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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, 2002
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
Pennsylvania
(State or other jurisdiction of 23-1174060
incorporation or organization) (I.R.S. Employer Identification No.)
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(Address of principal 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 | |.
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|
At November 29, 2002, there were 26,781,785, shares of UGI Utilities Common
Stock, par value $2.25 per share, outstanding, all of which were held,
beneficially and of record, by UGI Corporation
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No | |
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TABLE OF CONTENTS
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PART I: BUSINESS 1
Items 1 And 2. Business and Properties................................................. 1
General............................................................... 1
Gas Utility Operations................................................ 1
Item 3. Legal Proceedings....................................................... 9
Item 4. Submission of Matters to a Vote of Security Holders..................... 11
PART II: SECURITIES AND FINANCIAL INFORMATION 12
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters... 12
Item 6. Selected Financial Data................................................. 13
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 14
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.............. 25
Item 8. Financial Statements and Supplementary Data............................. 25
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 25
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS 26
Item 10. Directors and Executive Officers of the Registrant...................... 26
Item 11. Executive Compensation.................................................. 31
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters............................................. 38
(i)
Page
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Item 13. Certain Relationships and Related Transactions.......................... 40
Item 14. Controls and Procedures................................................. 40
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS 41
Item 15. Exhibits, Financial Statement Schedule, and Reports on Form 8-K......... 41
Signatures............................................................ 47
Certifications........................................................ 50
Index to Financial Statements and Financial Statement Schedule........ F-2
(ii)
PART I: BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities", "UGI Utilities" or the "Company") is a
public utility company that owns and operates (i) a natural gas distribution
utility serving 14 counties in eastern and southeastern Pennsylvania ("Gas
Utility"), and (ii) an electric utility serving parts of Luzerne and Wyoming
counties in northeastern Pennsylvania ("Electric Utility"). In response to state
deregulation legislation, effective October 1, 1999 we transferred our electric
generation assets to our non-utility subsidiary, UGI Development Company
("UGID"). UGID contributed certain of its generation assets to a joint venture
with a subsidiary of Allegheny Energy, Inc. in December 2000. We are a wholly
owned subsidiary of UGI Corporation ("UGI").
Utilities was incorporated in Pennsylvania in 1925 as the successor to a
business founded in 1882. We are subject to regulation by the Pennsylvania
Public Utility Commission ("PUC"). Our executive offices are located at 100
Kachel Boulevard, Suite 400, Green Hills Corporate Center, Reading, Pennsylvania
19607, and our telephone number is (610) 796-3400. In this report, the terms
"Company" and "Utilities," as well as the terms, "our," "we," and "its," are
sometimes used to refer to UGI Utilities, Inc. or, collectively, UGI Utilities,
Inc. and its consolidated subsidiaries.
GAS UTILITY OPERATIONS
NATURAL GAS CHOICE AND COMPETITION ACT
On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act
("Gas Competition Act") was signed into law. The purpose of the Gas Competition
Act was to provide all natural gas consumers in Pennsylvania with the ability to
purchase their gas supplies from the supplier of their choice. Under the Gas
Competition Act, local distribution companies ("LDCs") like Gas Utility may
continue to sell gas to customers, and such sales of gas, as well as
distribution services provided by LDCs, continue to be subject to price
regulation by the PUC.
Generally, Pennsylvania LDCs will serve as the supplier of last resort for
all residential and small commercial and industrial customers unless the PUC
approves another supplier of last resort. The Gas Competition Act requires
energy marketers seeking to serve customers of LDCs to accept assignment of a
portion of the LDC's interstate pipeline capacity and storage contracts at
contract rates, thus avoiding the creation of stranded costs.
On October 1, 1999, Gas Utility filed its restructuring plan with the PUC
pursuant to the Gas Competition Act. On June 29, 2000, the PUC entered its order
("Gas Restructuring Order") approving Gas Utility's restructuring plan
substantially as filed. Gas Utility designed its restructuring plan to ensure
reliability of gas supply deliveries to Gas Utility on behalf of
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residential and small commercial and industrial customers. In addition, the plan
changed Gas Utility's base rates for firm customers. It also changed the
calculation of purchased gas cost rates. See "Utility Regulation and Rates."
Since October 1, 2000, all of Gas Utility's customers have had the option
to purchase their gas supplies from an alternative gas supplier. Large
commercial and industrial customers of Gas Utility have been able to purchase
their gas from other suppliers since 1982. During fiscal year 2002, two
third-party suppliers qualified to serve residential or small commercial and
industrial customers in Gas Utility's service territory. Together, they are
serving approximately 2,400 customers. Management believes none of the Gas
Competition Act, the Gas Restructuring Order, or commodity sales to core-market
customers by third party suppliers will have a material adverse impact on the
Company's financial condition or results of operations.
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 286,000 customers in
portions of 14 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,700 miles of gas mains. The service area
consists of approximately 3,000 square miles and includes the cities of
Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon and
Reading, Pennsylvania. Located in Gas Utility's service area are major
production centers for basic industries such as specialty metals, aluminum and
glass.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 2002 fiscal year was
approximately 70.5 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 41% of system throughput, while gas transported for residential,
commercial and industrial customers (who bought their gas from others) accounted
for approximately 59% of system throughput. Based on industry data for 2000,
residential customers account for approximately 31% of total system throughput
by LDCs in the United States. By contrast, for the 2002 fiscal year, Gas
Utility's residential customers represented 24% of its total system throughput.
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 service contracts. These arrangements enable Gas Utility to
purchase gas from Gulf Coast, 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 and Transcontinental Gas Pipeline
Corporation.
GAS SUPPLY CONTRACTS
During fiscal year 2002, Gas Utility purchased approximately 28 bcf of
natural gas for sale to customers. Approximately 90% of the volumes purchased
were supplied under
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agreements with six major suppliers. The remaining 10% of
gas purchased was supplied by over 30 producers and marketers. Gas supply
contracts are generally no longer than one year.
In fiscal year 2002, as a result of changing market conditions following
the bankruptcy of Enron Corp., a number of suppliers that Utilities formerly did
business with exited the wholesale trading market. This development did not
significantly impact Utilities' ability to secure gas supplies.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas Utility's
sales are seasonal. Approximately 57% of fiscal year 2002 throughput and
approximately 68% of earnings before interest expense, income taxes,
depreciation and amortization occurred during the winter season from November
through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
seeking new load, primarily in the new construction market. Fuel oil dealers
compete 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 gas distribution services. Under the Gas Competition Act, retail
customers may purchase their natural gas from a supplier other than Gas Utility.
Commercial and industrial customers in Gas Utility's service territory have been
able to do this since 1982. As of October 2002, two marketers have qualified to
serve residential and small commercial and industrial customers. Together they
serve approximately 2,400 customers. Gas Utility provides transportation
services for residential and small commercial and industrial customers who
purchase natural gas from others.
Many of 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 rates which are competitively priced with respect to
their alternate fuel. Gas Utility's profitability from these customers,
therefore, is affected by the difference, or "spread," between the customers'
delivered cost of gas and the customers' delivered alternate fuel cost. See
"Utility Regulation and Rates - Gas Utility Rates." Commercial and industrial
customers representing 17% of total system throughput have locations which
afford them the option, although none has exercised it, of seeking
transportation service directly from interstate pipelines, thereby bypassing Gas
Utility. The majority of customers in this group are served under transportation
contracts having three- to twenty-year terms. Included in these two groups are
Utilities' ten largest customers in terms of annual volume. All of these
customers have contracts with Utilities, eight of which extend into
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fiscal year 2004. No single customer represents, or is anticipated to represent,
more than 5% of the total revenues of Gas Utility.
OUTLOOK FOR GAS SERVICE AND SUPPLY
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 through fiscal year 2003. Supply mix is diversified, market priced,
and delivered pursuant to a number of long- and short-term firm transportation
and storage arrangements, including transportation contracts held by some of
Utilities' larger customers.
During fiscal year 2002, Gas Utility supplied transportation service to
two major cogeneration 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
approximately 9,200 residential heating customers during fiscal year 2002, which
represented a record annual increase. Of those new customers, new home
construction accounted for over 7,100 heating customers. Customers converting
from other energy sources, primarily oil and electric, and existing non-heating
gas customers who have added gas heating systems to replace other energy
sources, accounted for the balance of the additions. The number of new
commercial and industrial customers was over 1,100.
Utilities continues to monitor and participate extensively in rulemaking
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 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's objective in negotiations with interstate pipeline and
natural gas suppliers, and in litigation before regulatory agencies, is to
assure availability of supply, transportation and storage alternatives to serve
market requirements at the lowest cost possible, taking into account the need
for security of supply. Consistent with that objective, Gas Utility negotiates
the terms of firm transportation capacity on all pipelines serving Gas Utility,
arranges for appropriate storage and peak-shaving resources, negotiates with
producers for competitively priced gas purchases and aggressively participates
in regulatory proceedings related to transportation rights and costs of service.
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ELECTRIC OPERATIONS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, Pennsylvania's Electricity Generation Customer Choice
and Competition Act ("ECC Act") became effective. The ECC Act permits all
Pennsylvania retail electric customers to choose their electric generation
supplier. Pursuant to the Act, all electric utilities were required to file
restructuring plans with the PUC which, among other things, included unbundled
prices for electric generation, transmission and distribution and a competitive
transition charge (CTC) for the recovery of "stranded costs" which would be paid
by all customers receiving distribution service. 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 ECC Act, Electric Utility generally may not
increase prices for electric generation as long as stranded costs are being
recovered through the CTC. In accordance with the restructuring proceedings
discussed below, Utilities collected a CTC from commercial and industrial
customers until September 2002 and expects to collect from all other
distribution customers until May 2003. Under the ECC Act, Electric Utility is
obligated to provide energy at the capped rates to customers who do not choose
alternate suppliers. Electric Utility will continue to be the only regulated
electric utility having the right, granted by the PUC or by law, to distribute
electric energy in its service territory.
On June 19, 1998, the PUC entered its Opinion and Order (the
"Restructuring Order") in Electric Utility's restructuring proceeding under the
ECC Act. The Electric Restructuring Order authorized Electric Utility to recover
from its customers approximately $32.5 million in stranded costs (on a full
revenue requirements basis, which includes all income and gross receipts taxes)
over a four-year period which commenced January 1, 1999 through a CTC, together
with carrying charges on unrecovered balances of 7.94%.
The PUC approved a settlement establishing rules for Electric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively, the "POLR
Settlement") under which Electric Utility terminated stranded cost recovery
through its CTC from commercial and industrial ("C&I") customers on July 31,
2002, and from residential customers on October 31, 2002, and is no longer
subject to the statutory rate caps as of August 1, 2002 for C&I customers and as
of November 1, 2002 for residential customers. Charges for generation service
will (1) initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 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
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open shopping period, and may, in certain circumstances, be subject to
generation rate surcharges.
SERVICE AREA; SALES ANALYSIS
Electric Utility supplies electric service to approximately 61,500
customers in portions of Luzerne and Wyoming Counties in northeastern
Pennsylvania through a system consisting of approximately 2,100 miles of
transmission and distribution lines and 14 transmission substations. For fiscal
year 2002, about 52% of sales volume came from residential customers, 36% from
commercial customers and 12% from industrial customers. Electricity transported
for customers who purchased their power from others pursuant to the ECC Act
represented approximately 1% of fiscal year 2002 sales volume.
SOURCES OF SUPPLY
Effective October 1, 1999, Utilities transferred its electric generation
assets to its non-utility subsidiary, UGI Development Company ("UGID"). These
generation assets consisted principally of Utilities' Hunlock generating station
("Hunlock Station"), located near Kingston, Pennsylvania and its 1.11% interest
in the Conemaugh generating station ("Conemaugh Station"), located near
Johnstown, Pennsylvania. Effective December 8, 2000, UGID entered into a
partnership ("Energy Ventures") with a subsidiary of Allegheny Energy, Inc. for
the purpose of owning and operating electric generation facilities. UGID
contributed Hunlock Station, coal inventory and $6 million to the partnership
and Allegheny contributed a 44 megawatt gas combustion electric generator. UGID
has the right to purchase half the output of Energy Ventures' generation at
cost. During fiscal year 2002, Electric Utility purchased approximately 28% of
its energy requirements from UGID. Effective October 1, 2002, Electric Utility
has generation supply contracts in place for substantially all of its expected
on-peak energy requirements through fiscal year 2004. UGID plans to market the
electric generation it controls to third parties.
Electric Utility distributes both electricity that it purchases from
others (including UGID) and electricity that customers purchase from other
suppliers. At September 30, 2002, alternate suppliers served customers
representing less than 1% of system load. Electric Utility expects to continue
to provide energy to the great majority of its distribution customers for the
foreseeable future.
ENVIRONMENTAL FACTORS
Energy Ventures' operation of Hunlock Station complies with the air
quality standards of the Pennsylvania Department of Environmental Resources
("DER") with respect to stack emissions. Under the Federal Water Pollution
Control Act, UGID 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.
Both
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the Conemaugh Station and the Hunlock Station are in material compliance with
these emission standards.
SEASONALITY
Sales and distribution of electricity for residential heating purposes
accounted for approximately 19% of the total sales of Electric Utility during
fiscal year 2002. Electricity competes with natural gas, oil, propane and other
heating fuels in this use. Approximately 51% of volume occurred during the six
coldest months of fiscal year 2002 (November through April), demonstrating
modest seasonality favoring winter due to the use of electricity for residential
heating purposes.
UTILITY REGULATION AND RATES
PENNSYLVANIA 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, accounting matters, issuance of securities, contracts and
other arrangements with affiliated entities, and various other matters. As noted
earlier, effective October 1, 1999, Utilities contributed its electric
generation assets to UGID. UGID has FERC authority to sell power at market-based
rates. Generally, UGID is not subject to regulation by the PUC.
FERC ORDERS 888 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 Utilities 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 its transmission facilities are used by third parties.
GAS UTILITY RATES
The Gas Restructuring Order included an increase in firm, core-market base
rates, effective October 1, 2000. The increase, calculated in accordance with
the Gas Competition Act, was designed to generate approximately $16.7 million in
additional annual revenues. The Order also provided that Gas Utility 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 core market customers by an amount equal to the
margin it receives from customers
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served under interruptible rates to the extent they use capacity contracted for
by Gas Utility for core-market customers. As a result of these changes in its
regulated rates, since December 1, 2001, Gas Utility's operating results have
been more sensitive to heating season weather and less sensitive to the market
prices of alternative fuel than in the past.
BASE RATES
As stated above, Gas Utility's current base rates went into effect October
1, 2000 pursuant to The Gas Restructuring Order. See Note 4 to the Company's
Consolidated Financial Statements.
PURCHASED GAS COST RATES
Gas Utility's gas service tariff contains Purchased Gas Cost ("PGC") rates
which provide for annual increases or decreases in the rate per thousand cubic
feet ("mcf") which Gas Utility charges for natural gas sold by it, to reflect
Utilities' projected cost of purchased gas. PGC rates may also be adjusted
quarterly, or monthly, to reflect purchased gas costs. Each proposed annual PGC
rate is required to be filed with the PUC six months prior to its effective
date. During this period the PUC holds hearings to determine whether the
proposed rate reflects a least-cost fuel procurement policy consistent with the
obligation to provide safe, adequate and reliable service. After completion of
these hearings, the PUC issues an order permitting the collection of gas costs
at levels which meet that standard. The PGC mechanism also provides for an
annual reconciliation. Utilities has two PGC rates. PGC (1) is applicable to
small, firm, core-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 separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC (2)
rate. As described above, the Gas Restructuring Order provided for ongoing
adjustments to Gas Utilities' PGC rates, commencing December 1, 2001, to reflect
margins, if any, from interruptible rate customers who do not obtain their own
pipeline capacity.
ELECTRIC UTILITY RATES
Electric Utility's rates for electric generation are frozen through
approximately July 2003 for commercial and industrial customers and
approximately May 2004 for residential customers. After these dates and through
December 2004, Electric Utility can increase generation rates by up to 5% of the
total rate for distribution, transmission and generation. See "Electricity
Generation Customer Choice and Competition Act." The ECC Act obligates Electric
Utility to act as "provider of last resort" to customers who do not choose
alternate generation suppliers.
STATE TAX SURCHARGE CLAUSES
Utilities' gas and electric service tariffs contain state tax surcharge
clauses. The surcharges are recomputed whenever any of the tax rates included in
their calculation are changed. These clauses protect Utilities from the effect
of increases in most of the Pennsylvania taxes to which it is subject.
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UTILITY FRANCHISES
Utilities holds certificates of public convenience issued by the PUC and
certain "grandfather rights" predating the adoption of the Pennsylvania Public
Utility Code and its predecessor statutes which it believes are adequate to
authorize it to carry on its business in substantially all the territory to
which it now renders gas and electric service. Under applicable Pennsylvania
law, Utilities also has certain rights of eminent domain as well as the right to
maintain its facilities in streets and highways in its territories.
OTHER GOVERNMENT REGULATION
In addition to regulation by the PUC, the gas and electric utility
operations of Utilities are subject to various federal, state and local laws
governing environmental matters, occupational health and safety, pipeline safety
and other matters. Certain of Utilities' activities involving the interstate
movement of natural gas, the transmission of electricity, transactions with
non-utility generators of electricity, like UGID, and other matters, are also
subject to the jurisdiction of FERC.
Utilities is subject to the requirements of the federal Resource
Conservation and Recovery Act, CERCLA and comparable state statutes with respect
to the release of hazardous substances on property owned or operated by
Utilities. See ITEM 3. "LEGAL PROCEEDINGS - Environmental Matters-Manufactured
Gas Plants." The electric generation activities of Utilities are also subject to
the Clean Air Act Amendments, the Federal Water Pollution Control Act and
comparable state statutes and regulations. See "UTILITY OPERATIONS - Electric
Operations - Environmental Factors."
EMPLOYEES
At September 30, 2002, Utilities and its subsidiaries had approximately
1,100 employees.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' operating segments for the 2002,
2001 and 2000 fiscal years appears in Note 10 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal
proceedings are pending involving Utilities, any of its subsidiaries or any of
their properties, and no such proceedings are known to be contemplated by
governmental authorities.
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ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
In 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 residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the 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 Gas Utility and
Electric Utility.
UGI Utilities 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 UGI Utilities is currently permitted to include in 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 (1) MGPs were formerly operated by it or owned or
operated by its former subsidiaries and (2) either environmental agencies or
private parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating two
claims against it relating to out-of-state sites.
Fishbein Family Partnership v. PPG Industries, Inc., et al. In July 1993,
Public Service Electric and Gas Company ("PSE&G") joined Utilities as a
third-party defendant in a civil action in the United States District Court for
the District of New Jersey, seeking damages as a result of contamination
relating to the former manufactured gas plant operations at Halladay Street in
Jersey City, New Jersey. The case principally involved claims by the Fishbein
Family Partnership against PPG Industries, Inc. for damages associated with
chemical contamination unrelated to gas plant operations. In November 2001, the
parties agreed voluntarily to dismiss all claims by and against PSE&G without
prejudice. All claims against Utilities have been dismissed, although they could
be re-instituted in the future.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On
September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit
against UGI Utilities, Inc. in the United States District Court for the Southern
District of New York, seeking contribution from Utilities for an allocated share
of response costs associated with investigating and assessing gas plant related
contamination at former manufactured gas plant sites in eleven communities in
Westchester County, New York. The complaint alleges that Utilities "owned and
operated" the plants prior to 1904. The complaint also seeks a declaration that
Utilities is responsible for an allocated percentage of future investigative and
remedial costs at the sites. ConEd has stated that the cost of remediation at
two of the sites, Tarrytown and White Plains, could exceed $20 million and $10
million respectively. ConEd has not provided specific estimates of costs at the
remainder of the sites and Utilities has no other information on which to base
estimates. Utilities continues to investigate its involvement at these sites and
is defending the claim.
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EnergyNorth Natural Gas, Inc. v. UGI Utilities, Inc. By letter dated
October 26, 2000, EnergyNorth Natural Gas, Inc. ("EnergyNorth") notified
Utilities that it has filed suit in the United States District Court for the
District of New Hampshire, seeking contribution from Utilities for response and
remediation costs associated with contamination on the site of a former
manufactured gas plant allegedly operated by former subsidiaries of Utilities.
EnergyNorth has not stated the amount of the costs and has provided no
information on which Utilities could make an estimate. Utilities is actively
defending the suit.
Management believes that under applicable law UGI Utilities should not be
liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that the subsidiary's separate corporate
form should be disregarded.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et. al. On February
11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas of
Montgomery County, Pennsylvania against more than fifty insurance companies,
including Associated Electric and Gas Insurance Services, Ltd. (AEGIS). The
complaint alleges that the defendants breached contracts of insurance by failing
to indemnify Utilities for certain environmental costs. To date, Utilities has
recovered a significant portion of its claims through settlements with most of
the defendants, including AEGIS. The court has not yet set a date for trial of
the claims against the remaining defendants.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the last
fiscal quarter of fiscal year 2002.
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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
Cash dividends declared on the Company's Common Stock totaled $37.9
million in fiscal year 2002, $35.3 million in fiscal year 2001 and $44.0 million
in fiscal year 2000.
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ITEM 6. SELECTED FINANCIAL DATA (a)
Year Ended
September 30,
------------------------------------------------------------------------
2002 2001 2000 1999 1998
--------- --------- --------- --------- ---------
(Thousands of dollars)
FOR THE PERIOD:
INCOME STATEMENT DATA:
Revenues $ 490,552 $ 584,762 $ 436,942 $ 420,647 $ 422,283
========= ========= ========= ========= =========
Net income $ 44,095 $ 48,137 $ 50,476 $ 38,868 $ 35,551
Dividends on preferred stock 1,550 1,550 1,550 1,550 2,160
--------- --------- --------- --------- ---------
Net income after dividends
on preferred stock $ 42,545 $ 46,587 $ 48,926 $ 37,318 $ 33,391
========= ========= ========= ========= =========
AT PERIOD END:
BALANCE SHEET DATA:
Total assets $ 798,123 $ 784,409 $ 751,137 $ 717,169 $ 690,317
========= ========= ========= ========= =========
Capitalization:
Debt:
Bank loans $ 37,200 $ 57,800 $ 100,400 $ 87,400 $ 68,400
Long-term debt including
current maturities 248,369 208,477 172,924 180,047 187,170
--------- --------- --------- --------- ---------
Total debt 285,569 266,277 273,324 267,447 255,570
Preferred stock subject to
mandatory redemption 20,000 20,000 20,000 20,000 20,000
Common equity 237,854 235,757 224,473 219,560 211,242
--------- --------- --------- --------- ---------
Total capitalization $ 543,423 $ 522,034 $ 517,797 $ 507,007 $ 486,812
========= ========= ========= ========= =========
RATIO OF CAPITALIZATION:
Total debt 52.6% 51.0% 52.8% 52.8% 52.5%
UGI Utilities preferred stock 3.7% 3.8% 3.9% 3.9% 4.1%
Common equity 43.7% 45.2% 43.3% 43.3% 43.4%
--------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0%
========= ========= ========= ========= =========
(a) Arthur Andersen LLP audited our consolidated financial statements for
2001, 2000, 1999 and 1998. See Item 15 - Notice Regarding Arthur Andersen
LLP.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In the following Management's Discussion and Analysis ("MD&A") of
Financial Condition and Results of Operations, Electric Utility and UGID's
electric generation business are collectively referred to as "Electric
Operations." The MD&A should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the business segment information in Note 10.
FISCAL 2002 COMPARED WITH FISCAL 2001
Increase
Year Ended September 30, 2002 2001 (Decrease)
- ------------------------ ---- ---- ----------
(Millions of dollars)
GAS UTILITY:
Revenues $404.5 $ 500.8 $ (96.3) (19.2)%
Total margin (a) $162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
System throughput - bcf 70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal (17.4)% 2.0% -- --
ELECTRIC OPERATIONS:
Revenues $ 86.0 $ 83.9 $ 2.1 2.5%
Total margin (a) $ 32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 13.2 $ 10.7 $ 2.5 23.4%
Distribution sales - gwh 933.6 945.5 (11.9) (1.3)%
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
(a) Gas Utility's total margin represents total revenues less cost of sales.
Electric Operation's total margin represents total revenues less cost of
sales and revenue-related taxes, i.e. Electric Utility gross receipts
taxes. For financial statement purposes, revenue-related taxes are
included in "taxes other than income taxes" on the Consolidated Statements
of Income.
GAS UTILITY.
Weather in Gas Utility's service territory during Fiscal 2002 based upon
heating degree days was 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 the effects of a weak economy on commercial and industrial natural
gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in Fiscal 2002 Gas Utility revenues reflects
the impact of lower PGC rates, resulting from the pass through of lower natural
gas costs to firm- residential, commercial and industrial (collectively,
"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
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million in Fiscal 2001 reflecting lower natural gas costs and the decline in
core-market throughput in Fiscal 2002.
The decline in Gas Utility margin principally reflects a $6.0 million
decline in core-market margin due to the lower sales; a $6.6 million decline in
interruptible margin due principally to the flowback of certain interruptible
customer margin to core-market customers beginning December 1, 2001 pursuant to
the Gas Restructuring Order; and lower firm delivery service total margin due to
lower sales. 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 margin and a decrease in
pension income partially offset by lower operating expenses. Operating expenses
declined $4.1 million primarily as a result of lower charges for uncollectible
accounts and lower distribution system expenses. Depreciation expense declined
$1.2 million due to a change effective April 1, 2002 in the estimated useful
lives of Gas Utility's natural gas distribution assets resulting from an asset
life study required by the PUC.
ELECTRIC OPERATIONS. The decline in kilowatt-hour sales in Fiscal 2002
reflects the effects on heating-related sales of significantly warmer winter
weather partially offset by the effects on air conditioning sales of warmer
summer weather. Notwithstanding the decrease in total kilowatt-hour sales,
revenues increased $2.1 million principally due to an increase in state tax
surcharge revenue and greater third-party sales of electricity produced by our
Pennsylvania-based electric generation facilities. Electric Operations cost of
sales was $48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001
principally reflecting the impact of the lower sales and lower purchased power
unit costs partially offset by the full-period increase to cost of sales
resulting from the transfer of our Hunlock Creek electricity generation assets
to Hunlock Creek Energy Ventures ("Energy Ventures") in December 2000. Energy
Ventures is an electricity generation joint-venture with a subsidiary of
Allegheny Energy, Inc. Subsequent to the formation of Energy Ventures, our
electric generating business purchases its share of the power produced by Energy
Ventures rather than producing this electricity itself. As a result, the cost of
this power is reflected in cost of sales whereas prior to the formation of
Energy Ventures such costs were reflected as operating and administrative
expenses.
Electric Operations total margin increased $4.2 million in Fiscal 2002 as
a result of lower purchased power unit costs partially offset by the
weather-driven decline in sales. Operating income increased $2.5 million
reflecting the greater total margin and lower operating costs subsequent to the
formation of Energy Ventures partially offset by a decline in other income.
INTEREST EXPENSE. The lower interest expense in Fiscal 2002 resulted
primarily from lower levels of long-term debt and lower bank loans outstanding.
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FISCAL 2001 COMPARED WITH FISCAL 2000
Increase
Year Ended September 30, 2001 2000 (Decrease)
- ------------------------ ---- ---- ----------
(Millions of dollars)
GAS UTILITY:
Revenues $ 500.8 $ 359.0 $ 141.8 39.5 %
Total margin $ 177.9 $ 170.8 $ 7.1 4.2 %
Operating income $ 87.8 $ 86.2 $ 1.6 1.9 %
System throughput - bcf 77.3 79.7 (2.4) (3.0)%
Degree days - % colder (warmer)
than normal 2.0% (9.9)% -- --
ELECTRIC OPERATIONS:
Revenues $ 83.9 $ 77.9 $ 6.0 7.7 %
Total margin $ 28.6 $ 40.8 $ (12.2) (29.9)%
Operating income $ 10.7 $ 15.1 $ (4.4) (29.1)%
Distribution sales - gwh 945.5 907.2 38.3 4.2 %
GAS UTILITY. Although temperatures based upon heating degree days were
colder in Fiscal 2001, total system throughput declined 3.0% as the impact of
the colder weather was more than offset by lower interruptible and firm delivery
service volumes, the impact of price-induced customer conservation, and the
effects of a slowing economy. Natural gas prices were significantly higher in
Fiscal 2001 than in the prior year. The higher prices resulted in fuel switching
by many of our interruptible customers, who have the ability to switch to
alternate fuels, and encouraged price-induced conservation by many of our firm
customers. Throughput to our core-market customers increased 3.3 bcf (10.6%)
reflecting the impact of the colder Fiscal 2001 weather.
The significant increase in Gas Utility revenues is primarily a result of
higher core-market revenues reflecting greater PGC rates and higher revenues
from sales to customers not on our distribution system ("off-system sales"). Gas
Utility's tariffs permit it to pass through prudently incurred gas costs to its
core-market customers through higher PGC rates. Gas Utility cost of gas totaled
$322.9 million in Fiscal 2001 compared with $184.2 million in Fiscal 2000
principally reflecting the higher average PGC rates and, to a lesser extent,
higher core-market and off-system sales.
Gas Utility total margin increased $7.1 million reflecting a $12.1 million
increase in core-market margin partially offset by lower total margin from
interruptible customers. The decline in interruptible margin reflects lower
average interruptible unit margins due to a decline in the spread between oil
and natural gas prices and the lower interruptible throughput.
Gas Utility operating income increased $1.6 million as the previously
mentioned increase in total margin and an increase in pension income was
partially offset by higher operating and administrative expenses. The increase
in operating and administrative expenses includes, among
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other things, greater allowances for uncollectible accounts, reflecting
significantly higher Fiscal 2001 customer bills, and lower income from
environmental insurance litigation settlements. Such settlements totaled $0.9
million in Fiscal 2001 compared with $4.5 million in Fiscal 2000. Depreciation
expense increased $1.1 million reflecting greater depreciation associated with
distribution system capital expenditures.
ELECTRIC OPERATIONS. Electric Utility distribution system sales in Fiscal
2001 increased 4.2% on favorable weather. Revenues increased as a result of the
higher distribution system sales as well as off-system sales of electricity
generated by Energy Ventures. Cost of sales totaled $51.9 million in Fiscal 2001
compared to $34.2 million in the prior year. The increase reflects higher
per-unit purchased power costs, the impact on cost of sales resulting from the
formation of Energy Ventures, and the higher Fiscal 2001 sales.
Electric Operations total margin decreased $12.2 million as a result of
the higher purchased power costs. Operating income declined less than the
decline in total margin reflecting lower power production and depreciation
expenses subsequent to the formation of Energy Ventures and lower utility realty
taxes.
INTEREST EXPENSE. The greater interest expense in Fiscal 2001 resulted
primarily from greater long-term debt outstanding.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities debt outstanding totaled $285.6 million at September 30, 2002.
Included in this amount is $37.2 million under revolving credit agreements.
Utilities may borrow up to a total of $97 million under its revolving
credit agreements. The revolving credit agreements contain financial covenants
including interest coverage ratios, debt service, and minimum tangible net
worth. In September 2002, Utilities issued $40 million face value of its Series
C Medium-Term Notes under a shelf registration statement with the U.S.
Securities and Exchange Commission ("SEC"). The proceeds of the issuance were
used after the end of Fiscal 2002 principally to repay debt maturing in October
2002. Utilities may issue up to an additional $85 million of debt securities
under the shelf registration statement.
Based upon cash expected to be generated from operations, the expected
ability to refinance all or a portion of long-term debt maturing in Fiscal 2003,
and borrowings available under revolving credit agreements, management believes
that Utilities will be able to meet its anticipated contractual and projected
cash commitments in Fiscal 2003. For a more detailed discussion of Utilities'
debt and credit facilities, see Note 3 to Consolidated Financial Statements.
-17-
CASH FLOWS
OPERATING ACTIVITIES. Cash provided by operating activities was $55.1
million in Fiscal 2002 compared to $76.1 million in Fiscal 2001. Changes in
working capital required $23.3 million of operating cash flow in Fiscal 2002
compared to $3.8 million of operating cash flow provided in Fiscal 2001. Cash
flow before working capital changes increased to $78.4 million in Fiscal 2002
compared to $72.3 million in Fiscal 2001, notwithstanding the decrease in Fiscal
2002 net income, reflecting in large part higher noncash charges for deferred
income taxes.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment
totaled $35.9 million during Fiscal 2002 compared to $36.8 million during Fiscal
2001. Cash used for investing activities in Fiscal 2001 included a $6 million
cash contribution relating to the formation of Energy Ventures in December 2000.
FINANCING ACTIVITIES. We paid cash dividends to UGI totaling $37.9 million
in Fiscal 2002 compared to $35.3 million in Fiscal 2001. We also paid dividends
of $1.6 million on our preferred stock. In September 2002, we issued $40 million
face amount of Medium-Term Notes and used the proceeds after the end of Fiscal
2002 principally to repay debt maturing in October 2002. During Fiscal 2001, we
issued $50 million face amount of Medium-Term Notes and used the proceeds for
working capital purposes, to repay $15 million of maturing Medium-Term Notes,
and to reduce borrowings under our revolving credit agreements.
UTILITIES PENSION PLAN
Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI, Utilities, and certain of UGI's other subsidiaries. During
Fiscal 2002 and 2001, the market value of plan assets was negatively affected by
persistent declines in the equity markets. Notwithstanding the significant
decline in the market value of plan assets during these years, at September 30,
2002 the Pension Plan's assets exceeded its accumulated benefit obligations by
approximately $7.2 million. Utilities is in full compliance with regulations
governing defined benefit pension plans, including ERISA rules and regulations,
and does not anticipate it will be required to make a contribution to the
Pension Plan in Fiscal 2003. Pretax pension income reflected in Fiscal 2002,
2001 and 2000 results was $3.9 million, $5.7 million, and $2.9 million,
respectively. Pension income in Fiscal 2003 is expected to decline to
approximately $1.0 million principally as a result of the impact of recent
declines in the market value of Pension Plan assets.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business
segment for Fiscal 2002, 2001 and 2000. We also provide amounts we expect to
spend in Fiscal 2003. We expect to finance a substantial portion of Fiscal 2003
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.
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Year Ended September 30, 2003 2002 2001 2000
- ------------------------ ---- ---- ---- ----
(Millions of dollars) (estimate)
Gas Utility $ 39.6 $ 31.0 $ 31.8 $ 31.7
Electric Utility 5.3 4.9 5.0 4.7
------ ------ ------ ------
$ 44.9 $ 35.9 $ 36.8 $ 36.4
====== ====== ====== ======
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The following table presents significant contractual cash obligations
under agreements existing as of September 30, 2002 (in millions).
Fiscal Fiscal
2003 - 2004 2005 - 2006 Thereafter Total
----------- ----------- ---------- -----
Long-term debt $ 76.0 $ 70.0 $ 102.0 $ 248.0
UGI Utilities redeemable preferred stock -- 2.0 18.0 20.0
Operating leases 5.4 3.9 5.6 14.9
Gas and Electric utility supply agreements 202.9 80.2 107.3 390.4
------- ------- ------- -------
Total $ 284.3 $ 156.1 $ 232.9 $ 673.3
======= ======= ======= =======
REGULATORY MATTERS
The PUC approved a settlement establishing rules for Electric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively the "POLR
Settlement"). Under the terms of the POLR Settlement, Electric Utility
terminated stranded cost recovery through its CTC from commercial and industrial
("C&I") customers on July 31, 2002, and from residential customers on October
31, 2002, and is no longer subject to the statutory rate caps as of August 1,
2002 for C&I customers and as of November 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. Charges for generation service will (1)
initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 2004; and
(3) may be set at market rates thereafter. Electric Utility may also offer
multiple year POLR contracts to its customers. The POLR Settlement provides for
annual shopping periods during which customers may elect to remain on POLR
service or choose an alternate supplier. Customers who do not select an
alternate supplier will be obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service at a time
other than during the annual shopping period must remain on POLR service until
the date of the second open shopping period after returning.
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C&I customers who return to POLR service at a time other than during the annual
shopping period must remain on POLR service until the next open shopping period,
and may, in certain circumstances, be subject to generation rate surcharges.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order")
approving Gas Utility's restructuring plan filed by Gas Utility pursuant to
Pennsylvania's Natural Gas Choice and Competition Act. Among other things, the
implementation of the Gas Restructuring Order resulted in an increase in Gas
Utility's core-market base rates effective October 1, 2000. This base rate
increase was designed to generate approximately $16.7 million in additional net
annual revenues. In accordance with the Gas Restructuring Order, Gas Utility
reduced its core-market PGC rates by an annualized amount of $16.7 million in
the first 14 months following the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its PGC
rates by amounts equal to the margin it receives from interruptible customers
using pipeline capacity contracted by Gas Utility for core-market customers. As
a result, Gas Utility operating results are more sensitive to the effects of
heating-season weather and less sensitive to the market prices of alternative
fuels.
MANUFACTURED GAS PLANTS
From the late 1800s through the mid-1900s, 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 residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
Utilities 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 on which (1) MGPs were formerly operated by it or owned or operated
by its former subsidiaries and (2) either environmental agencies or private
parties are investigating the extent of environmental contamination or
performing environmental remediation. Utilities is currently litigating two
claims against it relating to out-of-state sites.
Management believes that under applicable law Utilities should not be
liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that Utilities
directly operated, or that were owned or operated by former
-20-
subsidiaries of Utilities, if a court were to conclude that the subsidiary's
separate corporate form should be disregarded.
Utilities has filed suit against more than fifty insurance companies
alleging that the defendants breached contracts of insurance by failing to
indemnify Utilities for certain environmental costs. The suit seeks to recover
more than $11 million in such costs. During 2002, 2001 and 2000, Utilities
entered into settlement agreements with several of the insurers and recorded
pre-tax income of $0.4 million, $0.9 million and $4.5 million, respectively,
which amounts are included in operating and administrative expenses in the
Consolidated Statements of Income.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding
Disclosure About Critical Accounting Policies," the Company has identified the
following critical accounting policies that are most important to the portrayal
of the Company's financial condition and results of operations. The following
accounting policies require management's most subjective or complex judgments,
as a result of the need to make estimates regarding matters that are inherently
uncertain.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are
involved in litigation regarding pending claims and legal actions that arise in
the normal course of our businesses. In addition, Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be present. In accordance with accounting
principles generally accepted in the United States, 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 its various classes of depreciable property. Changes
in the estimated useful lives of property, plant and equipment could have a
material effect on our results of operations.
REGULATORY ASSETS AND LIABILITIES. Gas Utility, and Electric Utility's
distribution business, are subject to regulation by the Pennsylvania Public
Utility Commission. In accordance with SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," we record the effects of rate regulation in our
financial statements as regulatory assets or regulatory liabilities. We
continually assess whether the regulatory assets are probable of future recovery
by evaluating the
-21-
regulatory environment, recent rate orders and public statements issued by the
PUC and the status of any pending deregulation legislation. If future recovery
of regulatory assets ceases to be probable, the elimination of those regulatory
assets would adversely impact our results of operations. As of September 30,
2002, our regulatory assets totaled $62.0 million.
MARKET RISK DISCLOSURES
Gas Utility's tariffs contain clauses that permit recovery of
substantially all of the prudently incurred cost of natural gas it sells to its
customers. The recovery clauses provide for a periodic adjustment for the
difference between the total amount actually collected from customers and the
recoverable costs incurred. Because of this ratemaking mechanism, there is
limited commodity price risk associated with our Gas Utility operations.
During Fiscal 2002, 2001 and 2000, Electric Utility purchased all of its
electric power needs, in excess of the electric power it obtained from its
interests in electric generating facilities, under power supply arrangements of
various lengths and on the spot market. Beginning September 2002, Electric
Utility began purchasing its power needs from electricity suppliers under
fixed-price energy and capacity contracts and, to a much lesser extent, on the
spot market, and our electricity generation businesses began selling on the spot
market electric power produced from its interests in electricity generating
facilities to third parties. Prices for electricity can be volatile especially
during periods of high demand or tight supply. Although the generation component
of Electric Utility's rates is subject to various rate cap provisions as a
result of the Electricity Restructuring Order and the POLR Settlement, Electric
Utility's fixed-price contracts with electricity suppliers mitigate most risks
associated with offering customers a fixed price during the contract periods.
However, should any of the suppliers under these contracts fail to provide
electric power under the terms of the power and capacity contracts, increases,
if any, in the cost of replacement power or capacity would negatively impact
Electric Utility results. In order to reduce this non-performance risk, Electric
Utility has diversified its purchases across several suppliers and entered into
bilateral collateral arrangements with certain of them.
We have both fixed-rate and variable-rate debt. Changes in interest rates
impact the cash flows of variable-rate debt but generally do not impact its fair
value. Conversely, changes in interest rates impact the fair value of fixed-rate
debt but do not impact their cash flows.
Our variable-rate debt includes borrowings under our revolving credit
agreements. These agreements provide for interest rates on borrowings that are
indexed to short-term market interest rates. Based upon the average level of
borrowings outstanding under these agreements in Fiscal 2002 and Fiscal 2001, an
increase in short-term interest rates of 100 basis points (1%) would have
increased annual interest expense by $0.5 million and $0.7 million,
respectively.
-22-
The remainder of our debt outstanding is subject to fixed rates of
interest. A 100 basis point increase in market interest rates would result in
decreases in the fair value of this fixed-rate debt of $11.0 million and $8.5
million at September 30, 2002 and 2001, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $12.0 million and $9.2 million at September 30, 2002 and
2001, respectively.
In order to reduce interest rate risk associated with near-term issuances
of fixed-rate debt, we may enter into interest rate protection agreements. The
fair value of our interest rate protection agreements, which have been
designated and qualify as cash flow hedges, was $(1.2) million at September 30,
2002. An adverse change in interest rates on ten-year U.S. treasury notes of 100
basis points would result in a $2.2 million decrease in the fair value of these
interest rate protection agreements.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No.
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144");
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146").
SFAS 143 addresses financial accounting and reporting for legal
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred with a corresponding increase in the carrying value of the
related asset. Entities shall subsequently charge the retirement cost to expense
using a systematic and rational method over the related asset's useful life and
adjust the fair value of the liability resulting from the passage of time
through charges to operating expense. We adopted SFAS 143 effective October 1,
2002. The adoption of SFAS 143 did not have a material effect on our financial
position or results of operations.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121") and
the accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" as it relates to the disposal of a segment of a business. SFAS 144
establishes a single accounting model for long-lived assets to be disposed of
based upon the framework of SFAS 121, and resolves significant implementation
issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption
of SFAS 144 did not affect our financial position or results of operations.
-23-
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"),
effective May 15, 2002. SFAS 4 had required that material gains and losses on
extinguishment of debt be classified as an extraordinary item. Under SFAS 145,
it is less likely that a gain or loss on extinguishment of debt would be
classified as an extraordinary item in our Consolidated Statement of Income.
Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases,"
to require that certain lease modifications that have economic effects similar
to sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. The provisions of SFAS 145 relating to leases
became effective for transactions occurring after May 15, 2002. The adoption of
SFAS 145 did not affect our financial position or results of operations.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force ("EITF") No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity." Generally, SFAS 146 requires that a liability for costs
associated with an exit or disposal activity, including contract termination
costs, employee termination benefits and other associated costs, be recognized
when the liability is incurred. Under EITF No. 94-3, a liability was recognized
at the date of an entity's commitment to an exit plan. SFAS 146 will be
effective for disposal activities initiated after December 31, 2002.
FORWARD-LOOKING STATEMENTS
Information 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 may 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 reasonable. However,
we caution you that actual results almost always vary from assumed facts or
bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking
statements, you should keep in mind the following important factors which could
affect our future results and could cause those results to differ materially
from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) price volatility and availability of
oil, electricity and natural gas and the capacity to transport to market areas;
(3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) liability for environmental claims; (6) customer conservation measures and
improvements in energy efficiency and technology resulting in reduced demand;
(7) adverse labor relations; (8)
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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 distributing 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 from those expressed in any of our
forward-looking statements. Other unknown or unpredictable factors could also
have material adverse effects on future results. We undertake no obligation to
update publicly any forward-looking statement whether as a result of new
information or future events.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
"Quantitative and Qualitative Disclosures About Market Risk" are contained
in Management's Discussion and Analysis of Financial Condition and Results of
Operations under the caption "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-27 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 2002, the Company engaged a new independent auditor,
PricewaterhouseCoopers LLP. The information required by Item 9 is incorporated
in this Report by reference to the Company's Current Report on Form 8-K dated
May 21, 2002.
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PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Lon R. Greenberg 52 1994 Mr. Greenberg has been Chairman of the Board of Directors of
UGI Utilities, Inc. since August 1996. He was formerly Vice
Chairman of the Board from 1995 to 1996, and Senior Vice
President - Legal and Corporate Development from 1989 to
1994.
James W. Stratton 66 1979 Mr. Stratton is the Chairman, Chief Executive Officer, and a
director of Stratton Management Company (an investment
advisory and financial consulting firm) (since 1972). Mr.
Stratton also serves as a director of AmeriGas Propane,
Inc.; Stratton Growth Fund, Inc.; Stratton Monthly Dividend
REIT Shares, Inc.; Stratton Small-Cap Value Fund; Teleflex,
Inc.; and BE&K, Inc.
Richard C. Gozon 64 1989 Mr. Gozon retired as Executive Vice President of
Weyerhaeuser Company in April of 2002 (an integrated forest
products company) and Chairman of Norpac (North Pacific
Paper Company, a joint venture with Nippon Paper Industries
headquartered in Tokyo, Japan) positions he has held since
1994. Mr. Gozon was formerly a director (1984 to 1993),
President and Chief Operating Officer of Alco Standard
Corporation (a provider of paper and office products) (1988
to 1993); Executive Vice President and Chief Operating
Officer (1988), President (1985 to 1987) of Paper
Corporation of America. He also serves as a director of
AmeriSource Bergen Corp.; and Triumph Group, Inc.
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Stephen D. Ban 62 1991 Dr. Ban is currently serving as the Director of the
Technology Transfer Division of the Argonne National
Laboratory (science-based Department of Energy laboratory
dedicated to advancing the frontiers of science in energy,
environment, biosciences and materials. He previously served
as President and Chief Executive Officer of the Gas Research
Institute (GRI), a gas industry research and development
organization funded by distributors, transporters, and
producers of natural gas (1987 through 1999). He also served
as Executive Vice President. Prior to coming to GRI in 1981,
he was Vice President, Research and Development and Quality
Control of Bituminous Materials, Inc. Dr. Ban also serves as
a director of Energen Corporation.
Robert J. Chaney 60 1999 Mr. Chaney has been President and Chief Executive Officer of
UGI Utilities, Inc. (since March 1999). He previously served
as Executive Vice President - Utilities (1998 to 1999) and
Vice President and General Manager-Gas Utility Division of
the Company (1991 to 1998).
Marvin O. Schlanger 54 1998 Mr. Schlanger is a Principal in the firm of Cherry Hill
Chemical Investments, L.L.C. (management services and
capital for chemical and allied industries) (October 1998 to
present) and Chairman and Chief Executive Officer of
Resolution Performance Products, Inc. (a producer and
marketer of specialty and intermediate chemicals) (November
2000 to present). Mr. Schlanger was previously President and
Chief Executive Officer (May 1998 to October 1998),
Executive Vice President and Chief Operating Officer (1994
to May 1998) and a director (1994 to 1998) of ARCO Chemical
Company. Mr. Schlanger also serves as a director of Wellman,
Inc.
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Thomas F. Donovan 69 1998 Mr. Donovan retired as Vice Chairman of Mellon Bank on
January 31, 1997, a position he had held since 1988. He
continues to serve as a director of AmeriGas Propane, Inc.
and Nuclear Electric Insurance Ltd.
Anne Pol 55 1999 (and Mrs. Pol is President and Chief Operating Officer of Trex
1993-1997) Enterprises Corporation (a high technology research and
development company), a position she has held since
October 15, 2001. She previously served as Senior Vice
President, Thermo Electron Corporation (environmental
monitoring, analytical instruments and a major producer of
recycling equipment, biomedical products and alternative
energy systems) (1998 to 2001); and Vice President (1996
to 1998). Mrs. Pol also served as 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 (1990 to 1991).
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Ernest E. Jones 58 2002 Mr. Jones is President and Chief Executive Officer of
Philadelphia Workforce Development Corporation (an agency
which funds, coordinates and implements employment and
training activities in Philadelphia), a position he has
held since 1998. He formerly served as President and
Executive Director of the Greater Philadelphia Urban
Affairs Coalition (1983 to 1998). Mr. Jones also served
as Executive Director of Community Legal Services, Inc.
(1977 to 1983). Mr. Jones also serves as a director of
the African American Museum in Philadelphia; First Union
Regional Foundation; Thomas Jefferson University; United
Way of Southeastern Pennsylvania; and the William Penn
Foundation.
(1) All of the directors except Mr. Chaney also serve as directors of UGI
Corporation. In addition, Messrs. Greenberg, Donovan, Gozon, and Stratton serve
as directors of AmeriGas Propane, Inc., the General Partner of AmeriGas
Partners, L.P.
EXECUTIVE OFFICERS
Name Age Position
- ---- --- --------
Lon R. Greenberg 52 Chairman of the Board of Directors
Robert J. Chaney 60 President and Chief Executive Officer
Peter G. Terranova 50 Vice President -Operations
John C. Barney 54 Senior Vice President-Finance
Brendan P. Bovaird 54 Vice President and General Counsel
Vicki O. Ebner 43 Vice President -Marketing and Gas Supply
Directors are elected annually. All officers are elected for a one-year
term at the organizational meeting of the Board of Directors held each year.
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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.
The following is a summary of the business experience of the executive
officers listed above during at least the last five years:
Lon R. Greenberg
Mr. Greenberg is Chairman of the Board of the Company (since August 1996),
having served as a Director since 1994; he is also Chairman (since 1996), Chief
Executive Officer (since August 1995) and President (since 1994) of UGI. In
addition, he is Chairman of AmeriGas Propane, Inc. (since August 1996). Mr.
Greenberg previously served as President and Chief Executive Officer of AmeriGas
Propane, Inc. (1996 to 2000).
Robert J. Chaney
Mr. Chaney is President and Chief Executive Officer of the Company (since
March 1999). He previously served as Executive Vice President - Utilities (1998
to 1999) and Vice President and General Manager-Gas Utility Division of the
Company (1991 to 1998).
John C. Barney
Mr. Barney is Senior Vice President-Finance of Utilities (since March
1999). Previously, Mr. Barney served as Vice President-Finance and Accounting
(1992 to 1999).
Brendan P. Bovaird
Mr. Bovaird is Vice President and General Counsel of the Company (since
April 1995). He is also Vice President and General Counsel of UGI Corporation
and AmeriGas Propane, Inc. (since April 1995). Mr. Bovaird previously served as
Division Counsel and Member of the Executive and Operations Committees of
Wyeth-Ayerst International Inc. (1992 to 1995).
Peter G. Terranova
Mr. Terranova is Vice President - Operations (since 1999). He previously
served as Vice President - Marketing and Rates (1994-2000).
Vicki O. Ebner
Mrs. Ebner is Vice President - Marketing, Rates and Gas Supply (since
1999). She previously served as Vice President - Gas Supply (1998-1999),
Customer Relations Manager - Harrisburg (1996-1998) and Manager - Gas Supply
Services and Regulatory Affairs (1991-1995).
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ITEM 11. EXECUTIVE COMPENSATION
The following table shows cash and other compensation paid or accrued to
the Company's Chief Executive Officer and each of its four other most highly
compensated executive officers, (collectively, the "Named Executives") for the
last three fiscal years.
Summary Compensation Table
Annual Compensation Long Term Compensation
------------------------------- ------------------------------------
Awards Payouts
--------------------------- -------
Other
Annual Restricted Securities All Other
Name and Principal Fiscal Compen- Stock underlying LTIP Compensation
Position Year Salary Bonus (1) sation(2) Awards (3) Options / SARs Payouts (4)
-------- ---- ------ --------- --------- ---------- -------------- ------- ---
Robert J. Chaney 2002 $294,415 $105,754 $6,814 $120,800 18,000 $0 $9,867
President and Chief $120,800
Executive Officer(6) $120,800
2001 $285,500 $144,144 $7,511 $64,688 0 $0 $9,609
$133,450
2000 $264,307 $141,570 $7,679 $0 45,000 $0 $7,569
Lon R. Greenberg, 2002 $705,015 $521,092 $15,342 $785,200 120,000 $0 $28,033
Chairman(5)(6) $785,200
$785,200
2001 $667,799 $595,010 $14,849 $323,438 0 $0 $20,939
$1,000,875
2000 $640,662 $262,836 $13,092 $0 225,000 $0 $20,417
Brendan P. Bovaird, 2002 $232,683 $95,459 $5,449 $90,600 14,500 $0 $7,411
Vice President and
General Counsel $90,600
(5)(6) $90,600
2001 $222,283 $96,708 $5,012 $38,813 0 $0 $6,112
$120,105
2000 $210,392 $49,349 $7,264 $0 28,000 $0 $5,927
John C. Barney 2002 $176,033 $64,262 $6,340 $60,400 8,000 $0 $5,124
Senior Vice President $60,400
- -Finance $60,400
2001 $170,826 $51,710 $3,827 $31,050 0 $0 $5,167
$68,059
2000 $164,848 $58,806 $2,145 $0 15,000 $0 $4,453
Mark R. Dingman, 2002 $156,003 $35,161 $7,335 $60,400 8,000 $0 $3,510
Vice President and $60,400
General Manager - $60,400
Electric Utility 2001 $152,882 $0 $6,862 $38,813 0 $0 $4,258
$88,077
2000 $149,583 $36,383 $6,907 $0 28,000 $0 $4,385
(1) Bonuses earned under the Annual Bonus Plan are for the year reported,
regardless of the year paid. The Company's Annual Bonus Plan is based on
the achievement of business and/or financial performance objectives, which
support business plans and goals. Bonus opportunities vary by position and
for Fiscal 2002 ranged from 0% to 86% of base salary for Mr. Chaney, 0% to
184% of base salary for Mr. Greenberg, 0% to 104% of base salary for Mr.
Bovaird, 0% to 60% of base salary for Mr. Barney and 0% to 52% of base
salary for Mr. Dingman.
(2) Amounts represent tax payment reimbursements for certain benefits and, for
Messrs. Barney and Bovaird, above-market interest on deferred
compensation.
(3) Effective January 1, 2002, the Board of Directors of UGI Corporation,
approved three phantom performance-contingent
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restricted stock awards ("Restricted Shares") to the Named Executives
under the UGI Corporation 2000 Stock Incentive Plan. The restriction
period for all three awards will end on December 31, 2004 provided that
certain performance criteria are met for each performance period. Each
award has a separate performance period as follows: January 1, 2002
through December 31, 2002, January 1, 2002 through December 31, 2003, and
January 1, 2002 through December 31, 2004. The performance requirement is
that UGI's Total Shareholder Return (TSR) during the relevant performance
period equals the median of a peer group. The peer group is the group of
companies that comprises the S&P Utilities Index. The actual amount of the
award may be higher or lower than the original grant, or even zero, based
on UGI's TSR percentile rank relative to the companies in the S&P
Utilities Index. The maximum payout potential is 200% of the original
award. The share price used for determining the TSR at the beginning and
the end of each performance period will be the average price for the
90-day period preceding each December 31st.
The dollar values shown in the restricted stock awards column of the table
above represent the aggregate value of each award on the date of grant,
determined by multiplying the number of shares awarded by the closing
price of UGI Common Stock on the New York Stock Exchange on the effective
dates of the respective grants.
Based on the closing stock price of UGI Common Stock on the New York Stock
Exchange on September 30, 2002, Mr. Greenberg's 128,000 Restricted Shares
had a market value of $4,652,800; Mr. Chaney's 19,500 Restricted Shares
had a market value of $708,825; Mr. Bovaird's 15,000 Restricted Shares had
a market value of $545,250; Mr. Barney's 9,750 Restricted Shares had a
market value of $354,413 and Mr. Dingman's 10,800 Restricted Shares had a
market value of $392,580.
(4) Amounts represent matching contributions by the Company or UGI in
accordance with the provisions of the UGI Utilities, Inc. Employee Savings
Plan and/or allocations under the Executive Retirement Plan. During 2002,
2001 and 2000, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: for each of Messrs.
Greenberg, Chaney, Bovaird and Barney $3,825, $3,825, and $3,825; and Mr.
Dingman $3,510, $3,825, and $3,825; (ii) under the Supplemental Executive
Retirement Plan: Mr. Greenberg, $24,208, $17,114, and $16,592; Mr. Chaney,
$6,042, $5,784, and, $3,744; Mr. Bovaird, $3,586, $2,287, and $2,102; Mr.
Barney, $1,299, $1,342, and $628; and Mr. Dingman, $0, $433, and $560.
(5) Compensation for Mr. Greenberg is attributable to his employment as
Chairman, President and Chief Executive Officer of UGI Corporation.
Compensation for Mr. Bovaird is attributable to his employment as Vice
President and General Counsel of UGI Corporation. Mr. Greenberg and Mr.
Bovaird receive no compensation from UGI Utilities, Inc.
(6) Compensation reported for Messrs. Greenberg, Bovaird and Chaney is also
reported in the Proxy Statement for UGI's 2002 Annual Meeting of
Shareholders and is not additive.
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Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values
The following table shows information for fiscal year 2002 concerning
exercised and unexercised stock options for shares of UGI Common Stock for each
of the Named Executives.
Option Exercises in Fiscal 2002
And Fiscal Year-End Option Values
Value of
Number of Securities Unexercised
Underlying Unexercised In-The-Money
Number of Options at Options at
Shares Fiscal Year End Fiscal Year End (2)
Acquired on Value -------------------------- ------------------------------
Name Exercise Realized (1) Exercisable Unexercisable Exercisable Unexercisable
---- -------- ------------ ----------- ------------- ----------- -------------
Robert J. Chaney 13,639 $135,697 78,889 33,000 $1,152,475 $339,375
Lon R. Greenberg 123,959 $1,661,893 468,750 251,250 $7,113,281 $2,767,969
Brendan P. Bovaird 0 $0 48,667 14,500 $705,289 $83,375
John C. Barney 0 $0 20,000 13,000 $294,500 $124,625
Mark R. Dingman 18,666 $220,176 0 17,334 $0 $192,777
(1) Value realized is calculated on the difference between the option exercise
price and the closing market price of UGI's Common Stock on the date
of exercise multiplied by the number of shares to which the exercise
relates.
(2) The closing price of UGI's Common Stock as reported on the New York
Stock Exchange Composite tape on September 30, 2002 was $36.35 and is used
in calculating the value of unexercised options.
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Option Grants in Last Fiscal Year
The following table shows information on grants of stock options for UGI
Corporation Common Stock during fiscal year 2002 to each of the Named
Executives.
OPTION GRANTS IN LAST FISCAL YEAR
Grant Date
Individual Grants Value
----------------- -----
Number of
Securities % of Total
Underlying Options Granted Grant Date
Options to Employees in Exercise Present
Name Granted Fiscal Year (1) or Base Price Expiration Date Value (2)
---- ------- --------------- ------------- --------------- ---------
Robert J. Chaney 18,000 4.02% $30.600 12/31/2011 $92,093
Lon R. Greenberg 120,000 26.77% $30.600 12/31/2011 $613,953
Brendan P. Bovaird 14,500 3.23% $30.600 12/31/2011 $74,186
John C. Barney 8,000 1.78% $30.600 12/31/2011 $40,930
Mark R. Dingman 8,000 1.78% $30.600 12/31/2011 $40,930
(1) A total of 448,250 options were granted to employees and executive
officers of the Company during fiscal year 2002 under the 1992
Non-Qualified Stock Option Plan, the 2000 Stock Incentive Plan and the
2002 Non-Qualified Stock Option Plan. Under each Plan, the option exercise
price is not less than 100% of the fair market value of UGI's Common Stock
on the date of grant. All options will vest at the rate of 33% per year on
the anniversary of the grant date. Options 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.
(2) Based on the Black-Scholes options pricing model. The assumptions used in
calculating the grant date present value are as follows:
- Three years of closing monthly stock price and dividend observations
were used to calculate the stock volatility and dividend yield
assumptions.
- Stock volatility 29.10%
- Stock's dividend yield 6.70%
- Length of option term 10 years
- Annualized risk-free interest rate 5.54%
- Discount of risk of forfeiture 0% per year
All options were granted at fair market value. The actual value, if any, the
executive may realize will depend on the excess of the stock price on the date
the option is exercised over the exercise price. There is no assurance that the
value realized by the executive will be at or near the value estimated by the
Black-Scholes model.
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RETIREMENT BENEFITS
The following table shows the annual benefits payable upon retirement to
the Named Executive Officers under the Retirement Income Plan for Employees of
UGI Utilities, Inc. and participating employers (the "Retirement Plan") and the
UGI Supplemental Executive Retirement Plan. The amounts shown assume the
executive retires in 2002 at age 65, and that the aggregate benefits are not
subject to statutory maximums.
PENSION PLAN BENEFITS TABLE
ANNUAL PLAN BENEFIT FOR YEARS CREDITED SERVICE SHOWN (1)
FINAL 5-YEAR
AVERAGE ANNUAL 5 10 15 20 25 30 35 40
EARNINGS (2) YEARS YEARS YEARS YEARS YEARS YEARS YEARS YEARS
------------ ----- ----- ----- ----- ----- ----- ----- -----
$ 200,000 $ 19,000 $ 38,000 $ 57,000 $ 76,000 $ 95,000 $ 114,000 $ 133,000 $ 136,800 (3)
$ 400,000 $ 38,000 $ 76,000 $114,000 $152,000 $190,000 $ 228,000 $ 266,000 $ 273,600 (3)
$ 600,000 $ 57,000 $114,000 $171,000 $228,000 $285,000 $ 342,000 $ 399,000 $ 410,400 (3)
$ 800,000 $ 76,000 $152,000 $228,000 $304,000 $380,000 $ 456,000 $ 532,000 $ 547,200 (3)
$1,000,000 $ 95,000 $190,000 $285,000 $380,000 $475,000 $ 570,000 $ 665,000 $ 684,000 (3)
$1,200,000 $114,000 $228,000 $342,000 $456,000 $570,000 $ 684,000 $ 798,000 $ 820,800 (3)
$1,400,000 $133,000 $266,000 $399,000 $532,000 $665,000 $ 798,000 $ 931,000 $ 957,600 (3)
$1,600,000 $152,000 $304,000 $456,000 $608,000 $760,000 $ 912,000 $1,064,000 $1,094,400 (3)
$1,800,000 $171,000 $342,000 $513,000 $684,000 $855,000 $1,026,000 $1,197,000 $1,231,200 (3)
$2,000,000 $190,000 $380,000 $570,000 $760,000 $950,000 $1,140,000 $1,330,000 $1,368,000 (3)
(1) Annual benefits are computed on the basis of straight life annuity
amounts. These amounts include pension benefits, if any, to which a
participant may be entitled as a result of participation in a pension plan
of a subsidiary during previous periods of employment. The amounts shown
do not take into account exclusion of up to 35% of the estimated primary
Social Security benefit. The Retirement Plan provides a minimum benefit
equal to 25% of a participant's final 12 months' earnings, reduced
proportionately for less than 15 years of credited service at retirement.
The minimum Retirement Plan Benefit is not subject to Social Security
offset. Messrs. Greenberg, Barney, Chaney, Dingman and Bovaird had,
respectively, 22 years, 30 years, 38 years, 29 years and 7 years of
estimated credited service at September 30, 2002.
(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.
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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, Barney and Dingman 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.
The UGI Severance Plan provides for cash payments equal to a participant's
compensation for a period of time ranging from 3 months to 15 months (30 months
in the case of Mr. Greenberg), depending on length of service. In addition, a
participant receives the cash equivalent of his or her target bonus under the
Annual Bonus Plan, pro-rated for the number of months served in the fiscal year.
However, if the termination occurs in the last two months of the fiscal year,
the Chief Executive Officer has the discretion to determine whether the
participant will receive a pro-rated target bonus, or the actual annual bonus
which would have been paid after the end of the fiscal year, assuming that the
participant's entire bonus was contingent on meeting the applicable financial
performance goal. Certain employee benefits are continued under the Plan for a
period of up to 15 months (30 months in the case of Mr. Greenberg). Utilities
has the option to pay a participant the cash equivalent of those employee
benefits.
In order to receive benefits under the UGI Severance Plan, a senior
executive is required to execute a release which discharges Utilities and its
affiliates from liability for any claims the senior executive may have against
any of them, other than claims for amounts or benefits due to the executive
under any plan, program or contract provided by or entered into with Utilities
or its affiliates. The senior executive is also required to cooperate in
attending to matters pending at the time of his or her termination of
employment.
CHANGE OF CONTROL ARRANGEMENTS
Named Executives Employed by UGI Corporation. Messrs. Greenberg and
Bovaird each have an agreement with UGI Corporation (the "Agreement") which
provides certain benefits in the event of a change of control of UGI. The
Agreements operate independently of the UGI Severance Plan, continue through
July 2004, and are automatically extended in one-year increments thereafter
unless, prior to a change of control, UGI terminates an Agreement. In the
absence of a change of control, each Agreement will terminate when, for any
reason, the executive terminates his employment with UGI or its subsidiaries.
A change of control is generally deemed to occur if: (i) any person (other
than the executive, his affiliates and associates, UGI or any of its
subsidiaries, any employee benefit plan of UGI or any of its subsidiaries, or
any person or entity organized, appointed, or established by UGI or its
subsidiaries for or pursuant to the terms of any such employee benefit plan),
together with all affiliates and associates of such person, acquires securities
representing 20% or more of either (x) the then outstanding shares of common
stock of UGI or (y) the combined voting power
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of UGI's then outstanding voting securities; (ii) individuals who at the
beginning of any 24-month period constitute the Board of Directors (the
"Incumbent Board") and any new director whose election by the Board, or
nomination for election by UGI's shareholders, was approved by a vote of at
least a majority of the Incumbent Board, cease for any reason to constitute a
majority thereof; (iii) UGI is reorganized, merged or consolidated with or into,
or sells all or substantially all of its assets to, another corporation in a
transaction in which former shareholders of UGI do not own more than 50% of the
outstanding common stock and the combined voting power, respectively, of the
then outstanding voting securities of the surviving or acquiring corporation
after the transaction; or (iv) UGI is liquidated or dissolved.
Upon a change of control, the Agreement provides for an immediate cash
payment equal to the market value of any pending target award under UGI's
long-term compensation plan.
Severance benefits are payable under the Agreements if there is a
termination of the executive's employment without cause at any time within three
years after a change of control. In addition, following a change of control, the
executive may elect to terminate his or her employment without loss of severance
benefits in certain specified contingencies, including termination of officer
status; a significant adverse change in authority, duties, responsibilities or
compensation; the failure of UGI to comply with and satisfy any of the terms of
the Agreement; or a substantial relocation or excessive travel requirements.
An executive who is terminated with rights to severance compensation under
an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 (2.5 in
the case of Mr. Greenberg) times his average total cash remuneration for the
preceding five calendar years. If the severance compensation payable under the
Agreement, either alone or together with other payments to an executive, would
constitute "excess parachute payments," as defined in Section 280G of the
Internal Revenue Code of 1986, as amended (the "Code"), the executive will also
receive an amount to satisfy the executive's additional tax burden.
Named Executives Employed by UGI Utilities, Inc. Messrs. Chaney, Barney
and Dingman each have an agreement with UGI Utilities (the "Agreement") which
provides certain benefits in the event of a change of control of Utilities or of
UGI. The Agreements operate independently of the UGI Severance Plan, continue
through July 2004, and are automatically extended in one-year increments
thereafter unless, prior to a change of control, the Company terminates an
Agreement. In the absence of a change of control, each Agreement will terminate
when, for any reason, the executive terminates his employment with Utilities or
its subsidiaries.
A change of control is generally deemed to occur if a change of control of
UGI, as defined above, occurs or if: (i) UGI and its subsidiaries fail to own
more than fifty percent of the combined voting power of the Company's then
outstanding voting securities, (ii) the Company is reorganized, merged or
consolidated with or into, or sells all or substantially all of its assets to,
another corporation in a transaction in which former shareholders of the Company
do not own more than 50% of the outstanding common stock and the combined voting
power, respectively, of the then outstanding voting securities of the surviving
or acquiring corporation after the transaction, or (iii) the Company is
liquidated or dissolved.
-37-
Upon a change of control, the Agreement provides for an immediate cash
payment equal to the market value of any pending target award under Utilities'
long-term compensation plan.
Severance benefits are payable under the Agreements if there is a
termination of the executive's employment without cause at any time within three
years after a change of control. In addition, following a change of control, the
executive may elect to terminate his or her employment without loss of severance
benefits in certain specified contingencies, including termination of officer
status; a significant adverse change in authority, duties, responsibilities or
compensation; the failure of the Company to comply with and satisfy any of the
terms of the Agreement; or a substantial relocation or excessive travel
requirements.
An executive who is terminated with rights to severance compensation under
an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 times his
average total cash remuneration for the preceding five calendar years. If the
severance compensation payable under the Agreement, either alone or together
with other payments to an executive, would constitute "excess parachute
payments," as defined in Section 280G of the Internal Revenue Code of 1986, as
amended (the "Code"), the executive will also receive an amount to satisfy the
executive's additional tax burden.
COMPENSATION OF DIRECTORS
Messrs. Chaney and Greenberg are not compensated for service on the Board
of Directors or on any Committee of the Board. The other members of the
Company's Board of Directors also serve on the UGI Board and receive no
additional compensation for service on the Company's Board. The Company
reimburses UGI for 50% of the attendance fees and expenses incurred by the
non-employee directors of UGI.
COMPENSATION COMMITTEE
The members of the UGI Utilities, Inc. Compensation and Management
Development Committee are Richard C. Gozon (Chairman), Thomas F. Donovan and
Anne Pol.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
At December 2, 2002, UGI Corporation held 100% of the Company's Common
Stock. UGI is located at 460 North Gulph Road, King of Prussia, PA 19406.
The following table sets forth, as of October 31, 2002, the number of
shares of Common Stock of UGI beneficially owned by each director of the Company
and each of the Named Executives, as well as all directors and executive
officers as a group. Mr. Greenberg is the beneficial owner of approximately 2%
of UGI's Common Stock. All other directors, Named Executives and executive
officers own less than 1% of UGI's outstanding shares. The total
-38-
number of shares beneficially owned by all directors and executive officers as a
group (including 726,739 shares subject to exercisable options) represents
approximately 4% of UGI's outstanding shares.
SECURITY OWNERSHIP OF MANAGEMENT
NUMBER OF SHARES
AND NATURE OF
BENEFICIAL
OWNERSHIP NUMBER OF
EXCLUDING OPTIONS EXERCISABLE STOCK
NAME OF BENEFICIAL OWNER (1) OPTIONS TOTAL
------------------------ --- ------- -----
Stephen D. Ban 15,470 (2) 14,100 29,570
John C. Barney (3) 8,343 20,000 28,343
Brendan P. Bovaird (4) 22,965 48,667 71,632
Robert J. Chaney 38,450 (5) 78,889 117,339
Thomas F. Donovan 5,629 (2) 12,800 18,429
Richard C. Gozon 25,964 (2) 16,800 42,764
Lon R. Greenberg (6) 112,040 468,750 580,790
Anne Pol 11,752 (2) 12,800 24,552
Marvin O. Schlanger 9,433 (2) 12,800 22,233
James W. Stratton (7) 16,427 (2) 16,800 33,227
Peter G. Terranova (8) 4,871 20,333 25,204
Mark R. Dingman 17,000 0 17,000
Ernest E. Jones 1,084 (2) 4,000 5,084
All directors and executive
officers as a group (13 total) 314,761 726,739 1,041,500
(1) The director or officer has sole voting and investment power unless
otherwise specified.
(2) The number of Shares shown includes Deferred Units ("Units")
acquired through the 1997 Amended and Restated Directors' Equity
Compensation Plan. Units are neither actual shares nor other
securities, but each Unit will be converted to one share of Common
Stock and paid out to directors upon their retirement or termination
of service. The number of Units included for each director is as
follows: Messrs. Donovan (3,546), Stratton (13,316), Schlanger
(6,950), Gozon (18,853), Ban (9,653), Mrs. Pol (9,879) and Mr. Jones
(970).
(3) Mr. Barney holds 236 shares represented by units held in the UGI
Stock Fund of the 401(k) Employee Savings Plan, based on September
30, 2002 Savings Plan statements. Mr. Barney disclaims beneficial
ownership of 200 Shares owned by an adult son.
-39-
(4) Mr. Bovaird holds 19,993 shares jointly with his spouse and 2,972
Shares represented by units held in the UGI Stock Fund of the 401(k)
Employee Savings Plan, based on September 30, 2002 Saving Plan
statements.
(5) Mr. Chaney is trustee of a trust that holds 13,650 shares.
(6) Mr. Greenberg holds 88,220 shares jointly with his spouse and 6,105
Shares represented by units held in the UGI Stock Fund of the 401(k)
Employee Savings Plan, based on September 30, 2002 Saving Plan
statements.
(7) Mr. Stratton holds 3,111 shares jointly with his spouse.
(8) Mr. Terranova holds 820 shares represented by units held in the UGI
Stock Fund of the 401(k) Employee Savings Plan, based on September
30, 2002 Savings Plan statements.
(9) The total number of shares beneficially owned by the directors and
officers as a group represents approximately 4% of UGI's outstanding
Shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 2002 UGI allocated 49%, or approximately $6.7 million, of
its general corporate expenses to Utilities.
ITEM 14. CONTROLS AND PROCEDURES
An evaluation of the effectiveness of the design and operation of the
Company's disclosure controls and procedures as of December 20, 2002 was carried
out by the Company under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the Company's disclosure controls and
procedures have been designed and are being operated in a manner that provides
reasonable assurance that the information required to be disclosed by the
Company in reports filed under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms. A controls system, no matter how well designed and
operated, cannot provide absolute assurance that the objectives of the controls
system are met, and no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within a company have
been detected. Subsequent to the date of the most recent evaluation of the
Company's internal controls, there were no significant changes in the Company's
internal controls or in other factors that could significantly affect the
internal controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.
-40-
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(a) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
Included under Item 8 are the following financial statements
and supplementary data:
Reports of Independent Public Accountants
Consolidated Balance Sheets as of September 30, 2002 and
2001
Consolidated Statements of Income for the fiscal years
ended September 30, 2002, 2001 and 2000
Consolidated Statements of Cash Flows for the fiscal
years ended September 30, 2002, 2001 and 2000
Consolidated Statements of Stockholders' Equity for the
fiscal years ended September 30, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2002, 2001 and 2000
II- Valuation and Qualifying Accounts
We have omitted all other financial statement schedules
because the required information is (1) not present; (2) not
present in amounts sufficient to require submission of the
schedule; or (3) included elsewhere in the financial
statements or notes thereto contained in this report.
NOTICE REGARDING ARTHUR ANDERSEN LLP
Arthur Anderson LLP audited our consolidated financial
statements for the three years in the period ended September
30, 2001 and issued a report thereon dated November 16, 2001.
Arthur Anderson LLP has not reissued its report or consented
to the incorporation by reference of such report into the
Company's prospectuses relating to offering and sale of our
debt
-41-
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.
(3) LIST OF EXHIBITS:
The exhibits filed as part of this report 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 Registration 3
Statement
No. 333-72540
*3.2 Bylaws of UGI Utilities as in effect since
September 24, 2002
4 Instruments defining the rights of security holders,
including indentures. (The Company agrees to furnish
to the Commission upon request a copy of any
instrument defining the rights of holders of its
long-term debt not required to be filed pursuant to
the description of Exhibit 4 contained in Item 601 of
Regulation S-K)
4.1 Utilities' Articles of Incorporation and Bylaws
referred to in Exhibit Nos. 3.1 and 3.2
4.2 Indenture between Utilities and First Union National UGI Form 10-K (4)e
Bank (formerly, First Fidelity Bank, N.A. (9/30/93)
Pennsylvania,) Trustee, dated as of August 1, 1993 and
related 6.5% Note due 2003
-42-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
4.3 Form of Fixed Rate Medium-Term Note Utilities Form 8-K (4)i
(8/26/94)
4.4 Form of Fixed Rate Series B Medium-Term Note Utilities Form 8-K 4(i)
(8/1/96)
4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii)
(8/1/96)
4.6 Service Agreement for comprehensive delivery service UGI Form 10-K 10.40
(Rate CDS) dated February 23, 1998 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv)
series (8/26/94)
4.9 Form of Officer's Certificate establishing Series B Utilities Form 8-K 4(iv)
Medium-Term Notes under the Indenture (8/1/96)
4.10 Forms of Floating Rate and Fixed Rate Series C Utilities Form 8-K 4.1
Medium-Term Notes (5/21/02)
4.11 Form of Officers' Certificate establishing Series C Utilities Form 8-K 4.2
Medium-Term Notes under the Indenture (5/21/02)
10.1 Service Agreement (Rate FSS) dated as of November 1, UGI Form 10-K 10.5
1989 between Utilities and Columbia, as modified (9/30/95)
pursuant to the orders of the Federal Energy
Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Paragraph 61,060 (1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities Form 10-K (10)o.
between Utilities and Columbia, as modified by (12/31/90)
Supplement No. 1 dated October 1, 1988; Supplement No.
2 dated November 1, 1989; Supplement No. 3 dated
November 1, 1990; Supplement No. 4 dated November 1,
1990; and Supplement No. 5 dated January 1, 1991, as
further modified pursuant to the orders of the Federal
Energy Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Paragraph 61,060 (1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
10.3 Transportation Service Agreement (Rate FTS-1) dated Utilities Form 10-K (10)p.
November 1, 1989 between Utilities and Columbia Gulf (12/31/90)
Transmission Company, as modified pursuant to the
orders of the Federal Energy Regulatory Commission in
Docket No. RP93-6-000 reported at Columbia Gulf
Transmission Co., 64 FERC Paragraph 61,060 (1993),
order on rehearing, 64 FERC Paragraph 61,365 (1993)
-43-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
10.4** UGI Corporation 1992 Directors' Stock Plan UGI Form 10-Q (10)ff
(6/30/92)
10.5** UGI Corporation Directors' Deferred Compensation Plan Form 10-K 10.6
Amended and Restated as of January 1, 2000 UGI (9/30/00)
10.6** UGI Corporation Directors' Equity Compensation Plan Form 10-K 10.9
Amended and Restated as of January 1, 2000 UGI (9/30/00)
10.7** UGI Corporation 1992 Stock Option and Dividend Form 10-Q (10)ee
Equivalent Plan, as amended May 19, 1992 UGI (6/30/92)
10.8** UGI Corporation Annual Bonus Plan dated March 8, 1996 UGI Form 10-Q 10.4
(6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Plan dated March 8, Form 10-Q 10.4
1996` Utilities (6/30/96)
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive Employee Severance Form 10-K 10.12
Pay Plan effective January 1, 1997 UGI (9/30/97)
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, Form 10-K 10.39
as amended UGI (9/30/00)
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-K 10.13
(9/30/99)
10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-Q 10.1
(6/30/00)
10.15** Service Agreement for comprehensive delivery service
(Rate CDS) dated February 23, 1999 between UGI
Utilities, Inc. and Texas Eastern Transmission Form 10-K 10.41
Corporation UGI (9/30/00)
10.16** UGI Corporation 1997 Stock Option and Dividend Form 10-Q 10.2
Equivalent Plan UGI (3/31/97)
10.17** UGI Corporation Supplemental Executive Retirement Plan Form 10-Q 10
Amended and Restated effective October 1, 1996 UGI (6/30/98)
10.18 ** Summary of Terms of UGI Corporation 1999 Restricted Form 10-Q 10
Stock Awards UGI (6/30/99)
10.20** Description of Change of Control arrangements for UGI Form 10-K 10.33
Messrs. Greenberg and Bovaird (9/30/99)
10.21** Description of Change of Control arrangements for UGI Form 10-K 10.34
Messrs. Chaney, Barney and Dingman (9/30/99)
10.22** Consulting Services Agreement dated as of August 1, UGI Form 10-K 10.38
2000 between Stephen D. Ban and UGI Corporation (9/30/00)
-44-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
10.23 Power Sales Agreement between UGI Utilities, Inc. and Utilities Form 10-K 10.23
UGI Development Company dated as of November 30, 2001 (9/30/01)
10.24 Partnership Agreement of Hunlock Creek Energy Ventures Utilities Form 10-K 10.24
dated December 8, 2001 by and between UGI Hunlock (9/30/01)
Development Company and Allegheny Energy Supply
Hunlock Creek LLC
*10.25 Storage Transportation Service Agreement (Rate
Schedule SST) between Utilities and Columbia dated
November 1, 1993, as modified pursuant to orders of
the Federal Energy Regulatory Commission
*10.26 No-Notice Transportation Service Agreement (Rate
Schedule NTS) between Utilities and Columbia dated
November 1, 1993, as modified pursuant to orders of
the Federal Energy Regulatory Commission
*10.27 No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas Eastern
Transmission dated February 23, 1999, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*10.28 No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas Eastern
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*10.29 Firm Transportation Service Agreement (Rate Schedule
FT-1) between Utilities and Texas Eastern Transmission
dated June 15, 1999, as modified pursuant to various
orders of the Federal Energy Regulatory Commission
*10.30 Firm Transportation Service Agreement (Rate Schedule
FT-1) between Utilities and Texas Eastern Transmission
dated October 31, 2000, as modified pursuant to
various orders of the Federal Energy Regulatory
Commission
*10.31 Firm Transportation Service Agreement (Rate Schedule
FT) between Utilities and Transcontinental Gas Pipe
Line dated October 1, 1996, as modified pursuant to
various orders of the Federal Energy Regulatory
Commission
10.32** 2002 UGI Corporation Non-Qualified Stock Option Plan UGI Form 10-K 10.38
(9/30/02)
*12.1 Computation of Ratio of Earnings to Fixed Charges
Computation of Ratio of Earnings to Combined Fixed
*12.2 Charges and Preferred Stock Dividends
-45-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
----------- ------- ---------- ------ -------
21 Subsidiaries of the Registrant Utilities Form 10-K 21
(9/30/00)
*23 Consent of PricewaterhouseCoopers LLP
*99 Certification by the Chief Executive Officer and the
Chief Financial Officer relating to the Registrant's
Report on Form 10-K for the fiscal year ended
September 30, 2002
* Filed herewith.
** As required by Item 14(a)(3), this exhibit is identified as a compensatory
plan or arrangement.
(b) REPORTS ON FORM 8-K:
The Company filed the following Current Reports on Form 8-K during the
fourth quarter of fiscal year 2002:
Date Item Number(s) Content
---- -------------- -------
09/16/02 5 Other Events - Standard & Poor's Ratings
Services Press Release dated September 11, 2002
re: Corporate Credit and Unsecured Debt Ratings
-46-
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 17, 2002 By: John C. Barney
-------------------------------
John C. Barney
Senior Vice President - Finance
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 17, 2002 by the following persons on
behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
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
-47-
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 17, 2002 by the following persons on
behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Ernest E. Jones Director
- -------------------------------
Ernest E. Jones
Richard C. Gozon Director
- -------------------------------
Richard C. Gozon
Anne Pol Director
- -------------------------------
Anne Pol
Marvin O. Schlanger Director
- -------------------------------
Marvin O. Schlanger
James W. Stratton Director
- -------------------------------
James W. Stratton
-48-
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT:
No annual report or proxy material was sent to security holders in fiscal year
2002.
-49-
CERTIFICATIONS
I, Robert J. Chaney, certify that:
1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors:
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: December 20, 2002
Robert J. Chaney
-------------------------------------
Robert J. Chaney
President and Chief Executive Officer
-50-
I, John C. Barney, certify that:
1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors:
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: December 20, 2002
John C. Barney
--------------------------------------------
John C. Barney
Senior Vice President - Finance and Chief
Financial Officer
-51-
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2002
F-1
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
Pages
-----
Financial Statements:
Reports of Independent Accountants F-3 to F-4
Consolidated Balance Sheets as of September 30,
2002 and 2001 F-5 to F-6
Consolidated Statements of Income for the years
ended September 30, 2002, 2001 and 2000 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 2002, 2001 and 2000 F-8
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 2002, 2001 and 2000 F-9
Notes to Consolidated Financial Statements F-10 to F-27
Financial Statement Schedule:
For the years ended September 30, 2002, 2001 and 2000:
II - Valuation and Qualifying Accounts S-1
We have omitted all other financial statement schedules because the
required information is either (1) not present; (2) not present in
amounts sufficient to require submission of the schedule; or (3) included
elsewhere in the financial statements or related notes.
F-2
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
In our opinion, the consolidated financial statements as of and for the year
ended September 30, 2002 listed in the index appearing under Item 15a(1) and (2)
present fairly, in all material respects, the financial position of UGI
Utilities, Inc. and its subsidiaries at September 30, 2002 and the results of
their operations and their cash flows for the year ended September 30, 2002 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule as of and
for the year ended September 30, 2002 listed in the Index to Financial
Statements and Financial Statement Schedule present fairly, in all material
respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and
financial statement schedule are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion. The financial statements of
UGI Utilities, Inc. and its subsidiaries as of September 30, 2001, and for each
of the two years in the period ended September 30, 2001 were audited by other
independent accountants who have ceased operations. Those independent
accountants expressed an unqualified opinion on those financial statements in
their report dated November 16, 2001.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 15, 2002
F-3
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S
REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY
ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
We have audited the accompanying consolidated balance sheets of UGI Utilities,
Inc. and subsidiaries as of September 30, 2001 and 2000, and the related
consolidated statements of income, cash flows and stockholder's equity for each
of the 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 audits.
We conducted our audits in accordance with auditing standards generally accepted
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 audits 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, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2001 in conformity with accounting principles
generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. 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
Philadelphia, Pennsylvania
November 16, 2001
F-4
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
September 30,
2002 2001
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 6,090 $ 7,711
Accounts receivable (less allowances for doubtful
accounts of $1,972 and $3,151, respectively) 38,554 39,152
Accrued utility revenues 8,069 11,110
Inventories 38,654 48,074
Deferred income taxes 2,610 5,527
Income taxes recoverable 6,892 -
Deferred fuel costs 4,304 -
Prepaid expenses and other current assets 3,151 2,178
--------- ---------
Total current assets 108,324 113,752
Property, plant and equipment
Gas utility 760,161 734,661
Electric operations 111,265 108,423
General 11,909 12,113
--------- ---------
883,335 855,197
Less accumulated depreciation and amortization (290,194) (276,429)
--------- ---------
Net property, plant and equipment 593,141 578,768
Regulatory assets 57,685 56,155
Other assets 38,973 35,734
--------- ---------
Total assets $ 798,123 $ 784,409
========= =========
See accompanying notes to consolidated financial statements.
F-5
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
September 30,
2002 2001
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 76,000 $ -
Bank loans 37,200 57,800
Accounts payable 57,499 67,456
Employee compensation and benefits accrued 8,984 8,356
Dividends and interest accrued 5,443 5,392
Income taxes accrued - 11,138
Customer deposits and refunds 8,745 6,032
Other current liabilities 22,346 21,264
--------- ---------
Total current liabilities 216,217 177,438
Long-term debt 172,369 208,477
Deferred income taxes 131,483 121,890
Deferred investment tax credits 8,385 8,783
Other noncurrent liabilities 11,815 12,064
Commitments and contingencies (note 8)
Preferred stock subject to mandatory redemption,
without par value 20,000 20,000
Common stockholder's equity:
Common Stock, $2.25 par value (authorized - 40,000,000 shares;
issued and outstanding - 26,781,785 shares) 60,259 60,259
Additional paid-in capital 73,057 72,792
Retained earnings 107,312 102,706
Accumulated other comprehensive loss (2,774) -
--------- ---------
Total common stockholder's equity 237,854 235,757
--------- ---------
Total liabilities and stockholders' equity $ 798,123 $ 784,409
========= =========
See accompanying notes to consolidated financial statements.
F-6
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------------------
2002 2001 2000
--------- --------- ---------
Revenues $ 490,552 $ 584,762 $ 436,942
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power 290,282 374,781 218,119
Operating and administrative expenses 80,910 88,310 85,425
Operating and administrative expenses - related parties 6,664 5,277 4,159
Taxes other than income taxes 11,930 9,182 17,052
Depreciation and amortization 22,172 23,767 23,612
Other income, net (11,723) (15,111) (12,660)
--------- --------- ---------
400,235 486,206 335,707
--------- --------- ---------
Operating income 90,317 98,556 101,235
Interest expense 16,652 18,988 18,353
--------- --------- ---------
Income before income taxes 73,665 79,568 82,882
Income taxes 29,570 31,431 32,406
--------- --------- ---------
Net income 44,095 48,137 50,476
Dividends on preferred stock 1,550 1,550 1,550
--------- --------- ---------
Net income after dividends on preferred stock $ 42,545 $ 46,587 $ 48,926
========= ========= =========
See accompanying notes to consolidated financial statements.
F-7
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------------------
2002 2001 2000
--------- --------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 44,095 $ 48,137 $ 50,476
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 22,172 23,767 23,612
Deferred income taxes, net 11,114 (2,016) 2,866
Provision for uncollectible accounts 5,270 8,269 4,386
Pension income (3,857) (5,671) (2,930)
Other (391) (177) 4,892
Net change in:
Accounts receivable and accrued utility revenues (1,631) (14,704) (14,823)
Inventories 9,420 (14,508) (8,831)
Deferred fuel costs (7,056) 9,948 (3,751)
Accounts payable (9,957) 13,318 16,257
Other current assets and liabilities (14,123) 9,769 9,293
--------- --------- ---------
Net cash provided by operating activities 55,056 76,132 81,447
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (35,884) (36,783) (36,391)
Net costs of property, plant and equipment disposals (704) (1,407) (838)
Cash contribution to partnership - (6,000) -
--------- --------- ---------
Net cash used by investing activities (36,588) (44,190) (37,229)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (39,489) (36,809) (45,563)
Issuance of long-term debt 40,000 50,603 -
Repayment of long-term debt - (15,000) (7,143)
Bank loans increase (decrease) (20,600) (42,600) 13,000
Capital contribution from UGI Corporation - 4,000 -
--------- --------- ---------
Net cash used by financing activities (20,089) (39,806) (39,706)
--------- --------- ---------
Cash and cash equivalents increase (decrease) $ (1,621) $ (7,864) $ 4,512
========= ========= =========
CASH AND CASH EQUIVALENTS:
End of year $ 6,090 $ 7,711 $ 15,575
Beginning of year 7,711 15,575 11,063
--------- --------- ---------
Increase (decrease) $ (1,621) $ (7,864) $ 4,512
========= ========= =========
See accompanying notes to consolidated financial statements.
F-8
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, 1999 $ 60,259 $ 68,559 $ 90,742 $ - $ 219,560
Net income 50,476 50,476
Cash dividends - common stock (44,013) (44,013)
Cash dividends - preferred stock (1,550) (1,550)
---------- ---------- --------- -------- ----------
Balance September 30, 2000 60,259 68,559 95,655 - 224,473
Net income 48,137 48,137
Capital contribution by UGI Corporation 4,000 4,000
Cash dividends - common stock (35,259) (35,259)
Cash dividends - preferred stock (1,550) (1,550)
Dividends of net assets (4,277) (4,277)
Other 233 233
---------- ---------- --------- -------- ----------
Balance September 30, 2001 60,259 72,792 102,706 - 235,757
Net income 44,095 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 (37,939) (37,939)
Cash dividends - preferred stock (1,550) (1,550)
Other 265 265
---------- ---------- --------- -------- ----------
Balance September 30, 2002 $ 60,259 $ 73,057 $ 107,312 $ (2,774) $ 237,854
========== ========== ========= ======== ==========
See accompanying notes to consolidated financial statements.
F-9
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"), a wholly owned subsidiary of UGI
Corporation ("UGI"), owns and operates (1) a natural gas distribution utility
("Gas Utility") in parts of eastern and southeastern Pennsylvania and (2) an
electricity distribution utility ("Electric Utility") and electricity generation
business (which together with Electric Utility are referred to herein as
"Electric Operations") in northeastern Pennsylvania. The Company's interests in
electric generation assets are owned by our non-utility subsidiary, UGI
Development Company ("UGID") and its 50%-owned joint-venture partnership Hunlock
Creek Energy Ventures ("Energy Ventures") which is accounted for under the
equity method. We refer to UGI Utilities and its subsidiaries collectively as
"the Company" or "we." Our consolidated financial statements include the
accounts of UGI Utilities and its majority-owned subsidiaries. We eliminate all
significant intercompany accounts and transactions when we consolidate. UGID
has been granted "Exempt Wholesale Generator" status by the Federal Energy
Regulatory Commission.
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
Gas Utility and Electric Utility (collectively, "Utilities") are subject to
regulation by the Pennsylvania Public Utility Commission ("PUC"). We account for
Gas Utility and Electric Utility in accordance with Statement of Financial
Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of
rate regulation in the financial statements. If a separable portion of Gas
Utility or Electric Utility no longer meets the provisions of SFAS 71, we are
required to eliminate the financial statement effects of regulation for that
portion of our operations.
On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in Gas
Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
provisions of the Gas Restructuring Order and the Gas Competition Act, we
believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS
71. For further information on the impact of the Gas Competition Act and
Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see
Note 2.
F-10
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CONSOLIDATED STATEMENTS OF CASH FLOWS
We define cash equivalents as all highly liquid investments with maturities of
three months or less when purchased. We record cash equivalents at cost plus
accrued interest, which approximates market value.
We paid interest totaling $16,348 in 2002, $17,543 in 2001 and $17,941 in 2000.
We paid income taxes totaling $36,282 in 2002, $29,000 in 2001 and $23,108 in
2000.
REVENUE RECOGNITION
Gas Utility and Electric Utility record regulated revenues for service provided
to the end of each month which 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 recognized as services are performed.
INVENTORIES
Our inventories are stated at the lower of cost or market. We determine cost
principally on an average cost method except for appliances for which we use the
specific identification method.
INCOME TAXES
Gas Utility and Electric Utility record deferred income taxes in the
Consolidated Statements of Income resulting from the use of accelerated
depreciation methods based upon amounts recognized for ratemaking purposes. They
also record a deferred tax liability for tax benefits that are flowed through to
ratepayers when temporary differences originate and record a regulatory income
tax asset for the probable increase in future revenues that will result when the
temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities' plant
additions over the service lives of the related property. 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. We
also reduce the regulatory income tax asset for the probable reduction in future
revenues that will result when such deferred investment tax credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income
tax return. We are charged or credited for our share of current taxes resulting
from the effects of our transactions in the UGI consolidated federal income tax
return including giving effect to intercompany transactions. The result of this
allocation is generally consistent with income taxes calculated on a separate
return basis.
F-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
We record property, plant and equipment at cost. We charge to accumulated
depreciation the original cost of UGI Utilities' retired plant and equipment,
together with the net cost of removal, for financial accounting purposes.
We record depreciation expense for Utilities' plant and equipment on 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 Gas Utility was 2.5% in 2002 and 2.6% in
each of 2001 and 2000. Depreciation expense as a percentage of the related
average depreciable base for Electric Operations was 3.0% in each of 2002 and
2001, and 3.5% in 2000. Depreciation expense was $21,649 in 2002, $22,701 in
2001 and $23,000 in 2000.
We evaluate the impairment of long-lived assets whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable. We evaluate recoverability based upon undiscounted future cash
flows expected to be generated by such assets.
COMPUTER SOFTWARE COSTS
We include in property, plant and equipment costs associated with computer
software we develop or obtain for use in our businesses. We amortize computer
software costs on a straight-line basis over expected periods of benefit not
exceeding ten years once the installed software is ready for its intended use.
DEFERRED FUEL COSTS
Gas Utility's tariffs contain clauses which permit recovery of certain purchased
gas costs through the application of purchased gas cost ("PGC") rates. The
clauses provide for periodic adjustments to PGC rates for the difference between
the total amount of purchased gas costs collected from customers and the
recoverable costs incurred. In accordance with SFAS 71, we defer the difference
between amounts recognized in revenues and the applicable gas costs incurred
until they are subsequently billed or refunded to customers.
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. We do not discount to
present value the costs of future expenditures for environmental liabilities. 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.
F-12
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DERIVATIVE INSTRUMENTS
Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133, as amended,
establishes accounting and reporting standards for derivative instruments and
for hedging activities. It requires that all derivative instruments be
recognized as either assets or liabilities and measured at fair value. The
accounting for changes in fair value depends upon the purpose of the derivative
instrument and whether it is designated and qualifies for hedge accounting. To
the extent a derivative instrument qualifies and is designated as a hedge of the
variability of cash flows associated with a forecasted transaction ("cash flow
hedge"), the effective portion of the gain or loss on such derivative instrument
is generally reported in other comprehensive income and the ineffective portion,
if any, is reported in net income. Such amounts reported in other comprehensive
income are reclassified into net income when the forecasted transaction affects
earnings. If a cash flow hedge is discontinued because it is probable that the
forecasted transaction will not occur, the net gain or loss is immediately
reclassified into net income. To the extent derivative instruments qualify and
are designated as hedges of changes in the fair value of an existing asset,
liability or firm commitment ("fair value hedge"), the gain or loss on the
hedging instrument is recognized in earnings along with changes in the fair
value of the hedged asset, liability or firm commitment attributable to the
hedged risk.
On occasion, we have used a managed program of natural gas and oil futures
contracts to preserve gross margin associated with certain of our natural gas
customers. These contracts were designated as cash flow hedges. The Company did
not enter into these types of contracts in 2002. During 2001, the amount of cash
flow hedge gains associated with these contracts that were reclassified to
earnings because it became probable that the original forecasted transactions
would not occur was $1,034 which amount is included in other income.
During 2002, in order to reduce our interest rate risk associated with
forecasted issuances of fixed-rate debt, we entered into interest rate
protection agreements ("IRPAs") which have been designated and qualify as cash
flow hedges. Included in accumulated other comprehensive loss at September 30,
2002 are net after-tax losses of $2,774 from settled and unsettled IRPAs
associated with forecasted issuances of debt. The amount of this net loss
expected to be reclassified into net income during the next twelve months is not
material. The fair value of our unsettled IRPAs was a loss of $1,205 at
September 30, 2002 which is included in other current liabilities on the
Consolidated Balance Sheet. These IRPAs hedge interest rate risk associated with
forecasted issuances of debt to occur during Fiscal 2003. We did not have any
derivative instruments outstanding at September 30, 2001.
During 2002 and 2001, there were no gains or losses from hedge ineffectiveness
or from excluding a portion of a derivative instrument's gain or loss from the
assessment of hedge effectiveness, and there were no gains or losses recognized
in earnings as a result of a hedged firm commitment no longer qualifying as a
fair value hedge.
We are a party to a number of contracts that have elements of a derivative
instrument. These contracts include, among others, binding purchase orders,
contracts which provide for the delivery of natural gas, and service contracts
that require the counterparty to provide commodity storage, transportation or
capacity service to meet our normal sales commitments. Although
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
many of these contracts have the requisite elements of a derivative instrument,
these contracts are not subject to the accounting requirements of SFAS 133
because they provide for the delivery of products or services in quantities
that are expected to be used in the normal course of operating our business or
the value of the contract is directly associated with the price or value of a
service.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income
(loss). Other comprehensive loss of $(2,774) for the year ended September 30,
2002 is the result of losses on IRPAs qualifying as hedges. The Company's
comprehensive income was the same as net income for the years ended September
30, 2001 and 2000.
ADOPTION OF SFAS 142
Effective October 1, 2001, we early adopted the provisions of SFAS No. 142,
"Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the
financial accounting and reporting for acquired goodwill and other intangible
assets and supersedes Accounting Principles Board ("APB") Opinion No. 17,
"Intangible Assets." SFAS 142 addresses the financial accounting and reporting
for intangible assets acquired individually or with a group of other assets
(excluding those acquired in a business combination) at acquisition and also
addresses the financial accounting and reporting for goodwill and other
intangible assets subsequent to their acquisition. Under SFAS 142, an
intangible asset is amortized over its useful life unless that life is
determined to be indefinite. Goodwill and other intangible assets with
indefinite lives are not amortized but are subject to tests for impairment at
least annually. Because we do not have significant intangible assets or
goodwill resulting from prior business combinations, the adoption of SFAS 142
did not impact our results of operations or financial position.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144");
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146").
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using
a systematic and rational method over the related asset's useful life and
adjust the fair value of the liability resulting from the passage of time
through charges to operating expense. We adopted SFAS 143 effective October 1,
2002. The adoption of SFAS 143 did not have a material effect on our financial
position or results of operations.
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," as it relates to the disposal of a segment of a business. SFAS
144 establishes a single accounting model for long-lived assets to be disposed
of based upon the framework of SFAS 121, and resolves significant
implementation issues of SFAS 121. We adopted SFAS 144 effective October 1,
2002. The adoption of SFAS 144 did not affect our financial position or results
of operations.
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment
of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective for fiscal
years beginning after May 15, 2002. SFAS 4 had required that material gains and
losses on extinguishment of debt be classified as an extraordinary item. Under
SFAS 145, it is less likely that a gain or loss on extinguishment of debt would
be classified as an extraordinary item in the Consolidated Statement of Income.
Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases,"
to require that certain lease modifications that have economic effects similar
to sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. The provisions of SFAS 145 relating to leases were
effective for transactions occurring after May 15, 2002. The application of
SFAS 145 did not affect our financial position or results of operations during
2002.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and replaces the guidance in Emerging Issues Task Force ("EITF") No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability
for costs associated with an exit or disposal activity, including contract
termination costs, employee termination benefits and other associated costs, be
recognized when the liability is incurred. Under EITF No. 94-3, a liability was
recognized at the date an entity committed to an exit plan. SFAS 146 will be
effective for disposal activities initiated after December 31, 2002.
2. UTILITY REGULATORY MATTERS
Gas Utility
Gas Competition Act. On June 22, 1999, the Gas Competition Act was signed into
law. The purpose of the Gas Competition Act is to provide all natural gas
consumers in Pennsylvania with the ability to purchase their gas supplies from
the supplier of their choice. Under the Gas Competition Act, local gas
distribution companies ("LDCs") like Gas Utility may continue to sell gas to
customers, and such sales of gas, as well as distribution services provided by
LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the
supplier of last resort for all residential and small commercial and industrial
("core-market") customers unless the PUC approves another supplier of last
resort. The Gas Competition Act requires energy marketers seeking to serve
customers of LDCs to accept assignment of a portion of the LDC's pipeline
capacity and storage contracts at contract rates, thus avoiding the creation of
stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC
to avoid such contract release or
F-15
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
assignment. However, such petition may be granted only if the LDC fully
recovers the cost of contracts. The Gas Competition Act, in conjunction with a
companion bill, eliminated the gross receipts tax on sales of gas effective
January 1, 2000.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas
Utility's restructuring plan filed by Gas Utility pursuant to the Gas
Competition Act. Among other things, the implementation of the Gas
Restructuring Order resulted in an increase in Gas Utility's core-market base
rates effective October 1, 2000. This base rate increase was designed to
generate approximately $16,700 in additional net annual revenues. In accordance
with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates
by an annualized amount of $16,700 in the first 14 months following the October
1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its core-market
PGC rates by amounts equal to the margin it receives from interruptible
customers using pipeline capacity contracted by Gas Utility for core-market
customers. As a result, beginning December 31, 2001, Gas Utility operating
results are more sensitive to the effects of heating-season weather and less
sensitive to the market prices of alternative fuels.
Transfer of Assets. On May 24, 2001, the PUC approved Gas Utility's application
for approval to transfer its liquefied natural gas ("LNG") and propane air
("LP") facilities, along with related assets, to an unregulated affiliate,
Energy Services, Inc. ("Energy Services"), a second-tier wholly owned
subsidiary of UGI. The associated reduction in Gas Utility's base rates,
adjusted for the impact of the transfer on net operating expenses, is not
expected to have a material effect on our results of operations. Gas Utility
transferred the LNG and LP assets, which had a net book value of $4,277, on
September 30, 2001. The transfer is reflected as a dividend of net assets in
the 2001 Consolidated Statement of Stockholder's Equity.
Electric Utility
Electric Utility Restructuring Order. On June 19, 1998, the PUC entered its
Opinion and Order ("Electricity Restructuring Order") in Electric Utility's
restructuring proceeding pursuant to the Electricity Choice Act. Under the
terms of the Electricity Restructuring Order, Electric Utility was authorized
to recover $32,500 in stranded costs (on a full revenue requirements basis
which includes all income and gross receipts taxes) over a four-year period
beginning January 1, 1999 through a Competitive Transition Charge ("CTC")
(together with carrying charges on unrecovered balances of 7.94%) and to charge
unbundled rates for generation, transmission and distribution services.
Stranded costs are electric generation-related costs that traditionally would
be recoverable in a regulated environment but may not be recoverable in a
competitive electric generation market. Electric Utility's recoverable stranded
costs included $8,692 for the buy-out of a 1993 power purchase agreement with
an independent power producer. Under the terms of the Electricity Restructuring
Order and in accordance with the Electricity Choice Act, Electric Utility
generally could not increase the generation component of prices during the
period that stranded costs were being recovered through the CTC. Since January
1, 1999, all of Electric Utility's customers have been permitted to choose an
alternative generation supplier. Customers choosing an alternative supplier
during the stranded cost recovery period received a "shopping credit."
F-16
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The PUC approved a settlement establishing rules for Electric Utility Provider
of Last Resort ("POLR") service on March 28, 2002 and a separate settlement
that modified these rules on June 13, 2002 (collectively the "POLR Settlement")
under which Electric Utility terminated stranded cost recovery through its CTC
from commercial and industrial ("C&I") customers on July 31, 2002, and from
residential customers on October 31, 2002, and is no longer subject to the
statutory rate caps as of August 1, 2002 for C&I customers and as of November
1, 2002 for residential customers. Charges for generation service will (1)
initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 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.
Formation of Hunlock Creek Energy Ventures. On December 8, 2000, UGID
contributed its coal-fired Hunlock Creek generating station ("Hunlock") and
certain related assets having a net book value of $4,214, and $6,000 in cash,
to Energy Ventures, a general partnership jointly owned by the Company and a
subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was
recorded at its carrying value and no gain was recognized by the Company. Also
on December 8, 2000, Allegheny contributed a newly constructed, gas-fired
combustion turbine generator to be operated at the Hunlock site. Under the
terms of our arrangement with Allegheny, each partner is entitled to purchase
50% of the output of the joint venture at cost. Total purchases from Energy
Ventures in 2002 and 2001 were $9,751 and $7,966, respectively. At September
30, 2002 and 2001, the carrying amounts of our investment in Energy Ventures
were $10,017 and $10,832, respectively, which amounts are included in other
assets in the Consolidated Balance Sheets.
Regulatory Assets and Liabilities
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
- -----------------------------------------------------------
2002 2001
- -----------------------------------------------------------
Regulatory assets:
Income taxes recoverable $ 54,727 $ 51,761
Power agreement buy-out - 1,338
Other postretirement benefits 2,397 2,633
Deferred fuel costs 4,304 -
Other 561 423
- -----------------------------------------------------------
Total regulatory assets $ 61,989 $ 56,155
- -----------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 4,332 $ 4,339
Deferred fuel costs - 2,752
- -----------------------------------------------------------
Total regulatory liabilities $ 4,332 $ 7,091
- -----------------------------------------------------------
F-17
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company's regulatory liabilities are included in "other current
liabilities" and "other noncurrent liabilities" on the Consolidated Balance
Sheets. The Company's regulatory assets do not earn a return.
3. DEBT
Long-term debt comprises the following at September 30:
- -----------------------------------------------------------------------------------------------------
2002 2001
- -----------------------------------------------------------------------------------------------------
Medium-Term Notes:
7.25% Notes, due November 2017 $ 20,000 $ 20,000
7.17% Notes, due June 2007 20,000 20,000
7.37% Notes, due October 2015 22,000 22,000
6.73% Notes, due October 2002 26,000 26,000
6.62% Notes, due May 2005 20,000 20,000
7.14% Notes, due December 2005 (including unamortized
premium of $392 and $533, respectively, effective rate - 6.64%) 30,392 30,533
7.14% Notes, due December 2005 20,000 20,000
5.53% Notes due September 2012 40,000 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $23 and $56, respectively) 49,977 49,944
- -----------------------------------------------------------------------------------------------------
Total long-term debt 248,369 208,477
Less current maturities (76,000) -
- -----------------------------------------------------------------------------------------------------
Long-term debt due after one year $172,369 $208,477
- -----------------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt for each of the next five
fiscal years ending September 30 are as follows: 2003 - $76,000; 2004 - $0;
2005 - $20,000; 2006 - $50,000; 2007 - $20,000.
At September 30, 2002, UGI Utilities had revolving credit agreements with four
banks providing for borrowings of up to $97,000. These agreements expire at
various dates through September 2005. UGI Utilities may borrow at various
prevailing interest rates, including LIBOR. UGI Utilities pays quarterly
commitment fees on these credit lines. UGI Utilities had borrowings under these
agreements totaling $37,200 at September 30, 2002 and $57,800 at September 30,
2001, which we classify as bank loans. The weighted-average interest rates on
bank loans were 2.35% at September 30, 2002 and 3.75% at September 30, 2001.
UGI Utilities' credit agreements have restrictions on such items as total debt,
debt service, and payments for investments. They also require consolidated
tangible net worth of at least $125,000. At September 30, 2002, UGI Utilities
was in compliance with its financial covenants.
F-18
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
The provisions for income taxes consist of the following:
- -------------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------
Current expense:
Federal $ 13,341 $ 25,344 $ 22,721
State 5,115 8,103 6,819
- -------------------------------------------------------------------------------------------
Total current expense 18,456 33,447 29,540
Deferred (benefit) expense 11,512 (1,618) 3,264
Investment tax credit amortization (398) (398) (398)
- -------------------------------------------------------------------------------------------
Total income tax expense $ 29,570 $ 31,431 $ 32,406
- -------------------------------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
- -------------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 6.3 6.5 6.1
Deferred investment tax credit amortization (0.5) (0.5) (0.5)
Other, net (0.7) (1.5) (1.5)
- -------------------------------------------------------------------------------------------
Effective tax rate 40.1% 39.5% 39.1%
- -------------------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
- -------------------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and
equipment $ 107,627 $ 99,928
Regulatory assets 25,108 23,301
Employee-related expenses 10,546 8,901
Other 777 804
- -------------------------------------------------------------------------------------------
Gross deferred tax liabilities 144,058 132,934
- -------------------------------------------------------------------------------------------
Deferred investment tax credits (3,479) (3,644)
Employee-related expenses (6,371) (6,067)
Power purchase agreement liability (515) (1,487)
Accumulated other comprehensive loss (1,968) -
Other (2,852) (5,373)
- -------------------------------------------------------------------------------------------
Gross deferred tax assets (15,185) (16,571)
- -------------------------------------------------------------------------------------------
Net deferred tax liabilities $ 128,873 $116,363
- -------------------------------------------------------------------------------------------
UGI Utilities had recorded deferred tax liabilities of approximately $35,498 as
of September 30, 2002 and $33,928 as of September 30, 2001 pertaining to utility
temporary differences, principally
F-19
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
a result of accelerated tax depreciation, the tax benefits of which previously
were or will be flowed through to ratepayers. These deferred tax liabilities
have been reduced by deferred tax assets of $3,479 at September 30, 2002 and
$3,644 at September 30, 2001, pertaining to utility deferred investment tax
credits. UGI Utilities had recorded regulatory income tax assets related to
these net deferred taxes of $54,727 as of September 30, 2002 and $51,761 as of
September 30, 2001. These regulatory income tax assets represent future revenues
expected to be recovered through the ratemaking process. We will recognize this
regulatory income tax asset in deferred tax expense as the corresponding
temporary differences reverse and additional income taxes are incurred.
5. EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS
We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for
employees of UGI, UGI Utilities, and certain of UGI's other wholly owned
subsidiaries. In addition, we provide postretirement health care benefits to
certain retirees and a limited number of active employees meeting certain age
and service requirements, and postretirement life insurance benefits to nearly
all active and retired employees.
F-20
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following provides a reconciliation of benefit obligations, plan assets, and
funded status of the plans as of September 30:
- -------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
----------------------- ---------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 165,154 $ 150,952 $ 18,179 $ 16,939
Service cost 3,582 3,085 90 75
Interest cost 12,480 12,076 1,474 1,390
Actuarial loss 18,589 7,901 5,051 1,404
Plan amendments 395 - - -
Benefits paid (9,327) (8,860) (1,397) (1,629)
- -------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 190,873 $ 165,154 $ 23,397 $ 18,179
- -------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets - beginning of year $ 183,736 $ 223,524 $ 6,994 $ 6,411
Actual return on plan assets (8,345) (30,928) 144 190
Employer contributions - - 2,105 2,022
Benefits paid (9,327) (8,860) (1,397) (1,629)
- -------------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $ 166,064 $ 183,736 $ 7,846 $ 6,994
- -------------------------------------------------------------------------------------------------
Funded status of the plans $ (24,809) $ 18,582 $ (15,551) $(11,185)
Unrecognized net actuarial loss 50,190 4,166 5,945 632
Unrecognized prior service cost 3,038 3,337 - -
Unrecognized net transition (asset) obligation (3,004) (4,634) 7,059 7,743
- -------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 25,415 $ 21,451 $ (2,547) $ (2,810)
- -------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.8% 7.7% 6.8% 7.7%
Expected return on plan assets 9.5% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5%
- -------------------------------------------------------------------------------------------------
Included in the end of year pension benefit obligations above are $13,955 at
September 30, 2002 and $10,544 at September 30, 2001 relating to employees of
UGI and certain of its other subsidiaries. Included in the end of year
postretirement obligations above are $649 at September 30, 2002 and $471 at
September 30, 2001 relating to employees of UGI and certain of its other
subsidiaries.
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension and other postretirement benefit costs relating to UGI
Utilities employees include the following components:
- ---------------------------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
------------------------------------- -------------------------------
2002 2001 2000 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
Service cost $ 3,193 $ 2,785 $ 2,898 $ 84 $ 82 $ 70
Interest cost 11,600 11,319 11,090 1,453 1,326 1,168
Expected return on assets (17,778) (17,766) (16,010) (366) (366) (252)
Amortization of:
Transition (asset) obligation (1,518) (1,530) (1,534) 680 679 680
Prior service cost 646 625 626 - - -
Actuarial gain (loss) - (1,104) - 20 - -
- ---------------------------------------------------------------------------------------------------------------------------
Net benefit cost (income) (3,857) (5,671) (2,930) 1,871 1,721 1,666
Change in regulatory assets and liabilities - - - 1,228 1,378 1,433
- ---------------------------------------------------------------------------------------------------------------------------
Net expense (income) $ (3,857) $ (5,671) $ (2,930) $ 3,099 $ 3,099 $ 3,099
- ---------------------------------------------------------------------------------------------------------------------------
UGI Utilities Pension Plan assets are held in trust and consist principally of
equity and fixed income mutual funds and a commingled bond fund. UGI Common
Stock comprised approximately 6% of trust assets at September 30, 2002. Although
the UGI Utilities Pension Plan projected benefit obligation exceeded plan assets
at September 30, 2002, plan assets exceeded accumulated benefit obligation by
$7,154.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary
Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and
life insurance benefits and to fund the UGI Utilities' postretirement benefit
liability. UGI Utilities is required to fund its postretirement benefit
obligations by depositing into the VEBA the annual amount of postretirement
benefits costs determined under SFAS No. 106, "Employers Accounting for
Postretirement Benefits Other than Pensions." The difference between such
amounts and amounts included in UGI Utilities' rates is deferred for future
recovery from, or refund to, ratepayers. VEBA investments consist principally of
money market funds.
The assumed health care cost trend rates are 12.0% for fiscal 2003, decreasing
to 5.5% in fiscal 2010. A one percentage point change in the assumed health care
cost trend rate would change the 2002 postretirement benefit cost and obligation
as follows:
- --------------------------------------------------------------------------
1% 1%
Increase Decrease
- --------------------------------------------------------------------------
Effect on total service and interest costs $ 87 $ (77)
Effect on postretirement benefit obligation 1,345 (1,192)
- --------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 2002 and 2001, the projected benefit obligations of these plans
were not material. We recorded expense for these plans of $269 in 2002, $235 in
2001 and $131 in 2000.
DEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings
Plan"). Generally, participants in the Utilities Savings Plan may contribute a
portion of their compensation on a
F-22
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
before-tax and after-tax basis. We may, at our discretion, match a portion of
participants' contributions. The cost of benefits under the savings plans
totaled $932 in 2002, $936 in 2001, and $948 in 2000.
6. INVENTORIES
Inventories comprise the following at September 30:
- -------------------------------------------------------
2002 2001
- -------------------------------------------------------
Utility fuel and gases $ 36,208 $ 45,628
Appliances for sale 480 599
Materials, supplies and other 1,966 1,847
- -------------------------------------------------------
Total inventories $ 38,654 $ 48,074
- -------------------------------------------------------
7. SERIES PREFERRED STOCK
The Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 2,000,000 shares authorized for issuance.
The holders of shares of Series Preferred Stock have the right to elect a
majority of the Board of Directors (without cumulative voting) if dividend
payments on any series are in arrears in an amount equal to four quarterly
dividends. This election right continues until the arrearage has been cured. We
have paid cash dividends at the specified annual rates on all outstanding Series
Preferred Stock.
At September 30, 2002 and 2001, we had outstanding 200,000 shares of $7.75
Series cumulative 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 our $7.75 Series at a price of $100 per share. The $7.75 Series is
redeemable, in whole or in part, at our option on or after October 1, 2004, at a
price of $100 per share. All outstanding shares of $7.75 Series are subject to
mandatory redemption on October 1, 2009, at a price of $100 per share.
8. COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer and office equipment
under operating leases. Certain of our leases contain renewal and purchase
options and also contain escalation clauses. Our aggregate rental expense for
such leases was $4,690 in 2002, $4,624 in 2001 and $4,594 in 2000.
Minimum future payments under operating leases that have initial or remaining
noncancelable terms in excess of one year for the fiscal years ending September
30 are as follows: 2003 - $2,819; 2004 - $2,579; 2005 - $2,139; 2006 - $1,812;
2007 - $1,554; after 2007 - $3,961.
Gas Utility has gas supply agreements with producers and marketers with terms of
less than one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity which Gas Utility may terminate at various
dates through 2015. Gas Utility's costs associated with
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
transportation and 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 spot-market prices.
Electric Utility purchases its capacity requirements and electric energy needs
under contracts with various suppliers and on the spot market. Contracts with
producers for capacity and energy needs expire at various dates through December
2006.
Future contractual cash obligations under Gas Utility and Electric Utility
supply agreements existing at September 30, 2002 are as follows: 2003 -
$106,400; 2004 - $96,532; 2005 - $56,865; 2006 - $23,255; 2007 - $14,856; after
2007 - $92,446.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities 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. UGI Utilities has been notified of several sites
outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or
operated by its former subsidiaries and (2) either environmental agencies or
private parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating two
claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable
in those instances in which a former subsidiary operated an MGP. There could be,
however, significant future costs of an uncertain amount associated with
environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that the subsidiary's separate corporate
form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance companies
alleging that the defendants breached contracts of insurance by failing to
indemnify UGI Utilities for certain environmental costs. The suit seeks to
recover more than $11,000 in such costs. During 2002, 2001, and 2000, UGI
Utilities entered into settlement agreements with several of the insurers and
recorded pretax income of $390, $943 and $4,500, respectively, which amounts are
included in operating and administrative expenses in the Consolidated Statements
of Income.
F-24
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In addition to these environmental matters, there are other pending claims and
legal actions arising in the normal course of our businesses. We cannot predict
with certainty the final results of environmental and other matters. However, it
is reasonably possible that some of them could be resolved unfavorably to us. We
believe, after consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a material
adverse effect on our financial position but could be material to our operating
results or cash flows in future periods depending on the nature and timing of
future developments with respect to these matters and the amounts of future
operating results and cash flows.
9. FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding current maturities of long-term debt) approximate
their fair values because of their short-term nature. The estimated fair value
of our long-term debt is approximately $263,000 at September 30, 2002 and
$218,000 at September 30, 2001. We estimate the fair value of long-term debt by
using current market prices and by discounting future cash flows using rates
available for similar type debt. The estimated fair value of our Series
Preferred Stock is approximately $20,400 at September 30, 2002 and $21,400 at
September 30, 2001. We estimated the fair value of our Series Preferred Stock
based on the fair value of redeemable preferred stock with similar credit
ratings and redemption features.
We have financial instruments such as trade accounts receivable which could
expose us to concentrations of credit risk. The credit risk from trade accounts
receivable is limited because we have a large customer base which extends across
many different markets. At September 30, 2002 and 2001, we had no significant
concentrations of credit risk.
F-25
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2)
Electric Operations comprising Electric Utility and our electricity generation
business. Gas Utility revenues are derived principally from the sale and
distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Operations derives its revenues principally from the sale
and distribution of electricity in two northeastern Pennsylvania counties.
The accounting policies of our reportable segments are the same as those
described in Note 1. We evaluate the performance of our Gas Utility and Electric
Operations segments principally based upon their earnings before income taxes.
No single customer represents more than ten percent of our consolidated revenues
and there are no significant intersegment transactions. In addition, all of our
reportable segments' revenues are derived from sources within the United States,
and all of our reportable segments' long-lived assets are located in the United
States. Financial information by business segment follows:
- -------------------------------------------------------------------------
Gas Electric
Total Utility Operations
- -------------------------------------------------------------------------
2002
Revenues $ 490,552 $ 404,519 $ 86,033
Depreciation and amortization 22,172 18,983 3,189
Operating income 90,317 77,148 13,169
Interest expense 16,652 14,224 2,428
Income before income taxes 73,665 62,924 10,741
Total assets 798,123 689,080 109,043
Capital expenditures 35,884 31,034 4,850
- -------------------------------------------------------------------------
2001
Revenues $ 584,762 $ 500,832 $ 83,930
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
- -------------------------------------------------------------------------
2000
Revenues $ 436,942 $ 359,041 $ 77,901
Depreciation and amortization 23,612 19,098 4,514
Operating income 101,235 86,178 15,057
Interest expense 18,353 16,175 2,178
Income before income taxes 82,882 70,003 12,879
Total assets 751,137 653,766 97,371
Capital expenditures 36,391 31,665 4,726
- -------------------------------------------------------------------------
F-26
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. QUARTERLY DATA (UNAUDITED)
The following quarterly information includes all adjustments (consisting only of
normal recurring adjustments), which we 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,
2001 2000 2002 2001 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------
Revenues $ 141,481 $ 166,503 $ 179,945 $ 231,591 $ 88,249 $ 103,772 $ 80,877 $ 82,896
Operating income 27,609 33,463 41,319 46,500 13,222 12,745 8,167 5,848
Net income 14,045 17,095 22,549 25,156 5,552 4,990 1,949 896
- -----------------------------------------------------------------------------------------------------
12. OTHER INCOME, NET
Other income, net, comprises the following:
- ---------------------------------------------------------------------
2002 2001 2000
- ---------------------------------------------------------------------
Non-tariff service income $ 5,701 $ 5,410 $ 3,182
Pension income 3,858 5,671 2,930
Interest income 1,110 235 2,860
Other 1,054 3,795 3,688
- ---------------------------------------------------------------------
$ 11,723 $ 15,111 $ 12,660
- ---------------------------------------------------------------------
13. RELATED PARTY TRANSACTIONS
UGI bills UGI Utilities for an allocated share of its general corporate
expenses. This allocation is based upon a three-factor formula which includes
revenues, costs and expenses, and net assets. These billed expenses are
classified as operating and administrative expenses - related parties in the
Consolidated Statements of Income.
F-27
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, 2002
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,151 $ 5,270 $ (6,449)(1) $ 1,972
========== =========
Other reserves (3) $ 3,467 $ 748 $ (2,352)(2) $ 3,363
========== =========
1,500 (4)
YEAR ENDED SEPTEMBER 30, 2001
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 2,061 $ 8,269 $ (7,179)(1) $ 3,151
========== =========
Other reserves (3) $ 1,954 $ 1,696 $ (276)(2) $ 3,467
========== =========
93 (4)
YEAR ENDED SEPTEMBER 30, 2000
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 1,716 $ 4,386 $ (4,041)(1) $ 2,061
========== =========
Other reserves (3) $ 1,345 $ 1,007 $ (455)(2) $ 1,954
========== =========
57 (4)
(1) Uncollectible accounts written off, net of recoveries.
(2) Payments, net
(3) Includes reserves for self-insured property and casualty liability,
insured property and casualty liability, environmental, litigation and
other.
(4) Other adjustments
S-1
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.2 Bylaws in effect since September 24, 2002
10.25 Storage Transportation Service Agreement (Rate Schedule SST)
between Utilities and Columbia dated November 1, 1993, as
modified pursuant to orders of the Federal Energy Regulatory
Commission
10.26 No-Notice Transportation Service Agreement (Rate Schedule
NTS) between Utilities and Columbia dated November 1, 1993,
as modified pursuant to orders of the Federal Energy
Regulatory Commission
10.27 No-Notice Transportation Service Agreement (Rate Schedule
CDS) between Utilities and Texas Eastern Transmission dated
February 23, 1999, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.28 No-Notice Transportation Service Agreement (Rate Schedule
CDS) between Utilities and Texas Eastern Transmission dated
October 31, 2000, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.29 Firm Transportation Service Agreement (Rate Schedule FT-1)
between Utilities and Texas Eastern Transmission dated June
15, 1999, as modified pursuant to various orders of the
Federal Energy Regulatory Commission
10.30 Firm Transportation Service Agreement (Rate Schedule FT-1)
between Utilities and Texas Eastern Transmission dated
October 31, 2000, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.31 Firm Transportation Service Agreement (Rate Schedule FT)
between Utilities and Transcontinental Gas Pipe Line dated
October 1, 1996, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
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12.1 Computation of Ratio of Earnings to Fixed Charges
12.2 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends
23 Consent of PricewaterhouseCoopers LLP
99 Certification by Chief Executive Officer and Chief Financial
Officer
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