, 1997. The difference between amounts
collected and costs actuallynet of
related third-party payments, associated with Pennsylvania sites. Gas Utility is
currently permitted to include in rates, through future base rate proceedings, a
five-year average of such prudently incurred as of January 1, 1997 is being
considered by the PUC in conjunction with Electric Utility's Customer
Choice Act restructuring plan. Such amount was not material.removal costs.
F-12
65
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DERIVATIVE INSTRUMENTS
Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133, as amended,
establishes accounting and reporting standards for derivative instruments and
for hedging activities. It requires that all derivative instruments be
recognized as either assets or liabilities and measured at fair value. The
accounting for changes in fair value depends upon the purpose of the derivative
instrument and whether it is designated and qualifies for hedge accounting. To
the extent a derivative instrument qualifies and is designated as a hedge of the
variability of cash flows associated with a forecasted transaction ("cash flow
hedge"), the effective portion of the gain or loss on such derivative instrument
is generally reported in other comprehensive income and the ineffective portion,
if any, is reported in net income. Such amounts reported in other comprehensive
income are reclassified into net income when the forecasted transaction affects
earnings. If a cash flow hedge is discontinued because it is probable that the
forecasted transaction will not occur, the net gain or loss is immediately
reclassified into net income. To the extent derivative instruments qualify and
are designated as hedges of changes in the fair value of an existing asset,
liability or firm commitment ("fair value hedge"), the gain or loss on the
hedging instrument is recognized in earnings along with changes in the fair
value of the hedged asset, liability or firm commitment attributable to the
hedged risk.
On occasion, we have used a managed program of natural gas and oil futures
contracts to preserve gross margin associated with certain of our natural gas
customers. These contracts were designated as cash flow hedges. The Company did
not enter into these types of contracts in 2002. During 2001, the amount of cash
flow hedge gains associated with these contracts that were reclassified to
earnings because it became probable that the original forecasted transactions
would not occur was $1,034 which amount is included in other income.
During 2002, in order to reduce our interest rate risk associated with
forecasted issuances of fixed-rate debt, we entered into interest rate
protection agreements ("IRPAs") which have been designated and qualify as cash
flow hedges. Included in accumulated other comprehensive loss at September 30,
2002 are net after-tax losses of $2,774 from settled and unsettled IRPAs
associated with forecasted issuances of debt. The amount of this net loss
expected to be reclassified into net income during the next twelve months is not
material. The fair value of our unsettled IRPAs was a loss of $1,205 at
September 30, 2002 which is included in other current liabilities on the
Consolidated Balance Sheet. These IRPAs hedge interest rate risk associated with
forecasted issuances of debt to occur during Fiscal 2003. We did not have any
derivative instruments outstanding at September 30, 2001.
During 2002 and 2001, there were no gains or losses from hedge ineffectiveness
or from excluding a portion of a derivative instrument's gain or loss from the
assessment of hedge effectiveness, and there were no gains or losses recognized
in earnings as a result of a hedged firm commitment no longer qualifying as a
fair value hedge.
We are a party to a number of contracts that have elements of a derivative
instrument. These contracts include, among others, binding purchase orders,
contracts which provide for the delivery of natural gas, and service contracts
that require the counterparty to provide commodity storage, transportation or
capacity service to meet our normal sales commitments. Although
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
many of these contracts have the requisite elements of a derivative instrument,
these contracts are not subject to the accounting requirements of SFAS 133
because they provide for the delivery of products or services in quantities
that are expected to be used in the normal course of operating our business or
the value of the contract is directly associated with the price or value of a
service.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income
(loss). Other comprehensive loss of $(2,774) for the year ended September 30,
2002 is the result of losses on IRPAs qualifying as hedges. The Company's
comprehensive income was the same as net income for the years ended September
30, 2001 and 2000.
ADOPTION OF SFAS 142
Effective October 1, 2001, we early adopted the provisions of SFAS No. 142,
"Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the
financial accounting and reporting for acquired goodwill and other intangible
assets and supersedes Accounting Principles Board ("APB") Opinion No. 17,
"Intangible Assets." SFAS 142 addresses the financial accounting and reporting
for intangible assets acquired individually or with a group of other assets
(excluding those acquired in a business combination) at acquisition and also
addresses the financial accounting and reporting for goodwill and other
intangible assets subsequent to their acquisition. Under SFAS 142, an
intangible asset is amortized over its useful life unless that life is
determined to be indefinite. Goodwill and other intangible assets with
indefinite lives are not amortized but are subject to tests for impairment at
least annually. Because we do not have significant intangible assets or
goodwill resulting from prior business combinations, the adoption of SFAS 142
did not impact our results of operations or financial position.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144");
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146").
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using
a systematic and rational method over the related asset's useful life and
adjust the fair value of the liability resulting from the passage of time
through charges to operating expense. We adopted SFAS 143 effective October 1,
2002. The adoption of SFAS 143 did not have a material effect on our financial
position or results of operations.
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," as it relates to the disposal of a segment of a business. SFAS
144 establishes a single accounting model for long-lived assets to be disposed
of based upon the framework of SFAS 121, and resolves significant
implementation issues of SFAS 121. We adopted SFAS 144 effective October 1,
2002. The adoption of SFAS 144 did not affect our financial position or results
of operations.
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment
of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective for fiscal
years beginning after May 15, 2002. SFAS 4 had required that material gains and
losses on extinguishment of debt be classified as an extraordinary item. Under
SFAS 145, it is less likely that a gain or loss on extinguishment of debt would
be classified as an extraordinary item in the Consolidated Statement of Income.
Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases,"
to require that certain lease modifications that have economic effects similar
to sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. The provisions of SFAS 145 relating to leases were
effective for transactions occurring after May 15, 2002. The application of
SFAS 145 did not affect our financial position or results of operations during
2002.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and replaces the guidance in Emerging Issues Task Force ("EITF") No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability
for costs associated with an exit or disposal activity, including contract
termination costs, employee termination benefits and other associated costs, be
recognized when the liability is incurred. Under EITF No. 94-3, a liability was
recognized at the date an entity committed to an exit plan. SFAS 146 will be
effective for disposal activities initiated after December 31, 2002.
2. UTILITY REGULATORY MATTERS
ELECTRICITY GENERATION CUSTOMER CHOICEGas Utility
Gas Competition Act. On June 22, 1999, the Gas Competition Act was signed into
law. The purpose of the Gas Competition Act is to provide all natural gas
consumers in Pennsylvania with the ability to purchase their gas supplies from
the supplier of their choice. Under the Gas Competition Act, local gas
distribution companies ("LDCs") like Gas Utility may continue to sell gas to
customers, and such sales of gas, as well as distribution services provided by
LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the
supplier of last resort for all residential and small commercial and industrial
("core-market") customers unless the PUC approves another supplier of last
resort. The Gas Competition Act requires energy marketers seeking to serve
customers of LDCs to accept assignment of a portion of the LDC's pipeline
capacity and storage contracts at contract rates, thus avoiding the creation of
stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC
to avoid such contract release or
F-15
UGI UTILITIES, INC. AND COMPETITION ACT
OnSUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
assignment. However, such petition may be granted only if the LDC fully
recovers the cost of contracts. The Gas Competition Act, in conjunction with a
companion bill, eliminated the gross receipts tax on sales of gas effective
January 1, 1997,2000.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas
Utility's restructuring plan filed by Gas Utility pursuant to the Gas
Competition Act. Among other things, the implementation of the Gas
Restructuring Order resulted in an increase in Gas Utility's core-market base
rates effective October 1, 2000. This base rate increase was designed to
generate approximately $16,700 in additional net annual revenues. In accordance
with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates
by an annualized amount of $16,700 in the first 14 months following the October
1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its core-market
PGC rates by amounts equal to the margin it receives from interruptible
customers using pipeline capacity contracted by Gas Utility for core-market
customers. As a result, beginning December 31, 2001, Gas Utility operating
results are more sensitive to the effects of heating-season weather and less
sensitive to the market prices of alternative fuels.
Transfer of Assets. On May 24, 2001, the PUC approved Gas Utility's application
for approval to transfer its liquefied natural gas ("LNG") and propane air
("LP") facilities, along with related assets, to an unregulated affiliate,
Energy Services, Inc. ("Energy Services"), a second-tier wholly owned
subsidiary of UGI. The associated reduction in Gas Utility's base rates,
adjusted for the impact of the transfer on net operating expenses, is not
expected to have a material effect on our results of operations. Gas Utility
transferred the LNG and LP assets, which had a net book value of $4,277, on
September 30, 2001. The transfer is reflected as a dividend of net assets in
the 2001 Consolidated Statement of Stockholder's Equity.
Electric Utility
Electric Utility Restructuring Order. On June 19, 1998, the PUC entered its
Opinion and Order ("Electricity Restructuring Order") in Electric Utility's
restructuring proceeding pursuant to the Electricity Generation Customer Choice Act. Under the
terms of the Electricity Restructuring Order, Electric Utility was authorized
to recover $32,500 in stranded costs (on a full revenue requirements basis
which includes all income and Competition Act (Customer Choice Act) became effective. The Customer
Choice Act permits all Pennsylvania retail electric customers to choose
their electric generation suppliergross receipts taxes) over a three-year phase-infour-year period
commencingbeginning January 1, 1999. The Customer Choice Act requires all
electric utilities1999 through a Competitive Transition Charge ("CTC")
(together with carrying charges on unrecovered balances of 7.94%) and to file restructuring plans with the PUC which, among
other things, includecharge
unbundled pricesrates for electric generation, transmission and distribution and a competitive transition charge (CTC)
for the recovery of "stranded costs" which would be paid by all
customers receiving transmission and distribution service. "Stranded
costs" generallyservices.
Stranded costs are electric generation-related costs that traditionally would
be recoverable in a regulated environment but may not be recoverable in a
competitive electric generation market. Electric Utility's recoverable stranded
costs included $8,692 for the buy-out of a 1993 power purchase agreement with
an independent power producer. Under the Customerterms of the Electricity Restructuring
Order and in accordance with the Electricity Choice Act, Electric Utility's rates for transmission and
distribution services provided through June 30, 2001 are capped at
levels in effect on January 1, 1997. In addition, Electric Utility
generally maycould not increase the generation component of prices as long asduring the
period that stranded costs arewere being recovered through the CTC. Electric Utility
will continue to be the only regulated electric utility having the
right, granted by the PUC or by law, to distribute electric energy in
its service territory.
On August 7, 1997, Electric Utility filed its restructuring plan with
the PUC. The restructuring plan includes a claim for the recovery of
$34,426 for stranded costs during the periodSince January
1, 1999, through
December 31, 2002. The claim is primarily for the recovery of: (1) plant
investments in excessall of estimated competitive market value and electric
generation facility retirement costs; (2) potential costs associated
with existing power purchase agreements; and (3) regulatory assets
(principally income taxes) recoverable from ratepayers under current
regulatory practice. The claim also seeks to establish a recovery
mechanism that would permit the recovery of up to an additional $28,000
of costs associated with the buyout or implementation of a December 1993
agreement to purchase power from an independent power producer. The PUC
is expected to take action on Electric Utility's filing in May 1998.
Based uponcustomers have been permitted to choose an
evaluation ofalternative generation supplier. Customers choosing an alternative supplier
during the various factors and conditions affecting
futurestranded cost recovery the Company does not expect the Customer Choice
Act to haveperiod received a material adverse effect on its financial condition or
results of operations.
BASE RATE CASES
On January 27, 1995, Gas Utility filed with the PUC for a $41,300
increase in base rates to be effective March 28, 1995. In accordance
with normal PUC practice, the effective date was suspended pending
further investigation. On August 31, 1995, the PUC approved a settlement
of this proceeding (Gas Utility Base Rate Settlement) authorizing a
$19,500 increase in annual revenues. The increase in base rates became
effective on August 31, 1995.
F-13"shopping credit."
F-16
66
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
On January 26, 1996, Electric Utility filed with the PUC for a $6,200
increase in base rates. On July 18, 1996, theThe PUC approved a settlement establishing rules for Electric Utility Provider
of this proceeding authorizingLast Resort ("POLR") service on March 28, 2002 and a $3,100 increaseseparate settlement
that modified these rules on June 13, 2002 (collectively the "POLR Settlement")
under which Electric Utility terminated stranded cost recovery through its CTC
from commercial and industrial ("C&I") customers on July 31, 2002, and from
residential customers on October 31, 2002, and is no longer subject to the
statutory rate caps as of August 1, 2002 for C&I customers and as of November
1, 2002 for residential customers. Charges for generation service will (1)
initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 2004;
and (3) may be set at market rates thereafter. Electric Utility may also offer
multiple-year POLR contracts to its customers. The POLR Settlement provides for
annual shopping periods during which customers may elect to remain on POLR
service or choose an alternate supplier. Customers who do not select an
alternate supplier will be obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service at a time
other than during the annual shopping period must remain on POLR service until
the date of the second open shopping period after returning. C&I customers
who return to POLR service at a time other than during the annual shopping
period must remain on POLR service until the next open shopping period, and
may, in annual revenues,
effective July 19, 1996.
REGULATORY ASSETS (LIABILITIES)certain circumstances, be subject to generation rate surcharges.
Formation of Hunlock Creek Energy Ventures. On December 8, 2000, UGID
contributed its coal-fired Hunlock Creek generating station ("Hunlock") and
certain related assets having a net book value of $4,214, and $6,000 in cash,
to Energy Ventures, a general partnership jointly owned by the Company and a
subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was
recorded at its carrying value and no gain was recognized by the Company. Also
on December 8, 2000, Allegheny contributed a newly constructed, gas-fired
combustion turbine generator to be operated at the Hunlock site. Under the
terms of our arrangement with Allegheny, each partner is entitled to purchase
50% of the output of the joint venture at cost. Total purchases from Energy
Ventures in 2002 and 2001 were $9,751 and $7,966, respectively. At September
30, 2002 and 2001, the carrying amounts of our investment in Energy Ventures
were $10,017 and $10,832, respectively, which amounts are included in other
assets in the Consolidated Balance Sheets.
Regulatory Assets and Liabilities
The following regulatory assets (liabilities)and liabilities are included in theour accompanying
balance sheets at September 30:
1997 1996
-------- --------- -----------------------------------------------------------
2002 2001
- -----------------------------------------------------------
Regulatory income tax assetassets:
Income taxes recoverable $ 44,43854,727 $ 42,90851,761
Power agreement buy-out - 1,338
Other postretirement benefits 3,809 4,322
Refundable state taxes (3,102) (4,166)2,397 2,633
Deferred fuel costs (recoveries), net (3,565) 1,0744,304 -
Other 561 423
- -----------------------------------------------------------
Total regulatory assets $ 61,989 $ 56,155
- -----------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 4,332 $ 4,339
Deferred producer settlement and pipeline
transition recoveries (3,852) (5,876)
Deferred environmentalfuel costs 706 697- 2,752
- -----------------------------------------------------------
Total regulatory liabilities $ 4,332 $ 7,091
- -----------------------------------------------------------
F-14F-17
67
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company's regulatory liabilities are included in "other current
liabilities" and "other noncurrent liabilities" on the Consolidated Balance
Sheets. The Company's regulatory assets do not earn a return.
3. DEBT
Long-term debt comprises the following at September 30:
1997 1996
--------- ---------- -----------------------------------------------------------------------------------------------------
2002 2001
- -----------------------------------------------------------------------------------------------------
First Mortgage Bonds:
7.85% SeriesMedium-Term Notes:
7.25% Notes, due November 19962017 $ --20,000 $ 8,400
Other long-term debt:20,000
7.17% Series B Medium-Term Notes, due June 2007 20,000 --20,000
7.37% Medium-Term Notes, due October 2015 22,000 22,000
6.73% Medium-Term Notes, due October 2002 26,000 26,000
6.62% Medium-Term Notes, due May 2005 20,000 20,000
7.14% Notes, due December 2005 (including unamortized
premium of $392 and $533, respectively, effective rate - 6.64%) 30,392 30,533
7.14% Notes, due December 2005 20,000 20,000
5.53% Notes due September 2012 40,000 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $134$23 and $153,$56, respectively) 49,866 49,847
8.70% Notes, due March 1997 and 1998 in annual
installments of $10,000 10,000 20,000
9.71% Notes, due through September 2000 in
annual installments of $7,143 21,428 28,571
Other -- 1,836
--------- ---------49,977 49,944
- -----------------------------------------------------------------------------------------------------
Total long-term debt 169,294 176,654248,369 208,477
Less current maturities (17,143) (25,543)
--------- ---------(76,000) -
- -----------------------------------------------------------------------------------------------------
Long-term debt due after one year $ 152,151 $ 151,111
--------- ---------$172,369 $208,477
- -----------------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt for each of the next five
fiscal years ending September 30 are as follows: 19982003 - $17,143; 1999$76,000; 2004 - $7,143;
2000$0;
2005 - $7,142; 2001$20,000; 2006 - $ -; 2002$50,000; 2007 - $ -.
The mortgage collateralizing UGI Utilities First Mortgage Bonds
constitutes a first lien on UGI Utilities' plant.$20,000.
At September 30, 1997,2002, UGI Utilities had revolving credit agreements with fivefour
banks providing for borrowings of up to $102,000$97,000. These agreements expire at
various dates through December 1997 and $82,000 through June 2000. The commitments expiring in
June 2000 may be extended for one-year periods, upon timely notice,
unless the banks elect not to renew. The agreements provideSeptember 2005. UGI Utilities with the option tomay borrow at various
prevailing interest rates, including the prime rate. ALIBOR. UGI Utilities pays quarterly
commitment fee at an annual rate of
3/16 of 1% is payable quarterlyfees on the unused available committedthese credit lines. At September 30, 1997 and 1996,UGI Utilities had borrowings under these
agreements totaled $67,000totaling $37,200 at September 30, 2002 and $50,500, respectively, and are classified$57,800 at September 30,
2001, which we classify as bank loans. The weighted-average interest rates on
UGI Utilities' bank loans were 2.35% at September 30, 19972002 and 1996 were 6.3%3.75% at September 30, 2001.
UGI Utilities' credit agreements have restrictions on such items as total debt,
debt service, and 5.9%, respectively.
F-15payments for investments. They also require consolidated
tangible net worth of at least $125,000. At September 30, 2002, UGI Utilities
was in compliance with its financial covenants.
F-18
68
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Certain of UGI Utilities' debt agreements contain limitations with
respect to incurring additional debt, require the maintenance of
consolidated tangible net worth of at least $125,000, and restrict the
amount of payments for investments, redemptions of capital stock,
prepayments of subordinated indebtedness and dividends. Under the most
restrictive of these provisions, permitted future restricted payments
aggregate $149,413 at September 30, 1997.
4. INCOME TAXES
The provisions for income taxes consist of the following:
1997 1996 1995
-------- -------- --------- -------------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------
Current:Current expense:
Federal $ 18,16813,341 $ 12,18425,344 $ 6,74222,721
State 5,847 3,704 2,630
-------- -------- --------
24,015 15,888 9,3725,115 8,103 6,819
- -------------------------------------------------------------------------------------------
Total current expense 18,456 33,447 29,540
Deferred 947 7,880 2,768(benefit) expense 11,512 (1,618) 3,264
Investment tax credit amortization (398) (399) (399)
-------- -------- --------(398) (398)
- -------------------------------------------------------------------------------------------
Total income tax expense $ 24,56429,570 $ 23,36931,431 $ 11,741
-------- -------- --------32,406
- -------------------------------------------------------------------------------------------
F-16
69
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
A reconciliation from the statutory federal tax rate to theour effective tax rate
is as follows:
1997 1996 1995
---- ---- ----- -------------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 6.3 6.5 6.2 7.5
Adjustment to deferred state
income taxes -- -- (10.7)6.1
Deferred investment tax credit amortization (.6) (.7) (1.0)(0.5) (0.5) (0.5)
Other, net (2.1) (2.6) (1.3)
---- ---- ----(0.7) (1.5) (1.5)
- -------------------------------------------------------------------------------------------
Effective tax rate 38.8% 37.9% 29.5%
---- ---- ----40.1% 39.5% 39.1%
- -------------------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
1997 1996
--------- ---------- -------------------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and
equipment $ 85,387107,627 $ 81,06099,928
Regulatory income tax asset 18,439 17,802assets 25,108 23,301
Employee-related expenses 10,546 8,901
Other 6,862 8,977
--------- ---------777 804
- -------------------------------------------------------------------------------------------
Gross deferred tax liabilities 110,688 107,839
--------- ---------144,058 132,934
- -------------------------------------------------------------------------------------------
Deferred investment tax credits (4,305) (4,471)
Deferred fuel refunds (1,450) --(3,479) (3,644)
Employee-related expenses (4,494) (4,348)
Regulatory(6,371) (6,067)
Power purchase agreement liability (515) (1,487)
Accumulated other comprehensive loss (1,968) -
state income taxes (1,287) (1,729)
Other (6,463) (8,155)
--------- ---------(2,852) (5,373)
- -------------------------------------------------------------------------------------------
Gross deferred tax assets (17,999) (18,703)
--------- ---------(15,185) (16,571)
- -------------------------------------------------------------------------------------------
Net deferred tax liabilities $ 92,689 $ 89,136
--------- ---------128,873 $116,363
- -------------------------------------------------------------------------------------------
During 1995,
UGI Utilities had recorded a regulatory incomedeferred tax asset of
$12,587 related to $11,329 of existing deferred state income taxes
expected to be recovered in the future through the ratemaking process.
Pursuant to the Gas Utility Base Rate Settlement, UGI Utilities recorded
a regulatory liability of $5,319 associated with a five-year flowback to
ratepayersliabilities of approximately $4,787 in previously recovered deferred
state income taxes. The net effect$35,498 as
of these adjustments increased 1995
net income by $4,251.
F-17September 30, 2002 and $33,928 as of September 30, 2001 pertaining to utility
temporary differences, principally
F-19
70
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
As of September 30, 1997 and 1996, UGI Utilities had recorded
approximately $30,305 and $29,575, respectively, of deferred tax
liabilities pertaining to utility temporary differences, principally
a result of accelerated tax depreciation, the tax benefits of which previously
were or will be flowed through to ratepayers. These deferred tax liabilities
have been reduced by deferred tax assets of $4,305 and
$4,471$3,479 at September 30, 19972002 and
1996, respectively,$3,644 at September 30, 2001, pertaining to utility deferred investment tax
credits. As of September 30, 1997 and
1996, UGI Utilities had recorded a regulatory income tax assetassets related to
these net deferred taxes of $44,438$54,727 as of September 30, 2002 and $42,908, respectively,
representing$51,761 as of
September 30, 2001. These regulatory income tax assets represent future revenues
expected to be recovered through the ratemaking process. ThisWe will recognize this
regulatory income tax asset will be recognized in deferred tax expense as the corresponding
temporary differences reverse and additional income taxes are incurred.
5. EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION PLAN AND OTHER POSTEMPLOYMENT BENEFITS
The Retirement Income Plan for Employees of UGI Utilities, Inc. (UGI
Utilities Plan) isPOSTRETIREMENT PLANS
We sponsor a noncontributory defined benefit pension plan covering substantially all("UGI Utilities Pension Plan") for
employees of UGI, UGI Utilities, and UGI. UGI
Utilities Plan's benefits are generally based on yearscertain of service and
employee compensation during the last years of employment.
The components of net pension income associated with UGI Utilities'
employees participating in the UGI Utilities Plan include the following:
1997 1996 1995
--------- --------- ----------
Service cost - benefits earned
during the period $ 2,564 $ 2,657 $ 2,020
Interest cost on projected
benefit obligation 10,037 9,621 9,500
Actual return on plan assets (38,240) (15,393) (26,745)
Net amortization and deferral 24,482 2,330 14,542
--------- --------- ----------
Net pension income $ (1,157) $ (785) $ (683)
--------- --------- ----------
F-18
71
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table sets forth UGI Utilities Plan's actuarial present
value of benefit obligations and funded status at September 30:
1997 1996
--------- ---------
Projected benefit obligation:
Vested benefits $(118,180) $(106,917)
Nonvested benefits (6,772) (5,912)
--------- ---------
Accumulated benefit obligation (124,952) (112,829)
Effect of projected future salary levels (24,111) (21,337)
--------- ---------
Projected benefit obligation (149,063) (134,166)
Plan assets at fair value 189,539 157,264
--------- ---------
Excess of plan assets over projected benefit
obligation 40,476 23,098
Unrecognized net gain (26,885) (9,609)
Unrecognized prior service cost 5,999 6,664
Unrecognized transition asset (11,155) (12,785)
--------- ---------
Prepaid pension cost $ 8,435 $ 7,368
--------- ---------
Included in the September 30, 1997 and 1996 projected benefit obligation
amounts above are $8,264 and $7,569, respectively, relating to employees
of UGI.
The major actuarial assumptions used in determining UGI Utilities Plan's
funded status as of September 30, 1997, 1996 and 1995, and net pension
income for each of the years then ended, are as follows:
1997 1996 1995
---- ---- ----
Funded status at September 30:
Discount rate 7.4% 8.0% 7.5%
Rate of increase in salary levels 4.5 4.75 4.5
Net pension income for the year:
Discount rate 8.0 7.5 8.7
Rate of increase in salary levels 4.75 4.5 5.0
Expected return on plan assets 9.5 9.5 9.5
---- ---- ----
UGI Utilities Plan's assets at September 30, 1997 consist principally of
equity and fixed income mutual funds and investment-grade corporate and
U. S. Government obligations. The Company also has unfunded nonqualified
retirement benefit plans for certain key employees and directors. At
September 30, 1997 and 1996, the projected benefit obligations of these
nonqualified plans were not material. During 1997, 1996 and 1995, the
Company recorded expense for these plans of $244, $257 and $336,
respectively.
F-19
72
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company sponsors a 401(k) savings plan (Savings Plan) for eligible
employees. Participants in the Savings Plan may contribute a portion of
their compensation on a before-tax and after-tax basis. The Company may,
at its discretion, match a portion of participants' contributions to the
Savings Plan. The cost of such Company matching contributions for 1997,
1996 and 1995 were $880, $865 and $770, respectively.
The Company providesUGI's other wholly owned
subsidiaries. In addition, we provide postretirement health care benefits to
certain retirees and a limited number of active employees meeting certain age
and service requirements, as of January 1, 1989 and also provides limited postretirement life insurance benefits to substantiallynearly
all active and retired employees.
The components of net periodic postretirement benefit cost are as
follows:
1997 1996 1995
------- ------- -------
Service cost - benefits earned
during the period $ 61 $ 67 $ 51
Interest cost on accumulated
postretirement benefit
obligation 1,576 1,908 1,763
Actual return on plan assets (142) -- --
Net amortization and deferral 1,071 1,369 1,055
------- ------- -------
Net periodic postretirement
benefit cost 2,566 3,344 2,869
Decrease (increase) in
regulatory asset 513 (149) (983)
------- ------- -------
Net expense $ 3,079 $ 3,195 $ 1,886
------- ------- -------
The following table sets forth the actuarial present value and funded
status of the Company's postretirement health care and life insurance
benefit plans at September 30:
F-20
73
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following provides a reconciliation of benefit obligations, plan assets, and
funded status of the plans as of September 30:
1997 1996
-------- --------- -------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
----------------------- ---------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $(18,618) $(20,355)
Fully eligible active participants (1,834) (4,000)
Other active participants (1,520) (1,306)
-------- --------
(21,972) (25,661)
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 165,154 $ 150,952 $ 18,179 $ 16,939
Service cost 3,582 3,085 90 75
Interest cost 12,480 12,076 1,474 1,390
Actuarial loss 18,589 7,901 5,051 1,404
Plan amendments 395 - - -
Benefits paid (9,327) (8,860) (1,397) (1,629)
- -------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 190,873 $ 165,154 $ 23,397 $ 18,179
- -------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at fair- beginning of year $ 183,736 $ 223,524 $ 6,994 $ 6,411
Actual return on plan assets (8,345) (30,928) 144 190
Employer contributions - - 2,105 2,022
Benefits paid (9,327) (8,860) (1,397) (1,629)
- -------------------------------------------------------------------------------------------------
Fair value 3,479 1,853of plan assets - end of year $ 166,064 $ 183,736 $ 7,846 $ 6,994
- -------------------------------------------------------------------------------------------------
Funded status of the plans $ (24,809) $ 18,582 $ (15,551) $(11,185)
Unrecognized net gain (1,881) (2,835)actuarial loss 50,190 4,166 5,945 632
Unrecognized prior service cost -- 2,1493,038 3,337 - -
Unrecognized net transition (asset) obligation 16,320 19,921
-------- --------
Accrued postretirement(3,004) (4,634) 7,059 7,743
- -------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ (4,054)25,415 $ (4,573)
-------- --------21,451 $ (2,547) $ (2,810)
- -------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.8% 7.7% 6.8% 7.7%
Expected return on plan assets 9.5% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5%
- -------------------------------------------------------------------------------------------------
Included in the end of year pension benefit obligations above are $13,955 at
September 30, 19972002 and 1996 accumulated postretirement
benefit obligation amounts above are $406 and $365, respectively,$10,544 at September 30, 2001 relating to employees of
UGI.
The major actuarial assumptions usedUGI and certain of its other subsidiaries. Included in determining the funded statusend of the Company'syear
postretirement health care and life insurance benefit
plansobligations above are $649 at September 30, 1997, 19962002 and 1995,$471 at
September 30, 2001 relating to employees of UGI and netcertain of its other
subsidiaries.
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension and other postretirement benefit cost forcosts relating to UGI
Utilities employees include the years then ended, are as follows:following components:
1997 1996 1995
------- ------- -------- ---------------------------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
------------------------------------- -------------------------------
2002 2001 2000 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
Funded status at September 30:
Discount rate 7.4% 8.0% 7.5%
Health care
Service cost trend rate 6.0-5.5 6.5-5.5 7.0-5.5$ 3,193 $ 2,785 $ 2,898 $ 84 $ 82 $ 70
Interest cost 11,600 11,319 11,090 1,453 1,326 1,168
Expected return on assets (17,778) (17,766) (16,010) (366) (366) (252)
Amortization of:
Transition (asset) obligation (1,518) (1,530) (1,534) 680 679 680
Prior service cost 646 625 626 - - -
Actuarial gain (loss) - (1,104) - 20 - -
- ---------------------------------------------------------------------------------------------------------------------------
Net periodic postretirement benefit cost for the year:
Discount rate 8.0 7.5 8.7
Health care cost trend rate 6.5-5.5 7.0-5.5 10.0-5.5
------- ------- --------(income) (3,857) (5,671) (2,930) 1,871 1,721 1,666
Change in regulatory assets and liabilities - - - 1,228 1,378 1,433
- ---------------------------------------------------------------------------------------------------------------------------
Net expense (income) $ (3,857) $ (5,671) $ (2,930) $ 3,099 $ 3,099 $ 3,099
- ---------------------------------------------------------------------------------------------------------------------------
The ultimate health care cost trend rateUGI Utilities Pension Plan assets are held in trust and consist principally of
5.5% in the table above is
assumed for all years after 2007. Increasing the health care cost trend
rate one percent increases theequity and fixed income mutual funds and a commingled bond fund. UGI Common
Stock comprised approximately 6% of trust assets at September 30, 1997 and 19962002. Although
the UGI Utilities Pension Plan projected benefit obligation exceeded plan assets
at September 30, 2002, plan assets exceeded accumulated postretirement benefit obligationsobligation by
$1,534 and $2,150, respectively,
and increases$7,154.
Pursuant to orders issued by the net periodic postretirement benefit costs for 1997,
1996 and 1995, by $115, $160 and $130, respectively.PUC, UGI Utilities has established an Employee Benefit Trust (VEBA)a Voluntary
Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and
life insurance benefits and to fund the UGI Utilities' postretirement benefit
liability. UGI Utilities is required to fund its postretirement benefit
obligations by depositing into the VEBA the annual amount of postretirement
benefits costs determined under SFAS No. 106, "Employers Accounting for
Postretirement Benefits Other than Pensions." The difference between such
amounts and amounts included in UGI Utilities' rates is deferred for future
recovery from, or refund to, ratepayers. VEBA investments consist principally of
money market funds.
The assumed health care cost trend rates are 12.0% for fiscal 2003, decreasing
to 5.5% in fiscal 2010. A one percentage point change in the assumed health care
cost trend rate would change the 2002 postretirement benefit cost and obligation
as follows:
- --------------------------------------------------------------------------
1% 1%
Increase Decrease
- --------------------------------------------------------------------------
Effect on total service and interest costs $ 87 $ (77)
Effect on postretirement benefit obligation 1,345 (1,192)
- --------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 1997,2002 and 2001, the VEBA balance totaled $3,479projected benefit obligations of these plans
were not material. We recorded expense for these plans of $269 in 2002, $235 in
2001 and was primarily invested$131 in money market
funds.
F-212000.
DEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings
Plan"). Generally, participants in the Utilities Savings Plan may contribute a
portion of their compensation on a
F-22
74
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Effective August 31, 1995, Gas Utility is permitted to recover in its
rates approximately $2,400 in ongoing annual costs incurredbefore-tax and after-tax basis. We may, at our discretion, match a portion of
participants' contributions. The cost of benefits under the provisions of SFAS No. 106, "Employers Accounting for Postretirement
Benefits Other Than Pensions" (SFAS 106). Gas Utility is required to
defer the difference between the amount of SFAS 106 costs includedsavings plans
totaled $932 in rates2002, $936 in 2001, and the actuarially determined annual SFAS 106 costs for recovery
or refund to ratepayers$948 in future rate proceedings. Also effective
August 31, 1995, Gas Utility was permitted the recovery over 17.25 years
of approximately $4,000 in deferred excess SFAS 106 costs. These
deferred costs represent the difference between costs incurred under
SFAS 106, comprising principally deferred transition obligation
amortization, and costs incurred on a pay-as-you-go basis for periods
prior to August 31, 1995. Gas Utility's 1995 Base Rate Settlement,
however, reserved the right of any party to challenge the prospective
recovery of these deferred excess SFAS 106 costs in future rate
proceedings. The Company continues to monitor administrative and
judicial proceedings involving deferred excess SFAS 106 costs and
recognizes that, based on applicable law, it is possible that in future
rate proceedings Utilities could prospectively be denied recovery of
some or all of its deferred excess SFAS 106 costs.
Effective October 1, 1994, the Company adopted SFAS No. 112, "Employers'
Accounting for Postemployment Benefits" (SFAS 112). SFAS 112 requires,
among other things, the accrual of benefits provided to former or
inactive employees (who are not retirees) and to their beneficiaries and
covered dependents. Prior to the adoption of SFAS 112, the Company
accounted for these postemployment benefits on a pay-as-you-go basis.
The cumulative effect of SFAS 112 on the Company's results of operations
for periods prior to October 1, 1994 of $1,798 pre-tax ($1,028
after-tax) has been reflected in the 1995 Consolidated Statement of
Income as "Change in accounting for postemployment benefits."2000.
6. INVENTORIES
Inventories comprise the following at September 30:
1997 1996
------- -------- -------------------------------------------------------
2002 2001
- -------------------------------------------------------
Utility fuel and gases $25,963 $26,012$ 36,208 $ 45,628
Appliances for sale 1,877 1,374480 599
Materials, supplies and other 2,805 2,649
------- -------
$30,645 $30,035
------- -------1,966 1,847
- -------------------------------------------------------
Total inventories $ 38,654 $ 48,074
- -------------------------------------------------------
7. SERIES PREFERRED STOCK
The Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 2,000,000 shares authorized for issuance.
The holders of shares of Series Preferred Stock have the right to elect a
majority of the Board of Directors (without cumulative voting) if dividend
payments on any series are in arrears in an amount equal to four quarterly
dividends. This election right continues until the F-22
75
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
arrearage has been cured. CashWe
have paid cash dividends have been paid at the specified annual rates on all outstanding Series
Preferred Stock.
Series Preferred Stock subject to mandatory redemption comprises the
following atAt September 30:
1997 1996
-------- --------
$1.80 Series, stated at involuntary liquidation
value of $23.50 per share, cumulative (issued30, 2002 and 2001, we had outstanding - 7,963 shares) $ 187 $ 187
$8.00 Series, stated at involuntary liquidation
value of $100 per share, cumulative (issued
and outstanding - 150,000 shares) 15,000 15,000
$7.75 Series, stated at involuntary liquidation
value of $100 per share, cumulative (issued
and outstanding - 200,000 shares) 20,000 20,000
-------- --------
Total Series Preferred Stock subject to mandatory
redemption 35,187 35,187
Less current portion (3,000) --
-------- --------
Total Series Preferred Stock due after one year $ 32,187 $ 35,187
-------- --------
UGI Utilities is required to purchase shares of its $1.80$7.75
Series Preferred Stock tendered at a purchase price of $23.50 per share. After
January 1, 1998, UGI Utilities may call any untendered $1.80 Series
shares at a redemption price of $23.50 per share.
UGI Utilities is required to establish a sinking fund to redeem on April
1 in each year, commencing April 1, 1998, 30,000 shares of its $8.00
Series Preferred Stock at a price of $100 per share. The $8.00 Series is
redeemable, in whole or in part, at the option of UGI Utilities at a
price of $103.56 per share commencing April 2, 1997, decreasing by equal
amounts on April 2 of each subsequent year through 2001.
UGI Utilities iscumulative preferred stock. We are required to establish a sinking fund
to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares
of itsour $7.75 Series Preferred Stock at a price of $100 per share. The $7.75 Series Preferred Stock is
redeemable, in whole or in part, at theour option
of UGI Utilities on or after October 1, 2004, at a
price of $100 per share. All outstanding shares of $7.75 Series Preferred Stock are subject to
mandatory redemption on October 1, 2009, at a price of $100 per share.
Mandatory sinking fund requirements on UGI Utilities' Series Preferred
Stock during each of the fiscal years 1998 to 2002 is $3,000.
F-23
76
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. COMMITMENTS AND CONTINGENCIES
The Company leasesWe lease various buildings and transportation, data processingcomputer and office equipment
under operating leases. Certain of theour leases contain renewal and purchase
options and also contain escalation clauses. TheOur aggregate rental expense for
such leases for 1997, 1996was $4,690 in 2002, $4,624 in 2001 and 1995 was $5,083, $4,891 and $4,861, respectively.$4,594 in 2000.
Minimum future payments under operating leases havingthat have initial or remaining
noncancelable terms in excess of one year for the fiscal years ending September
30 are as follows: 19982003 - $4,210; 1999$2,819; 2004 - $3,526; 2000$2,579; 2005 - $2,883; 2001$2,139; 2006 - $2,400; 2002$1,812;
2007 - $2,104;$1,554; after 20022007 - $1,578.$3,961.
Gas Utility has gas supply agreements with producers and marketers that
expire at various dates through 2000 andwith terms of
less than one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity that expirewhich Gas Utility may terminate at various
dates through 20172015. Gas Utility's costs associated with
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
transportation and 2014, respectively.storage capacity agreements are included in its annual PGC
filing with the PUC and are recoverable through PGC rates. In addition, Gas
Utility has short-term gas supply agreements which permit it to purchase certain
of its gas supply needs on a firm or interruptible basis at spotspot-market prices.
Electric Utility has a power supply agreementpurchases its capacity requirements and electric energy needs
under contracts with Pennsylvania Powervarious suppliers and Light, Inc. (PP&L) pursuant to which PP&L supplies allon the electric
power required byspot market. Contracts with
producers for capacity and energy needs expire at various dates through December
2006.
Future contractual cash obligations under Gas Utility and Electric Utility
above that provided fromsupply agreements existing at September 30, 2002 are as follows: 2003 -
$106,400; 2004 - $96,532; 2005 - $56,865; 2006 - $23,255; 2007 - $14,856; after
2007 - $92,446.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other sources. The costresidues of such electricity supplied by PP&L is basedthe manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on PP&L's actual system costs. During 1997, 1996the sites of
former MGPs. Between 1882 and 1995, approximately
53%, 52%1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and 50%, respectively,elsewhere and also operated the businesses of
Electric Utility's total electric
system output was supplied by PP&L. Electricsome gas companies under agreement. Pursuant to the requirements of the Public
Utility has provided notice
to PP&LHolding Company Act of 1935, UGI Utilities divested all of its intention to terminate this agreement as of March 2001.utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities along with other companies, has been named as a
potentially responsible party (PRP) in several administrative
proceedingsdoes not expect its costs for the cleanup of various waste sites, including some
Superfund sites. Also, certain private parties have filed, or threatened
to file, suit against the Company to recover costs of investigation and as appropriate, remediation of
several wastehazardous substances at Pennsylvania MGP sites to be material to its results of
operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. In addition, UGI Utilities has identified environmental contamination atbeen notified of several ofsites
outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or
operated by its propertiesformer subsidiaries and has voluntarily undertaken investigation and, as
appropriate, remediation of these sites in cooperation with appropriate(2) either environmental agencies or
private parties.
With respect to a manufactured gas plant site in Concord, New Hampshire,
EnergyNorth Natural Gas, Inc. (EnergyNorth) filed suit againstparties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities alone seeking UGI Utilities' allocable share of response costs
associated with remediating gas plant related contaminants atis currently litigating two
claims against it relating to out-of-state sites.
Management believes that site.
In September 1997,under applicable law UGI Utilities reached a settlement pursuant to which
it agreed to pay EnergyNorth a portion of its remediation costs. The
settlement didshould not materially affect the Company's results of
operations.
At a manufactured gas plant sitebe liable
in Burlington, Vermont, the United
States Environmental Protection Agency has named 19 parties, including
UGI Utilities, as PRPs for gas plant contamination that resulted from
the operations of a former subsidiary of UGI Utilities. In
F-24
77
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
September 1997, after several years of study, a coordinating council of
community groups and PRPs recommended a remedial plan consisting of
capping and monitoring the site. In December 1997, Green Mountain Power
Company, the lead PRP at the site, agreed in principle to relieve UGI
Utilities of any liability at the site on terms that would not
materially affect the Company's results of operations.
At sitesthose instances in which a former subsidiary of UGI Utilities operated a
manufactured gas plant, UGI Utilities should not have significant
liability because UGI Utilities generally is not legally liable for the
obligations of its subsidiaries. Under certain circumstances, however,
courts have found parent companies liable for environmental damage
caused by subsidiary companies when the parent company exercised such
substantial control over the subsidiary that the court concluded that
the parent company either (i) itself operated the facility causing the
environmental damage or (ii) otherwise so controlled the subsidiary that
the subsidiary's separate corporate form should be disregarded.an MGP. There could be,
therefore,however, significant future costs of an uncertain amount associated with
environmental damage caused by manufactured gas plantsMGPs outside Pennsylvania that UGI Utilities owned or
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that the level of control exercised bysubsidiary's separate corporate
form should be disregarded.
UGI Utilities overhas filed suit against more than fifty insurance companies
alleging that the subsidiary satisfies the standard described above. In many circumstances
wheredefendants breached contracts of insurance by failing to
indemnify UGI Utilities may be liable, expenditures may not be reasonably
quantifiable because of a number of factors, including various costs
associatedfor certain environmental costs. The suit seeks to
recover more than $11,000 in such costs. During 2002, 2001, and 2000, UGI
Utilities entered into settlement agreements with potential remedial alternatives, the unknown number of
other potentially responsible parties involved and their ability to
contribute to the costs of investigation and remediation, and changing
environmental laws and regulations.
The Company's policy is to accrue environmental investigation and
cleanup costs when it is probable that a liability exists and the amount
or range of amounts can be reasonably estimated. The Company intends to
pursue recovery of any incurred costs through all appropriate means,
including regulatory relief, although such recovery cannot be assured.
Under the termsseveral of the Gas Utility Base Rate Settlement, Gas Utility is
permitted to amortize as removal costs site-specific environmental
investigationinsurers and
remediation costs, netrecorded pretax income of related third-party
payments, associated with Pennsylvania sites. Gas Utility will be
permitted to include$390, $943 and $4,500, respectively, which amounts are
included in rates, through future base rate proceedings, a
five-year averageoperating and administrative expenses in the Consolidated Statements
of such prudently incurred removal costs.Income.
F-24
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In addition to these environmental matters, there are various other pending claims and
legal actions arising in the normal course of the
Company'sour businesses. TheWe cannot predict
with certainty the final results of environmental and other matters cannot be predicted with certainty.matters. However, it
is reasonably possible that some of them could be resolved unfavorably to the Company.
Management believes,us. We
believe, after consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a material
adverse effect on the Company'sour financial position but could be material to our operating
results or cash flows in future periods depending on the nature and timing of
future developments with respect to these matters and the amounts of future
operating results and cash flows.
9. FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding current maturities of long-term debt) approximate
their fair values because of their short-term nature. The estimated fair value
of our long-term debt is approximately $263,000 at September 30, 2002 and
$218,000 at September 30, 2001. We estimate the fair value of long-term debt by
using current market prices and by discounting future cash flows using rates
available for similar type debt. The estimated fair value of our Series
Preferred Stock is approximately $20,400 at September 30, 2002 and $21,400 at
September 30, 2001. We estimated the fair value of our Series Preferred Stock
based on the fair value of redeemable preferred stock with similar credit
ratings and redemption features.
We have financial instruments such as trade accounts receivable which could
expose us to concentrations of credit risk. The credit risk from trade accounts
receivable is limited because we have a large customer base which extends across
many different markets. At September 30, 2002 and 2001, we had no significant
concentrations of credit risk.
F-25
78
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. FINANCIAL INSTRUMENTS10. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2)
Electric Operations comprising Electric Utility and our electricity generation
business. Gas Utility revenues are derived principally from the sale and
distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Operations derives its revenues principally from the sale
and distribution of electricity in two northeastern Pennsylvania counties.
The carrying amounts reportedaccounting policies of our reportable segments are the same as those
described in Note 1. We evaluate the performance of our Gas Utility and Electric
Operations segments principally based upon their earnings before income taxes.
No single customer represents more than ten percent of our consolidated revenues
and there are no significant intersegment transactions. In addition, all of our
reportable segments' revenues are derived from sources within the United States,
and all of our reportable segments' long-lived assets are located in the consolidated balance sheets for
cash and cash equivalents, accounts receivable, accounts payable and
bank loans approximate fair value because of the immediate or short-term
maturity of these financial instruments. Based upon current market
prices and discounted present value methods calculated using borrowing
rates available for debt with similar credit ratings, terms and
maturities, the fair values of the Company's long-term debt at September
30, 1997 and 1996 are estimated to be approximately $173,000 and
$176,000, respectively. The fair values of the Company's Series
Preferred Stock are based upon the fair values of redeemable preferred
stock with similar credit ratings and redemption features and are
estimated to be approximately $36,000 and $37,000 at September 30, 1997
and 1996, respectively.United
States. Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade accounts
receivable. This risk is limited due to the Company's large customer
base and its dispersion across many different markets. At September 30,
1997 and 1996, the Company had no significant concentrations of credit
risk.
10. MISCELLANEOUS INCOME
Miscellaneous income comprises the following:information by business segment follows:
1997 1996 1995
------ ------ ------- -------------------------------------------------------------------------
Gas Electric
Total Utility Operations
- -------------------------------------------------------------------------
2002
Revenues $ 490,552 $ 404,519 $ 86,033
Depreciation and amortization 22,172 18,983 3,189
Operating income 90,317 77,148 13,169
Interest expense 16,652 14,224 2,428
Income before income taxes 73,665 62,924 10,741
Total assets 798,123 689,080 109,043
Capital expenditures 35,884 31,034 4,850
- -------------------------------------------------------------------------
2001
Revenues $ 153584,762 $ 403 $1,286
Gas brokerage500,832 $ 83,930
Depreciation and amortization 23,767 20,171 3,596
Operating income -- -- 1,409
Other 2,624 1,439 1,085
------ ------ ------
$2,777 $1,842 $3,780
------ ------ ------98,556 87,846 10,710
Interest expense 18,988 16,258 2,730
Income before income taxes 79,568 71,588 7,980
Total assets 784,409 678,947 105,462
Capital expenditures 36,783 31,757 5,026
- -------------------------------------------------------------------------
2000
Revenues $ 436,942 $ 359,041 $ 77,901
Depreciation and amortization 23,612 19,098 4,514
Operating income 101,235 86,178 15,057
Interest expense 18,353 16,175 2,178
Income before income taxes 82,882 70,003 12,879
Total assets 751,137 653,766 97,371
Capital expenditures 36,391 31,665 4,726
- -------------------------------------------------------------------------
Effective August 1, 1995, the Company dividended the net assets of
GASMARK, the Company's gas brokerage business, to UGI. Such net assets
totaled $973.
F-26
79
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SEGMENT INFORMATION
Information on revenues, operating income, identifiable assets,
depreciation and amortization and capital expenditures by business
segment for 1997, 1996 and 1995 follows:
1997 1996 1995
--------- --------- ---------
REVENUES
Gas utility $ 389,064 $ 390,994 $ 291,258
Electric utility 72,144 69,502 66,106
--------- --------- ---------
Total $ 461,208 $ 460,496 $ 357,364
--------- --------- ---------
OPERATING INCOME (LOSS)
Gas utility $ 74,790 $ 72,937 $ 51,947
Electric utility 10,689 8,622 9,109
Other 223 102 2,126
Corporate general (5,555) (3,850) (6,585)
--------- --------- ---------
Total $ 80,147 $ 77,811 $ 56,597
--------- --------- ---------
IDENTIFIABLE ASSETS
(at period end)
Gas utility $ 594,331 $ 561,793 $554,277
Electric utility 86,247 83,872 86,637
Corporate general and other 800 4,234 20,566
--------- --------- ---------
Total $ 681,378 $ 649,899 $661,480
--------- --------- ---------
DEPRECIATION AND AMORTIZATION
Gas utility $ 17,194 $ 17,576 $ 16,068
Electric utility 4,237 4,024 3,682
Corporate general - 2 4
--------- --------- ---------
Total $ 21,431 $ 21,602 $ 19,754
--------- --------- ---------
CAPITAL EXPENDITURES
Gas utility $ 36,691 $ 34,624 $ 45,273
Electric utility 4,993 5,035 5,922
Corporate general and other - - 26
--------- --------- ---------
Total $ 41,684 $ 39,659 $ 51,221
========= ========= =========
F-27
80
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. QUARTERLY DATA (UNAUDITED)
The following quarterly information includes all adjustments (consisting only of
normal recurring adjustments), which the Company considerswe consider necessary for a fair
presentation of such information. Quarterly results fluctuate because of the
seasonal nature of UGI Utilities' businesses.
- -----------------------------------------------------------------------------------------------------
December 31, March 31, June 30, September 30,
1996 1995 1997 1996 1997 1996 1997 1996
-------- -------- -------- -------- -------- -------- -------- --------2001 2000 2002 2001 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------
Revenues $134,154 $122,241 $173,304 $181,412 $ 88,208141,481 $ 88,860166,503 $ 65,542179,945 $ 67,983231,591 $ 88,249 $ 103,772 $ 80,877 $ 82,896
Operating income (loss) 30,343 27,712 41,022 40,495 8,977 9,389 (195) 21527,609 33,463 41,319 46,500 13,222 12,745 8,167 5,848
Net income (loss) 16,185 14,660 22,763 22,425 2,970 3,702 (3,207) (2,439)
-------- -------- -------- -------- -------- -------- -------- --------14,045 17,095 22,549 25,156 5,552 4,990 1,949 896
- -----------------------------------------------------------------------------------------------------
12. OTHER INCOME, NET
Other income, net, comprises the following:
- ---------------------------------------------------------------------
2002 2001 2000
- ---------------------------------------------------------------------
Non-tariff service income $ 5,701 $ 5,410 $ 3,182
Pension income 3,858 5,671 2,930
Interest income 1,110 235 2,860
Other 1,054 3,795 3,688
- ---------------------------------------------------------------------
$ 11,723 $ 15,111 $ 12,660
- ---------------------------------------------------------------------
13. RELATED PARTY TRANSACTIONS
UGI bills UGI Utilities for an allocated share of its general corporate
expenses. This allocation is based upon a three-factor formula which includes
revenues, costs and expenses, and net assets. These billed expenses are
classified as operating and administrative expenses - related parties in the
Consolidated Statements of Income for 1997, 1996 and 1995.
F-28Income.
F-27
81
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II --- VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
Balance at Charged to Balance at
beginning costs and end of
of year expenses Other year
----------- ---------- ---------- ------------------- ----------
YEAR ENDED SEPTEMBER 30, 1997
- -----------------------------2002
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $3,976 $4,272 $(4,915)$ 3,151 $ 5,270 $ (6,449)(1) $3,333
======== ======== ======= ========$ 1,972
========== =========
Other reserves(3) $3,160 $3,021reserves (3) $ (236)3,467 $ 748 $ (2,352)(2) $5,945
======== ======== ======= ========$ 3,363
========== =========
1,500 (4)
YEAR ENDED SEPTEMBER 30, 1996
- -----------------------------2001
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $2,660 $4,933 $(3,617)$ 2,061 $ 8,269 $ (7,179)(1) $3,976
======== ======== ======= ========$ 3,151
========== =========
Other reserves(3) $3,255reserves (3) $ 2371,954 $ (332)1,696 $ (276)(2) $3,160
======== ======== ======= ========$ 3,467
========== =========
93 (4)
YEAR ENDED SEPTEMBER 30, 1995
- -----------------------------2000
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $2,796 $3,376 $(3,512)$ 1,716 $ 4,386 $ (4,041)(1) $2,660
======== ======== ======= ========$ 2,061
========== =========
Other reserves(3) $2,294 $1,411reserves (3) $ (450)1,345 $ 1,007 $ (455)(2) $3,255
======== ======== ======= ========$ 1,954
========== =========
57 (4)
(1) Uncollectible accounts written off, net of recoveries.
(2) Represents property and casualty liability payments.Payments, net
(3) Includes reserves for self-insured property and casualty liability,
insured property and casualty liability, environmental, litigation and
other.
(4) Other adjustments
S-1
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.2 Bylaws in effect since September 24, 2002
10.25 Storage Transportation Service Agreement (Rate Schedule SST)
between Utilities and Columbia dated November 1, 1993, as
modified pursuant to orders of the Federal Energy Regulatory
Commission
10.26 No-Notice Transportation Service Agreement (Rate Schedule
NTS) between Utilities and Columbia dated November 1, 1993,
as modified pursuant to orders of the Federal Energy
Regulatory Commission
10.27 No-Notice Transportation Service Agreement (Rate Schedule
CDS) between Utilities and Texas Eastern Transmission dated
February 23, 1999, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.28 No-Notice Transportation Service Agreement (Rate Schedule
CDS) between Utilities and Texas Eastern Transmission dated
October 31, 2000, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.29 Firm Transportation Service Agreement (Rate Schedule FT-1)
between Utilities and Texas Eastern Transmission dated June
15, 1999, as modified pursuant to various orders of the
Federal Energy Regulatory Commission
10.30 Firm Transportation Service Agreement (Rate Schedule FT-1)
between Utilities and Texas Eastern Transmission dated
October 31, 2000, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.31 Firm Transportation Service Agreement (Rate Schedule FT)
between Utilities and Transcontinental Gas Pipe Line dated
October 1, 1996, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
-52-
12.1 Computation of Ratio of Earnings to Fixed Charges
12.2 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends
23 Consent of PricewaterhouseCoopers LLP
99 Certification by Chief Executive Officer and Chief Financial
Officer
-53-