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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, 2000
Commission file number 1-1398
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Pennsylvania 23-1174060
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER IDENTIFICATION NO.)
OF INCORPORATION OR ORGANIZATION)
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(610) 796-3400
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED
TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING
THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS
REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING
REQUIREMENTS FOR THE PAST 90 DAYS.
YES X . NO .
--- ---
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 December 1, 2000 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.
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TABLE OF CONTENTS
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PART I BUSINESS
Items 1 and 2 Business and Properties................................... 1
General................................................. 1
Gas Utility Operations.................................. 1
Electric Utility Operations............................. 5
Item 3 Legal Proceedings......................................... 10
Item 4 Submission of Matters to a Vote of
Security Holders........................................ 12
PART II SECURITIES AND FINANCIAL INFORMATION
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...................................................... 23
Item 8 Financial Statements and Supplementary Data............... 23
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................. 23
PART III UGI UTILITIES, INC. MANAGEMENT AND SECURITY HOLDERS
Item 10 Directors and Executive Officers of the Registrant........ 24
Item 11 Executive Compensation.................................... 29
Item 12 Security Ownership of Certain Beneficial
Owners and Management................................... 37
Item 13 Certain Relationships and Related
Transactions............................................ 39
PART IV ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
Item 14 Exhibits, Financial Statement Schedules
and Reports on Form 8-K................................. 39
Signatures................................................ 43
Index to Financial Statements and
Financial Statement Schedule.............................. F-2
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PART I: BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("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"). Utilities' executive offices are located at
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center, Reading,
Pennsylvania 19607, and its 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 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 Pennsylvania Public Utility Commission ("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. Gas Utility designed its restructuring
plan to ensure reliability of gas supply deliveries to Gas Utility on behalf of
residential and small commercial customers. The plan also
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provides for recovery of costs associated with existing pipeline capacity and
gas supply contracts. In addition, the plan changes Gas Utility's base rates for
firm customers. It also changes the calculation of purchased gas cost rates. See
"Utility Regulation and Rates." The effect of these two changes is to lessen the
financial impact of volatility in revenues associated with customers who have
the ability to switch to another fuel and are served under "interruptible
rates." On June 29, 2000, the PUC entered its order ("Gas Restructuring Order")
approving Gas Utility's restructuring plan substantially as filed.
Effective October 1, 2000, all of Gas Utility's customers have 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. Management believes neither the Gas
Competition Act nor the Gas Restructuring Order 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 272,000 customers
in portions of 14 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,500 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. For the fiscal years ended September 30, 2000, 1999 and 1998, revenues of
Gas Utility accounted for approximately 82%, 82% and 83%, respectively, of our
total consolidated revenues.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 2000 fiscal year was
approximately 79.7 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 40% of system throughput, while gas transported for commercial and
industrial customers (who bought their gas from others) accounted for
approximately 60% of system throughput. Based on industry data for 1999,
residential customers account for approximately 33% of total system throughput
by local gas distribution companies in the United States. By contrast, for the
2000 fiscal year, Gas Utility's residential customers represented 23% 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, storage and
transportation services from pipeline companies, and its own propane-air and
liquefied natural gas peak-shaving facilities. Purchases of natural gas in the
spot market are also made to reduce costs and manage storage inventory levels.
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.
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GAS SUPPLY CONTRACTS
During the 2000 fiscal year, Gas Utility purchased approximately 31.5
bcf of natural gas for sale to customers. Approximately 87% of the volumes
purchased were supplied under agreements with ten major suppliers of natural
gas. The remaining 13% of gas purchased was supplied by producers and marketers
under other arrangements, including multi-month agreements at spot prices. In
fiscal year 2001 Gas Utility will continue to obtain necessary gas supplies
under contracts no longer than 12 months in duration.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas
Utility's sales are seasonal. Approximately 58% of fiscal year 2000 throughput
and approximately 71% 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. Competition with
fuel oil dealers is focused on 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 distribution services. Under the Gas Competition Act, retail
customers now have the option to 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 for over 15 years. Gas Utility will
provide transportation services for residential and small commercial retail
customers who purchase natural gas from others, however, as of October 1, 2000,
no marketers had completed the requirements to serve those customers.
Commercial and industrial customers representing approximately 44% of
Gas Utility's transportation system throughput (27% of transportation revenues)
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 margins from these customers,
therefore, are affected by the difference, or "spread," between the customers'
delivered cost of gas and the customers' delivered alternate fuel cost. In
addition, other customers representing 30% of transportation system throughput
(17% of transportation revenues) have locations which afford them the option,
although none has exercised it, of seeking transportation service directly from
interstate pipelines, thereby bypassing Gas Utility. The majority of customers
in the latter 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
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contracts with Utilities, seven of which extend into fiscal year 2004. No single
customer represents, or is anticipated to represent, more than 1% 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 2001. 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. Gas Utility also operates propane air and liquefied
natural gas facilities to meet winter peak service requirements.
During fiscal year 2000, Gas Utility supplied transportation service to
three major cogeneration installations and two utility generation sites. 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
7,968 residential heating customers during fiscal year 2000, a 12% increase from
the previous year. Of those new customers, new home construction accounted for a
record 6,261 heating customers, an increase of approximately 10% from the prior
year. Customers converting from other energy sources, primarily oil, 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 total
number of new commercial and industrial customers was 1,226.
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 UTILITY 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's rates for transmission
and distribution services provided through June 30, 2001 are capped at levels in
effect on January 1, 1997. In addition, Electric Utility generally may not
increase prices for electric generation as long as stranded costs are being
recovered through the CTC. In accordance with the restructuring proceedings
discussed below, Utilities expects to collect a CTC from all distribution
customers until December 31, 2002. Under the ECC Act, Electric Utility remains
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 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%. Electric Utility's
recoverable stranded costs include approximately $8.7 million for the
termination of a 1993 power purchase agreement with Foster Wheeler Penn
Resources, Inc., an independent power producer. Since January 1, 1999, all of
Electric Utility's customers have been permitted to select an alternative
electric generation supplier. Customers choosing another supplier currently
receive an average generation "shopping credit" (developed from system-wide
generation rates) of 3.67 cents per kilowatt hour ("kwh"), which will remain in
effect through December 31, 2000. The shopping credit will increase to 4.3 cents
per kwh in calendar years 2001 and 2002.
As noted above, Electric Utility's power generation rates are capped
until December 31, 2002. Because Electric Utility has discontinued regulatory
accounting, which permitted it to adjust customer charges to reflect changes in
Electric Utility's power costs, quarterly results have been, and future results
are likely to be, more volatile than they were prior to deregulation, due in
large part to seasonal variations in such costs. Results will also be affected
by the number of customers who choose to purchase their power from other
suppliers during any given time period.
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SERVICE AREA; REVENUE ANALYSIS
Electric Utility supplies electric service to approximately 61,000
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 2000, about 52% of sales volume came from residential customers, 35% from
commercial customers and 13% from industrial customers. Electricity transported
for customers who purchased their power from others pursuant to the ECC Act
represented approximately 5% of this sales volume. For the 2000, 1999 and 1998
fiscal years, revenues of Electric Utility accounted for approximately 18%, 18%
and 17%, respectively, of our total consolidated revenues.
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. These two coal-fired stations provided
approximately 50% of Electric Utility's energy requirements during fiscal year
2000. Effective December 8, 2000, UGID entered into a partnership 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
the partnership's generation at cost. Electric Utility has contracts in place or
control over generation representing in the aggregate approximately 90% of its
expected on-peak energy requirements for fiscal year 2001. It plans to meet the
balance of its energy needs with short-term contracts and spot market purchases.
Electric Utility distributes both electricity that it purchases from
others (including UGID) and electricity that customers purchase from other
suppliers. At September 30, 2000, alternate suppliers served approximately 3% of
system load. Electric Utility expects to continue to provide energy to the great
majority of its customers.
ENVIRONMENTAL FACTORS
The operation of Hunlock Station complies with the air quality
standards of the Pennsylvania Department of Environmental Resources ("DER") with
respect to stack emissions. Under the Federal Water Pollution Control Act, 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 the Conemaugh
Station and the Hunlock Station are in material compliance with these emission
standards.
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SEASONALITY
Sales and distribution of electricity for residential heating purposes
accounted for approximately 20% of the total sales of Electric Utility during
fiscal year 2000. Electricity competes with natural gas, oil, propane and other
heating fuels in this use. Approximately 53% of volume occurred during the six
coldest months of fiscal year 2000 (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 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 provides that Gas Utility must reduce
its purchased gas cost rates by $16.7 million in the first year of the base rate
increase. As a result, customers who purchase their gas from Gas Utility will
not be affected by the increase in base rates for twelve months.
Beginning in fiscal year 2002, Gas Utility must reduce its purchased
gas cost rates by an amount equal to the revenues it receives from customers
served under interruptible rates who do not obtain their own pipeline capacity.
As a result of these changes in its regulated rates, Gas Utility expects that
the risk to operating results associated with year- to- year fluctuations in
interruptible revenues will be mitigated. Due to the required allocation of
interruptible revenues
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under the Gas Restructuring Order, beginning with fiscal year 2001, Gas Utility
operating results are expected to be 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 2 to the
Company's Consolidated Financial Statements.
PURCHASED GAS COST RATES
Gas Utility's gas service tariff contains Purchased Gas Cost ("PGC")
rates which provide for annual increases or decreases in the rate per thousand
cubic feet ("mcf") which Gas Utility 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. The Gas Restructuring Order provides for a one-time adjustment to Gas
Utility's PGC rates as described above, as well as ongoing adjustments to
reflect revenues, if any, from interruptible rate customers who do not obtain
their own pipeline capacity.
ELECTRIC UTILITY RATES
Electric Utility's rates for transmission and distribution services
provided through June 30, 2001 are capped at levels in effect on January 1,
1997. Its rates for electric generation are capped through December 2002. 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. Electric Utility is actively
participating in the regulatory process for establishing rules to ensure that
Electric Utility recovers all its costs of providing generation when the rate
cap period ends in December 2002.
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, however,
any increase in Electric Utility's state tax surcharge is generally subject to
the rate caps discussed above.
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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, Comprehensive Environmental Response,
Compensation and Liability Act ("Superfund Law") 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 "ELECTRIC UTILITY
OPERATIONS - Environmental Factors."
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' operating segments for the 2000,
1999 and 1998 fiscal years appears in Note 10 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
EMPLOYEES
At September 30, 2000, Utilities and its subsidiaries had 1,120
employees.
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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.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
Prior to the general availability of natural gas, in the 1800s through
the mid-1900s, most gas for lighting and heating nationwide was manufactured
from combustibles such as coal, oil and coke. 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
manufactured gas plants.
Utilities and its former subsidiaries owned and operated a number of
manufactured gas plants. Between 1882 and 1953, Utilities owned the stock of
subsidiary gas companies in Pennsylvania and elsewhere and also operated the
businesses of some gas companies under agreement. By the mid-1930s, Utilities
was one of the largest public utility holding companies in the country. 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 the
Gas Utility and the Electric Utility.
Utilities has been notified of several sites outside Pennsylvania on
which (i) gas plants were formerly operated by it or owned or operated by its
former subsidiaries and (ii) 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.
At one such site, in July 1993, Public Service Electric and Gas Company
("PSE&G") joined Utilities as a third-party defendant in the civil action
Fishbein Family Partnership v. PPG Industries, Inc., et al 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 Halladay Street gas plant
operated from approximately 1884 until 1950. PSE&G has asserted that Utilities
is liable for that portion of the costs associated with operations of the plant
between 1886 and 1940. PPG Industries, Inc. is also a defendant in the action
for costs associated with chemical contamination at the site unrelated to gas
plant operations. To date, that action has focused on the chemical contamination
allegedly associated with PPG Industries' activities and the third-party action
against Utilities has been stayed. Investigations of the site conducted to date
are insufficient to establish the extent of environmental remediation necessary,
if any. Hence, Utilities is unable to estimate the total cost of cleanup
associated with manufactured gas plant wastes at this site.
Management believes that Utilities should not have significant
liability in those instances in which a former subsidiary operated a
manufactured gas plant because Utilities generally is not legally liable for the
obligations of its subsidiaries. Under certain circumstances, however, a court
could find a parent company liable for environmental damage caused by a
subsidiary company
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when the parent company either (i) itself operated the facility causing the
environmental damage or (ii) otherwise so controlled the subsidiary that the
subsidiary's separate corporate form should be disregarded. There could be,
therefore, significant future costs of an uncertain amount associated with
environmental damage caused by manufactured gas plants that Utilities owned or
directly operated, or that were owned or operated by former subsidiaries of
Utilities, if a court were to conclude that the subsidiary's separate corporate
form should be disregarded. See also Notes 1 and 8 to the Company's Consolidated
Financial Statements.
Utilities has identified 40 sites in Pennsylvania where either (i)
Utilities formerly conducted some manufactured gas operations or (ii) Utilities
owns or at one time owned the site. Most of the sites are no longer owned by
Utilities and there have been no manufactured gas operations at any of the sites
since at least the early 1950s. Utilities or other parties are currently
conducting or have completed investigative and remedial activities at eleven of
the 40 sites. Based on the 1995 settlement agreement with the PUC relating to
Gas Utilities' 1995 base rate increase filing, rate relief will be permitted for
certain remediation expenditures on environmentally contaminated sites located
in Pennsylvania. Because of this, Utilities does not expect its costs for
Pennsylvania sites to be material to its results of operations.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et. al. On
February 11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas
of Montgomery County, Pennsylvania against more than fifty insurance companies,
including Insurance Services, Ltd. (AEGIS). The complaint alleges that the
defendants breached contracts of insurance by failing to indemnify Utilities for
certain environmental costs. 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.
-11-
<PAGE> 14
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 2000.
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
Dividends declared on the Company's Common Stock totaled $44 million in
fiscal year 2000, $29 million in fiscal year 1999 and $22.6 million in fiscal
year 1998.
-12-
<PAGE> 15
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended
September 30,
--------------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
FOR THE PERIOD:
INCOME STATEMENT DATA:
Revenues $436,942 $420,647 $422,283 $461,208 $460,496
======== ======== ======== ======== ========
Net income $ 50,476 $ 38,868 $ 35,551 $ 38,711 $ 38,348
Dividends on preferred stock 1,550 1,550 2,160 2,764 2,765
-------- -------- -------- -------- --------
Net income after dividends
on preferred stock $ 48,926 $ 37,318 $ 33,391 $ 35,947 $ 35,583
======== ======== ======== ======== ========
AT PERIOD END:
BALANCE SHEET DATA:
Total assets $754,122 $717,169 $690,317 $681,378 $649,899
======== ======== ======== ======== ========
Capitalization:
Debt:
Bank loans $100,400 $ 87,400 $ 68,400 $ 67,000 $ 50,500
Long-term debt including
current maturities: 172,924 180,047 187,170 169,294 176,654
-------- -------- -------- -------- --------
Total debt 273,324 267,447 255,570 236,294 227,154
Preferred stock subject to
mandatory redemption 20,000 20,000 20,000 35,187 35,187
Common equity 224,473 219,560 211,242 200,494 189,441
-------- -------- -------- -------- --------
Total capitalization $517,797 $507,007 $486,812 $471,975 $451,782
======== ======== ======== ======== ========
RATIO OF CAPITALIZATION:
Total debt 52.8% 52.8% 52.5% 50.0% 50.3%
UGI Utilities preferred stock 3.9% 3.9% 4.1% 7.5% 7.8%
Common equity 43.3% 43.3% 43.4% 42.5% 41.9%
-------- -------- -------- -------- --------
100.0% 100.0% 100.0% 100.0% 100.0%
======== ======== ======== ======== ========
</TABLE>
-13-
<PAGE> 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FISCAL 2000 COMPARED WITH FISCAL 1999
<TABLE>
<CAPTION>
Year Ended September 30, 2000 1999 Increase
-----------------------------------------------------------------------------------
(Millions of dollars)
<S> <C> <C> <C> <C>
GAS UTILITY:
Revenues $359.0 $345.6 $ 13.4 3.9%
Total margin $170.8 $160.6 $ 10.2 6.4%
EBITDA(a) $105.3 $ 87.0 $ 18.3 21.0%
Operating income $ 86.2 $ 68.0 $ 18.2 26.8%
System throughput - bcf(b) 79.7 76.1 3.6 4.7%
Degree days - % warmer than normal 9.9% 12.8% -- --
ELECTRIC UTILITY:
Revenues $ 77.9 $ 75.0 $ 2.9 3.9%
Total margin $ 40.5 $ 38.6 $ 1.9 4.9%
EBITDA(a) $ 19.6 $ 16.8 $ 2.8 16.7%
Operating income $ 15.1 $ 12.8 $ 2.3 18.0%
Sales - gwh(b) 907.2 900.4 6.8 0.8%
-----------------------------------------------------------------------------------
</TABLE>
(a) EBITDA (earnings before interest expense, income taxes, depreciation and
amortization) should not be considered as an alternative to net income (as
an indicator of operating performance) or as an alternative to cash flow (as
a measure of liquidity or ability to service debt obligations) and is not a
measure of performance or financial condition under generally accepted
accounting principles.
(b) bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin
represents revenues less cost of sales and revenue-related taxes.
GAS UTILITY. Weather in Gas Utility's service territory was 9.9% warmer than
normal in Fiscal 2000 but 3.8% colder than in Fiscal 1999. The increase in
system throughput during Fiscal 2000 resulted from higher interruptible delivery
service volumes and higher sales to our firm retail ("core market") customers.
-14-
<PAGE> 17
The increase in Gas Utility's revenues during Fiscal 2000 principally resulted
from (1) a $13.1 million increase in core market revenues reflecting higher
sales and higher average purchased gas cost ("PGC") rates partially offset by
the impact of the elimination of gross receipts tax revenue effective January 1,
2000 pursuant to Pennsylvania's Gas Competition Act and (2) a $5.9 million
increase in revenues from interruptible customers. These increases in revenue
were partially offset by lower off-system sales and firm delivery service
revenues. Gas Utility cost of gas was $184.2 million in Fiscal 2000 compared
with $172.0 million in Fiscal 1999. The increase reflects higher average PGC
rates and higher core market sales partially offset by lower costs associated
with the decline in off-system sales.
Gas Utility total margin increased $10.2 million reflecting (1) a $4.2 million
increase in total interruptible retail and interruptible delivery service
margin; (2) a $4.9 million increase in core market margin; and (3) slightly
higher firm delivery service total margin.
Gas Utility EBITDA and operating income increased $18.3 million and $18.2
million, respectively, as a result of (1) the higher total margin; (2) a $5.0
million increase in other income; and (3) a decrease in net operating expenses.
Other income in Fiscal 2000 includes, among other things, (1) income from the
refund of revenue-related tax overpayments made in prior years (including
associated interest); (2) interest income from PGC undercollections; and (3)
higher income from a construction project and other activities. Gas Utility's
net operating expenses declined $3.1 million, despite an increase in
distribution system maintenance expenses, principally reflecting (1) $4.5
million in income from insurance litigation settlements and (2) $0.9 million
from adjustments to incentive compensation accruals.
ELECTRIC UTILITY. Electric sales for Fiscal 2000 increased 0.8% on weather that
was slightly colder than in the prior year. Revenues increased as a result of
the higher sales as well as an increase in transmission revenues from wholesale
transmission services which have been unbundled as a result of electric customer
choice. Cost of sales increased to $33.9 million in Fiscal 2000 from $33.2
million in Fiscal 1999 reflecting the higher sales and higher costs associated
with wholesale transmission services.
Electric Utility total margin increased $1.9 million principally reflecting the
impact of lower average power costs and higher sales. EBITDA and operating
income also increased reflecting higher total margin and a $2.5 million increase
in other income principally from the sale of pollution credits. These increases
were partially offset by higher utility realty taxes and greater power
production maintenance expenses.
-15-
<PAGE> 18
<TABLE>
<CAPTION>
Increase
Year Ended September 30, 1999 1998 (Decrease)
--------------------------------------------------------------------------------
(Millions of dollars)
<S> <C> <C> <C> <C>
GAS UTILITY:
Revenues $345.6 $350.2 $ (4.6) (1.3)%
Total margin $160.6 $157.2 $ 3.4 2.2%
EBITDA $ 87.0 $ 82.9 $ 4.1 4.9%
Operating income $ 68.0 $ 64.8 $ 3.2 4.9%
Natural gas system throughput - bcf $ 76.1 $ 74.9 $ 1.2 1.6%
Degree days - % warmer than normal 12.8% 16.3% -- --
ELECTRIC UTILITY:
Revenues $ 75.0 $ 72.1 $ 2.9 4.0%
Total margin $ 38.6 $ 34.0 $ 4.6 13.5%
EBITDA $ 16.8 $ 13.6 $ 3.2 23.5%
Operating income $ 12.8 $ 9.7 $ 3.1 32.0%
Sales - gwh 900.4 876.4 24.0 2.7%
--------------------------------------------------------------------------------
</TABLE>
GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than
normal in Fiscal 1999 but 4.2% colder than in Fiscal 1998. Total system
throughput increased 1.6% as a result of the slightly colder weather as well as
an increase in total customers.
The decrease in Gas Utility revenues in Fiscal 1999 is principally due to
several of our core market industrial customers switching from retail to
delivery service. Under retail service, we bill our customers for the
transportation of gas through our distribution system as well as the cost of the
gas, for which we get dollar-for-dollar recovery. Under delivery service, we
bill customers for the transportation of the gas but not for the gas itself. Our
revenues from customers who switch to delivery service are therefore lower, but
there is little impact on our total margin. Partially offsetting the decline in
revenues from our core market industrial customers was an increase in revenues
from sales to our core market residential and commercial customers. Gas Utility
cost of gas was $172.0 million in Fiscal 1999, a decrease of $7.6 million from
Fiscal 1998, reflecting the impact of core market industrial customers switching
to delivery service.
-16-
<PAGE> 19
The increase in Gas Utility total margin in Fiscal 1999 includes a $3.6 million
increase from sales to our core market residential and commercial customers.
Total margin from interruptible customers (who have the ability to switch to
alternate fuels, principally oil) was slightly lower in Fiscal 1999. The decline
in total margin from our interruptible customers reflects lower interruptible
rates due to a decline in the spread between oil and natural gas prices during
most of Fiscal 1999.
Gas Utility operating income was higher in Fiscal 1999 reflecting the increase
in total margin and higher other income partially offset by slightly higher
operating and administrative expenses and increased charges for depreciation.
Operating expenses in the prior year are net of $1.6 million of income from an
insurance recovery. Excluding the impact of the insurance recovery in Fiscal
1998, total Gas Utility operating and administrative expenses in Fiscal 1999
were essentially unchanged.
ELECTRIC UTILITY. The increase in Fiscal 1999 sales of electricity reflects
slightly colder heating season weather and warmer weather during the summer air
conditioning season. Electric Utility revenues increased $2.9 million in Fiscal
1999 principally as a result of the higher sales. Although Electric Utility's
Restructuring Order filed pursuant to Pennsylvania's Electricity Customer Choice
Act gives all of our customers the ability to choose their electricity
generation supplier effective January 1, 1999, only approximately 5% of our
sales during Fiscal 1999 represented electricity we distributed for alternate
suppliers. Notwithstanding the increase in Electric Utility sales in Fiscal
1999, cost of sales decreased $1.8 million to $33.2 million. The impact of the
higher Fiscal 1999 sales on purchased power costs was more than offset by (1)
the benefit of a power supply agreement settlement and (2) lower average
purchased power costs.
Electric Utility's total margin increased $4.6 million as a result of (1) the
power supply agreement settlement; (2) lower average purchased power costs; and
(3) the higher sales. EBITDA and operating income were also higher as the
greater total margin was partially offset by higher maintenance costs associated
with our generation assets, higher customer service and information expenses,
and lower other income.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
UGI Utilities' debt outstanding at September 30, 2000 totaled $273.3 million
compared with $267.4 million at September 30, 1999. The increase reflects higher
borrowings under our revolving credit facilities. During Fiscal 2000, we made
long-term debt repayments of $7.1 million.
UGI Utilities' primary sources of cash have been (1) cash generated by
operations; (2) borrowings under its revolving credit agreements; and (3) debt
issued under its Medium-Term Note program. UGI Utilities can issue up to an
additional $52 million under its Medium-Term Note program.
-17-
<PAGE> 20
UGI Utilities may borrow up to a total of $122 million under its revolving
credit agreements. Borrowings under revolving credit agreements totaled $100.4
million at September 30, 2000 and $87.4 million at September 30, 1999.
Management believes that UGI Utilities' cash flow from operations and borrowings
under its Medium-Term Note program and bank credit facilities will satisfy UGI
Utilities' cash needs in fiscal 2001. For a more detailed discussion of UGI
Utilities' debt and credit facilities, including financial covenants and ratios,
see Note 3 to Consolidated Financial Statements.
CASH FLOWS
OPERATING ACTIVITIES. Cash flow from operating activities was $81.4 million in
Fiscal 2000 compared with $62.2 million in Fiscal 1999. Cash flow from operating
activities before changes in operating working capital was $83.3 million in
Fiscal 2000 compared with $70.5 million in Fiscal 1999. Changes in operating
working capital used $1.9 million of operating cash flow in Fiscal 2000 compared
with $8.4 million of operating cash flows in Fiscal 1999.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment were $36.4
million in both Fiscal 2000 and Fiscal 1999.
FINANCING ACTIVITIES. During Fiscal 2000, we paid $44.0 million in cash
dividends to UGI and $1.6 million in dividends to holders of our preferred
stock. During Fiscal 1999, we paid $29 million in cash dividends to UGI and $1.6
million in dividends on our preferred stock. In Fiscal 2000, we borrowed a net
$13 million under our revolving credit agreements compared with net borrowings
of $19 million in Fiscal 1999. In both Fiscal 2000 and 1999, we repaid $7.1
million of maturing long-term debt.
CAPITAL EXPENDITURES
The following table presents capital expenditures of Gas Utility and Electric
Utility for the fiscal years ended September 30, 2000, 1999 and 1998, as well as
expected amounts for fiscal 2001. Utilities expects to finance fiscal 2001
capital expenditures through internally generated cash and borrowings under its
credit facilities.
<TABLE>
<CAPTION>
Year Ended September 30, 2001 2000 1999 1998
--------------------------------------------------------------------------------
(Millions of dollars) (estimate)
<S> <C> <C> <C> <C>
Gas Utility $ 34.9 $ 31.7 $ 31.9 $ 32.0
Electric Utility 6.0 4.7 4.5 5.2
--------------------------------------------------------------------------------
$ 40.9 $ 36.4 $ 36.4 $ 37.2
--------------------------------------------------------------------------------
</TABLE>
-18-
<PAGE> 21
UTILITY MATTERS
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 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 Pennsylvania Public Utility Commission ("PUC"). As of January
1, 2000, the Gas Competition Act, in conjunction with a companion bill,
eliminated the gross receipts tax.
Generally, 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. LDCs are generally precluded from increasing rates for
the recovery of costs, other than gas costs, until January 1, 2001. 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. After July 1, 2002, a natural gas supplier may petition the PUC to avoid
such contract release or assignment. The PUC, however, may only grant the
petition if certain findings are made and the LDC fully recovers the cost of
contracts.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas
Utility's restructuring plan substantially as filed. Among other things, the
restructuring plan (1) provides for recovery of costs associated with existing
pipeline capacity and gas supply contracts; (2) increases Gas Utility's base
rates for firm customers; and (3) changes the calculation of PGC rates. The
effect of (2) and (3) above is to reduce the financial impact of volatility in
revenues from customers who have the ability to switch to an alternate fuel
under interruptible rates and increase our sensitivity to changes in weather.
Because the Gas Competition Act requires alternate suppliers to accept
assignment of a portion of the LDC's pipeline capacity and storage contracts, we
do not believe the Gas Competition Act and the Gas Restructuring Order will have
a material adverse impact on our financial condition or results of operations.
In September 2000, UGIDC agreed to joint venture with a subsidiary of Allegheny
Energy, Inc. ("Allegheny") to own and operate electric generation facilities,
including Electric Utility's coal-fired Hunlock Creek generating station
("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock,
certain related assets, and approximately $6 million in cash. Allegheny will
contribute a newly-constructed gas-fired combustion turbine generator to be
operated at the existing Hunlock site. Each partner will be entitled to purchase
50% of the output of the joint venture at cost. The joint venture became
operational in December 2000.
MANUFACTURED GAS PLANTS
Prior to the general availability of natural gas, in the 1800s through the
mid-1900s, most gas for lighting and heating nationwide was manufactured from
combustibles such as coal, oil and coke. Some constituents of coal tars and
other residues of the manufactured gas process are today considered hazardous
substances under the federal "Comprehensive Environmental Response,
-19-
<PAGE> 22
Compensation and Liability Act," or "Superfund Law," and may be present on the
sites of former manufactured gas plants ("MGPs").
UGI Utilities and its former subsidiaries owned and operated a number of 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. By the mid-1930s, UGI Utilities was one of the
largest public utility holding companies in the country. Pursuant to the
requirements of the Pubic 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 has been notified of several sites outside Pennsylvania on which
(i) gas plants were formerly operated by it or owned or operated by its former
subsidiaries and (ii) 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 UGI Utilities should not have significant liability in
those instances in which a former subsidiary operated an MGP because UGI
Utilities generally is not legally liable for the obligations of its
subsidiaries. Under certain circumstances, however, a court could find a parent
company liable for environmental damage caused by a subsidiary company when the
parent company either (i) itself operated the facility causing the environmental
damage or (ii) otherwise so controlled the subsidiary that the subsidiary's
separate corporate form should be disregarded. There could be, therefore,
significant future costs of an uncertain amount associated with environmental
damage caused by MGPs that UGI Utilities owned or directly operated, or that
were owned or operated by former subsidiaries of UGI Utilities, if a court were
to conclude that the subsidiary's separate corporate form should be disregarded.
UGI Utilities has identified 40 sites in Pennsylvania where either (i) UGI
Utilities formerly conducted some manufactured gas operations or (ii) UGI
Utilities owns or at one time owned the site. Because Gas Utility is currently
permitted to include in rates, through future base rate proceedings, prudently
incurred remediation costs associated with Pennsylvania sites, the Company does
not expect its costs for Pennsylvania sites to be material to future results of
operations.
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 million in such costs. During Fiscal 2000, UGI Utilities
entered into settlement agreements with several of the insurers and recorded
pre-tax income of $4.5 million.
MARKET RISK DISCLOSURES
The current regulatory framework allows Gas Utility to recover prudently
incurred gas costs from its customers. Because of this ratemaking mechanism,
there is limited commodity price risk associated with our Gas Utility
operations.
-20-
<PAGE> 23
Electric Utility purchases electricity it does not otherwise produce,
representing approximately 50% of its electric power needs, under power supply
arrangements of varying length terms with other producers and on the spot
market. Spot market prices for electricity and, to a lesser extent, monthly
market-based contract prices can be volatile, especially during periods of high
demand. Because Electric Utility's generation rates are capped through
approximately December 2002 under its Restructuring Order, any increases in
costs to produce or purchase power will negatively impact Electric Utility's
results.
We have interest rate exposure associated with borrowings under our revolving
credit agreements. These agreements provide for interest rates on borrowings
which are indexed to short-term market interest rates. Based upon the average
level of borrowings outstanding under these agreements during Fiscal 2000 and
Fiscal 1999, an increase in short-term interest rates of 100 basis points (1%)
would have increased annual interest expense by $0.8 million and $0.6 million,
respectively.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" ("SFAS 138"), which
addressed a limited number of issues causing implementation difficulties. SFAS
133, as amended, establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires that an entity recognize all
derivative instruments as either assets or liabilities and measure them 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. We were required to adopt the provisions of SFAS 133 effective
October 1, 2000.
We are a party to a number of contracts that have the 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 many of these
contracts have the requisite elements of a derivative instrument, they provide
for the delivery of products or services in quantities that are expected to be
used or sold in the normal course of operating our businesses. Accordingly, we
believe these contracts are not subject to the accounting requirements of SFAS
133 because they qualify for the normal purchases and normal sales exception of
that standard. The adoption of SFAS 133 will not have a material impact on the
Company's results of operations or financial position but may impact future
results of operations or financial position depending upon the extent to which
we use derivative instruments and their designation and effectiveness as hedges
of market risk.
-21-
<PAGE> 24
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 with respect to expected financial results and future events is
forward-looking, based on our estimates and assumptions and subject to risk and
uncertainties. For those statements, we claim the protection of the safe harbor
for forward-looking statements contained in the Private Securities Litigation
Reform Act of 1995.
The following important factors 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)
improvements in energy efficiency and technology resulting in reduced demand,
(7) labor relations, (8) large customer or supplier defaults, (9) operating
hazards and risks incidental to generating and distributing electricity and
distributing natural gas including the risk of explosions and fires resulting in
personal injury and property damage, (10) regional economic conditions, 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.
-22-
<PAGE> 25
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
"Quantitative and Qualitative Disclosures About Market Risk" are
contained in Management's Discussion and Analysis of Financial Condition and
Results of Operations under the 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-25 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
None.
-23-
<PAGE> 26
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships(1)
---- --- --------- --------------------------------------------------
<S> <C> <C> <C>
Lon R. Greenberg 50 1994 Chairman (since August 1996) and Vice Chairman
(1994 to 1996) of the Company; Chairman (since
August 1996), Chief Executive Officer (since
August 1995), Director and President (since 1994)
of UGI; formerly, Senior Vice President-Legal and
Corporate Development of UGI (1989 to July 1994).
Mr. Greenberg is also a director on the Mellon
PSFS Advisory Board.
James W. Stratton 64 1979 President and Chief Executive Officer of Stratton
Management Company since 1972 (investment advisory
firm); Chairman and a director of EFI (financial
services firm) (since 1979). Mr. Stratton is also
a director of Stratton Growth Fund, Inc.; Stratton
Monthly Dividend REIT Shares, Inc.; Stratton
Small-Cap Value Fund; Teleflex, Inc.; and BE&K,
Inc.
David I. J. Wang 68 1988 Mr. Wang is Chairman of Paperloop.com. In 1991,
Mr. Wang retired as Executive Vice
President-Timber and Specialty Products and a
director of International Paper Company (1987 to
1991). Mr. Wang serves as a director of BE&K Inc.;
Emsource Inc.; Forest Resources LLC; and Waterhill
LLC.
</TABLE>
-24-
<PAGE> 27
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships(1)
---- --- --------- --------------------------------------------------
<S> <C> <C> <C>
Richard C. Gozon 62 1989 Executive Vice President of Weyerhaeuser Company
(integrated forest products company) (since 1994).
Formerly Director (1984 to 1993), President and
Chief Operating Officer of Alco Standard
Corporation (provider of paper and office
products) (1988 to 1993); Executive Vice President
and Chief Operating Officer (1987); Vice President
(1982 to 1988); President (1979 to 1987) of Paper
Corporation of America. Mr. Gozon is also a
director of AmeriSource Health Corporation; and
Triumph Group, Inc.
Stephen D. Ban 60 1991 Past President and Chief Executive Officer of Gas
Research Institute (gas industry research and
development) (1987 to 1999); formerly Executive
Vice President of Gas Research Institute (1986);
formerly Vice President Research and Development,
Bituminous Materials, Inc. (1981). Dr. Ban is also
a director of Energen Corporation.
Robert J. Chaney 58 1999 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).
</TABLE>
-25-
<PAGE> 28
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships(1)
---- --- --------- --------------------------------------------------
<S> <C> <C> <C>
Marvin O. Schlanger 52 1998 Mr. Schlanger is Chairman of the Board of
Resolution Performance Products, Inc. (a global
producer and marketer of intermediate and
specialty chemicals) (November 2000 to present).
Mr. Schlanger is also 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). He
was President and Chief Executive Officer (May
1998 to October 1998), Executive Vice President
and Chief Operating Officer (1994 to 1998) and a
director (1994 to 1998) of ARCO Chemical Company.
Mr. Schlanger also held the position of Senior
Vice President of ARCO Chemical Company and
President of ARCO Chemical Americas Company (1992
to 1994). Mr. Schlanger also served as interim
President of OneChem, Ltd. (1999 to 2000), Mr.
Schlanger is also a director of OneChem, Ltd.; and
Wellman, Inc.
Thomas F. Donovan 67 1998 Retired; formerly Vice Chairman of Mellon Bank
(1988 to 1997). Mr. Donovan continues to serve as
an advisory board member to Mellon Bank Corp. He
is also a director of Nuclear Electric Insurance
Co.; and Merrill Lynch International Bank, Ltd.
Anne Pol 53 1999 Mrs. Pol is Senior Vice President, Thermo Electron
(and Corporation (environmental monitoring, and
1993- analytical instruments and a major producer of
1997) recycling equipment, biomedical products and
alternative energy systems), a position she has
held since 1998. She previously served as Vice
President (1996 to 1998). As Senior Vice
President, she is responsible for Human Resources,
Government Relations, Information Technology and
the Thermo Coleman Group of companies. Mrs. Pol
also served as President, Pitney Bowes Shipping
and
</TABLE>
-26-
<PAGE> 29
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships(1)
---- --- --------- --------------------------------------------------
<S> <C> <C> <C>
Weighing Systems Division, a business unit of
Pitney Bowes Inc. (mailing and related business
equipment) (1993 to 1996); Vice President, New
Product Programs in the Mailing Systems Division
of Pitney Bowes Inc. (1991 to 1993); and Vice
President, Manufacturing Operations in the Mailing
Systems Division of Pitney Bowes, Inc. (1990 to
1991).
</TABLE>
(1) All of the directors except Mr. Chaney, also serve as directors of UGI. In
addition, Messrs. Greenberg, Donovan, Gozon, Stratton and Wang serve as
directors of AmeriGas Propane, Inc., the General Partner of AmeriGas
Partners, L.P.
EXECUTIVE OFFICERS
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Lon R. Greenberg 50 Chairman of the Board of Directors
Robert J. Chaney 58 President and Chief Executive Officer
Mark R. Dingman 51 Vice President and General Manager-
Electric Utility Division
John C. Barney 52 Senior Vice President-Finance
Brendan P. Bovaird 52 Vice President and General Counsel
</TABLE>
Directors are elected annually. All officers are elected for a one-year
term at the organizational meeting of the Board of Directors held each year.
There are no family relationships between any of the directors or any
of the officers or between any of the officers and any of the directors.
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).
-27-
<PAGE> 30
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).
Mark R. Dingman
Mr. Dingman is Vice President and General Manager-Electric Utility
Division of the Company (since 1990).
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).
-28-
<PAGE> 31
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 the four other most highly
compensated executive officers (collectively, the "Named Executives") for the
last three fiscal years.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
LONG TERM COMPENSATION
--------------------------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
---------------------------------------------------------------------------------------------------------------------
SECURITIES
OTHER UNDER- ALL
ANNUAL RESTRICTED LYING OTHER
NAME AND PRINCIPAL FISCAL COMPEN- STOCK OPTIONS/ LTIP COMPEN-
POSITION YEAR SALARY BONUS (1) SATION (2) AWARDS(3) SARS PAYOUTS SATION (4)
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Lon R. Greenberg (5)(6) 2000 $640,662 $262,836 $ 13,092 $ 0 225,000 (8) $0 $20,417
Chairman 1999 $587,139 $266,776 $ 11,359 $ 611,260 225,000 (7a) $0 $18,273
1998 $559,616 $225,000 $ 8,209 $ 0 0 $0 $22,154
Robert J. Chaney 2000 $264,307 $141,570 $ 5,898 $ 0 45,000 (8) $0 $ 7,569
President and Chief 1999 $221,445 $ 72,109 $ 7,817 $ 142,625 5,556 (7b) $0 $ 5,742
Executive Officer 1998 $171,801 $ 33,777 $ 4,528 $ 0 8,333 (7b) $0 $ 5,023
John C. Barney 2000 $164,848 $ 58,806 $ 1,899 $ 0 15,000 (8) $0 $ 4,453
Senior Vice President - 1999 $150,279 $ 33,055 $ 0 $ 101,875 0 $0 $ 4,156
Finance 1998 $139,870 $ 34,412 $ 0 $ 0 0 $0 $ 3,813
Mark R. Dingman 2000 $149,583 $ 36,383 $ 6,907 $ 0 28,000 (8) $0 $ 4,385
Vice President & 1999 $139,783 $ 45,303 $ 7,723 $ 101,875 0 $0 $ 4,209
General Manager, 1998 $132,796 $ 47,282 $ 7,524 $ 0 0 $0 $ 3,580
Electric Utility
Division
Brendan P. Bovaird (5)(6) 2000 $210,392 $ 49,349 $ 6,332 $ 0 28,000 (8) $0 $ 5,927
Vice President and 1999 $189,600 $ 53,048 $ 14,399 $ 142,625 0 $0 $ 5,215
General Counsel 1998 $176,677 $ 42,188 $ 4,075 $ 0 0 $0 $ 5,425
</TABLE>
(1) Bonuses earned under the UGI Corporation and UGI Utilities, Inc. Annual
Bonus Plans are for the year reported, regardless of the year paid. The
Annual Bonus Plans are based on the achievement of pre-determined business
and/or financial performance objectives which support business plans and
goals. Bonus opportunities vary by position and for fiscal year 2000
ranged from 0% to 168% of base salary for Mr. Greenberg, from 0% up to 78%
for Mr. Chaney, from 0% to 52% for Messrs. Barney and Dingman, and from 0%
to 92% for Mr. Bovaird.
(2) Amounts represent tax payment reimbursements for certain benefits.
-29-
<PAGE> 32
(3)(a)On June 4, 1999, the Board of Directors of UGI Corporation approved
restricted stock awards to certain executives of UGI and UGI Utilities,
Inc. The dollar values shown above represent the aggregate value of each
award on the date of grant, determined by multiplying the number of shares
awarded by the closing stock price of UGI Common Stock on the New York
Stock Exchange on June 4, 1999. Holders of restricted shares have the
right to vote and to receive dividends during the restriction period.
(b)Based on the closing stock price of UGI Common Stock on the New York Stock
Exchange on September 30, 1999, Mr. Greenberg's 30,000 share grant had a
market value of $727,500; Mr. Chaney's and Mr. Bovaird's 7,000 share grant
each had a market value of $169,750 and Mr. Barney's and Mr. Dingman's
5,000 share award each had a value of $121,250.
(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 2000,
1999 and 1998, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: for each of Messrs.
Greenberg and Chaney, $3,825, $3,600 and $3,600; Mr. Barney, $3,825,
$3,403 and $3,600; Mr. Dingman, $3,825, $3,202 and $3,580; Mr. Bovaird,
$3,825, $3,509 and $3,600; and (ii) under the Supplemental Executive
Retirement Plan: Mr. Greenberg, $16,592, $14,673 and $18,554; Mr. Bovaird,
$2,102, $1,706 and $1,825; Mr. Chaney, $3,744, $2,142 and $1,423; Mr.
Barney, $628, $752 and $213; Mr. Dingman, $560, $1,007 and $0.
(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 2001 Annual Meeting of
Shareholders and is not additive.
(7)(a)Non-qualified stock options granted on June 4, 1999 under the UGI 1997
Stock Option and Dividend Equivalent Plan (the "1997 Plan") without the
opportunity to earn dividend equivalents described below.
(b)Non-qualified stock options granted under the 1997 Plan which included
the opportunity for participants to earn an amount equivalent to the
dividends paid on shares covered by options, subject to a comparison of
the total return realizable on a share of UGI's Common Stock with the
total return achieved by each member of a group of comparable peer
companies over a three-year period beginning January 1, 1997 and ending
December 31, 1999. No dividend equivalents were earned for these options.
(8) Non-qualified stock options granted effective January 1, 2000 under the
1997 Plan without the opportunity to earn dividend equivalents.
(9) Non-qualified stock options granted under the UGI 1992 Non-Qualified Stock
Option Plan.
-30-
<PAGE> 33
OPTION GRANTS IN LAST FISCAL YEAR
The following table shows information on grants of stock options during
fiscal year 2000 to each of the Named Executives.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
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 (1) FISCAL YEAR (2) OR BASE PRICE EXPIRATION DATE VALUE (3)
-----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Lon R. Greenberg 225,000 29% $20.625 12/31/09 $678,980
John C. Barney 15,000 2% $20.625 12/31/09 $ 45,265
Robert J. Chaney 45,000 6% $20.625 12/31/09 $135,796
Mark R. Dingman 28,000 4% $20.625 12/31/09 $ 84,495
Brendan P. Bovaird 28,000 4% $20.625 12/31/09 $ 84,495
-----------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Non-qualified stock options granted effective January 1, 2000 under the
1997 SODEP. This grant does not include the opportunity to earn an amount
equivalent to the dividends paid during a performance period on shares
covered by options. The option exercise price is the fair market value of
UGI's Common Stock determined on the date of the grant. These options
become exercisable in three equal annual installments beginning on the
first anniversary of the grant date. Options granted under the Plan are
nontransferable and are generally exercisable only while the optionee is
employed by the Company or an affiliate. Options are subject to adjustment
in the event of recapitalizations, stock splits, mergers, and other
similar corporate transactions affecting UGI's Common Stock.
(2) A total of 766,750 options were granted to employees and executive
officers of the Company and its affiliates during fiscal year 2000 under
the 1997 SODEP and the 1992 Non-Qualified Stock Option Plan. Under the
1992 Non-Qualified Stock Option Plan, the option exercise price is not
less than 100% of the fair market value of UGI's Common Stock on the date
of grant. These options become exercisable in three equal annual
installments beginning on the first anniversary of the grant date. Options
under the 1992 Plan are nontransferable and generally exercisable only
while the optionee is employed by the Company or an affiliate. Options are
subject to adjustment in the event of recapitalizations, stock splits,
mergers, and other similar corporate transactions affecting UGI's Common
Stock.
(3) Based on the Black-Scholes options pricing model. The assumptions used in
calculating the grant date present value are as follows:
- Three years of closing monthly stock price observations were used to
calculate the stock volatility and dividend yield assumptions.
- Stock volatility 23.89%
- Stock's dividend yield 6.22%
- Length of option term 10 years
- Annualized risk-free interest rate 6.79%
- Discount of risk of forfeiture 3% per year
-31-
<PAGE> 34
OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
The following table shows information for fiscal year 2000 concerning
exercised and unexercised stock options for shares of UGI Common Stock for each
of the Named Executives.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUE
------------------------------------------------------------------------------------------------------------------------
VALUE OF
SHARES NUMBER OF SECURITIES UNEXERCISED
ACQUIRED ON UNDERLYING UNEXERCISED IN-THE-MONEY
EXERCISE VALUE OPTIONS/SARS OPTIONS/SARS
NAME (#) REALIZED AT FISCAL YEAR-END (#) AT FISCAL YEAR-END*
------------------------------------------------------------------------------------------------------------------------
EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
93,959 168,750 $387,581 (1) $653,906 (3)
Lon R. Greenberg (7) 0 $ 0 200,000 225,000 $325,000 (2) $815,625 (4)
56,250 $217,969 (3)
John C. Barney 0 $ 0 10,000 15,000 $ 16,250 (2) $ 54,375 (4)
43,639 45,000 $180,011 (1) $163,125 (4)
Robert J. Chaney (7) 0 $ 0 35,000 $ 56,875 (2)
8,333 $ 15,624 (5)
5,556 $ 16,668 (6)
Mark R. Dingman 0 $ 0 35,000 28,000 $ 56,875 (2) $101,500 (4)
Brendan P. Bovaird (7) 0 $ 0 5,007 28,000 $ 20,654 (1) $101,500 (4)
30,000 $ 48,750 (2)
------------------------------------------------------------------------------------------------------------------------
</TABLE>
* The fiscal 2000 year-end closing stock price was $24.25.
(1) Value is calculated using the difference between $20.125 (1992 SODEP
option price) and $24.25 multiplied by the number of shares underlying the
option.
(2) Value is calculated using the difference between $22.625 (1997 SODEP
option grant price at December 10, 1996) and $24.25 multiplied by the
number of shares underlying the option.
(3) Value is calculated using the difference between $20.375 (1997 SODEP
option grant price at June 4, 1999) and $24.25 multiplied by the number of
shares underlying the option.
(4) Value is calculated using the difference between $20.625 (1997 SODEP
option price at January 1, 2000) and $24.25 multiplied by the number of
shares underlying the option.
(5) Value is calculated using the difference between $22.375 (1997 SODEP grant
price at September 29, 1998) and $24.25 multiplied by the number of shares
underlying the option.
(6) Value is calculated using the difference between $21.250 (1997 SODEP grant
price at February 23, 1999) and $24.25 multiplied by the number of shares
underlying the option.
(7) Information reported for Messrs. Greenberg, Chaney and Bovaird is also
reported in the Proxy Statement for UGI's 2001 Annual Meeting of
Shareholders and is not additive.
-32-
<PAGE> 35
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 2000 at age 65, and that the aggregate benefits are not
subject to statutory maximums.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
PENSION PLAN BENEFITS TABLE
-------------------------------------------------------------------------------------------------------------
FINAL 5-YEAR
AVERAGE ANNUAL ANNUAL BENEFIT FOR YEARS OF CREDITED SERVICE SHOWN (1)
EARNINGS (2)
--------------------------------------------------------------------------------------------
15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS 40 YEARS
-------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$ 100,000 $ 28,500 $ 38,000 $ 47,500 $ 57,000 $ 66,500 $ 68,400 (3)
$ 200,000 $ 57,000 $ 76,000 $ 95,000 $114,000 $133,000 $136,800 (3)
$ 300,000 $ 85,500 $114,000 $142,500 $171,000 $199,500 $205,200 (3)
$ 400,000 $114,000 $152,000 $190,000 $228,000 $266,000 $273,600 (3)
$ 500,000 $142,500 $190,000 $237,500 $285,000 $332,500 $342,000 (3)
$ 600,000 $171,000 $228,000 $285,000 $342,000 $399,000 $410,400 (3)
$ 700,000 $199,500 $266,000 $332,500 $399,000 $465,500 $478,800 (3)
$ 800,000 $228,000 $304,000 $380,000 $456,000 $532,000 $547,200 (3)
$ 900,000 $256,500 $342,000 $427,500 $513,000 $598,500 $615,600 (3)
$1,000,000 $285,000 $380,000 $475,000 $570,000 $665,000 $684,000 (3)
$1,200,000 $342,000 $456,000 $570,000 $684,000 $798,000 $820,800 (3)
$1,400,000 $399,000 $532,000 $665,000 $798,000 $931,000 $957,600 (3)
-------------------------------------------------------------------------------------------------------------
</TABLE>
(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, 20 years, 29 years, 36 years, 27 years and 5 years of
estimated credited service at September 30, 2000.
(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.
-33-
<PAGE> 36
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. The Plan also provides for separation pay equal to one day's
pay per month of service, not to exceed 12 months' compensation. 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
-34-
<PAGE> 37
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.
-35-
<PAGE> 38
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
David I. J. Wang.
-36-
<PAGE> 39
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
At December 1, 2000, 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, 2000, the number of
shares of Common Stock of UGI beneficially owned by each director of the Company
and each of the Named Executives, as well as all directors and executive
officers as a group. Mr. Greenberg is the beneficial owner of approximately
1.76% of UGI's Common Stock. All other directors, Named Executives and executive
officers own less than 1% of UGI's outstanding shares. The total number of
shares beneficially owned by all directors and executive officers includes
shares subject to options exercisable within 60 days.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
SECURITY OWNERSHIP OF MANAGEMENT
----------------------------------------------------------------------------------------------
NUMBER OF SHARES AND
NATURE OF BENEFICIAL
OWNERSHIP EXCLUDING NUMBER OF
OPTIONS (1) EXERCISABLE STOCK
NAME OF BENEFICIAL OWNER (2) OPTIONS TOTAL
----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Stephen D. Ban 14,847(3) 6,900 21,747
John C. Barney 10,760(7) 10,000 20,760
Brendan P. Bovaird 23,255(4) 35,007 58,262
Robert J. Chaney 41,520(5) 92,528 109,248
Mark R. Dingman 12,408 35,000 47,408
Thomas F. Donovan 3,856 4,000 7,856
Richard C. Gozon 20,862 9,000 29,862
Lon R. Greenberg 125,778(6) 350,209 475,987
Anne Pol 7,000 4,000 11,000
Marvin O. Schlanger 6,258 4,000 10,258
James W. Stratton 12,651 9,000 21,651
David I. J. Wang 24,596 9,000 33,596
All directors and executive
officers as a group (12) 303,790 568,644 872,434(8)
----------------------------- ---------------------- ------------------- ---------------------
</TABLE>
(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
-37-
<PAGE> 40
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 (2,022), Stratton (10,789), Schlanger (4,024),
Wang (9,734), Gozon (14,000), Ban (7,289) and Mrs. Pol (5,436).
(3) Dr. Ban holds 7,558 Shares jointly with his spouse.
(4) Mr. Bovaird holds 12,993 Shares jointly with his spouse and 3,262 Shares
represented by units held in the UGI Stock Fund of the 401(k) Employee
Savings Plan, based on September 30, 2000 Savings Plan statements.
(5) Mr. Chaney holds 27,361 Shares jointly with his spouse.
(6) Mr. Greenberg holds 88,220 Shares jointly with his spouse and 5,518 Shares
represented by units held in the UGI Stock Fund of the 401(k) Employee
Savings Plan, based on September 30, 2000 Savings Plan statements.
(7) Mr. Barney holds 216 Shares represented by units held in the UGI Stock
Fund of the 401(k) Employee Savings Plan, based on September 30, 2000
Savings Plan statements. Mr. Barney disclaims beneficial ownership of 200
Shares owned by an adult son.
(8) The total number of Shares beneficially owned by the directors and
officers as a group represents 3.2% of UGI's outstanding shares.
-38-
<PAGE> 41
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 2000 UGI allocated 51%, or $4.2 million, of its general
corporate expenses to Utilities.
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 14. 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:
Report of Independent Public Accountants
Consolidated Balance Sheets, September 30, 2000 and 1999
Consolidated Statements of Income for the fiscal years ended
September 30, 2000, 1999 and 1998
Consolidated Statements of Cash Flows for the fiscal years ended
September 30, 2000, 1999 and 1998
Consolidated Statements of Stockholders' Equity for the fiscal years
ended September 30, 2000, 1999 and 1998
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE
For the years ended September 30, 2000, 1999 and 1998
II- Valuation and Qualifying Accounts
All other financial statement schedules are omitted because the required
information is either (1) not present; (2) not present in amounts sufficient
to require submission of the schedule; or (3) the information required is
included elsewhere in the respective financial statements or notes thereto
contained in this report.
-39-
<PAGE> 42
(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):
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
INCORPORATION BY REFERENCE
-------------------------------------------------------------------------------------------------------------------
Exhibit No. Exhibit Registrant Filing Exhibit
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
3.1 Utilities' Articles of Incorporation Utilities Form 8-K 4(a)
(9/22/94)
3.2 Bylaws of UGI Utilities as in effect since September Utilities Form 10-K 3.2
26, 1995 (9/30/95)
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
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)
4.8 Calculation Agent Agreement dated August 1, 1996 Utilities Form 8-K 4(iii)
between UGI Utilities, Inc. and First Union National (8/1/96)
Bank
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)
-------------------------------------------------------------------------------------------------------------------
</TABLE>
-40-
<PAGE> 43
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------
INCORPORATION BY REFERENCE
------------------------------------------------------------------------------------------------------------------
Exhibit No. Exhibit Registrant Filing Exhibit
------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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)
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 UGI Form 10-K 10.6
Amended and Restated as of January 1, 2000 (9/30/00)
10.6** UGI Corporation Directors' Equity Compensation Plan UGI Form 10-K 10.9
Amended and Restated as of January 1, 2000 (9/30/00)
10.7** UGI Corporation 1992 Stock Option and Dividend UGI Form 10-Q (10)ee
Equivalent Plan, as amended May 19, 1992 (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, Utilities Form 10-Q 10.4
1996` (6/30/96)
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive Employee Severance UGI Form 10-K 10.12
Pay Plan effective January 1, 1997 (9/30/97)
</TABLE>
-41-
<PAGE> 44
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------
INCORPORATION BY REFERENCE
------------------------------------------------------------------------------------------------------------------
Exhibit No. Exhibit Registrant Filing Exhibit
------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, UGI Form 10-K 10.39
as amended (9/30/00)
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-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 UGI Form 10-K 10.41
(Rate CDS) dated February 23, 1999 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
10.16** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.2
Equivalent Plan (3/31/97)
10.17** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10
Amended and Restated effective October 1, 1996 (6/30/98)
10.18 ** Summary of Terms of UGI Corporation 1999 Restricted UGI Form 10-Q 10
Stock Awards (6/30/99)
10.20** Description of Change of Control arrangements for UGI Form 10-K 10.33
Messrs. Greenberg and Bovaird Corporation (9/30/99)
10.21** Description of Change of Control arrangements for UGI Form 10-K 10.34
Messrs. Chaney, Dingman and Barney Corporation (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 Corporation (9/30/00)
*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
*21 Subsidiaries of Registrant
*23 Consent of Arthur Andersen LLP
*27 Financial Data Schedule
</TABLE>
* 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.
During the last quarter of fiscal year 2000, the Company filed no Current
Reports on Form 8-K.
-42-
<PAGE> 45
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 19, 2000 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 19, 2000 by the following persons on
behalf of the Registrant in the capacities indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C>
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
</TABLE>
-43-
<PAGE> 46
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 19, 2000 by the following persons on
behalf of the Registrant in the capacities indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C>
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
David I. J. Wang Director
------------------------------
David I. J. Wang
</TABLE>
-44-
<PAGE> 47
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2000
F-1
<PAGE> 48
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
<TABLE>
<CAPTION>
Pages
-----
<S> <C>
Financial Statements:
Report of Independent Public Accountants F-3
Consolidated Balance Sheets as of September 30,
2000 and 1999 F-4 to F-5
Consolidated Statements of Income for the years
ended September 30, 2000, 1999, and 1998 F-6
Consolidated Statements of Cash Flows for the years
ended September 30, 2000, 1999, and 1998 F-7
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 2000, 1999, and 1998 F-8
Notes to Consolidated Financial Statements F-9 to F-25
Financial Statement Schedule:
For the years ended September 30, 2000, 1999, and 1998:
II - Valuation and Qualifying Accounts S-1
</TABLE>
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
<PAGE> 49
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
UGI Utilities, Inc.
We have audited the accompanying consolidated balance sheets of UGI Utilities,
Inc. and subsidiaries as of September 30, 2000 and 1999, and the related
consolidated statements of income, stockholder's equity and cash flows for each
of the three years in the period ended September 30, 2000. 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, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2000 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
Chicago, Illinois
November 10, 2000
F-3
<PAGE> 50
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
<TABLE>
<CAPTION>
September 30,
2000 1999
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 15,575 $ 11,063
Accounts receivable (less allowances for doubtful
accounts of $2,061 and $1,716, respectively) 33,341 26,523
Accrued utility revenues 10,486 6,867
Inventories 36,934 28,103
Deferred income taxes 3,321 2,972
Prepaid expenses and other current assets 3,077 6,283
--------- ---------
Total current assets 102,734 81,811
Property, plant and equipment
Gas utility 717,119 689,558
Electric utility 128,712 124,558
General 11,974 12,680
--------- ---------
857,805 826,796
Less accumulated depreciation and amortization (287,835) (270,003)
--------- ---------
Net property, plant and equipment 569,970 556,793
Regulatory assets 62,276 61,082
Other assets 19,142 17,483
--------- ---------
Total assets $ 754,122 $ 717,169
========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE> 51
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
<TABLE>
<CAPTION>
September 30,
2000 1999
-------- --------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 15,000 $ 7,143
Bank loans 100,400 87,400
Accounts payable 54,138 37,881
Employee compensation and benefits accrued 7,846 8,278
Dividends and interest accrued 4,547 4,693
Income taxes accrued 6,607 179
Customer deposits and refunds 10,272 10,836
Other current liabilities 11,521 11,698
-------- --------
Total current liabilities 210,331 168,108
Long-term debt 157,924 172,904
Deferred income taxes 117,666 112,284
Deferred investment tax credits 9,182 9,580
Other noncurrent liabilities 14,546 14,733
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 68,559 68,559
Retained earnings 95,655 90,742
-------- --------
Total common stockholder's equity 224,473 219,560
-------- --------
Total liabilities and stockholders' equity $754,122 $717,169
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE> 52
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
---------------------------------------------
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
Revenues $ 436,942 $ 420,647 $ 422,283
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power 218,119 205,221 214,631
Operating and administrative expenses 85,425 86,740 85,983
Operating and administrative expenses
- related parties 4,159 4,946 4,837
Taxes other than income taxes 17,052 25,232 25,192
Depreciation and amortization 23,612 23,005 22,043
Other income, net (12,660) (5,168) (4,993)
--------- --------- ---------
335,707 339,976 347,693
--------- --------- ---------
Operating income 101,235 80,671 74,590
Interest expense 18,353 17,532 17,583
--------- --------- ---------
Income before income taxes 82,882 63,139 57,007
Income taxes 32,406 24,271 21,456
--------- --------- ---------
Net income 50,476 38,868 35,551
Dividends on preferred stock 1,550 1,550 2,160
--------- --------- ---------
Net income after dividends on preferred stock $ 48,926 $ 37,318 $ 33,391
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE> 53
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
------------------------------------------
2000 1999 1998
-------- -------- --------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 50,476 $ 38,868 $ 35,551
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 23,612 23,005 22,043
Deferred income taxes, net 2,866 5,792 5,468
Provision for uncollectible accounts 4,386 4,269 4,099
Other 1,962 (1,391) 1,887
-------- -------- --------
83,302 70,543 69,048
Net change in:
Accounts receivable and accrued utility revenues (14,823) (6,588) 1,895
Inventories (8,831) 357 2,185
Deferred fuel costs (3,751) (5,120) (5,741)
Accounts payable 16,257 (966) (6,520)
Other current assets and liabilities 9,293 3,935 (10,709)
-------- -------- --------
Net cash provided by operating activities 81,447 62,161 50,158
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (36,391) (36,384) (37,219)
Net proceeds (costs) of property, plant and equipment disposals (838) (741) 311
-------- -------- --------
Net cash used by investing activities (37,229) (37,125) (36,908)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (45,563) (30,550) (25,093)
Issuance of long-term debt -- -- 35,000
Repayment of long-term debt (7,143) (7,143) (17,143)
Bank loans increase 13,000 19,000 1,400
Redemption of Series Preferred Stock -- -- (15,507)
-------- -------- --------
Net cash used by financing activities (39,706) (18,693) (21,343)
-------- -------- --------
Cash and cash equivalents increase (decrease) $ 4,512 $ 6,343 $ (8,093)
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of period $ 15,575 $ 11,063 $ 4,720
Beginning of period 11,063 4,720 12,813
-------- -------- --------
Increase (decrease) $ 4,512 $ 6,343 $ (8,093)
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-7
<PAGE> 54
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
<TABLE>
<CAPTION>
Additional
Common Paid-in Retained
Stock Capital Earnings
----- ------- --------
<S> <C> <C> <C>
Balance September 30, 1997 $ 60,259 $ 68,249 $ 71,986
Net income 35,551
Cash dividends - common stock (22,633)
Cash dividends - preferred stock (2,160)
Redemption of Series Preferred Stock (320)
Other 310
-------- -------- --------
Balance September 30, 1998 60,259 68,559 82,424
Net income 38,868
Cash dividends - common stock (29,000)
Cash dividends - preferred stock (1,550)
-------- -------- --------
Balance September 30, 1999 60,259 68,559 90,742
Net income 50,476
Cash dividends - common stock (44,013)
Cash dividends - preferred stock (1,550)
-------- -------- --------
Balance September 30, 2000 $ 60,259 $ 68,559 $ 95,655
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-8
<PAGE> 55
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 a natural gas distribution utility ("Gas
Utility") in parts of eastern and southeastern Pennsylvania and an electric
distribution utility and electricity generation business ("Electric Utility") in
northeastern Pennsylvania. We refer to UGI Utilities and its subsidiaries
collectively as "The Company" or "We." Our consolidated financial statements
include the accounts of UGI Utilities and its subsidiaries. We eliminate all
significant intercompany accounts and transactions when we consolidate.
Effective October 1, 1999, Electric Utility's interests in its electric
generating facilities were transferred to UGI Utilities' wholly owned
non-utility subsidiary, UGI Development Company ("UGIDC"). UGIDC has been
granted "Exempt Wholesale Generator" status by the Federal Energy Regulatory
Commission.
RECLASSIFICATIONS
We have reclassified certain prior-period balances to conform with the current
period presentation.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United States.
These estimates and assumptions affect the reported amounts of assets and
liabilities, revenues and expenses, as well as the disclosure of contingent
assets and liabilities. Actual results could differ from these estimates.
REGULATED OPERATIONS
Gas Utility and Electric Utility are subject to regulation by the Pennsylvania
Public Utility Commission ("PUC"). We account for all of our regulated Gas
Utility and Electric Utility operations 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 the Company to record
the financial statement effects of the rate regulation to which such operations
are currently subject. 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.
F-9
<PAGE> 56
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
In June 1998, the PUC approved Electric Utility's restructuring plan which we
submitted pursuant to Pennsylvania's Electricity Customer Choice Act
("Electricity Customer Choice Act"). In accordance with the Financial Accounting
Standards Board's ("FASB's") Emerging Issues Task Force ("EITF") Statement 97-4,
"Deregulation of the Pricing of Electricity - Issues Related to the Application
of FASB Statements 71 and 101" ("EITF 97-4"), we discontinued the application of
SFAS 71 as it related to the electric generation portion of Electric Utility's
business in June 1998. This discontinuance of SFAS 71 did not have a material
effect on our financial position or results of 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 Electricity Customer Choice Act
and the Gas Competition Act, see Note 2.
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 $17,941 in 2000, $16,894 in 1999, and $15,816 in 1998.
We paid income taxes totaling $23,108 in 2000, $19,642 in 1999, and $21,116 in
1998.
REVENUE RECOGNITION
Gas Utility and Electric Utility record revenues for service provided to the end
of each month. We reflect Gas and Electric utility rate increases or decreases
in revenues from effective dates permitted by the PUC.
INVENTORIES
Our inventories are stated at the lower of cost or market. We determine cost
principally on an average or first-in, first-out ("FIFO") method except for
appliances for which we use the specific identification method.
INCOME TAXES
UGI Utilities' regulated operations 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. UGI
Utilities also recognizes a deferred tax liability for tax benefits that are
flowed through to ratepayers when temporary differences originate and
F-10
<PAGE> 57
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
establishes 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 UGI Utilities'
plant additions over the service lives of the related property. UGI Utilities
reduces its deferred income tax liability for the future tax benefits that will
occur when the deferred investment tax credits, which are not taxable, are
amortized. 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 allocated tax assets, liabilities, expense, benefits and
credits resulting from the effects of our transactions in the consolidated
federal income tax provision, including giving effect to all intercompany
transactions. The result of this allocation is not materially different from
income taxes calculated on a separate return basis.
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, together with
the net cost of removal, for financial accounting purposes.
We record depreciation expense for Gas Utility's and Electric Utility's plant
and equipment on a straight-line method over the estimated average remaining
lives of the various classes of depreciable property. Depreciation expense as a
percentage of the related average depreciable base for Gas Utility was 2.6% in
2000, and 2.7% in 1999 and 1998. Depreciation expense as a percentage of the
related average depreciable base for Electric Utility was 3.5% in 2000, and 3.2%
in 1999 and 1998. Depreciation expense was $23,000 in 2000, $22,371 in 1999, and
$21,454 in 1998.
COMPUTER SOFTWARE COSTS
Prior to October 1, 1999, we included in property, plant and equipment external
and incremental internal costs associated with computer software we developed or
obtained for use in our businesses. Effective October 1, 1999, we adopted
Statement of Position No. 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use" ("SOP 98-1"), which requires companies
to capitalize the cost of computer software, including nonincremental internal
costs, once certain criteria have been met. We amortize computer software costs
on a straight-line basis over five years once the installed software is ready
for its intended use. The adoption of SOP 98-1 did not have a material effect on
our financial position or results of operations.
DEFERRED FUEL COSTS
Gas Utility's tariffs contain clauses which permit recovery of certain purchased
gas costs ("PGCs") in excess of the level of such costs included in base rates.
The clauses provide for a
F-11
<PAGE> 58
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
periodic adjustment for the difference between the total amount collected from
customers under each clause and the recoverable costs incurred. 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.
COMPREHENSIVE INCOME
SFAS No. 130, "Reporting Comprehensive Income" ("SFAS 130"), establishes
standards for reporting and displaying comprehensive income, comprising net
income and other nonowner changes in equity, in the financial statements. For
all periods presented, comprehensive income was the same as net income.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" ("SFAS 138"), which
addressed a limited number of issues causing implementation difficulties. SFAS
133, as amended, establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires that an entity recognize all
derivative instruments as either assets or liabilities and measure them 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. We were required to adopt the provisions of SFAS 133 effective
October 1, 2000.
F-12
<PAGE> 59
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
We are a party to a number of contracts that have the 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 many of these
contracts have the requisite elements of a derivative instrument, they provide
for the delivery of products or services in quantities that are expected to be
used or sold in the normal course of operating our businesses. Accordingly, we
believe these contracts are not subject to the accounting requirements of SFAS
133 because they qualify for the normal purchases and normal sales exception of
that standard. The adoption of SFAS 133 will not have a material impact on the
Company's results of operations or financial position but may impact future
results of operations or financial position depending upon the extent to which
we use derivative instruments and their designation and effectiveness as hedges
of market risk.
2. UTILITY REGULATORY MATTERS
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 Customer Choice Act. Under the terms of the Electricity
Restructuring Order, commencing January 1, 1999, Electric Utility is 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 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 include $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 Customer Choice Act, Electric Utility's rates for transmission
and distribution services are capped through July 1, 2001. In addition, Electric
Utility generally may not increase the generation component of prices as long as
stranded costs are being recovered through the CTC. This generation rate cap is
expected to extend through December 31, 2002. Since January 1, 1999, all of
Electric Utility's customers have been permitted to select an alternative
generation supplier. Customers choosing an alternative supplier receive a
"shopping credit." As permitted by the Electricity Restructuring Order, on
October 1, 1999, Electric Utility transferred its electric generation assets to
UGIDC.
F-13
<PAGE> 60
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
In June 1998, Electric Utility discontinued the application of SFAS 71 as it
relates to the electric generation portion of its business, which assets
comprise less than 15% of Electric Utility's total assets. The discontinuance of
SFAS 71 did not have a material effect on our financial position or results of
operations.
NATURAL 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")
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. As of January 1, 2000, the Gas Competition Act, in
conjunction with a companion bill, eliminated the gross receipts tax on sales of
gas.
Generally, 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. LDCs are generally precluded from increasing rates for
the recovery of costs, other than gas costs, until January 1, 2001. 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 assignment. The PUC, however, may only grant the petition if certain
findings are made and the LDC fully recovers the cost of contracts.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas
Utility's restructuring plan substantially as filed. Among other things, the
restructuring plan (1) provides for the recovery of costs associated with
existing pipeline capacity and supply contracts; (2) increases Gas Utility's
base rates for firm customers; and (3) changes the calculation of PGC rates. The
effect of (2) and (3) above is to reduce the financial impact of volatility in
revenues from customers who have the ability to switch to an alternate fuel
under interruptible rates and increase our sensitivity to changes in weather.
Because the Gas Competition Act requires alternate suppliers to accept
assignment of a portion of the LDC's pipeline capacity and storage contracts, we
do not believe the Gas Competition Act and the Gas Restructuring Order will have
a material adverse impact on our financial condition or results of operations.
F-14
<PAGE> 61
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2000 1999
--------------------------------------------------------------------------------
<S> <C> <C>
Regulatory assets:
Income taxes recoverable $47,667 $46,875
Power agreement buy-out 3,536 6,756
Other postretirement benefits 2,869 3,104
Deferred fuel costs 7,195 3,444
Other 1,009 903
--------------------------------------------------------------------------------
Total regulatory assets $62,276 $61,082
--------------------------------------------------------------------------------
Regulatory liabilities:
Refundable state taxes $ -- $ 975
Other postretirement benefits 4,014 2,816
--------------------------------------------------------------------------------
Total regulatory liabilities $ 4,014 $ 3,791
--------------------------------------------------------------------------------
</TABLE>
3. DEBT
Long-term debt comprises the following at September 30:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------
2000 1999
-------------------------------------------------------------------------------
<S> <C> <C>
Medium-Term Notes:
7.25% Notes, due November 2017 $ 20,000 $ 20,000
7.17% Notes, due June 2007 20,000 20,000
6.17% Notes, due March 2001 15,000 15,000
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
6.50% Senior Notes, due August 2003 (less
unamortized discount of $76 and $96,
respectively) 49,924 49,904
9.71% Notes, due September 2000 -- 7,143
-------------------------------------------------------------------------------
Total long-term debt 172,924 180,047
Less current maturities (15,000) (7,143)
-------------------------------------------------------------------------------
Long-term debt due after one year $157,924 $172,904
-------------------------------------------------------------------------------
</TABLE>
F-15
<PAGE> 62
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Scheduled repayments of long-term debt for each of the next five fiscal years
ending September 30 are as follows: 2001 - $15,000; 2002 - $0; 2003 - $76,000;
2004 - $0; 2005 - $20,000.
At September 30, 2000, UGI Utilities had revolving credit agreements with four
banks providing for borrowings of up to $122,000 through June 2003. 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 $100,400 at September 30, 2000
and $87,400 at September 30, 1999, which we classify as bank loans. The
weighted-average interest rates on bank loans were 7.12% and 5.90% at September
30, 2000 and 1999, respectively.
UGI Utilities' credit agreements have restrictions on such items as total debt,
working capital, debt service, and payments for investments. They also require
consolidated tangible net worth of at least $125,000. At September 30, 2000, UGI
Utilities was in compliance with its financial covenants.
4. INCOME TAXES
The provisions for income taxes consist of the following:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2000 1999 1998
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Current:
Federal $22,721 $13,989 $12,184
State 6,819 4,490 3,804
--------------------------------------------------------------------------------
29,540 18,479 15,988
Deferred 3,264 6,190 5,866
Investment tax credit
amortization (398) (398) (398)
--------------------------------------------------------------------------------
Total income tax expense $32,406 $24,271 $21,456
--------------------------------------------------------------------------------
</TABLE>
F-16
<PAGE> 63
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2000 1999 1998
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of
federal benefit 6.1 6.3 6.4
Deferred investment tax
credit amortization (0.5) (0.7) (0.7)
Other, net (1.5) (2.2) (3.1)
--------------------------------------------------------------------------------
Effective tax rate 39.1% 38.4% 37.6%
--------------------------------------------------------------------------------
</TABLE>
Deferred tax liabilities (assets) comprise the following at September 30:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2000 1999
--------------------------------------------------------------------------------
<S> <C> <C>
Excess book basis over tax basis of property,
plant and equipment $ 95,905 $ 92,996
Regulatory assets 25,604 25,345
Other 7,411 6,158
--------------------------------------------------------------------------------
Gross deferred tax liabilities 128,920 124,499
--------------------------------------------------------------------------------
Deferred investment tax credits (3,810) (3,975)
Employee-related expenses (5,452) (4,960)
Regulatory liability - state income taxes -- (405)
Power purchase agreement liability (2,167) (3,215)
Other (3,146) (2,632)
--------------------------------------------------------------------------------
Gross deferred tax assets (14,575) (15,187)
--------------------------------------------------------------------------------
Net deferred tax liabilities $114,345 $109,312
--------------------------------------------------------------------------------
</TABLE>
UGI Utilities had recorded deferred tax liabilities of approximately $31,698 as
of September 30, 2000 and $31,400 as of September 30, 1999 pertaining to utility
temporary differences, principally a result of accelerated tax depreciation, the
tax benefits of which previously were or will be flowed through to ratepayers.
These deferred tax liabilities have been reduced by deferred tax assets of
$3,810 at September 30, 2000 and $3,975 at September 30, 1999, pertaining to
utility deferred investment tax credits. UGI Utilities had recorded a regulatory
income tax asset related to these net deferred taxes of $47,667 as of September
30, 2000 and $46,875 as of September 30, 1999. This regulatory income tax asset
represents future revenues expected to be
F-17
<PAGE> 64
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
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.
The following provides a reconciliation of benefit obligations, plan assets, and
funded status of the plans as of September 30:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
----------------------- ---------------------------
2000 1999 2000 1999
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $149,503 $ 164,817 $ 13,989 $ 13,277
Service cost 3,230 3,800 74 84
Interest cost 11,805 11,187 1,185 1,014
Actuarial (gain) loss (4,390) (21,442) 3,101 666
Benefits paid (9,196) (8,859) (1,410) (1,052)
--------------------------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 150,952 $ 149,503 $ 16,939 $ 13,989
--------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets - beginning of year $202,149 $ 183,281 $ 4,956 $ 4,905
Actual return on plan assets 30,571 27,727 330 232
Employer contributions - - 1,901 1,041
Benefits paid (9,196) (8,859) (776) (1,223)
--------------------------------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $223,524 $ 202,149 $ 6,411 $ 4,955
--------------------------------------------------------------------------------------------------------------------
Funded status of the plans $ 72,572 $ 52,646 $ (10,528) $ (9,034)
Unrecognized net actuarial gain (54,760) (36,807) (445) (3,230)
Unrecognized prior service cost 4,003 4,667 - -
Unrecognized net transition (asset) obligation (6,264) (7,894) 8,427 9,112
--------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 15,551 $ 12,612 $ (2,546) $ (3,152)
--------------------------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 8.2% 7.8% 8.2% 7.8%
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
--------------------------------------------------------------------------------------------------------------------
</TABLE>
F-18
<PAGE> 65
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Included in the end of year pension benefit obligations above are $9,101 at
September 30, 2000, and $8,401 at September 30, 1999, relating to employees of
UGI and certain of its other subsidiaries. Included in the end of year
postretirement obligations above are $441 at September 30, 2000, and $580 at
September 30, 1999, relating to employees of UGI.
Net periodic pension and other postretirement benefit costs relating to UGI
Utilities employees include the following components:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
------------------------------------------- ---------------------------------------
2000 1999 1998 2000 1999 1998
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 2,898 $ 3,459 $ 3,038 $ 70 $ 78 $ 77
Interest cost 11,090 10,548 10,233 1,168 991 890
Expected return on assets (16,010) (15,375) (14,332) (252) (256) (177)
Amortization of:
Transition (asset)
obligation (1,534) (1,539) (1,533) 680 679 680
Prior service cost 626 629 626 -- -- --
Actuarial gain -- -- -- -- (48) (237)
---------------------------------------------------------------------------------------------------------------------------
Net benefit cost (income) (2,930) (2,278) (1,968) 1,666 1,444 1,233
Change in regulatory
assets & liabilities -- -- -- 1,433 1,655 1,866
---------------------------------------------------------------------------------------------------------------------------
Net expense (income) $ (2,930) $ (2,278) $ (1,968) $ 3,099 $ 3,099 $ 3,099
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
Pension plan assets are held in trust and consist principally of equity and
fixed income mutual funds and investment grade corporate and U.S. government
obligations. UGI Common Stock comprises less than 2% of trust assets at
September 30, 2000.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary
Employee Benefit Trust ("VEBA") 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 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 10.0% for fiscal 2001, decreasing
to 5.5% in fiscal 2005. A one percentage point change in the assumed health care
cost trend rate would change the 2000 postretirement benefit cost and obligation
as follows:
F-19
<PAGE> 66
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
1% 1%
Increase Decrease
---------------------------------------------------------------------------------
<S> <C> <C>
Effect on total service and interest costs $ 84 $ (74)
Effect on postretirement benefit obligation 964 (842)
---------------------------------------------------------------------------------
</TABLE>
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 2000 and 1999, the projected benefit obligations of these plans
were not material. We recorded expense for these plans of $131 in 2000, $637 in
1999, and $1,101 in 1998.
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 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 $948 in 2000, $885 in 1999, and $987 in
1998.
6. INVENTORIES
Inventories comprise the following at September 30:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2000 1999
--------------------------------------------------------------------------------
<S> <C> <C>
Utility fuel and gases $33,581 $24,440
Appliances for sale 665 991
Materials, supplies and other 2,688 2,672
--------------------------------------------------------------------------------
Total inventories $36,934 $28,103
--------------------------------------------------------------------------------
</TABLE>
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, 2000 and 1999, 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.
F-20
<PAGE> 67
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
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 $4,594 in 2000, $5,103 in 1999, and $5,278 in 1998.
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: 2001 - $3,576; 2002 - $3,049; 2003 - $2,494; 2004 - $1,655;
2005 - $883; after 2005 - $656.
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. 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.
Prior to August 1, 1999, Pennsylvania Power & Light Company ("PP&L"), pursuant
to a 1992 power supply agreement for bundled energy and capacity, supplied all
of Electric Utility's electric power requirements above that provided by other
sources. As part of a settlement of all disputes concerning the 1992 power
supply agreement, during 1999 Electric Utility and PP&L entered into a new power
supply agreement under which PP&L will supply all of Electric Utility's capacity
requirements in excess of its capacity resources acquired from other sources
through February 2001, and 32 megawatts of energy in each hour of the day
through December 2000. Electric Utility has a number of additional power supply
contracts with PP&L and other power producers for various length terms expiring
through December 2001. In high usage months, Electric Utility meets its electric
power needs, above those provided by these contracts and its own generation
facilities, through monthly market-based contracts and through spot purchases at
market prices as delivered.
In September 2000, UGIDC agreed to joint venture with a subsidiary of Allegheny
Energy, Inc. ("Allegheny") to own and operate electric generation facilities,
including Electric Utility's coal-fired Hunlock Creek generating station
("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock,
certain related assets, and approximately $6 million in cash. Allegheny will
contribute a newly-constructed gas-fired combustion turbine generator to be
operated at Hunlock's site. Each partner will be entitled to purchase 50% of the
output of the joint venture at cost. The joint venture is expected to become
operational in December 2000.
F-21
<PAGE> 68
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Prior to the general availability of natural gas, in the 1800s through the
mid-1900s, most gas for lighting and heating nationwide was manufactured from
combustibles such as coal, oil and coke. Some constituents of coal tars and
other residues of the manufactured gas process are today considered hazardous
substances under the federal "Comprehensive Environmental Response, Compensation
and Liability Act," or "Superfund Law," and may be present on the sites of
former manufactured gas plants ("MGPs").
UGI Utilities and its former subsidiaries owned and operated a number of 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. By the mid-1930s, UGI Utilities was one of the
largest public utility holding companies in the country. Pursuant to the
requirements of the Pubic 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 has been notified of several sites outside Pennsylvania on which
(i) gas plants were formerly operated by it or owned or operated by its former
subsidiaries and (ii) 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 UGI Utilities should not have significant liability in
those instances in which a former subsidiary operated an MGP because UGI
Utilities generally is not legally liable for the obligations of its
subsidiaries. Under certain circumstances, however, a court could find a parent
company liable for environmental damage caused by a subsidiary company when the
parent company either (i) itself operated the facility causing the environmental
damage or (ii) otherwise so controlled the subsidiary that the subsidiary's
separate corporate form should be disregarded. There could be, therefore,
significant future costs of an uncertain amount associated with environmental
damage caused by MGPs that UGI Utilities owned or directly operated, or that
were owned or operated by former subsidiaries of UGI Utilities, if a court were
to conclude that the subsidiary's separate corporate form should be disregarded.
UGI Utilities has identified 40 sites in Pennsylvania where either (i) UGI
Utilities formerly conducted some manufactured gas operations or (ii) UGI
Utilities owns or at one time owned the site. Because Gas Utility is currently
permitted to include in rates, through future base rate proceedings, prudently
incurred remediation costs associated with Pennsylvania sites, the Company does
not expect its costs for Pennsylvania sites to be material to future results of
operations.
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 2000, UGI Utilities entered into
settlement agreements with several of the insurers and recorded pre-tax
F-22
<PAGE> 69
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
income of $4,500 which amount is included in operating and administrative
expenses in the 2000 Consolidated Statement of Income.
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.
Management believes, 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 $168,000 at September 30, 2000 and
$175,000 at September 30, 1999. 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 $21,000 at September 30, 2000 and 1999. 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, 2000 and 1999, we had no significant
concentrations of credit risk.
10. SEGMENT INFORMATION
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("SFAS 131"), defines operating segments as components of an
enterprise for which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. We have determined that the UGI
Utilities has two business segments: (1) Gas Utility and (2) Electric Utility.
Gas Utility revenues are derived principally from the sale and distribution of
natural gas to customers in eastern and southeastern Pennsylvania. Electric
Utility derives its revenues from the sale and distribution of electricity in
two northeastern Pennsylvania counties. Although the Electricity Customer Choice
Act unbundled the pricing for Electric Utility's electric generation,
transmission and distribution services, we currently manage and evaluate these
business components on a combined basis.
F-23
<PAGE> 70
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
The accounting policies of our reportable segments are substantially the same as
those described in the significant accounting policies section of Note 1. We
evaluate the performance of our Gas Utility and Electric Utility 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 U.S., and all
of our reportable segments' long-lived assets are located in the U.S. Financial
information by business segment follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
Elim- Gas Electric
Total inations Utility Utility Other
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2000
Revenues $ 436,942 $ -- $ 359,041 $ 77,901 $ --
EBITDA(1) $ 124,847 $ -- $ 105,276 $ 19,571 $ --
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 $ 754,122 $ -- $ 656,751 $ 97,371 $ --
Capital expenditures $ 36,391 $ -- $ 31,665 $ 4,726 $ --
----------------------------------------------------------------------------------------------------------------------
1999
Revenues $ 420,647 $ -- $ 345,637 $ 75,010 $ --
EBITDA(1) $ 103,677 $ -- $ 86,963 $ 16,780 $ (67)
Depreciation and amortization (23,005) -- (18,995) (4,010) --
----------------------------------------------------------------------------------------------------------------------
Operating income (loss) 80,671 -- 67,968 12,770 (67)
Interest expense (17,532) -- (15,184) (2,348) --
----------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes $ 63,139 $ -- $ 52,784 $ 10,422 $ (67)
Total assets $ 717,169 $ (52) $ 620,009 $ 95,261 $ 1,951
Capital expenditures $ 36,384 $ -- $ 31,929 $ 4,455 $ --
----------------------------------------------------------------------------------------------------------------------
1998
Revenues $ 422,283 $ -- $ 350,154 $ 72,129 $ --
EBITDA(1) $ 96,633 $ -- $ 82,937 $ 13,560 $ 136
Depreciation and amortization (22,043) -- (18,165) (3,878) --
----------------------------------------------------------------------------------------------------------------------
Operating income 74,590 -- 64,772 9,682 136
Interest expense (17,583) -- (15,269) (2,314) --
----------------------------------------------------------------------------------------------------------------------
Income before income taxes $ 57,007 $ -- $ 49,503 $ 7,368 $ 136
Total assets $ 690,317 $(101) $ 594,447 $ 95,587 $ 384
Capital expenditures $ 37,219 $ -- $ 32,033 $ 5,186 $ --
----------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Earnings before interest expense, income taxes, depreciation and
amortization (EBITDA) should not be considered as an alternative to net
income (as an indicator of operating performance) or as an alternative to
cash flow (as a measure of liquidity or ability to service debt obligations)
and is not a measure of performance or financial condition under generally
accepted accounting principles.
F-24
<PAGE> 71
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 with the exception of those indicated below) which
we consider necessary for a fair presentation of such information. Quarterly
results fluctuate because of the seasonal nature of UGI Utilities' businesses.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
December 31, March 31, June 30, September 30,
1999 1998 2000(a) 1999 2000 1999 2000(b) 1999
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $121,156 $112,770 $169,864 $167,692 $77,554 $77,338 $68,368 $62,847
Operating income (loss) 33,822 25,452 48,974 43,174 12,305 10,799 6,134 1,246
Net income (loss) 17,818 13,033 27,118 24,167 4,872 4,076 668 (2,408)
----------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Includes income from a litigation settlement which increased operating
income by $2,400 and net income by $1,400.
(b) Includes income from a litigation settlement which increased operating
income by $2,100 and net income by $1,228.
12. RELATED PARTY TRANSACTIONS
UGI bills UGI Utilities for an allocated share of its general corporate
expenses. These billed expenses are classified as operating and administrative
expenses - related parties in the Consolidated Statements of Income.
F-25
<PAGE> 72
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
<TABLE>
<CAPTION>
Balance at Charged to Balance at
beginning costs and end of
of year expenses Other year
------- -------- ----- ----
<S> <C> <C> <C> <C>
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)
YEAR ENDED SEPTEMBER 30, 1999
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 1,373 $4,269 $ (3,926)(1) $ 1,716
======= =======
Other reserves (3) $ 3,724 $1,079 $ (3,730)(2) $ 1,345
======= =======
272 (4)
YEAR ENDED SEPTEMBER 30, 1998
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,333 $4,099 $ (6,059)(1) $ 1,373
======= =======
Other reserves (3) $ 5,945 $ 159 $ (2,380)(2) $ 3,724
======= =======
</TABLE>
(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
<PAGE> 73
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<S> <C>
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
21 Subsidiaries of Registrant
23 Consent of Arthur Andersen LLP
27 Financial Data Schedule
</TABLE>
