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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 19972003
Commission file number 1-1398
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Pennsylvania 23-1174060
(STATE OR OTHER JURISDICTION OF (I.R.S. 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)
(610) 796-3400
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED
TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING
THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS
REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING
REQUIREMENTS FOR THE PAST 90 DAYS. YES X. NO___.[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 30, 2003, 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 [ ]
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND
(b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED
DISCLOSURE FORMAT PERMITTED BY THAT GENERAL INSTRUCTION.
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TABLE OF CONTENTS
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PART I BUSINESS PAGEI: BUSINESS............................................................................................... 1
Items 1 and 22. Business and Properties...................................................Properties........................................................ 1
General.................................................................General........................................................................ 1
Gas Utility Operations..................................................Operations......................................................... 1
Electric Utility Operations............................................. 4Operations.................................................... 5
Item 33. Legal Proceedings......................................................... 10
Item 4 Submission of Matters to a Vote of
Security Holders........................................................ 14Proceedings.............................................................. 8
PART IIII: SECURITIES AND FINANCIAL INFORMATIONINFORMATION................................................................... 11
Item 55. Market for Registrant's Common Equity and Related Stockholder Matters......................................... 14Matters.......... 11
Item 6 Selected Financial Data................................................... 15
Item 77. Management's Discussion and Analysis of Financial Condition and Results of
Operations..................................... 16Operations..................................................................... 12
Item 87A. Quantitative and Qualitative Disclosures About Market Risk..................... 26
Item 8. Financial Statements and Supplementary Data............................... 25Data.................................... 26
Item 99. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................. 25Disclosure..................................................................... 26
Item 9A. Controls and Procedures........................................................ 26
PART III UGI UTILITIES, INC. MANAGEMENT AND SECURITY HOLDERS
Item 10 Directors and Executive Officers of the Registrant........................ 25
Item 11 Executive Compensation.................................................... 30
Item 12 Security Ownership of Certain Beneficial
Owners and Management................................................... 39
Item 13 Certain Relationships and Related
Transactions............................................................ 40III: INTENTIONALLY OMITTED.................................................................................. 28
PART IVIV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTSREPORTS............................................................. 29
Item 1415. Exhibits, Financial Statement SchedulesSchedule, and Reports on Form 8-K................................................. 41
Signatures................................................................ 488-K................ 29
Signatures..................................................................... 35
Index to Financial Statements and Financial Statement Schedule..............................................Schedule................. F-2
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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 1415 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 isWe are a wholly
owned subsidiary of UGI Corporation ("UGI"). Utilities (formerly,In response to state deregulation
legislation, effective October 1, 1999 we transferred our electric generation
assets to our non-utility subsidiary, UGI Corporation)Development Company ("UGID"). UGID
contributed certain of its generation assets to a joint venture with a
subsidiary of Allegheny Energy, Inc. in December 2000. In June 2003, we
dividended the stock of UGID to UGI. UGID's results of operations did not have a
material effect on our results of operations for fiscal years 2003, 2002 or
2001.
Utilities was incorporated in Pennsylvania in 1925 as the successor to a business founded in 1882. The Company is1925. We 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 (for periods prior to July 2003), 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
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restructuring plan to ensure reliability of gas supply deliveries to Gas Utility
on behalf of 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 2003, 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 4,500 customers. Management believes none of the Gas
Competition Act, the Gas Restructuring Order, or commodity sales to residential
and small commercial and industrial 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 252,000292,000 customers
in portions of 1415 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,2004,800 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 19972003 fiscal year was
approximately 80.283.8 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 46%43% of system throughput, while gas transported for residential,
commercial and industrial customers (who buybought their gas from others) accounted
for approximately 54%57% of system throughput. Based on industry data for 1996,2001,
residential customers account for approximately 38%34% of total system throughput
by local gas
distribution companiesLDCs in the United States. By contrast, for the 19972003 fiscal year, Gas
Utility's residential customers represented 23%26% 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.
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GAS SUPPLY CONTRACTS
During the 1997 fiscal year 2003, Gas Utility purchased approximately 37.537 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%88% of the volumes purchased
were supplied under agreements with sixten major suppliers of natural
gas.suppliers. The remaining 6.5 bcf or 17%12% of
gas purchased was supplied by approximately 25 producers and marketers under other arrangements, including multi-month agreements at spot
prices. Certain gasmarketers. Gas
supply contracts require minimumare generally no longer than one year.
In fiscal years 2002 and 2003, as a result of changing market
conditions following the bankruptcy of Enron Corp., a number of suppliers with
which Utilities formerly did business exited the wholesale trading market. This
development did not significantly impact Utilities' ability to secure gas
purchases. Each of
these agreements, however, either terminates in fiscal year 1998, or includes
provisions which entitle Utilities 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 of 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 60% of fiscal year 2003 throughput
occurred during the months of 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 2003, two marketers have qualified to
serve residential and small commercial and industrial customers. Together they
serve approximately 4,500 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.
A number 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%18% of non-residentialtotal system throughput (8% of non-residential
revenues) have locations which
afford them the optionopportunity, although none has
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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,
nine of which extend beyond 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 1998.2004. 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 2003, 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 9,600 residential heating customers during the 1997 fiscal year an
increase of 8% from the previous year. Approximately 63% of the additions
represent gas2003, which
represented a record annual increase. Of those new customers, from the new home
construction market. The remaining 37%
represent customersaccounted for over 7,300 heating customers. Customers converting
from other energy sources, primarily oil and electricity, 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 casesproceedings 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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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)("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
mayis obligated to provide
energy to customers who do not increase the generation component of prices as long as stranded costs
are being recovered through the CTC.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 an estimated four-year period which commenced January 1, 1999 through December 31, 2002. The major componentsa
CTC, together with carrying charges on unrecovered balances of this claim are: (1) plant investments
in excess7.94%. Under the
terms of competitive market value and electricthe Restructuring Order, Electric Utility generally could not increase
the generation facility
retirement costs; (2) potentialcomponent of prices during the period that stranded costs associated with existing power purchase
agreements; and (3) regulatory assets (principally income taxes) recoverable
from ratepayers under current regulatory practice. It also seeks to establish a
recovery mechanism that would permitwere
being recovered through the CTC. Electric Utility's recovery of up to an additional $28
million ofstranded costs
associated withthrough 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 percent of the noncoincident peak load
of industrial, commercial 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 participate in the pilot.
Given the changing regulatory environment in the electric utility
industry, the Company continues 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 assetsCTC was completed 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.fiscal year 2003.
SERVICE AREA; SALES ANALYSIS
Electric Utility supplies electric service to approximately 61,00061,600
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 2003, about 53% of sales volume came from residential customers, 34%36% from
commercial customers and 13%11% 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 ofyear 2003 sales volume.
SOURCES OF SUPPLY
Electric Utility accountedhas third-party generation supply contracts in place
for approximately 16%, 15% and 18%,
respectively,substantially all of Utilities' total consolidated revenues.
Sources of Supply.its expected energy requirements for fiscal year 2004.
Electric Utility distributes both electricity whichthat it
generates or purchases from others. As the provisionsothers and
electricity that customers purchase from other suppliers. At September 30, 2003,
alternate suppliers served customers representing less than 1% 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 located near
Kingston, Pennsylvania ("Hunlock Station"), and has a 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 up to 69 megawatts of electric power forsystem load.
Electric Utility and provided approximately 47%expects to continue to provide energy to the great majority of
its energy requirements
duringdistribution customers for the 1997 fiscal year.
Utilities has a long-term power supply agreement with Pennsylvania
Power & Light Company ("PP&L"). Under this agreement, PP&L supplies all the
electric power required by Electric Utility above that provided from certain
other sources, including Hunlock Station. The cost of electricity supplied by
PP&L is based on PP&L's actual system costs. Utilities estimates that the cost
of electricity supplied by Hunlock is higher than projected market rates, but
lowerforeseeable future.
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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 notice of its intent to stop purchasing power under 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. The 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, Utilities 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. The Conemaugh Station is in compliance with
these standards, and the Hunlock Station is required to meet 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 Hunlock 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. Sales of electricity for residential heating purposes
accounted for approximately 23% of the total sales of Electric Utility during
the 1997 fiscal year. Electricity competes with natural gas, oil, propane and
other heating fuels in this use. Approximately 54% of
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sales occurred in the six coldest months of the 1997 fiscal year, 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. 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 residentialother arrangements with affiliated entities, and small
commercial customers. On March 27, 1997, proposed customer choice legislation
was introduced in the Pennsylvania General Assembly that would, amongvarious 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
April 1, 1999 and would also require Pennsylvania gas utilities to stop selling
natural gas. Legislative committees have conducted public hearings on 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.matters.
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-residential,
commercial and industrial ("retail 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 cost
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 reduce its
purchased gas cost rates to retail core-market customers by an amount equal to
the margin it receives from customers served under interruptible rates to the
extent they use capacity contracted for by Gas Utility for retail 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 electric utility operations are subjectless sensitive to regulation by the PUC asmarket prices of alternative fuel.
BASE RATES
As stated above, Gas Utility's current base rates went into effect
October 1, 2000 pursuant to rates,
terms and conditions of service, accounting matters, issuance of securities,
contracts and other arrangements with affiliated entities, and various other
matters.
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10
PurchasedThe Gas Cost Rates.Restructuring Order. See Note 2 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
-6-
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, under certain
conditions 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 will reflect
estimated PGC over-collections and under-collections through November 30, 1998.
Energy Cost Rates. In accordance with provisions of the Customer Choice
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 permitted Electric Utility to adjust customers' monthly
charges2001, to reflect
annual changes in the cost of purchased power, fuel,
interchange power and the cost of transmitting power purchasedmargins, if any, 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.interruptible rate customers who do not obtain their own
pipeline capacity.
ELECTRIC UTILITY RATES
The PUC approved a $19.5 million
settlement establishing rules for Electric Utility's
Provider of this proceeding, effective August 31, 1995.
Electric Rate Case. On January 26, 1996Last 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 filedterminated stranded cost recovery
through its CTC and is no longer subject to the statutory generation rate caps
as of August 1, 2002 for commercial and industrial ("C&I") customers and as of
November 1, 2002 for residential customers. Charges for generation service (1)
were initially 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 by up to 5% of the total rate for distribution,
transmission and generation 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 certain circumstances, be
subject to generation rate surcharges. Consistent with the PUCterms of the POLR
Settlement, Electric Utility's POLR rates will increase beginning January 2004
for a $6.2 million increase in its base rates,commercial and industrial customers, and June 2004 for residential
customers.
Additionally, pursuant to be effective March 26,
1996. On July 18, 1996,the requirements of the ECC, the PUC approved a settlementis
currently developing post-rate cap POLR regulations that are expected to further
define post-rate cap POLR service obligations and pricing. As 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, 1997September 30,
2003, fewer than 1% of 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.Utility's customers have chosen an alternative
electricity generation supplier.
-7-
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.
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, 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 ofEMPLOYEES
At September 30, 2003, 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 - Generation and Distribution
of Electricity-Environmental Factors."
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12had approximately 1,000 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,
19962003,
2002 and 19952001 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 theirits properties, and no
such proceedings are known to be
-8-
contemplated by governmental authorities.authorities other than claims arising in the
ordinary course of the Company's business.
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
claimthree claims against it relating to an out-of-state site. Ifsites.
Consolidated Edison Company of New York v. UGI 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 amountInc. On
September 20, 2001, Consolidated Edison Company 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 thatNew York ("ConEd") filed suit
against 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,
1993, Public Service Electric and Gas Company ("PSE&G") informed Utilities that
PSE&G had been named as a defendant in a civil action pendingInc. in the United States District Court offor the Southern
District of New Jersey,York, seeking damages as a resultcontribution from Utilities for an allocated share
of contamination relating to the former manufacturedresponse costs associated with investigating and assessing gas plant operationsrelated
contamination at Halladay Streetformer MGP sites in Jersey City,Westchester County, New Jersey.York. The Halladay Street gas plant
operated from approximately 1884 until 1950. PSE&G assertedcomplaint
alleges that Utilities "owned and operated" the MGPs prior to 1904. The
complaint also seeks a declaration that Utilities is liableresponsible for an
allocated percentage of future investigative and remedial costs at the sites.
ConEd believes that portionthe cost of remediation for all of the costs associated with operationssites could exceed
$70 million. Utilities believes that it has good defenses to the claim and is
defending the suit.
In November 2003, the court granted Utilities' motion for summary
judgment in part, dismissing all claims premised on a disregard of the plant
between 1886separate
corporate form of Utilities' former subsidiaries and 1899. PPG Industries, Inc. has also been named asdismissing claims premised
on Utilities' operation of three of the MGPs under operating leases with ConEd's
predecessors. The court reserved decision on the remaining theory of liability,
that UGI Utilities was a defendant
indirect operator of the action for costs associated with chemical contamination at the site
unrelated to gas plant operations.remaining MGPs.
City of Bangor, Maine v. Citizens Communications Co. In July 1993, PSE&GApril 2003,
Citizens Communications Company ("Citizens") served Utilities with a complaint naming Utilities
as a third-party defendant in thisa 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' involvement 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 Gas 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. v. UGI Utilities, Inc. Civil Action
No. 97CV4592. On July 14, 1997, Foster Wheeler Penn Resources, Inc. filed suit
against UGI Utilities, Inc.pending in United States District
Court for the Eastern
District of PennsylvaniaMaine. In
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that action, the plaintiff, City of Bangor, sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant
allegedly operated by Citizens' predecessors at a site on the Penobscot River.
Citizens subsequently joined Utilities and ten other third-party defendants
alleging among other things, that UGI Utilities
breachedthe third-party defendants are responsible for an Agreementequitable share
of any response costs Citizens may be required to pay to the City of Bangor.
Remedial proposals for the Salesite range between $5 million and Purchase$50 million.
Utilities is unable to estimate what portion of Net Electrical Energy under
which UGIthis potential cost may be
associated with MGP wastes. Utilities had agreed 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
declaration that the Sale and Purchase Agreement remains in effect or in the
alternative that Foster Wheeler be awarded damages in excess of $20 million.
Management believes that it has good defenses to Foster Wheeler's claims.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted tothe
claim.
Atlanta Gas Light Company v. UGI Utilities, Inc. By letter dated July
29, 2003, Atlanta Gas Light Company ("AGL") served Utilities with a votecomplaint
filed in the United States District Court for the Middle District of security holders duringFlorida in
which AGL alleges that Utilities is responsible for 20% of approximately $8
million incurred by AGL in the last
fiscal quarterinvestigation and remediation of a former MGP
site in St. Augustine, Florida. Utilities formerly owned stock of the 1997 fiscal year.St.
Augustine Gas Company, the owner and operator of the MGP. Utilities believes
that it has good defenses to the claim and is defending the suit.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et al. On
February 11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas
of Montgomery County, Pennsylvania against more than fifty insurance companies,
including Insurance Services, Ltd. (AEGIS). The complaint alleges that the
defendants breached contracts of insurance by failing to indemnify Utilities for
certain environmental costs. Utilities has now settled with all known solvent
defendants. The suit has been stayed pending resolution of the remaining claims.
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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 $33.9
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 $1.02003, $37.9 million in net
assets of its former GASMARK operation), respectively.
The information concerning restrictions on dividends required by Item 5
is includedfiscal year 2002 and $35.3 million
in Note 3 to the Company's Consolidated Financial Statements
included in this Report and is incorporated herein by reference.
-14-fiscal year 2001.
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17
ITEM 6. SELECTED FINANCIAL DATA
Nine
Months
Year Ended Ended
September 30, September 30,
------------------------------------------------- ----------------------
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(unaudited)
(Thousands of dollars)
FOR THE PERIOD ENDED:
Income statement data:
Revenues $ 461,208 $ 460,496 $ 357,364 $ 395,061 $ 251,210 $ 246,677
========= ========= ========= ========= ========= =========
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
Dividends on preferred stock 2,764 2,765 2,778 1,356 2,124 1,905
--------- --------- --------- --------- --------- ---------
Net income after dividends
on preferred stock $ 35,947 $ 35,583 $ 24,212 $ 29,117 $ 13,907 $ 27,348
========= ========= ========= ========= ========= =========
AT PERIOD END:
Balance sheet data:
Total assets $ 681,378 $ 649,899 $ 661,480 $ 581,426 $ 561,306 $ 560,672
========= ========= ========= ========= ========= =========
Capitalization:
Debt:
Bank loans $ 67,000 $ 50,500 $ 42,000 $ 17,000 $ -- $ --
Long-term debt including
current maturities: 169,294 176,654 208,162 177,444 200,421 198,273
--------- --------- --------- --------- --------- ---------
Total debt 236,294 227,154 250,162 194,444 200,421 198,273
--------- --------- --------- --------- --------- ---------
Preferred stock subject to
mandatory redemption 35,187 35,187 35,202 35,202 33,222 35,223
Common equity 200,494 189,441 186,803 178,071 169,077 161,971
--------- --------- --------- --------- --------- ---------
Total capitalization $ 471,975 $ 451,782 $ 472,167 $ 407,717 $ 402,720 $ 395,467
========= ========= ========= ========= ========= =========
Ratio of capitalization:
Total debt 50.0% 50.3% 53.0% 47.7% 49.8% 50.1%
UGI Utilities preferred stock 7.5% 7.8% 7.4% 8.6% 8.2% 8.9%
Common equity 42.5% 41.9% 39.6% 43.7% 42.0% 41.0%
--------- --------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
========= ========= ========= ========= ========= =========
(a) Includes results of AmeriGas and Ashtola prior to April 10, 1992. Also
includes the Company's oil field activities discontinued in 1986.
15
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
1997 COMPARED WITH 1996In the following Management's Discussion and Analysis of Financial Condition and
Results of Operations ("MD&A"), Electric Utility and UGID's electricity
generation business prior to its distribution to UGI in June 2003 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 2003 Compared with Fiscal 2002
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1997 1996 (Decrease)2003 2002 Increase
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars)
(Millions of dollars)
GAS UTILITY:
Natural gas systemRevenues $ 539.9 $ 404.5 $ 135.4 33.5%
Total margin (a) $ 196.9 $ 162.9 $ 34.0 20.9%
Operating income $ 96.1 $ 77.1 $ 19.0 24.6%
Income before income taxes $ 80.7 $ 62.9 $ 17.8 28.3%
System throughput - bcf 80.2 85.4 (5.2) (6.1)%83.8 70.5 13.3 18.9%
Degree days - % colder (warmer)
than normal (4.8) 4.2 -- --7.0% (17.4)% - -
ELECTRIC OPERATIONS:
Revenues $389.1 $391.0 $ (1.9) (.5)%96.9 $ 86.0 $ 10.9 12.7%
Total margin $168.7 $169.7(a) $ (1.0) (.6)%42.2 $ 32.8 $ 9.4 28.7%
Operating income $ 74.821.8 $ 72.913.2 $ 1.9 2.6 %
ELECTRIC UTILITY:
Electric8.6 65.2%
Income before income taxes $ 19.5 $ 10.7 $ 8.8 82.2%
Distribution sales - gwh 868.5 884.7 (16.2) (1.8)%
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 %
- -----------------------------------------------------------------------------------980.0 933.6 46.4 5.0%
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.taxes, i.e.
Electric Utility gross receipts taxes of $4.8 million and $4.6
million in Fiscal 2003 and Fiscal 2002, respectively. 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 based upon heating
degree days was 4.8%7.0% colder than normal during Fiscal 2003 compared to weather
that was 17.4% warmer than normal during Fiscal 2002. The significantly colder
weather resulted in 1997 comparedhigher heating-related sales to 4.2% colder than normalfirm- residential,
commercial and industrial ("retail core-market") customers and, to a lesser
extent, greater volumes transported for residential, commercial and industrial
delivery service customers. System throughput in 1996. The decreaseFiscal 2003 also benefited from
a year-over-year increase in total system throughputthe number of customers.
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Gas Utility revenues increased principally reflects the warmer weather's effect on core
market sales as well as a decrease in low-margin interruptibleresult of the previously
mentioned greater retail core-market and delivery service volumes associated with the shut-down of a gas-fired cogeneration facility.and higher
average retail core-market purchased gas cost ("PGC") rates resulting from
higher natural gas costs. Gas Utility revenues were $1.9 million 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 revenues from lower sales and an $8.1
million decrease in revenues from off-system sales. Costcost of gas sold by Gas
Utility decreased $1.1was $343.0 million to $205.2in Fiscal
2003, an increase of $101.3 million from the prior year, reflecting the lower off-systemhigher
retail core-market volumes sold and core market sales offset bythe higher averageretail core-market PGC rates.
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19
The decreaseincrease in Gas Utility total margin principally reflects a $6.3$27.1 million
decreaseincrease in retail core-market total margin due to the higher retail core-market
sales and increased margin from greater delivery service volumes.
The increase in Gas Utility operating income principally reflects the increase
in total margin from core market customers resulting from the warmer
weather partially offset by a $5.5$12.7 million increase in total margin from
interruptible customers.
Although total margin was slightly lower in 1997, Gas Utility operating income
increased $1.9 million principally as a result of a $1.5 million decrease in operating and
administrative expenses and higher miscellaneouslower other income. OperatingFiscal 2003 operating and
administrative expenses during 1997 decreasedinclude higher costs associated with litigation-related
costs and expenses, greater distribution system maintenance expenses, higher
uncollectible accounts expenses and increased incentive compensation costs.
Other income declined $3.2 million principally reflecting a $2.2 million
decrease in pension income and lower interest income on PGC undercollections.
The increase in Gas Utility income before income taxes reflects the increase in
operating income offset by higher interest expense on PGC overcollections and,
beginning July 1, 2003, dividends on preferred shares.
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2003 kilowatt-hour sales
increased principally as a result of a
decreaseweather that was 8.4% colder than normal
compared to weather that was 14.5% warmer than normal in distribution system expenses, lower accruals for uncollectible
accounts, and lower general and administrative expenses partially offset bythe prior year.
The higher costs associated with environmental matters.
ELECTRIC UTILITY.Electric Operations revenues reflect greater Electric Utility sales
decreasedand greater sales of electricity produced by UGID's electricity generation
assets to third parties prior to its distribution to UGI in 1997 reflecting weather
which was 5.6% warmer than inJune 2003. Prior to
September 2002, UGID sold substantially all of the prior-year period.electricity it produced to
Electric Utility base ratewith the associated revenue and margin eliminated in our
consolidated results. Beginning September 2002, Electric Utility began
purchasing its power needs exclusively from third-party electricity suppliers
under fixed-price energy and capacity contracts and, to a much lesser extent, on
the spot market, and UGID began selling electric power produced from its
interests in electricity generating facilities to third parties on the spot
market. Notwithstanding the significant increase in Electric Operations'
revenues, cost of sales increased $1.7only $1.3 million in Fiscal 2003 as a $2.8 million increasethe impact
on cost of sales resulting from higher
base ratesthe greater Electric Utility and electric
generation third-party sales was partially offset by a $1.1 million decrease resultinglower Electric Utility
per-unit purchased power costs.
The increase in Electric Operations' total margin principally reflects lower
Electric Utility per-unit purchased power costs, the increase in Electric
Utility sales, and margin from the lower sales. In addition, Electric Utility revenues include a $.9 million
increase in energy cost recoveries. Costgreater sales of sales increasedelectricity produced by
UGID's electricity generation assets to $33.8 million in
1997 from $33.4 million in 1996 as a result ofthird parties. The higher Fiscal 2003
operating income reflects the greater total margin and higher energy cost recoveriesother income
partially offset by the lower sales.
Electric Utility total margin and operating income increased in 1997 principally
as a result of theslightly 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.expenses. The
increase in Electric Operations income before income taxes reflects the increase
in operating income and slightly lower interest expense reflects
higher average bank loans outstanding partially offset by lower average
long-term debt outstanding. The effective income tax rate for 1997 was 38.8%
comparedexpense.
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Fiscal 2002 Compared with a rate of 37.9% for 1996.
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20
1996 COMPARED WITH 1995Fiscal 2001
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1996 19952002 2001 (Decrease)
- --------------------------------------------------------------------------------------------------------------------
(Millions of dollars)
- -----------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Natural gas systemRevenues $ 404.5 $ 500.8 $ (96.3) (19.2)%
Total margin $ 162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
Income before income taxes $ 62.9 $ 71.6 $ (8.7) (12.2)%
System throughput - bcf 85.4 82.4 3.0 3.6%70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal 4.2 (5.4) -- --(17.4)% 2.0% - -
ELECTRIC OPERATIONS:
Revenues $391.0 $291.3 $ 99.7 34.2%86.0 $ 83.9 $ 2.1 2.5%
Total margin $169.7 $140.9(a) $ 28.8 20.4%32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 72.913.2 $ 51.910.7 $ 21.0 40.5%
ELECTRIC UTILITY:
Electric2.5 23.4%
Income before income taxes $ 10.7 $ 8.0 $ 2.7 33.8%
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)933.6 945.5 (11.9) (1.3)%
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(a) Electric Operation's total margin represents total revenues
less cost of sales and revenue-related taxes.Electric Utility gross receipts taxes
of $4.6 million and $3.4 million in Fiscal 2002 and Fiscal
2001, respectively.
GAS UTILITY.
Weather in Gas Utility's service territory in 1996during Fiscal 2002 based upon heating
degree days was 17.4% warmer than normal compared to weather that was 2.0%
colder than normal in Fiscal 2001. As a result of the significantly warmer
weather and also colder thanthe effects of a weak economy on commercial and industrial natural
gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in 1995.Fiscal 2002 Gas Utility revenues reflects the
impact of lower PGC rates, resulting from the pass through of lower natural gas
costs to retail core-market customers, and the lower distribution system
throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared
to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and the
decline in retail core-market throughput in Fiscal 2002.
The increasedecline in Gas Utility margin principally reflects a $6.0 million decline in
retail 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 retail core-market customers beginning December 1, 2001
pursuant to the Gas Restructuring Order; and lower firm delivery service total
margin due to lower delivery service volumes. Interruptible customers are those
who have the ability to switch to alternate fuels.
Gas Utility operating income declined $10.7 million in Fiscal 2002 reflecting
the previously mentioned decline in total system throughput
includes a 5.4 bcf increase in sales to core market customersmargin and a .7 bcf
increase in throughput to interruptible customers. Partially offsetting these
increases was a decrease in firm delivery service volumespension
income partially offset by lower
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operating expenses. Operating expenses declined $4.1 million primarily as a
result of customer switchinglower charges for uncollectible accounts and lower distribution system
expenses. Depreciation expense declined $1.2 million due to interruptible delivery service.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. The
increasedecline in Gas Utility income before income taxes reflects the decrease in
operating income offset by lower interest expense resulting from lower levels of
bank loans outstanding and lower short-term interest rates.
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 the beneficial effect on air conditioning sales of warmer
summer weather. Notwithstanding the decrease in total kilowatt-hour sales,
revenues reflects a $68.4increased $2.1 million principally due to an increase in revenues from core market customers (reflecting higherstate tax
surcharge revenue and greater third-party sales andof electricity produced by
UGID's 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 full-year
effectimpact of higher base rates), greater off-systemthe lower sales and lower refunds of
producer settlement charges. Cost of gas sold was $206.3 million during 1996, an
increase of $67.7 million from 1995, reflecting principallypurchased power
unit costs partially offset by the greater sales to
core market customers, higher off-system sales, and lower refunds of producer
settlement charges.
Thefull-period increase in Gas Utilitycost of sales
resulting from the December 2000 transfer of our Hunlock Creek electricity
generation assets to our electricity generation joint venture, Energy Ventures.
Subsequent to the formation of Energy Ventures, our electricity generating
business purchases its share of the power produced by Energy Ventures rather
than producing this electricity itself. As a result, the purchased cost of this
power is reflected in cost of sales whereas prior to the formation of Energy
Ventures electricity generation costs were reflected in operating and
administrative expenses.
Electric Operations total margin increased $4.2 million in 1996 reflects a $34.5 million
increase in total margin from core market customersFiscal 2002 as a
result of lower purchased power unit costs partially offset by the
colder
weatherweather-driven decline in sales. Operating income increased $2.5 million
reflecting the greater total margin and higher base rates. However,lower operating and administrative costs
subsequent to the formation of Energy Ventures partially offsettingoffset by a decline in
other income. The increase in Electric Operations income before income taxes
reflects the 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 operating 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. The increase in
the cost of sales resulted from higher sales and higher energy cost recoveries.
Electric Utility total margin 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 $3.9 million in
1996 compared with $6.6 million in 1995. The allocated UGI corporate expenses in
1996 were lower as a result of adjustments to incentive compensation accruals.
Other operating income in 1995 principally reflects income from the gas
marketing activities 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.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.1 million in 1996
compared with $16.8 million in 1995. The decrease in 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% from 11.99%.
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22expense.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities'Utilities total debt outstanding at September 30, 1997 totaled $236.3 million
compared with $227.2was $258.0 million at September 30, 1996. The increase principally
reflects an increase2003.
Included in borrowingsthis amount is $40.7 million under its revolving credit facilities.agreements.
Utilities has revolving credit agreements providing for borrowings ofcommitments under which it may borrow up to $82
million under committed lines througha
total of $107 million. These agreements are currently scheduled to expire in
June 30, 2000.2005 and 2006. The revolving credit agreements have restrictions on such
items as total debt, debt service and payments for investments. At September 30,
1997,
borrowings under its revolving credit agreements totaled $67 million.2003, Utilities alsowas in compliance with these covenants. Utilities has a shelf
registration for issuance from time to time ofstatement with the U.S. Securities and Exchange Commission under
which it may issue up to $75an additional $40 million of Medium-Term Notes or other
debt securities.
Dividend paymentsBased upon cash expected to UGI totaled $24.1 million in 1997 compared with $32.9
million in 1996. The Company intends to declare and pay dividends to UGI subject
to the availability of earnings and the cash needs of its businesses. In
addition, certain of Utilities' debt agreements contain limitations with respect
to incurring additional debt, require the maintenance of consolidated tangible
net worth, as defined, 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 of these provisions,
permitted future payments aggregate $149.4 million at September 30, 1997.
Management believes that cash flowbe generated from the Company's 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
operations and
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borrowings available under revolving credit agreements, management believes that
Utilities will be able to meet its anticipated contractual and projected cash
commitments during Fiscal 2004. For a more detailed discussion of Utilities'
long-term debt and credit facilities, see Note 3 to Consolidated Financial
Statements.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of Utilities' businesses, cash
flows from operating activities are generally strongest during the second and
third fiscal quarters when customers pay for natural gas and electricity
consumed during the years endedpeak heating season months. Conversely, operating cash flows
are generally at their lowest levels during the first and fourth quarters when
the Company's investment in working capital, principally accounts receivable and
inventories, is generally greatest. Utilities uses its revolving credit
agreements to satisfy its seasonal operating cash flow needs. Cash flow from
operating activities was $97.8 million in Fiscal 2003, $55.1 million in Fiscal
2002, and $76.1 million in Fiscal 2001. Cash flow from operating activities
before changes in operating working capital was $91.8 million in Fiscal 2003,
$78.4 million in Fiscal 2002, and $72.3 million in Fiscal 2001. Changes in
operating working capital provided $6.0 million of operating cash flow in Fiscal
2003, used $23.3 million of operating cash flow in Fiscal 2002, and provided
$3.8 million of operating cash flow in Fiscal 2001. The increase in Fiscal 2003
cash flow from operating activities principally reflects the increased operating
results and greater cash flow from changes in Gas Utility deferred fuel
overcollections and accrued income taxes partially offset by higher inventories
resulting from greater natural gas prices.
INVESTING ACTIVITIES. Cash flow used in investing activities was $43.1 million
in Fiscal 2003, $36.6 million in Fiscal 2002, and $44.2 million in Fiscal 2001.
Expenditures for property, plant and equipment were $41.3 million in Fiscal
2003, $35.9 million in Fiscal 2002, and $36.8 million in Fiscal 2001. The higher
Fiscal 2003 level of capital expenditures reflects greater Gas Utility
distribution system capital expenditures. Net costs of property, plant and
equipment disposals were also higher in Fiscal 2003 principally reflecting
greater gas main replacement activity.
FINANCING ACTIVITIES. Cash flow used by financing activities was $60.5 million
in Fiscal 2003, $20.1 million in Fiscal 2002, and $39.8 million in Fiscal 2001.
Financing activity cash flow changes are primarily due to issuances and
repayments of long-term debt, net borrowings under revolving credit facilities,
dividends on preferred shares subject to mandatory redemption and dividends to,
and capital contributions from, UGI.
In October 2002, Utilities repaid $26 million of maturing long-term debt. In
August 2003, Utilities issued $25 million face amount of ten-year notes at an
interest rate of 5.37% and $20 million face amount of 30-year notes at an
interest rate of 6.50% under its Medium-Term Note program. The net proceeds from
these issuances along with existing cash balances were used to repay $50 million
of 6.50% Senior Notes maturing in August 2003.
During Fiscal 2003 we paid cash dividends to UGI of $33.9 million and dividends
on our preferred shares subject to mandatory redemption of $1.6 million of which
$0.4 million has been classified as
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interest expense in accordance with Statement of Financial Accounting Standards
("SFAS") No. 150 (see "Recently Issued Accounting Pronouncements" below).
DIVIDEND OF UGID
In June 2003, the Company dividended all of the common stock of UGID, and UGID's
subsidiaries, to UGI. The net book value of the assets and liabilities of UGID
and its subsidiaries on the date of distribution totaling $15.4 million
(including $2.6 million of cash) has been eliminated from the consolidated
balance sheet. The results of operations of UGID and its subsidiaries through
the date of distribution did not have a material effect on the Company's net
income in Fiscal 2003, 2002 or 2001.
UTILITIES PENSION PLAN
UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI Utilities, UGI, and certain of UGI's other subsidiaries. During
Fiscal 2002 and 2001, the market value of plan assets was negatively affected by
declines in the equity markets. Equity market performance improved in Fiscal
2003 and, as a result, the fair value of Pension Plan assets increased to $183.8
million at September 30, 1997, 19962003 compared to $166.1 million at September 30, 2002.
At September 30, 2003 and 1995, as well as2002, the Pension Plan's assets exceeded its
accumulated benefit obligations by $7.3 million and $7.2 million, respectively.
The Company 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 2004.
Pre-tax pension income reflected in Fiscal 2003, 2002 and 2001 results was $1.2
million, $3.9 million and $5.7 million, respectively. The decrease in pension
income during this period reflects the significant declines in the market value
of Plan assets and decreases in the discount rate assumptions. Pension expense
in Fiscal 2004 is expected to be approximately $1.1 million, compared to pension
income of $1.2 million in Fiscal 2003 due to decreases in the discount rate and
expected return on Pension Plan assets assumptions.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for
Fiscal 2003, Fiscal 2002 and Fiscal 2001. We also provide amounts for fiscal 1998. Utilities expectswe expect to
spend in Fiscal 2004. We expect to finance 1998a substantial portion of Fiscal 2004
capital expenditures through internallyfrom cash generated cashby operations and the remainder from
borrowings under itsour credit facilities.
- --------------------------------------------------------------------------------
Year Ended September 30, 1998 1997 1996 19952004 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars) (estimate)
Gas Utility $ 37.338.0 $ 36.737.2 $ 34.631.0 $ 45.331.8
Electric Utility 5.94.9 4.1 4.9 5.0
5.0 5.9
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
$ 43.242.9 $ 41.741.3 $ 39.635.9 $ 51.236.8
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CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has certain contractual cash obligations that extend beyond Fiscal
2003 including scheduled repayments of long-term debt and redeemable preferred
stock, operating lease obligations and unconditional purchase obligations for
pipeline capacity, pipeline transportation and natural gas storage services, and
commitments to purchase natural gas and electricity. The following table
presents significant contractual cash obligations under agreements existing as
of September 30, 2003 (in millions).
Payments Due by Period
---------------------------------------------------
Less than 2 - --------------------------------------------------------------------------------3 4 - 5 After
Total 1 year years years 5 years
- -----------------------------------------------------------------------------------------------
Long-term debt $217.0 $ - $ 70.0 $ 20.0 $127.0
UGI Utilities preferred shares subject
to mandatory redemption 20.0 - 2.0 2.0 16.0
Operating leases 13.4 2.9 4.5 2.8 3.2
Gas Utility and Electric Utility supply,
storage and service contracts 406.9 157.1 136.0 39.8 74.0
- -----------------------------------------------------------------------------------------------
Total $657.3 $160.0 $212.5 $ 64.6 $220.2
- -----------------------------------------------------------------------------------------------
YEAR 2000 MATTERS
The CompanyRELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI
Utilities monthly for an allocated share of its general corporate expenses. This
allocation is currentlybased upon a three-factor formula which includes revenues, costs
and expenses, and net assets. These billed expenses totaled $9.4 million in
Fiscal 2003, $6.7 million in Fiscal 2002 and $5.3 million in Fiscal 2001 and are
classified as operating and administrative expenses - related parties in the
processConsolidated Statements of modifying certainIncome.
In accordance with the terms of its computer
software systems so that they will function properly inan Affiliated Interest Agreement ("Affiliated
Agreement") approved by the year 2000. ThePUC, Gas Utility enters into wholesale natural gas
transactions with Energy Services, Inc. ("Energy Services"), a wholly owned
second-tier subsidiary of UGI, for winter storage service and, from time to
time, purchases of natural gas. In addition, from time to time, the Company
doessells natural gas to Energy Services pursuant to the terms of the Affiliated
Agreement. These transactions did 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
resultsnet income during Fiscal 2003, 2002 and 2001. For additional information on
these transactions, see Note 13 to Consolidated Financial Statements included
elsewhere in this Form 10-K.
OFF-BALANCE SHEET ARRANGEMENTS
We lease various buildings and other facilities, transportation, computer and
office equipment. We account for these arrangements as operating leases. These
off-balance sheet arrangements enable us to lease facilities and equipment from
third parties rather than, among other options, purchasing the equipment and
facilities using on-balance sheet financing. For a summary of
operations.
-20--18-
23
CASH FLOWS
OPERATING ACTIVITIES. Utilities' operating cash flows are seasonalscheduled future payments under these lease arrangements, see "Contractual Cash
Obligations and are
generally greatest duringCommitments."
REGULATORY MATTERS
As a result of Pennsylvania's Natural Gas Choice and Competition Act ("Gas
Competition Act") signed into law on June 22, 1999, all natural gas consumers in
Pennsylvania have the winterability 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 spring whensuch sales
of gas, as well as distribution services provided by LDCs, continue to be
subject to rate regulation by the PUC. LDCs serve as the supplier of last resort
for all residential and small commercial and industrial customers. As of
September 30, 2003, less than five percent of Gas Utility's retail customers
pay heating bills
incurred duringpurchase their gas from alternative suppliers.
On June 29, 2000, the heating season. Accordingly,PUC issued its order ("Gas Restructuring Order") approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to the actualGas
Competition Act. Among other things, the implementation of the Gas Restructuring
Order resulted in an increase in Gas Utility's retail 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 Gas Restructuring Order, Gas Utility reduced its retail core-market PGC
rates by an annualized 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$16.7 million in 1997 compared with $57.0 million in 1996. Cash flowsthe first 14 months following
the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its retail
core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
retail core-market customers. As a result, Gas Utility 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 partresults are
more sensitive to the effects of lower noncash deferred tax expense in 1997. Changes in operating working capital
in 1997 provided $5.4 millionheating-season weather and less sensitive to
the market prices 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 millionalternative fuels.
The PUC approved a settlement establishing rules for Electric Utility Provider
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:
- ------------------------------------------------------------------------------------
Increase in Annual Revenues
Division Effective Date Requested Granted
- ------------------------------------------------------------------------------------
(Millions of dollars)
Electric Utility 7/19/96 $ 6.2 $ 3.1
Gas Utility 8/31/95 41.3 19.5
- ------------------------------------------------------------------------------------
CUSTOMER CHOICE ACT
On January 1, 1997, the Customer Choice Act became effective. The Customer
Choice 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 Choice Act requires all
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24
electric utilities to file restructuring plans with the PUC which, among other
things, include unbundled prices for electric generation, transmission and
distributionLast 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 generation 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 (1) were initially set at a level equal to the Customerrates paid by Electric
Utility customers for POLR service under the statutory rate caps; (2) may be
raised by up to 5% of the total rate for distribution, transmission and
generation 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
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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 certain circumstances,
be subject to generation rate surcharges. Consistent with the terms of the POLR
Settlement, Electric Utility's POLR rates for commercial and industrial
customers will increase beginning January 2004, and for residential customers
beginning June 2004. Also, Electric Utility has offered and entered into
multiple-year POLR contracts with certain of its customers. Additionally,
pursuant to the requirements of the Electricity Choice Act, the PUC is currently
developing post-rate cap POLR regulations that are expected to further define
post-rate cap POLR service obligations and pricing. As of September 30, 2003,
less than 1% of Electric Utility's ratescustomers have chosen an alternative
electricity generation supplier.
We account for transmissionthe operations of Gas Utility 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 the
generation component of prices as long as stranded costs are 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 Planaccordance
with the PUC.
The Restructuring Plan includes a claim for the recovery of $34.4 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, the
Company continues to evaluate its ability to apply the provisions of Statement
of Financial Accounting Standards (SFAS)SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71) as it relates to its electric generation
operations.("SFAS 71"). SFAS 71 permitsallows us to defer expenses and revenues on the recording of costs (regulatory assets)balance
sheet as regulatory assets and liabilities when it is probable that have
been, or are expected tothose
expenses and income will be allowed in the ratesettingratemaking process in a period
different from the period in which such coststhey would be charged to expense byhave been reflected in the income
statement of an unregulated enterprise. The Company believes its electric generationcompany. These deferred assets and relatedliabilities are
then flowed through the income statement in the period in which the same amounts
are included in rates and recovered from or refunded to customers. As required
by SFAS 71, we monitor our regulatory and competitive environments to determine
whether the recovery of our regulatory assets continuecontinues to satisfy the criteriabe probable. If we
were to determine that recovery of SFAS 71. If such
electric generationthese regulatory assets is no longer
meet the criteria of SFAS 71, any related
regulatoryprobable, such 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
-22-
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 regard to the proposed legislation.written off against earnings.
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 three
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.
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Management believes that under applicable law Utilities should not have significant liabilitybe liable in
those instances in which a former subsidiary owned or 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
directly owned or directly operated, or that were owned or operated by former
subsidiaries of -23-
26
Utilities, if a court were to conclude that (1) the subsidiary's
separate corporate form should be disregarded or (2) Utilities exercised substantial
control over such subsidiaries.
Management believes, after consultationshould be
considered to have been an operator because of its conduct with counsel, that future costs of
investigationrespect to its
subsidiary's MGP.
With respect to a manufactured gas plant site in Manchester, New Hampshire,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities
seeking contribution from UGI Utilities for response and remediation if any, willcosts
associated with the contamination on the site of a former MGP allegedly operated
by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth agreed to
a settlement of this matter in June 2003. UGI Utilities recorded its estimated
liability for contingent payments to EnergyNorth under the terms of the
settlement agreement which did not have a material effect on Fiscal 2003 net
income.
In April 2003, Citizens Communications Company ("Citizens") served a complaint
naming UGI Utilities as a third-party defendant in a civil action pending in
United States District Court for the District of Maine. In that action, the
plaintiff, City of Bangor, Maine ("City") sued Citizens to recover environmental
response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens' predecessors at a site on the Penobscot River. Citizens
subsequently joined UGI Utilities and ten other third-party defendants alleging
that the third-party defendants are responsible for an equitable share of costs
Citizens may be required to pay to the City for cleaning up tar deposits in the
Penobscot River. The City believes that it could cost as much as $50 million to
clean up the river. UGI Utilities believes that it has good defenses to the
claim.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI
Utilities with a complaint filed in the United States District Court for the
Middle District of Florida in which AGL alleges that UGI Utilities is
responsible for 20% of approximately $8.0 million incurred by AGL in the
investigation and remediation of a former MGP site in St. Augustine, Florida.
UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner
and operator of the MGP. UGI Utilities believes that it has good defenses to the
claim and is defending the suit.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed
suit against UGI Utilities in the United States District Court for the Southern
District of New York, seeking contribution from UGI Utilities for an allocated
share of response costs associated with investigating and assessing gas plant
related contamination at former MGP sites in Westchester County, New York. The
complaint alleges that UGI Utilities "owned and operated" the MGPs prior to
1904. The complaint also seeks a declaration that UGI Utilities is responsible
for an allocated percentage of future investigative and remedial costs at the
sites. ConEd believes that the cost of remediation for all of the sites could
exceed $70 million. UGI Utilities believes that it has good defenses to the
claim and is defending the suit. In November 2003, the court granted UGI
Utilities' motion for summary judgment in part, dismissing all claims premised
on a disregard of the separate corporate form of UGI Utilities' former
subsidiaries and dismissing claims premised on UGI Utilities' operation of three
of the MGPs under operating leases with
-21-
ConEd's predecessors. The court reserved decision on the remaining theory of
liability, that UGI Utilities was a direct operator of the remaining MGPs.
MARKET RISK DISCLOSURES
Gas Utility's tariffs contain clauses that permit recovery of substantially all
of the prudently incurred costs of natural gas it sells to its customers. The
recovery clauses provide for a periodic adjustment for the difference between
the total amounts actually collected from customers through PGC rates and the
recoverable costs incurred. Because of this ratemaking mechanism, there is
limited commodity price risk associated with our Gas Utility operations. Gas
Utility uses exchange-traded natural gas call option contracts to reduce
volatility in the cost of gas it purchases for its retail core-market customers.
The cost of these call option contracts, net of associated gains, is included in
Gas Utility's PGC recovery mechanism.
Prior to September 2002, 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 third-party power supply arrangements of
various lengths and on the spot market. Beginning September 2002, Electric
Utility began purchasing its power needs exclusively from third-party
electricity suppliers under fixed-price energy and capacity contracts and, to a
much lesser extent, on the spot market and UGID, through the date of its
transfer to UGI in June 2003, began selling electric power produced from its
interests in electricity generating facilities to third parties on the spot
market. 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 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 2003 and Fiscal 2002, an
increase in short-term interest rates of 100 basis points (1%) would have
increased annual interest expense by $0.3 million and $0.5 million,
respectively.
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 $14.0 million and $11.0 million at
September 30, 2003 and 2002, respectively. A 100 basis point
-22-
decrease in market interest rates would result in increases in the fair value of
this fixed-rate debt of $15.7 million and $12.0 million at September 30, 2003
and 2002, 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 unsettled interest rate protection agreement, which has been
designated and qualifies as a cash flow hedge, was $0.4 million at September 30,
2003. An adverse change in interest rates on ten-year U.S. treasury notes of 50
basis points would result in a $0.4 million decrease in the fair value of this
interest rate protection agreement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with generally accepted accounting principles requires the selection and
application of appropriate accounting principles to the relevant facts and
circumstances of the Company's operations and the use of estimates made by
management. The Company has identified the following critical accounting
policies that are most important to the portrayal of the Company's financial
condition and results of operations. Changes in these policies could have a
material effect on the Company's financial position butstatements. The application of these accounting
policies necessarily requires management's most subjective or complex judgments
regarding estimates and projected outcomes of future events which could behave a
material to operating results
and cash flows dependingimpact on the naturefinancial statements. Management has reviewed these
critical accounting policies, and timingthe estimates and assumptions associated with
them, with its Audit Committee. In addition, management has reviewed the
following disclosures regarding the application of future developmentsthese critical accounting
policies with the Audit Committee.
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 present. In accordance with accounting
principles generally accepted in the United States of America, we establish
reserves for pending claims and legal 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 a broad range of information and prior 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. Becauseequipment could have a
material effect on our results of operations.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's
base ratesdistribution businesses are capped and Gas Utility's base rates can be adjusted
only through general rate filingssubject to regulation by the Pennsylvania Public
Utility Commission. In accordance with SFAS
-23-
No. 71, "Accounting for 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
costsEffects of purchased gas, fuel and power which comprise a substantial portionCertain Types of Gas Utility's costs and expenses.
The Company attempts to limitRegulation," we record
the effects of inflation on itsrate 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 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 through cost control efforts, productivity improvementsoperations. As of September 30, 2003, our regulatory
assets totaled $60.3 million.
DEFINED BENEFIT PENSION PLAN. The costs of providing benefits under our Pension
Plan are dependent on historical information such as employee age, length of
service, level of compensation and with
respectthe actual rate of return on plan assets. In
addition, certain assumptions relating to Gas Utility, timelythe future are utilized including, the
discount rate relief.applied to benefit obligations, the expected rate of return on
plan assets and the rate of compensation increase. Pension Plan assets are held
in trust and consist principally of equity and fixed income mutual funds and a
commingled bond fund. Changes in plan assumptions as well as fluctuations in
actual equity or bond market returns could have a material impact on future
pension costs.
RECENTLY ISSUED ACCOUNTING PRINCIPLES NOT YET ADOPTEDPRONOUNCEMENTS
In October 1996,April 2003, the American InstituteFASB issued SFAS No. 149, "Amendment of Certified Public Accountants issued
Statement of Position No. 96-1, "Environmental Remediation Liabilities" (SOP
96-1)133 on
Derivative Instruments and Hedging Activities" ("SFAS 149"). SOP 96-1 provides guidance on the recognition, measurement, display and
disclosure of environmental remediation liabilities. SOP 96-1,SFAS 149 is
effective for contracts entered into or modified after June 30, 2003 and for
hedging relationships designated after June 30, 2003. SFAS 149 (1) clarifies
under what circumstances a contract with an initial net investment meets the
characteristic of a derivative, (2) clarifies when a derivative contains a
financing component, (3) amends the definition of an underlying- rate, price or
index to conform it to language used in FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," and (4) amends certain other existing
pronouncements. SFAS 149 did not change the methods the Company uses to account
for and report its derivatives and hedging activities.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150").
SFAS 150 is effective at the beginning of the first interim period beginning
after June 15, 2003. SFAS 150 establishes guidelines on how an issuer classifies
and measures certain financial instruments with characteristics of both
liabilities and equity. SFAS 150 further defines and requires that certain
instruments within its scope be classified as liabilities on the financial
statements. The adoption of SFAS 150 resulted in the Company presenting its
preferred shares subject to mandatory redemption in the liabilities section of
the balance sheet, and reflecting dividends paid on these shares as a component
of interest expense, for periods presented after June 30, 2003. Because SFAS 150
specifically prohibits the restatement of financial statements prior to its
adoption, prior period amounts have not been reclassified.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective
immediately for variable interest
-24-
entities created or obtained after January 31, 2003. For variable interests
created or acquired before February 1, 2003, FIN 46 is effective for the first
fiscal yearsor interim period beginning after December 15, 1996.2003. If certain
conditions are met, FIN 46 requires the primary beneficiary to consolidate
certain variable interest entities in which the other equity investors lack the
essential characteristics of a controlling financial interest or their
investment at risk is not sufficient to permit the variable interest entity to
finance its activities without additional subordinated financial support from
other parties. The adoption of SOP 96-1 in
fiscal 1998FIN 46 is not expected to have a material effect onimpact the Company's
financial position or results of operations.
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 them 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) 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 reflectstatement whether as a result of new
information or future events or
circumstances afterexcept as required by federal securities laws.
-25-
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-28 and page S-1 of this Report 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.
PART III: UGI UTILITIES MANAGEMENTMay 21, 2002.
ITEM 9A. CONTROLS AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
Utilities
Director Principal Occupation
Name Age SincePROCEDURES
(a) Evaluation of Disclosure Controls and Other Directorships (1)
- ---- --- ----- ---------------------------
Lon R. Greenberg 47 1994 Chairman of the Company (since August
1996); 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.
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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.;Procedures
The Guardian Life Insurance Company
of America.
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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 Vice
President Research and Development,
Bituminous Materials, 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 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).
(1) With the exception of Mr. Bunn, all of the directors serve as directors of
UGI. Messrs. Greenberg, Forney, Stratton and Wang also serve as directors of
AmeriGas Propane, Inc., the General Partner of AmeriGas Partners, L.P.
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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
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.
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.
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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 (since August 1996), President and Chief Executive
Officer of AmeriGas Propane, Inc. (since July 1996). Mr. Greenberg previously
served as Senior Vice President-Legal and Corporate Development of UGI (1989 to
1994).
Richard L. Bunn
Mr. Bunn is President and Chief Executive Officer of the Company (since
May 1992). Mr. Bunn began his careerCompany's management, with the Company as an engineer in the
Electric Utility Division in 1958, and successively held various operating and
staff positions.
Robert J. Chaney
Mr. Chaney is Vice President and General Manager-Gas Utility Divisionparticipation of
the Company (since 1991). He previously served as Vice President-Rates and
Energy Utilization of the Company's Gas Utility Division (1981 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).
John C. Barney
Mr. Barney is Vice President-Finance and Accounting of Utilities (since
April 1992). Previously, Mr. Barney served as Vice President-Finance of the
Company's Gas Utility Division (1987 to April 1992).
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 Vice President,
General Counsel and Secretary of Orion Pictures Corporation (1990 to 1991).
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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 eachChief Financial Officer, evaluated the effectiveness of
the four other most highly
compensated executive officers (collectively, the "Named Executives") for the
last three fiscal years.
===================================================================================================================================
SUMMARY COMPENSATION TABLE
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Compensation
- -----------------------------------------------------------------------------------------------------------------------------------
Annual Compensation
Awards Payouts
- -----------------------------------------------------------------------------------------------------------------------------------
Securities
Other Underlying Long-Term All Other
Annual Options/SARs Incentive Compensation
Name and Year Salary ($) Bonus Compensation Granted Payouts ($) (3)
Principal Position ($) (1) ($) (2) (#) ($)
===================================================================================================================================
Lon R. Greenberg (4) (5) 1997 $509,827 $425,000 $7,671 200,000 (6) $0 $ 14,233
Chairman 1996 $465,000 $122,760 $7,359 0 $0 $ 10,462
1995 $381,923 $ 0 $7,365 14,167 (7) $0 $ 11,439
- -----------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn (5) 1997 $318,089 $139,073 $7,696 75,000 (6) $0 $ 10,254
President and Chief 1996 $305,900 $137,655 $5,855 0 $0 $ 10,579
Executive Officer 1995 $305,900 $164,268 $6,684 0 $0 $ 9,732
- -----------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney
Vice President & 1997 $164,396 $ 51,457 $4,272 35,000 (6) $0 $ 4,921
General Manager, 1996 $156,601 $ 54,321 $4,019 0 $0 $ 5,074
Gas Utility Division 1995 $156,429 $ 68,904 $2,757 0 $0 $ 4,579
- -----------------------------------------------------------------------------------------------------------------------------------
Mark R. Dingman
Vice President & 1997 $125,298 $ 26,322 $6,410 35,000 (6) $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
Vice President and 1996 $149,999 $ 21,853 $1,299 0 $0 $ 1,363
General Counsel 1995 $ 66,346 $ 8,663 $ 0 10,000 (7) $0 $ 0
===================================================================================================================================
(1) Bonuses earned under the UGI CorporationCompany's disclosure controls and UGI Utilities, Inc. Annual
Bonus Plans are for the year reported, regardlessprocedures as of the year paid. The
Annual Bonus Plans are 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 1997 ranged
from 0% to 148% of base salary for Mr. Greenberg, 0% to 52% for Mr. Bunn,
from 0% up to 38% for Mr. Chaney, from 0% to 30% for Mr. Dingman, and from
0% to 65% for Mr. Bovaird.
(2) Amounts represent tax payment reimbursements for certain benefits.
(3) Amounts represent matching contributions by the Company or UGI in
accordance with the provisionsend of the UGI Utilities, Inc. Employee Savings
Plan and/or allocations under the Executive Retirement Plan. During 1997,
1996 and 1995, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: For Messrs. Greenberg,
Bunn, Chaney and Dingman, $3,375, $3,375 and $3,375; and Mr. Bovaird,
-30-
33
$3,375, $1,363 and $0; and (ii) under the Supplemental Executive Retirement
Plan: Mr. Greenberg, $10,858, $7,087 and $8,064; Mr. Bunn, $6,879, $7,204
and $6,357; Mr. Bovaird $821, $0 and $0; Mr. Chaney, $1,546, $1,699 and
$1,204; Mr. Dingman, $274, $0 and $118.
(4) Mr. Greenberg was elected Chairman, UGI Utilities, Inc. effective August 1,
1996. 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) Compensation reported for Messrs. Greenberg, Bovaird and Bunn is also
reported in the Proxy Statement for UGI's 1998 Annual Meeting of
Shareholders and is not additive.
(6) Non-qualified stock options granted on December 10, 1996 under the UGI 1997
Stock Option and Dividend Equivalent Plan (the "1997 Plan"). The 1997 Plan
consists of non- qualified stock option grants and the opportunity for
participants to earn an amount equivalent to the dividends paid on sharesperiod
covered by options, subject to a comparison of the total return realizable
on a share of UGI's Common Stock ("UGI's Return") with the total return
achieved by each member 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 changes 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 YEAR
The following table shows information on grants of stock options during
fiscal year 1997 to each of the Named Executives.
- -------------------------------------------------------------------------------------------------------------------------------
OPTION GRANTS IN LAST FISCAL YEAR
- -------------------------------------------------------------------------------------------------------------------------------
INDIVIDUAL GRANTS GRANT DATE
VALUE
- -------------------------------------------------------------------------------------------------------------------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO EXERCISE
OPTIONS EMPLOYEES IN OR BASE EXPIRATION GRANT DATE
NAME GRANTED (1) FISCAL YEAR (2) PRICE DATE PRESENT VALUE (3)
- -------------------------------------------------------------------------------------------------------------------------------
Lon R. Greenberg 200,000 45% $22.625 12/09/06 $ 486,000
- -------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn 75,000 17% $22.625 12/09/06 $ 182,250
- -------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney 35,000 8% $22.625 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------
Mark R. Dingman 35,000 8% $22.625 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------
Brendan P. Bovaird 30,000 7% $22.625 12/09/06 $ 72,900
===============================================================================================================================
(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 445,000 options were granted to employees and executive officers
of the Company during fiscal year 1997 under the 1997 SODEP and the 1992
Non-Qualified Stock Option Plan. Under the 1992 Non-Qualified Stock Option
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 vested on the date of grant. 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)this report. 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 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%
- - Discount of risk of forfeiture - 0%
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 upon retirement at age 65
in 1997 applicable for various combinations of final average earnings and length
of service which may be payable under the Retirement Income Plan for Employees
of UGI Utilities, Inc. and participating employers (the "Retirement Plan") and
the UGI Supplemental Executive Retirement Plan.
=============================================================================================================================
PENSION PLAN BENEFITS
- -----------------------------------------------------------------------------------------------------------------------------
FINAL 5-
YEAR
AVERAGE ANNUAL BENEFIT FOR YEARS OF CREDITED SERVICE SHOWN (1)
ANNUAL
EARNINGS (2)
----------------------------------------------------------------------------------------------------------
15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS 40 YEARS
=============================================================================================================================
$100,000 $28,500 $38,000 $47,500 $57,000 $66,500 $68,400 (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 $114,000 $152,000 $190,000 $228,000 $266,000 $273,600 (3)
$500,000 $142,500 $190,000 $237,500 $285,000 $332,500 $342,000 (3)
$600,000 $171,000 $228,000 $285,000 $342,000 $399,000 $410,400 (3)
$700,000 $199,500 $266,000 $332,500 $399,000 $465,500 $478,800 (3)
$800,000 $228,000 $304,000 $380,000 $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 $285,000 $380,000 $475,000 $570,000 $665,000 $684,000 (3)
$1,200,000 $342,000 $456,000 $570,000 $684,000 $798,000 $820,800 (3)
$1,400,000 $399,000 $532,000 $665,000 $798,000 $931,000 $957,600 (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, Chaney, Dingman and Bovaird had, respectively, 17 years, 39 years, 33
years, 24 years and 2 years of estimated credited service at September 30,
1997.
-35-
38
(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.
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, Dingman and Ladner 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 sum cash payment in an amount
approximately equal to the sum of (i) three months of compensation (18 months in
the case of Mr. Greenberg), (ii) a pro rata portion of the senior executive's
annual target bonus under the Annual Bonus Plan for the current year, provided
that the employment termination date occurs during the first ten months of the
fiscal year, or, if the employment termination date occurs during the last two
months of the fiscal year, andevaluation, the Chief Executive Officer
determines not to use
his discretion to pay a pro-rata portionand Chief Financial Officer concluded that the Company's disclosure controls and
procedures as of the executive's annual target bonus,
the full bonus payable after the end of the fiscal year, assumingperiod covered by this report were designed and
functioning effectively to provide reasonable assurance that (x) the weightinginformation
required to be applied todisclosed by the business/financial performance goalsCompany in reports filed under the Securities
Exchange Act of 1934, as amended, is 100%,recorded, processed, summarized and
(y)reported within 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. Certain employee benefits are continued for
atime periods specified period (the "Employee Benefit Period") not exceeding 15 months (30
months in the caseSEC's rules and forms. The
Company believes that a controls system, no matter how well designed and
operated, cannot provide absolute assurance that the objectives of Mr. Greenberg) after termination, or the senior executive
may be paidcontrols
system are met, and no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within a lump sum equal to the present value of such 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 maycompany 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 cooperatebeen detected.
(b) Change in attending to matters pending at the time of his or her termination of
employment.
-36-Internal Control over Financial Reporting
-26-
39
CHANGE OF CONTROL ARRANGEMENTS
The Named Executives each have an agreement with UGI Corporation (the
"Agreement") which provides certain benefitsNo change in the event of a change ofCompany's internal control of UGI. The Agreements operate independently of the UGI Severance Plan, continue
through July 2002, 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 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; (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; or (iv) UGI is liquidated
or dissolved.
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
receive
-37-
40
an additional amount, such that the net amount retained after payment of
applicable taxes is equal to the severance total compensation payable.
BOARD OF DIRECTORS
Messrs. Bunn 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 ofover financial reporting occurred
during the Company's Board of
Directors also serve on the UGI Board and receive no additional compensation for
service onmost recent fiscal quarter that has materially affected, or
is reasonably likely to materially affect, 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., and David I. J. Wang.
-38-internal control over
financial reporting.
-27-
41
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
At December 9, 1997, UGI Corporation held 100% of the Company's Common
Stock. UGI is located at 460 N. Gulph Road, King of Prussia, PA 19406.
The following table sets forth, as of December 9, 1997, 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%
of UGI's Common Stock. All other directors, Named Executives and executive
officers own less than 1% of UGI's outstanding shares. The total number of
shares beneficially owned by the directors and executive officers as a group
(including 630,859 shares subject to options exercisable within 60 days),
represents approximately 2.7% of UGI's outstanding shares.
NUMBER OF
SHARES AND
NATURE OF
BENEFICIAL NUMBER
OWNERSHIP OF
EXCLUDING STOCK
NAME OF BENEFICIAL OWNER OPTIONS (1)(2) OPTIONS TOTAL
- ------------------------ -------------- ------- -----
Stephen D. Ban 8,705 (3) 3,400 12,105
Brendan P. Bovaird 8,147 (4) 40,000 48,147
Richard L. Bunn 62,600 (5) 75,000 137,600
Robert J. Chaney 9,720 (6) 149,500 159,220
Mark R. Dingman 358 35,000 35,358
Robert C. Forney 12,186 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 25,894
All directors and executive
officers as a group (13) 210,019 630,859 879,363
- --------------------
(1) This column shows shares held in the individual's name,
individually 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-PART III: INTENTIONALLY OMITTED
-28-
42
(2) Included in the number of shares shown above are Deferred Units ("Units")
acquired through the 1997 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. Stratton (7,351 Units), Forney (7,358
Units), Wang (6,466 Units), Gozon (5,340 Units), Smith (5,643 Units), Ban
(3,424 Units) and Mrs. Pol (2,923 Units).
(3) Shares are held jointly with Dr. Ban's spouse.
(4) Includes the number of shares represented by units held in the UGI Stock
Fund of the 401(k) Employee Savings Plan.
(5) Includes 45,092 shares held jointly with Mr. Bunn's spouse and 2,000 shares
held directly by his spouse.
(6) Includes 2,561 shares held jointly with Mr. Chaney's spouse.
(7) Includes 72,759 shares held jointly with Mr. Greenberg's spouse.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 1997 UGI allocated $5,554,727, representing 42% of its
general corporate expenses, to Utilities.
-40-
43
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 14.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(a)(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, 19972003 and 19962002
Consolidated Statements of Income for the
fiscal years ended September 30, 1997, 19962003, 2002
and 19952001
Consolidated Statements of Cash Flows for
the fiscal years ended September 30, 1997, 19962003,
2002 and 19952001
Consolidated Statements of Stockholders'
Equity for the fiscal years ended September
30, 1997, 19962003, 2002 and 19952001
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULES
II-ValuationSCHEDULE:
For the years ended September 30, 2003, 2002 and 2001
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.
-41-in this report.
NOTICE REGARDING ARTHUR ANDERSEN LLP
Arthur Andersen 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 Andersen 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
-29-
44
(3)securities. 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.
(4) 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 3.2amended through September
26, 1995 (9/30/95)
- -------------------------------------------------------------------------------------------------------------------------------30, 2003
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 UGI Form 10-K (4)e
Union National Bank (formerly, First (9/30/93)
Fidelity Bank, N.A. Pennsylvania,)
Trustee, dated as of August 1, 1993 and
related 6.5% Note due 2003.[Intentionally omitted]
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)
-30-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ---------------------------------------------------------------------------------------------------------------
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)
4.8 [Intentionally omitted]
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
ParagraphP. 61,060 (1993), order on rehearing, 64 FERC
ParagraphFERCP. 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
ParagraphP. 61,060 (1993), order on rehearing, 64 FERC ParagraphFERCP. 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 ParagraphFERCP. 61,060 (1993), order on
rehearing, 64 FERC ParagraphFERCP. 61,365 (1993)
- ----------------------------------------------------------------------------------------------------------------------------------10.4** UGI Corporation 1992 Directors' Stock Plan Amended and UGI Form 10-Q 10.2
Restated as of April 29, 2003 (3/31/03)
-44--31-
47
==============================================================================================================================
INCORPORATION BY REFERENCE
==============================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
==============================================================================================================================- ---------------------------------------------------------------------------------------------------------------
10.4** UGI Corporation 1992 Directors' UGI Form 10-Q (10)ff
Stock Plan (6/30/92)
10.5** UGI Corporation DirectorsDirectors' Deferred Compensation Plan UGI Form 10-K 10.39
Compensation Plan dated August 26,10.6
Amended and Restated as of January 1, 2000 (9/30/94)
199300)
10.6** UGI Corporation Directors' Equity Compensation Plan UGI Form 10-Q 10.1
Compensation Plan10.3
Amended and Restated as of April 29, 2003 (3/31/97)03)
10.7** UGI Corporation 1992 Stock Option UGI Form 10-Q (10)ee
and Dividend Equivalent Plan, as (6/30/92)
amended May 19, 1992[Intentionally omitted]
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 Plan dated March 8, Utilities Form 10-Q 10.4
Plan dated March 8, 1996 (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 Employee Severance UGI Form 10-K 10.12
Employee Severance Pay Plan (9/30/97) effective January 1, 1997 (9/30/97)
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, UGI Form 10-K 10.39
as amended (9/30/00)
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-Q 10.1
Amended and Restated as of April 29, 2003 (3/31/03)
10.14** UGI Corporation 2000 Stock Incentive Plan Amended and UGI Form 10-Q 10.5
Restated as of April 29, 2003 (3/31/03)
10.15 Service Agreement for comprehensive delivery service UGI Form 10-K 10.41
(Rate CDS) dated February 23, 1999 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
10.16** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.4
Equivalent Plan Amended and Restated as of April 29, (3/31/03)
2003
10.17** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10
Amended and Restated effective October 1, 1996 (6/30/98)
10.18** UGI Corporation 1992 Non-Qualified Stock Option Plan UGI Form 10-Q 10.3
Amended and Restated as of April 29, 2003 (3/31/03)
*10.19** UGI Utilities, Inc. Severance Plan for Exempt
Employees in Salary Grades 34-37 and Salary Grades
18-23 effective January 1, 1999
10.20** Description of Change of Control arrangements for Mr. UGI Form 10-K 10.33
Greenberg (9/30/99)
*10.21** Change of Control Agreement UGI Form 10-K 10.13
between UGI Corporation and Lon (9/30/97)
R. Greenberg
10.13*for Mr. Chaney
*10.22** Form of Change of Control Agreement UGI Form 10-K 10.14
between UGI Corporationfor executive
officers other than Messrs. Chaney and Mr. Bunn (9/30/97)
- --------------------------------------------------------------------------------------------------------------------------------Greenberg
10.23 [Intentionally omitted]
-45--32-
48
===================================================================================================================================
INCORPORATION BY REFERENCE
===================================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
===================================================================================================================================- ----------- -------------------------------------------------- ---------- --------- -------
10.14** Form of Change of Control10.24 [Intentionally omitted]
10.25 Storage Transportation Service Agreement UGI(Rate Utilities Form 10-K 10.1510.25
Schedule SST) between UGI CorporationUtilities and eachColumbia dated (9/30/02)
November 1, 1993, as modified pursuant to orders
of Corporation (9/30/97)
Messrs. Chaney, Dingman and Bovaird
10.15** UGI Corporation 1992 Non-Qualified AmeriGasthe Federal Energy Regulatory Commission
10.26 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.19
Stock Option Plan Partners, L.P.10.26
Schedule NTS) between Utilities and Columbia dated (9/30/95)
10.16** Amendment No.02)
November 1, 1993, as modified pursuant to UGI Corporation UGIorders
of the Federal Energy Regulatory Commission
10.27 No-Notice Transportation Service Agreement (Rate Utilities Form 10-Q 10
1992 Non-Qualified Stock Option Plan (6/10-K 10.27
Schedule CDS) between Utilities and Texas Eastern (9/30/97)
10.17** UGI Corporation 1997 Stock Option UGI02)
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 Utilities Form 10-Q 10.210-K 10.28
Schedule CDS) between Utilities and Dividend Equivalent Plan (3/31/97)
- -----------------------------------------------------------------------------------------------------------------------------------Texas Eastern (9/30/02)
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.29 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.29
Schedule FT-1) between Utilities and Texas Eastern (9/30/02)
Transmission dated June 15, 1999, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.30 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.30
Schedule FT-1) between Utilities and Texas Eastern (9/30/02)
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.31 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.31
Schedule FT) between Utilities and Transcontinental (9/30/02)
Gas Pipe Line dated October 1, 1996, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*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. 1*14 Code of Ethics for principal executive, financial
and accounting officers
*23 Consent of PricewaterhouseCoopers LLP
*31.1 Certification by the Chief Executive Officer
relating to the Registrant's Report on Form 8-K/A10-K
for the year ended September 30, 2003 pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
-33-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------- ---------- --------- -------
*31.2 Certification by the Chief Financial Officer
relating to the Registrant's Report on Form 8-K dated July 11, 1997
- -----------------------------------------------------------------------------------------------------------------------------------
*23.1 Consent10-K
for the year ended September 30, 2003 pursuant to
Section 302 of Arthur Andersen LLP
*23.2 Consentthe Sarbanes-Oxley Act of Coopers & Lybrand L.L.P.
*272002
*32 Certification by the Chief Executive Officer and
the Chief Financial Data Schedule
*99 Cautionary Statements Affecting
Forward-looking Information
===================================================================================================================================Officer relating to the
Registrant's Report on Form 10-K for the fiscal
year ended September 30, 2003
* 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 filedfurnished information in a Current Report on Form 8-K
dated July 11, 1997, consistingduring the fourth quarter of Items 4
and 7; and Amendment No. 1 on
-46-fiscal year 2003 as follows:
Date of Report Item Number(s) Content
- -------------- -------------- -------
07/30/03 7, 12 Press Release reporting financial results for the
third fiscal quarter ended June 30, 2003
-34-
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, 19972003 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, 19972003 by the following persons
on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Richard L. Bunn President and Chief
- ----------------------- Executive Officer
Richard L. Bunn (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- -----------------------
Lon R. Greenberg
John C. Barney Vice President -
- ----------------------- Finance and Accounting
John C. Barney (Principal Financial
Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- -----------------------
Stephen D. Ban
Robert C. Forney Director
- -----------------------
Robert C. Forney
-48-
SIGNATURE TITLE
--------- -----
Robert J. Chaney President and Chief
- --------------------------- Executive Officer
Robert J. Chaney (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- ---------------------------
Lon R. Greenberg
John C. Barney Senior Vice President -
- --------------------------- Finance
John C. Barney (Principal Financial
Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- ---------------------------
Stephen D. Ban
Thomas F. Donovan Director
- ---------------------------
Thomas F. Donovan
-35-
51
SIGNATURE TITLE
--------- -----
Richard C. Gozon Director
- ---------------------
Richard C. Gozon
Director
- ---------------------
Anne Pol
Quentin I. Smith, Jr. Director
- ---------------------
Quentin I. Smith, Jr.Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below on December 16, 2003 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
Marvin O. Schlanger Director
- ---------------------------
Marvin O. Schlanger
James W. Stratton Director
- ---------------------------
James W. Stratton
Director
- ---------------------
James W. Stratton
David I. J. Wang Director
- ---------------------
David I. J. Wang
-49-
-36-
52
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
12.1 Computation of Ratio of EarningsSUPPLEMENTAL 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 Fixed Charges
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
13 Amendment No. 1 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
Informationsecurity holders in fiscal year
2003.
53
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 19972003
F-1
54
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
Pages
-----------------
Financial Statements:
Reports of Independent Public AccountantsAuditors F-3 andto F-4
Consolidated Balance Sheets as of September 30,
19972003 and 19962002 F-5 andto F-6
Consolidated Statements of Income for the years
ended September 30, 1997, 19962003, 2002 and 19952001 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 1997, 19962003, 2002 and 19952001 F-8
Consolidated Statements of Stockholders'Stockholder's Equity
for the years ended September 30, 1997, 19962003, 2002 and 19952001 F-9
Notes to Consolidated Financial Statements F-10 to F-28
Financial Statement Schedule:
For the years ended September 30, 1997, 19962003, 2002 and 1995:2001:
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 AUDITORS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
In our opinion, the consolidated financial statements 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, 2003 and 2002, and the results of their operations and their cash flows for
each of the two years in the period ended September 30, 2003 in conformity with
accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the index
appearing under Item 15a (1) and (2) 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 audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The consolidated financial
statements of UGI Utilities, Inc. and its subsidiaries as of and for the year
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 17, 2003
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
-------- --------2003 2002
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents (note 1) $ 12,813304 $ 3,1006,090
Accounts receivable (less allowances for doubtful
accounts of $3,333$3,275 and $3,976,$1,972, respectively) 25,309 26,28830,101 38,554
Accrued utility revenues (note 1) 7,688 8,6127,431 8,069
Inventories (notes 1 and 6) 30,645 30,03554,017 38,654
Deferred income taxes (notes 1 and 4) 7,179 6,31610,375 2,610
Income taxes recoverable - 6,892
Deferred fuel costs - 4,304
Prepaid expenses and other current assets 4,653 1,920
-------- --------5,552 3,151
--------- ---------
Total current assets 88,287 76,271107,780 108,324
Property, plant and equipment
(notes 1 and 3):
Gas utility 637,943 605,150791,164 760,161
Electric utility 118,808 114,915operations 103,917 111,265
General 8,897 9,794
-------- --------
765,648 729,85912,777 11,909
--------- ---------
907,858 883,335
Less accumulated depreciation and amortization 237,293 222,559
-------- --------(296,871) (290,194)
--------- ---------
Net property, plant and equipment 528,355 507,300610,987 593,141
Regulatory income tax asset (notes 1 and 4) 44,438 42,908assets 60,253 57,685
Other assets 20,298 23,420
-------- --------30,028 38,973
--------- ---------
Total assets $681,378 $649,899
======== ========$ 809,048 $ 798,123
========= =========
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
-------- --------2003 2002
--------- ---------
LIABILITIES AND STOCKHOLDERS'STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt (note 3) $ 17,143- $ 25,543
Current portion of preferred stock (note 7) 3,000 --76,000
Bank loans (note 3) 67,000 50,50040,700 37,200
Accounts payable 45,367 39,51755,298 57,499
Employee compensation and benefits accrued 8,207 8,2108,457 8,984
Dividends and interest accrued 3,692 4,9756,466 5,443
Income taxes accrued 5,071 5,302479 -
Customer deposits and refunds 15,074 14,515
Deferred fuel costs 14,734 -
Other current liabilities 26,621 22,882
-------- --------11,703 16,576
--------- ---------
Total current liabilities 176,101 156,929152,911 216,217
Long-term debt (note 3) 152,151 151,111217,271 172,369
Deferred income taxes (notes 1 and 4) 99,868 95,452144,176 131,483
Deferred investment tax credits (notes 1 and 4) 10,376 10,7757,987 8,385
Other noncurrent liabilities 10,201 11,004
Commitments and contingencies (note 8)11,951 11,815
Preferred stockshares subject to mandatory redemption, without par value 20,000 -
Commitments and contingencies (note 7) 32,187 35,1878)
--------- ---------
Total liabilities 554,296 540,269
Preferred shares subject to mandatory redemption, without par value - 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 68,05279,046 73,057
Retained earnings 71,986 61,130
-------- --------117,496 107,312
Accumulated other comprehensive loss (2,049) (2,774)
--------- ---------
Total common stockholder's equity 200,494 189,441
-------- --------254,752 237,854
--------- ---------
Total liabilities and stockholders'stockholder's equity $681,378 $649,899
======== ========$ 809,048 $ 798,123
========= =========
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 19952003 2002 2001
--------- --------- ---------
Revenues (note 1) $ 461,208636,758 $ 460,496490,552 $ 357,364584,762
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power (note 1) 238,978 239,643 169,694392,901 290,282 374,781
Operating and administrative expenses 117,874 119,432 108,51491,947 80,910 88,310
Operating and administrative expenses - related parties (note 13) 5,555 3,850 6,5859,352 6,664 5,277
Taxes other than income taxes 12,195 11,930 9,182
Depreciation and amortization (note 1) 21,431 21,602 19,754
Miscellaneous21,240 22,172 23,767
Other income, net (note 10) (2,777) (1,842) (3,780)(8,745) (11,723) (15,111)
--------- --------- ---------
381,061 382,685 300,767518,890 400,235 486,206
--------- --------- ---------
Operating income 80,147 77,811 56,597117,868 90,317 98,556
Interest expense 16,872 16,094 16,83817,656 16,652 18,988
--------- --------- ---------
Income before income taxes 63,275 61,717 39,759100,212 73,665 79,568
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)39,540 29,570 31,431
--------- --------- ---------
Net income 38,711 38,348 26,99060,672 44,095 48,137
Dividends on preferred stock 2,764 2,765 2,778shares subject to mandatory redemption 1,163 1,550 1,550
--------- --------- ---------
Net income after dividends on preferred stockshares subject to
mandatory redemption $ 35,94759,509 $ 35,58342,545 $ 24,21246,587
========= ========= =========
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 19952003 2002 2001
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,71160,672 $ 38,34844,095 $ 26,99048,137
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 21,431 21,602 19,75421,240 22,172 23,767
Deferred income taxes, net 549 7,481 2,3692,097 11,114 (2,016)
Provision for uncollectible accounts 4,272 4,933 3,3767,778 5,270 8,269
Pension income (1,242) (3,857) (5,671)
Other (850) (704) 541
-------- -------- --------
64,113 71,660 53,0301,284 (391) (177)
Net change in:
Accounts receivable and accrued utility revenues (2,401) (9,444) (9,805)(610) (1,631) (14,704)
Inventories (610) (6,608) 2,823(15,601) 9,420 (14,508)
Deferred fuel adjustments 4,639 (10,731) (138)
Pipeline transition and producer settlement
recoveries (costs), net (1,769) 1,074 (7,591)costs 19,038 (7,056) 9,948
Accounts payable 5,850 5,894 7,803(454) (9,957) 13,318
Other current assets and liabilities (338) 5,184 (3,454)3,599 (14,123) 9,769
-------- -------- --------
Net cash provided by operating activities 69,484 57,029 42,66897,801 55,056 76,132
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (41,684) (39,659) (51,221)(41,297) (35,884) (36,783)
Net costs of property, plant and equipment disposals (884) (1,189) (973)
Other, net 500 740 1,225(1,831) (704) (1,407)
Cash contribution to partnership - - (6,000)
-------- -------- --------
Net cash used by investing activities (42,068) (40,108) (50,969)(43,128) (36,588) (44,190)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (26,823) (35,649) (16,897)(35,081) (39,489) (36,809)
Cash portion of UGID dividend (2,572) - -
Issuance of long-term debt 20,000 20,000 48,00044,694 40,000 50,603
Repayment of long-term debt (27,380) (54,828) (17,236)(76,000) - (15,000)
Bank loans increase 16,500 8,500 25,000
Redemption of Series Preferred Stock -- (15) --(decrease) 3,500 (20,600) (42,600)
Capital contribution from UGI Corporation 5,000 - 4,000
-------- -------- --------
Net cash provided (used)used by financing activities (17,703) (61,992) 38,867(60,459) (20,089) (39,806)
-------- -------- --------
Cash and cash equivalents increase (decrease)decrease $ 9,713 $(45,071)(5,786) $ 30,566(1,621) $ (7,864)
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of periodyear $ 12,813304 $ 3,1006,090 $ 48,1717,711
Beginning of period 3,100 48,171 17,605year 6,090 7,711 15,575
-------- -------- --------
Increase (decrease)Decrease $ 9,713 $(45,071)(5,786) $ 30,566(1,621) $ (7,864)
======== ======== ========
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, 19942000 $60,259 $68,559 $ 60,25995,655 $ 68,052- $ 49,760224,473
Net income 26,99048,137 48,137
Capital contribution by UGI Corporation 4,000 4,000
Cash dividends - common stock (14,507)(35,259) (35,259)
Cash dividends - preferred stock (2,778)
Dividend(1,550) (1,550)
Dividends of subsidiary net assets (973)(4,277) (4,277)
Other 233 233
------- ------- -------- -------- -----------------
Balance September 30, 19952001 60,259 68,052 58,49272,792 102,706 - 235,757
Net income 38,34844,095 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 (32,884)(37,939) (37,939)
Cash dividends - preferred stock (2,765)(1,550) (1,550)
Other (61)265 265
------- ------- -------- -------- -----------------
Balance September 30, 19962002 60,259 68,052 61,13073,057 107,312 (2,774) 237,854
Net income 38,71160,672 60,672
Net change in fair value of interest rate
protection agreements (net of tax of $365) 515 515
Reclassifications of net loss on interest rate
protection agreements (net of tax of $149) 210 210
-------- -------- ---------
Comprehensive income 60,672 725 61,397
Capital contribution by UGI Corporation 5,000 5,000
Cash dividends - common stock (24,060)(33,918) (33,918)
Cash dividends - preferred stock (2,764)(1,163) (1,163)
Dividend of subsidiary assets (1,031)UGID common stock (15,407) (15,407)
Other 197989 989
------- ------- -------- -------- -----------------
Balance September 30, 19972003 $60,259 $79,046 $117,496 $ 60,259(2,049) $ 68,249 $ 71,986254,752
======= ======= ======== ======== =================
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 a natural gas distribution utility (Gas Utility)("Gas
Utility") in parts of eastern and southeastern PennsylvaniaPennsylvania; owns and operates
an electricelectricity distribution utility (Electric Utility)("Electric Utility") in northeastern
Pennsylvania.
ThePennsylvania; and prior to the June 2003 distribution to UGI of UGI Development
Company ("UGID") and UGID's subsidiaries and 50%-owned joint-venture affiliate
Hunlock Creek Energy Ventures ("Energy Ventures"), owned interests in
Pennsylvania-based electricity generation assets through UGID. We refer to Gas
Utility, Electric Utility and UGID (prior to its distribution to UGI)
collectively as "the Company" or "we," and Electric Utility and UGID
collectively as "Electric Operations." 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 have been eliminatedwhen we
consolidate. Our investment in consolidation. Revenues of Gas Utility comprise more than four-fifths
ofEnergy Ventures was accounted for under the
Company's consolidated revenues.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the
financial statements, and revenues and expenses during the reporting
period. Actual results could differ from these estimates.
REGULATED OPERATIONSequity method. Gas Utility and Electric Utility (collectively, "Utilities") are
subject to regulation by the Pennsylvania Public Utility Commission (PUC)("PUC").
UGID was granted "Exempt Wholesale Generator" status by the Federal Energy
Regulatory Commission.
In June 2003, the Company dividended all of the common stock of UGID and its
subsidiaries to UGI. The net book value of the assets and liabilities of UGID
and its subsidiaries totaling $15,407 (including $2,572 of cash) was eliminated
from the consolidated balance sheet and reflected as a dividend from retained
earnings. UGID and its subsidiaries' results of operations did not have a
material effect on the Company's results of operations in 2003, 2002 and 2001.
RECLASSIFICATIONS
We have reclassified certain prior-year balances to conform to the current-year
presentation.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United States.
These estimates and assumptions affect the reported amounts of assets and
liabilities, revenues and expenses, as well as the disclosure of contingent
assets and liabilities. Actual results could differ from these estimates.
REGULATED UTILITY OPERATIONS
We account for the operations of 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, that financial
statements of a regulated enterprise reflectus
to record the actions of regulators,
where appropriate. The economic effects of rate regulation can result in
regulated enterprises recording costs that have been or are expected to
be allowed in the ratesetting processfinancial statements. Certain
expenses and credits subject to utility regulation and normally reflected in
a period different from the
period in which the costs would be charged to expense by an unregulated
enterprise. When this occurs, costsincome as incurred are deferred as assets inon the balance sheet (regulatory assets) and recordedrecognized in income as
expenses as thosethe related amounts are reflectedincluded in rates. Additionally, regulators can impose
liabilities upon a regulated enterprise for amounts previously collectedrates and recovered from customers and for recovery of costs that are expectedor refunded to
be
incurred in the future (regulatory liabilities). The Company continually
monitors the regulatory and competitive environments in which it
operates to determine that its regulatory assets are probable of
recovery.customers. As required
F-10
63
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Givenby SFAS 71, we monitor our regulatory and competitive environments to determine
whether the changingrecovery of our regulatory environment in the electric utility
industry (see Note 2), the Companyassets continues to evaluatebe probable. If we
were to determine that recovery of these regulatory assets is no longer
probable, such assets would be written off against earnings.
On June 29, 2000, the PUC issued its abilityorder ("Gas Restructuring Order") approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to applyPennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
provisions of SFAS 71 as it relates to its electric generation
operations. The Company believes its electric generation assetsthe Gas Restructuring Order and relatedthe Gas Competition Act, we
believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS
71. If such electric generation assets no longer meetFor further information on the criteriaimpact 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 fixedGas Competition Act 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."Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see
Note 2.
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 $16,046 in 2003, $16,348 in 2002 and 1995, was $17,507, $16,100$17,543 in 2001.
We paid income taxes totaling $29,372 in 2003, $36,282 in 2002 and $15,530, respectively. Income taxes paid during 1997, 1996 and 1995 were
$24,246, $15,736, and $11,535, respectively.$29,000 in
2001.
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 or products are
delivered.
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, andF-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
amortized. 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.
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
Property,We record property, plant and equipment is stated at cost. TheWhen Gas Utility and Electric
Utility retire depreciable utility plant and equipment, we charge the original
cost, of
UGI Utilities' retired plant, together with the net cost of removal is
chargedcosts and salvage value, 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, 1996Gas Utility was 2.3% in 2003, 2.5% in 2002
and 19952.6% in 2001. Depreciation expense as a percentage of the related average
depreciable base for Electric Utility was 2.7%, 2.9%3.0% in each of 2003 and 2.8%;2002 and 3.6%, 3.6% and 3.4% for3.3%
in 2001. The declines in the Gas Utility and Electric Utility respectively.percentages for
2003 and 2002 are the result of changes, effective April 1, 2002, in the
estimated remaining useful lives of Gas Utility's and Electric Utility's
distribution assets. Depreciation expense during 1997, 1996was $20,754 in 2003, $21,649 in 2002
and 1995 was $20,899, $20,848$22,701 in 2001.
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 $18,983,
respectively.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 with the provisions of the Customer Choice Act (see Note
2), the rates Electric Utility can charge its customers, including
amounts pertaining to the recovery of fuel and purchased power costs,
were capped effective January 1, 1997. The difference between amounts
collected and costs actually 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.
F-12
65
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003, the Company accounts for its preferred shares subject to
mandatory redemption in accordance with SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity"
("SFAS 150"). SFAS 150 establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The adoption of SFAS 150 results in the Company presenting its
preferred shares subject to mandatory redemption in the liabilities section of
the balance sheet, and reflecting dividends paid on these shares as a component
of interest expense, for periods presented after June 30, 2003. Because SFAS 150
specifically prohibits the restatement of financial statements prior to its
adoption, prior period amounts have not been reclassified.
ENVIRONMENTAL LIABILITIES
We 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. 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. In those instances for
which the amount and timing of cash payments associated with environmental
investigation and cleanup are reliably determinable, we discount such
liabilities to reflect the time value of money. We intend to pursue recovery of
any incurred costs through all appropriate means, including regulatory relief.
Gas Utility is permitted to amortize as removal costs site-specific
environmental investigation and remediation costs, net 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 removal costs. At September 30, 2003, the Company's
liability for environmental investigation and cleanup costs was not material.
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.
During 2003 and 2002, in order to manage interest rate risk associated with
forecasted issuances of fixed-rate long-term debt, we entered into interest rate
protection agreements ("IRPAs") which have been designated and qualify as cash
flow hedges in accordance with SFAS 133. Included in accumulated other
comprehensive loss at September 30, 2003 and 2002 are net after-tax losses of
$2,049 and $2,774, respectively, associated with settled and unsettled IRPAs.
The amount of the net loss at September 30, 2003 expected to be reclassified
into net income during the next twelve months is not material. The fair values
of our unsettled IRPAs were a gain of $369 at September 30, 2003 and a loss of
$1,205 at September 30, 2002. These amounts are included in other assets and
other current liabilities, respectively, on the Consolidated Balance Sheets. The
unsettled IRPA at September 30, 2003 hedges interest rate risk associated with
forecasted issuances of debt to occur during Fiscal 2005.
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
During 2003 and 2002, Gas Utility entered into natural gas call option contracts
to reduce volatility in the cost of gas it purchases for its firm- residential,
commercial and industrial ("retail core-market") customers. Because net gains or
losses associated with these contracts will be included in our PGC recovery
mechanism, as these contracts are recorded at fair value in accordance with SFAS
133, any gains or losses are deferred for future recovery from or refund to Gas
Utility's ratepayers.
During 2001, we 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. 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 2003, 2002 and 2001, there were no gains or losses recognized in earnings
as a result of 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 purchase and delivery of natural gas and
electricity, and service contracts that require the counterparty to provide
commodity storage, transportation or capacity service to meet our normal sales
commitments. Although many of these contracts have the requisite elements of a
derivative instrument, these contracts are not subject to the accounting
requirements of SFAS 133, as amended, 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 income (loss) of $725 and $(2,774) for the years ended
September 30, 2003 and 2002, respectively, is the result of gains or losses on
IRPAs qualifying as cash flow hedges, net of reclassifications to net income.
The Company's comprehensive income was the same as net income for the year ended
September 30, 2001.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No.
149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" ("SFAS 149"). SFAS 149 is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. SFAS 149 (i) clarifies under what circumstances a contract with an
initial net investment meets the characteristic of a derivative, (ii) clarifies
when a derivative contains a financing component, (iii) amends the definition of
an underlying- rate, price or index to conform it to language used in FASB
Interpretation No. 45,
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others," and (iv) amends certain other
existing pronouncements. SFAS 149 did not change the methods the Company uses to
account for and report its derivatives and hedging activities.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective
immediately for variable interest entities created or obtained after January 31,
2003. For variable interests created or acquired before February 1, 2003, FIN 46
is effective for the first fiscal or interim period beginning after December 15,
2003. If certain conditions are met, FIN 46 requires the primary beneficiary to
consolidate certain variable interest entities in which the other equity
investors lack the essential characteristics of a controlling financial interest
or their investment at risk is not sufficient to permit the variable interest
entity to finance its activities without additional subordinated financial
support from other parties. The adoption of FIN 46 is not expected to impact the
Company's financial position or results of operations.
2. UTILITY REGULATORY MATTERS
ELECTRICITY GENERATION CUSTOMER CHOICEGas Utility
Gas Restructuring Order. 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. The purpose of the Gas Competition Act, which was
signed into law on June 22, 1999, 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 customers.
Among other things, the implementation of the Gas Restructuring Order resulted
in an increase in Gas Utility's retail 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 retail 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 retail
core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
retail 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.
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
F-15
UGI UTILITIES, INC. AND COMPETITION ACTSUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
owned subsidiary of UGI. 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. The associated reduction in Gas Utility's base rates, adjusted for the
impact of the transfer on net operating expenses, did not have a material effect
on our results of operations.
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 Choice Act. Under the terms
of the Electricity Restructuring Order, Electric Utility was authorized to
recover $32,500 in stranded costs over a four-year period beginning January 1,
1997, the Electricity Generation Customer Choice1999 through a Competitive Transition Charge ("CTC") together with carrying
charges on unrecovered balances of 7.94% and Competition Act (Customer Choice Act) became effective. The Customer
Choice 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 Choice Act requires all
electric utilities 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. 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 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.
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, thealternative generation
supplier.
The PUC approved a settlement establishing rules for Electric Utility Provider
of this proceeding (GasLast 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 Base Rate Settlement) authorizingterminated 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 generation rate caps as of August 1, 2002 for C&I customers and as of
November 1, 2002 for residential customers. Charges for generation service (1)
were initially set at a $19,500level 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 by up to 5% of the total rate for distribution,
transmission and generation 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 certain circumstances, be
subject to generation rate surcharges. Consistent with the terms of the POLR
Settlement, Electric Utility's POLR rates for commercial and industrial
customers will increase in annual revenues. The increase in base rates became
effective on August 31, 1995.
F-13beginning January 2004, and for residential customers
beginning June 2004. Also, Electric Utility has offered and entered into
multiple-year POLR contracts with certain of its customers. Additionally,
pursuant to the requirements of the Electricity Choice Act, the PUC is currently
developing post-rate cap POLR regulations that are expected to further define
post-rate cap POLR service obligations and pricing. As of September 30, 2003,
less than
F-16
66
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1% of Electric Utility's customers have chosen an alternative electricity
generation supplier.
Formation of Hunlock Creek Energy Ventures. On January 26, 1996, Electric Utility filedDecember 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 a subsidiary of UGID 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 Energy Ventures to be operated at the Hunlock
site. Under the terms of our arrangement with Allegheny, each partner is
entitled to purchase 50% of the PUC for a $6,200
increaseoutput of the joint venture at cost. Total
purchases from Energy Ventures in base rates. On July 18, 1996, the PUC approved a settlement
of this proceeding authorizing a $3,100 increase in annual revenues,
effective July 19, 1996.
REGULATORY ASSETS (LIABILITIES)2003 (prior to its June 2003 distribution to
UGI), 2002 and 2001 were $6,360, $9,751 and $7,966, respectively.
Regulatory Assets and Liabilities
The following regulatory assets (liabilities)and liabilities are included in theour accompanying
balance sheets at September 30:
1997 1996
-------- --------2003 2002
- --------------------------------------------------------
Regulatory income tax asset $ 44,438 $ 42,908assets:
Income taxes recoverable $57,625 $54,727
Other postretirement benefits 3,809 4,322
Refundable state taxes (3,102) (4,166)2,162 2,397
Deferred fuel costs (recoveries), net (3,565) 1,074- 4,304
Other 466 561
- --------------------------------------------------------
Total regulatory assets $60,253 $61,989
- --------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 3,746 $ 4,332
Deferred producer settlement and pipeline
transition recoveries (3,852) (5,876)
Deferred environmentalfuel costs 706 69714,734 -
- --------------------------------------------------------
Total regulatory liabilities $18,480 $ 4,332
- --------------------------------------------------------
F-14The Company's regulatory liabilities relating to other postretirement benefits
are included in "other noncurrent liabilities" on the Consolidated Balance
Sheets. The Company does not recover a rate of return on its regulatory assets.
F-17
67
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. DEBT
Long-term debt comprises the following at September 30:
1997 1996
--------- ---------2003 2002
- -------------------------------------------------------------------------------------------------
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 $271 and $392, respectively, effective rate - 6.64%) 30,271 30,392
7.14% Notes, due December 2005 20,000 20,000
5.53% Notes due September 2012 40,000 40,000
5.37% Notes due August 2013 25,000 -
6.50% Notes due August 2033 20,000 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $134 and $153,
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
--------- ---------$23) - 49,977
- -------------------------------------------------------------------------------------------------
Total long-term debt 169,294 176,654217,271 248,369
Less current maturities (17,143) (25,543)
--------- ---------- (76,000)
- -------------------------------------------------------------------------------------------------
Long-term debt due after one year $ 152,151217,271 $ 151,111
--------- ---------172,369
- -------------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt for each of the next five
fiscal years ending September 30 are as follows: 19982004 - $17,143; 1999$0; 2005 - $7,143;
2000$20,000; 2006
- $7,142; 2001 - $ -; 2002$50,000; 2007 - $ -.
The mortgage collateralizing UGI Utilities First Mortgage Bonds
constitutes a first lien on UGI Utilities' plant.$20,000; 2008 - $0.
At September 30, 1997,2003, UGI Utilities had revolving credit agreements with five
banks providing for borrowings of up to $102,000 through
December 1997 and $82,000 through June 2000. The commitments expiring$107,000. These agreements are currently
scheduled to expire in June 2000 may be extended for one-year periods, upon timely notice,
unless the banks elect not to renew. The agreements provide2005 and 2006. UGI Utilities with the option tomay borrow at various
prevailing interest rates, including LIBOR and the banks' prime rate. AUGI
Utilities pays quarterly commitment fee at an annual rate of
3/16 of 1% is payable quarterlyfees on the unused available committedthese credit lines. AtUGI Utilities
had revolving credit agreement borrowings totaling $40,700 at September 30, 19972003
and 1996, borrowings under these agreements
totaled $67,000 and $50,500, respectively, and are classified$37,200 at September 30, 2002 which we classify as bank loans. The
weighted-average interest rates on UGI Utilities' bank loans were 1.63% at September 30, 19972003
and 1996 were 6.3%2.35% at September 30, 2002.
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, 2003, UGI Utilities
was in compliance with these 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
-------- -------- --------2003 2002 2001
- -------------------------------------------------------------------
Current:Current expense:
Federal $ 18,16827,027 $ 12,18413,341 $ 6,74225,344
State 5,847 3,704 2,630
-------- -------- --------
24,015 15,888 9,37210,416 5,115 8,103
- -------------------------------------------------------------------
Total current expense 37,443 18,456 33,447
Deferred 947 7,880 2,768expense (benefit) 2,495 11,512 (1,618)
Investment tax credit amortization (398) (399) (399)
-------- -------- --------(398) (398)
- -------------------------------------------------------------------
Total income tax expense $ 24,56439,540 $ 23,36929,570 $ 11,741
-------- -------- --------31,431
- -------------------------------------------------------------------
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
---- ---- ----2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 5.6 6.3 6.5 6.2 7.5
Adjustment to deferred state
income taxes -- -- (10.7)
Deferred investment tax credit amortization (.6) (.7) (1.0)(0.4) (0.5) (0.5)
Other, net (2.1) (2.6) (1.3)
---- ---- ----(0.7) (0.7) (1.5)
- -----------------------------------------------------------------------
Effective tax rate 38.8% 37.9% 29.5%
---- ---- ----39.5% 40.1% 39.5%
- -----------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
1997 1996
--------- ---------2003 2002
- --------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and
equipment $ 85,387117,891 $ 81,060107,627
Regulatory income taxassets 25,001 25,721
Pension plan asset 18,439 17,80211,019 10,546
Other 6,862 8,977
--------- ---------2,170 164
- --------------------------------------------------------------------------------
Gross deferred tax liabilities 110,688 107,839
--------- ---------156,081 144,058
- --------------------------------------------------------------------------------
Deferred investment tax credits (4,305) (4,471)
Deferred fuel refunds (1,450) --(3,314) (3,479)
Employee-related expenses (4,494) (4,348)(7,072) (6,371)
Regulatory liabilityliabilities (7,667) (1,797)
Accumulated other comprehensive loss (1,454) (1,968)
Other (2,773) (1,570)
- state income taxes (1,287) (1,729)
Other (6,463) (8,155)
--------- -----------------------------------------------------------------------------------------
Gross deferred tax assets (17,999) (18,703)
--------- ---------(22,280) (15,185)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ 92,689133,801 $ 89,136
--------- ---------128,873
- --------------------------------------------------------------------------------
During 1995, UGI Utilities recorded a regulatory income 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
ratepayers of approximately $4,787 in previously recovered deferred
state income taxes. The net effect of these adjustments increased 1995
net income by $4,251.
F-17F-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 of approximately $37,029 as
of September 30, 2003 and $35,498 as of September 30, 2002 pertaining to utility
temporary differences, principally a result of accelerated tax depreciation for
state income tax purposes, 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$3,314 at September 30, 19972003 and 1996, respectively,$3,479 at September
30, 2002, 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$57,625 at September 30, 2003 and $42,908, respectively,
representing$54,727 as of September 30, 2002. 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 of our 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 projected benefit obligations, plan
assets, and funded status of the plans as of September 30:
1997 1996
-------- --------Pension Other Postretirement
Benefits Benefits
---------------------- ----------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------- ----------------------
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 $ 190,873 $ 165,154 $ 23,397 $ 18,179
Service cost 4,544 3,582 117 90
Interest cost 12,976 12,480 1,518 1,474
Actuarial loss 10,472 18,589 863 5,051
Plan amendments - 395 - -
Benefits paid (9,406) (9,327) (1,328) (1,397)
- ----------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 209,459 $ 190,873 $ 24,567 $ 23,397
- ----------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at fair- beginning of year $ 166,064 $ 183,736 $ 7,846 $ 6,994
Actual return on plan assets 27,182 (8,345) 172 144
Employer contributions - - 2,310 2,105
Benefits paid (9,406) (9,327) (1,328) (1,397)
- ----------------------------------------------------------------------------------------------------
Fair value 3,479 1,853of plan assets - end of year $ 183,840 $ 166,064 $ 9,000 $ 7,846
- ----------------------------------------------------------------------------------------------------
Funded status of the plans $ (25,619) $ (24,809) $ (15,567) $ (15,551)
Unrecognized net gain (1,881) (2,835)actuarial loss 51,205 50,190 6,870 5,945
Unrecognized prior service cost -- 2,1492,345 3,038 - -
Unrecognized net transition (asset) obligation 16,320 19,921
-------- --------
Accrued postretirement(1,374) (3,004) 6,375 7,059
- ----------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ (4,054)26,557 $ (4,573)
-------- --------25,415 $ (2,322) $ (2,547)
- ----------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.2% 6.8% 6.2% 6.8%
Expected return on plan assets 9.0% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.0% 4.5% 4.0% 4.5%
- ----------------------------------------------------------------------------------------------------
Net pension income is determined using assumptions as of the beginning of each
year. Funded status is determined using assumptions as of the end of each year.
Included in the end of year pension benefit obligations above are $15,528 at
September 30, 19972003 and 1996 accumulated postretirement
benefit obligation amounts above are $406 and $365, respectively,$13,955 at September 30, 2002 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 $658 at September 30, 1997, 19962003 and 1995,$649 at
September 30, 2002 relating to employees of UGI and netcertain of its other
subsidiaries.
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension and other postretirement benefit cost forcosts relating to UGI
Utilities employees include the years then ended, are as follows:following components:
1997 1996 1995
------- ------- -------Pension Other Postretirement
Benefits Benefits
-------------------------------- --------------------------------
2003 2002 2001 2003 2002 2001
- ------------------------------------------------------------------------------ --------------------------------
Funded status at September 30:
Discount rate 7.4% 8.0% 7.5%
Health care
Service cost trend rate 6.0-5.5 6.5-5.5 7.0-5.5$ 4,051 $ 3,193 $ 2,785 $ 109 $ 84 $ 82
Interest cost 12,004 11,600 11,319 1,497 1,453 1,326
Expected return on assets (16,646) (17,778) (17,766) (414) (366) (366)
Amortization of:
Transition (asset) obligation (1,510) (1,518) (1,530) 680 680 679
Prior service cost 643 646 625 - - -
Actuarial (gain) loss 216 - (1,104) 203 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) (1,242) (3,857) (5,671) 2,075 1,871 1,721
Change in regulatory assets and liabilities - - - 1,024 1,228 1,378
- ------------------------------------------------------------------------------------------------------------------
Net expense (income) $ (1,242) $ (3,857) $ (5,671) $ 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 7% of trust assets at September 30, 19972003. Although
the UGI Utilities Pension Plan projected benefit obligations exceeded plan
assets at September 30, 2003 and 19962002, plan assets exceeded accumulated
postretirement benefit
obligations by $1,534$7,346 and $2,150, respectively,
and increases$7,154, respectively.
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
equity and fixed income mutual funds.
The assumed health care cost trend rates are 11.0% for fiscal 2004, decreasing
to 5.5% in fiscal 2010. A one percentage point change in the assumed health care
cost trend rate would change the 2003 postretirement benefit cost and obligation
as follows:
1% 1%
Increase Decrease
- -----------------------------------------------------------------------
Effect on total service and interest costs $ 91 $ (80)
Effect on postretirement benefit obligation 1,460 (1,286)
- -----------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 1997,2003 and 2002, the VEBA balance totaled $3,479projected benefit obligations of these plans
were $3,469 and was primarily invested$2,816, respectively. We recorded expense for these plans of
$353 in money market
funds.
F-212003, $269 in 2002 and $235 in 2001.
F-22
74
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Effective August 31, 1995, Gas Utility is permitted to recoverDEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings
Plan"). Generally, participants in its
rates approximately $2,400 in ongoing annual costs incurredthe Utilities Savings Plan may contribute a
portion of their compensation on a before-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 $968 in rates2003, $932 in 2002 and the actuarially determined annual SFAS 106 costs for recovery
or refund to ratepayers$936 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."2001.
6. INVENTORIES
Inventories comprise the following at September 30:
1997 1996
------- -------2003 2002
- -------------------------------------------------
Utility fuel and gases $25,963 $26,012$51,505 $36,208
Appliances for sale 1,877 1,374548 480
Materials, supplies and other 2,805 2,649
------- -------
$30,645 $30,035
------- -------1,964 1,966
- -------------------------------------------------
Total inventories $54,017 $38,654
- -------------------------------------------------
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, 2003 and 2002, 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 each8. COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer and office equipment and
other facilities under operating leases. Certain of the fiscal years 1998 toour leases contain renewal
and purchase options and also contain escalation clauses. Our aggregate rental
expense for such leases was $4,303 in 2003, $4,690 in 2002 is $3,000.and $4,624 in 2001.
F-23
76
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. COMMITMENTS AND CONTINGENCIES
The Company leases various buildings and transportation, data processing
and office equipment under operating leases. Certain of the leases
contain renewal and purchase options and also contain escalation
clauses. The aggregate rental expense for such leases for 1997, 1996 and
1995 was $5,083, $4,891 and $4,861, respectively.
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: 19982004 - $4,210; 1999$2,890; 2005 - $3,526; 2000$2,420; 2006 - $2,883; 2001$2,115; 2007 - $2,400; 2002$1,754;
2008 - $2,104;$1,024; after 20022008 - $1,578.$3,203.
Gas Utility has gas supply agreements with producers and marketers that
expire at various dates through 2000 andwith terms
not exceeding one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity that expirewhich Gas Utility may terminate at various
dates through 20172016. Gas Utility's costs associated with 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 2008.
Future contractual cash obligations under Gas Utility and Electric Utility
above that provided fromsupply, storage and service agreements existing at September 30, 2003 are as
follows: 2004 - $157,050; 2005 - $87,850; 2006 - $48,156; 2007 - $25,074; 2008 -
$14,714; after 2008 - $73,997.
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
three 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 Utilitiesowned or 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 (1) the level of control exercised bysubsidiary's separate
corporate form should be disregarded or (2) UGI Utilities over the
subsidiary satisfies the standard described above. In many circumstances
whereshould be considered
to have been an operator because of its conduct with respect to its subsidiary's
MGP.
F-24
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
With respect to a manufactured gas plant site in Manchester, New Hampshire,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities
may be liable, expenditures may not be reasonably
quantifiable because of a number of factors, including variousseeking contribution from UGI Utilities for response and remediation costs
associated with potential remedial alternatives, the unknown numbercontamination on the site of other potentially responsible parties involveda former MGP allegedly operated
by former subsidiaries of UGI Utilities. UGI Utilities and their abilityEnergyNorth agreed to
contributea settlement of this matter in June 2003. UGI Utilities recorded its estimated
liability for contingent payments 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.
UnderEnergyNorth under the terms of the
settlement agreement.
In April 2003, Citizens Communications Company ("Citizens") served a complaint
naming UGI Utilities as a third-party defendant in a civil action pending in
United States District Court for the District of Maine. In that action, the
plaintiff, City of Bangor, Maine ("City") sued Citizens to recover environmental
response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens' predecessors at a site on the Penobscot River. Citizens
subsequently joined UGI Utilities and ten other third-party defendants alleging
that the third party defendants are responsible for an equitable share of costs
Citizens may be required to pay to the City for cleaning up tar deposits in the
Penobscot River. The City believes that it could cost as much as $50,000 to
clean up the river. UGI Utilities believes that it has good defenses to the
claim.
By letter dated July 29, 2003, Atlanta Gas Utility Base Rate Settlement, Gas UtilityLight Company ("AGL") served UGI
Utilities with a complaint filed in the United States District Court for the
Middle District of Florida in which AGL alleges that UGI Utilities is
permitted to amortize as removal costs site-specific environmentalresponsible for 20% of approximately $8,000 incurred by AGL in the investigation
and remediation costs, net of related third-party
payments,a former MGP site in St. Augustine, Florida. UGI Utilities
formerly owned stock of the St. Augustine Gas Company, the owner and operator of
the MGP. UGI Utilities believes that it has good defenses to the claim and is
defending the suit.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed
suit against UGI Utilities in the United States District Court for the Southern
District of New York, seeking contribution from UGI Utilities for an allocated
share of response costs associated with Pennsylvaniainvestigating and assessing gas plant
related contamination at former MGP sites in Westchester County, New York. The
complaint alleges that UGI Utilities "owned and operated" the MGPs prior to
1904. The complaint also seeks a declaration that UGI Utilities is responsible
for an allocated percentage of future investigative and remedial costs at the
sites. Gas Utility will be
permittedConEd believes that the cost of remediation for all of the sites could
exceed $70,000. UGI Utilities believes that it has good defenses to includethe claim
and is defending the suit. In November 2003, the court granted UGI Utilities'
motion for summary judgment in rates, through future base rate proceedings,part, dismissing all claims premised on a
five-year averagedisregard of such prudently incurred removal costs.the separate corporate form of UGI Utilities' former subsidiaries
and dismissing claims premised on UGI Utilities' operation of three of the MGPs
under operating leases with ConEd's predecessors. The court reserved decision on
the remaining theory of liability, that UGI Utilities was a direct operator of
the remaining MGPs.
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.
Although we currently 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, butdamages or
settlements could be material to our operating results or cash flows in future
periods depending on the nature and timing of future
F-25
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
developments with respect to these matters and the amounts of future operating
results and cash flows.
F-259. 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 $233,000 at September 30, 2003 and
$263,000 at September 30, 2002. 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 $20,900 at September 30, 2003 and $20,400 at
September 30, 2002. 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, 2003 and 2002, we had no significant
concentrations of credit risk.
F-26
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. 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 income 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
- -----------------------------------------------------------------------------
2003
Revenues $ 636,758 $ 539,862 $ 96,896
Cost of sales 392,901 342,987 49,914
Depreciation and amortization 21,240 18,147 3,093
Operating income 117,868 96,086 21,782
Interest expense 17,656 15,409 2,247
Income before income taxes 100,212 80,677 19,535
Total assets 809,048 725,085 83,963
Capital expenditures 41,297 37,204 4,093
2002
Revenues $ 153490,552 $ 403 $1,286
Gas brokerage404,519 $ 86,033
Cost of sales 290,282 241,669 48,613
Depreciation and amortization 22,172 18,983 3,189
Operating income -- -- 1,409
Other 2,624 1,439 1,085
------ ------ ------
$2,777 $1,842 $3,780
------ ------ ------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 $ 584,762 $ 500,832 $ 83,930
Cost of sales 374,781 322,915 51,866
Depreciation and amortization 23,767 20,171 3,596
Operating income 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
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-26F - 27
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
-------- -------- -------- -------- -------- -------- -------- --------2002 2001 2003 2002 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Revenues $134,154 $122,241 $173,304 $181,412$168,351 $141,481 $269,296 $179,945 $121,546 $ 88,20888,249 $ 88,86077,565 $ 65,542 $ 67,98380,877
Operating income (loss) 30,343 27,712 41,022 40,495 8,977 9,389 (195) 21538,830 27,609 63,449 41,319 10,005 13,222 5,584 8,167
Net income (loss) 16,185 14,660 22,763 22,425 2,970 3,702 (3,207) (2,439)
-------- -------- -------- -------- -------- -------- -------- --------20,714 14,045 35,399 22,549 3,640 5,552 919 1,949
- ------------------------------------------------------------------------------------------------------------------------
12. OTHER INCOME, NET
Other income, net, comprises the following:
2003 2002 2001
- ------------------------------------------------------------
Non-tariff service income $ 5,693 $ 5,701 $ 5,410
Pension income 1,242 3,858 5,671
Interest income 128 1,110 235
Other 1,682 1,054 3,795
- ------------------------------------------------------------
$ 8,745 $ 11,723 $ 15,111
- ------------------------------------------------------------
13. RELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI
Utilities monthly 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
IncomeIncome.
In accordance with the terms of an Affiliated Interest Agreement ("Affiliated
Agreement") approved by the PUC, Gas Utility enters into wholesale natural gas
transactions with Energy Services, Inc. ("Energy Services"), a wholly owned
second-tier subsidiary of UGI, for 1997, 1996winter storage service and, 1995.
F-28from time to
time, purchases of natural gas. During 2003 and 2002, the aggregate amount of
these transactions totaled $4,709 and $2,614, respectively. Such amounts were
not material in 2001. In addition, from time to time, the Company sells natural
gas to Energy Services pursuant to the terms of the Affiliated Agreement. During
2003, 2002 and 2001, revenues associated with these sales to Energy Services
totaled $4,234, $17,379 and $10,976, respectively. These transactions did not
have a material effect on the Company's net income during 2003, 2002 and 2001.
F - 28
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
- -----------------------------2003
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $3,976 $4,272 $(4,915)$ 1,972 $ 7,778 $ (6,475)(1) $3,333
======== ========$ 3,275
======= ===============
Other reserves(3) $3,160 $3,021reserves (3) $ (236)3,363 $ 3,164 $ (3,294)(2) $5,945
======== ========$ 3,616
======= ===============
383 (4)
YEAR ENDED SEPTEMBER 30, 1996
- -----------------------------2002
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $2,660 $4,933 $(3,617)$ 3,151 $ 5,270 $ (6,449)(1) $3,976
======== ========$ 1,972
======= ===============
Other reserves(3) $3,255reserves (3) $ 2373,467 $ (332)748 $ (2,352)(2) $3,160
======== ========$ 3,363
======= ===============
1,500 (4)
YEAR ENDED SEPTEMBER 30, 1995
- -----------------------------2001
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $2,796 $3,376 $(3,512)$ 2,061 $ 8,269 $ (7,179)(1) $2,660
======== ========$ 3,151
======= ===============
Other reserves(3) $2,294 $1,411reserves (3) $ (450)1,954 $ 1,696 $ (276)(2) $3,255
======== ========$ 3,467
======= ===============
93 (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 as amended through September 30, 2003
10.19 UGI Utilities, Inc. Severance Plan for Exempt Employees
in Salary Grades 34-37 and Salary Grades 18-23 effective
January 1, 1999
10.21 Change of Control Agreement for Mr. Chaney
10.22 Form of Change of Control Agreement for executive
officers other than Messrs. Chaney and Greenberg
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
14 Code of Ethics for principal executive, financial and
accounting officers
23 Consent of PricewaterhouseCoopers LLP
31.1 Certification by the Chief Executive Officer relating to
the Registrant's Report on Form 10-K for the year ended
September 30, 2003 pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
31.2 Certification by the Chief Financial Officer relating to
the Registrant's Report on Form 10-K for the year ended
September 30, 2003 pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
32 Certification by Chief Executive Officer and Chief
Financial Officer