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                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 10-K

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2000

                         Commission file number 1-11071

                                 UGI CORPORATION

             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

          Pennsylvania                                 23-2668356
(STATE OR OTHER JURISDICTION OF            (I.R.S. EMPLOYER IDENTIFICATION NO.)
 INCORPORATION OR ORGANIZATION)

                 460 North Gulph Road, King of Prussia, PA 19406
               (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

                                 (610) 337-1000
              (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

                                                                       NAME OF EACH EXCHANGE
          TITLE OF CLASS                                                ON WHICH REGISTERED
                                                                
Common Stock, without par value                                    New York Stock Exchange, Inc.
                                                                   Philadelphia Stock Exchange, Inc.

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. [ ]

The aggregate market value of UGI Corporation Common Stock held by nonaffiliates
of the registrant on December 1, 2000 was $630,716,648.

At December 8, 2000 there were 27,024,689 shares of UGI Corporation Common Stock
issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Annual Report to
Shareholders for the year ended September 30, 2000 are incorporated by reference
into Parts I and II of this Form 10-K. Portions of the Proxy Statement for the
Annual Meeting of Shareholders to be held on February 27, 2001 are incorporated
by reference into Part III of this Form 10-K.

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                                TABLE OF CONTENTS

PART I                         BUSINESS                                                                         PAGE

        Items 1 and 2          Business and Properties....................................................        1
                               AmeriGas Propane Business..................................................        2
                               Utility Operations.........................................................        9
                               UGI Enterprises, Inc.......................................................       17
                                      -        Domestic Businesses .......................................       17
                                      -        International Businesses ..................................       17

        Item 3                 Legal Proceedings..........................................................       19

        Item 4                 Submission of Matters to a Vote of
                               Security Holders...........................................................       21

PART II                        SECURITIES AND FINANCIAL INFORMATION

        Item 5                 Market for Registrant's Common Equity
                               and Related Stockholder Matters............................................       21

        Item 6                 Selected Financial Data....................................................       23

        Item 7                 Management's Discussion and Analysis of
                               Financial Condition and Results of Operations..............................       24

        Item 7A                Quantitative and Qualitative Disclosures About Market Risk.................       24

        Item 8                 Financial Statements and Supplementary Data................................       24

        Item 9                 Changes in and Disagreements with
                               Accountants on Accounting and Financial Disclosure.........................       24

PART III                       UGI MANAGEMENT AND SECURITY HOLDERS

        Item 10                Directors and Executive Officers of the Registrant.........................       25

        Item 11                Executive Compensation.....................................................       25

        Item 12                Security Ownership of Certain Beneficial
                               Owners and Management......................................................       25

        Item 13                Certain Relationships and Related Transactions.............................       25

PART IV                        ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS

        Item 14                Exhibits, Financial Statement Schedules
                               and Reports on Form 8-K....................................................       28

                               Signatures.................................................................       34

                               Index to Financial Statements and
                               Financial Statement Schedules..............................................      F-2

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PART I: BUSINESS

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

         UGI Corporation is a holding company that operates propane
distribution, gas and electric utility, energy marketing and related businesses
through subsidiaries.

         Our majority-owned subsidiary, AmeriGas Partners, L.P., a Delaware
limited partnership ("AmeriGas Partners" or the "Partnership"), conducts one of
the nation's largest retail propane distribution businesses through its 98.99%
owned subsidiary AmeriGas Propane, L.P. (the "Operating Partnership"). We have
been in the retail propane distribution business for over 40 years, operating
through various subsidiaries. The Partnership's sole general partner is our
subsidiary, AmeriGas Propane, Inc. ("AmeriGas Propane" or the "General
Partner"). The common units of AmeriGas Partners, which represent limited
partner interests, are traded on the New York Stock Exchange under the symbol
"APU." We have a 55.5% combined ownership interest in the Partnership and the
Operating Partnership. The remaining interest is publicly held.

         Our subsidiary UGI Utilities, Inc. ("Utilities") owns and operates a
natural gas distribution utility and an electric distribution utility in eastern
Pennsylvania. In response to state deregulation legislation, effective October
1, 1999, Utilities' transferred its electric generation assets to its
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. Utilities is the successor to a
business founded in 1882. It serves 272,000 natural gas customers and 61,000
electric customers.

         Our subsidiary UGI Enterprises, Inc. ("Enterprises") conducts domestic
and international businesses through subsidiaries. The domestic businesses
include retail gas and electric marketing, a retailer of hearth, spa and grill
products, Hearth USA(TM), and a heating, ventilation and air-conditioning
business. In September 1999, Enterprises acquired FLAGA GmbH, the largest retail
propane distributor in Austria. Enterprises also has two international
energy-related joint ventures. We expect Enterprises to continue to evaluate and
develop new related and complementary business opportunities for us.

         UGI was incorporated in Pennsylvania in 1991. UGI is not subject to
regulation by the Pennsylvania Public Utility Commission ("PUC"). It is also
exempt from registration as a holding company and not otherwise subject to the
Public Utility Holding Company Act of 1935, except for Section 9(a)(2), which
regulates the acquisition of voting securities of an electric or gas utility
company. Our executive offices are located at 460 North Gulph Road, King of
Prussia, Pennsylvania 19406, and our telephone number is (610) 337-1000. In this
report, the terms "Company" and "UGI," as well as the terms "our," "we," and
"its," are sometimes used as abbreviated references to UGI Corporation or,
collectively, UGI Corporation and its consolidated subsidiaries. Similarly, the
terms "AmeriGas Partners" and the "Partnership" are sometimes used as
abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas
Partners, L.P. and its subsidiaries, including the Operating Partnership.

BUSINESS STRATEGY

         In July 1999, following a comprehensive study, we announced our
intention to refocus our strategic direction on growing our existing natural
gas, electric and propane businesses while seeking additional related and
complementary growth opportunities. We are employing our core

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competencies from our existing businesses, as well as using our national scope,
extensive asset base and access to customers, to accelerate growth in related
and complementary businesses, both domestic and international. During fiscal
year 2000, we completed four transactions in pursuit of this strategy.

                            AMERIGAS PROPANE BUSINESS

         Our domestic propane distribution business is conducted through
AmeriGas Partners. The Partnership is one of the largest retail propane
distributors in the United States, based on fiscal year 2000 retail volume of
771 million gallons. The Partnership operates from approximately 550 district
locations in 45 states. AmeriGas Propane manages the Partnership. Although our
consolidated financial statements include 100% of the Partnership's revenues,
assets and liabilities, our net income reflects only our majority interest in
the income or loss of the Partnership, due to the publicly-owned limited partner
interest. See Note 1 to the Company's Consolidated Financial Statements.

GENERAL INDUSTRY INFORMATION

         Propane is separated from crude oil during the refining process and
also extracted from natural gas or oil wellhead gas at processing plants.
Propane is normally transported and stored in a liquid state under moderate
pressure or refrigeration for economy and ease of handling in shipping and
distribution. When the pressure is released or the temperature is increased, it
is usable as a flammable gas. Propane is colorless and odorless; an odorant is
added to allow its detection. Propane is clean burning, producing negligible
amounts of pollutants when properly consumed.

         The primary customers for propane are residential, commercial,
agricultural, motor fuel and industrial users to whom natural gas is not readily
available. Propane is typically more expensive than natural gas, competitive
with fuel oil when operating efficiencies are taken into account and, in most
areas, cheaper than electricity on an equivalent energy basis. Several states
have adopted or are considering proposals that would substantially deregulate
the generation portion of the electric utility industry and thereby permit
retail electric customers to choose their electric supplier. While proponents of
electric utility deregulation believe that competition will ultimately reduce
the cost of electricity, we are unable to predict whether, or the extent to
which, the price of electricity may drop. Therefore, we cannot predict the
ultimate impact that electric utility deregulation may have on propane's
existing competitive price advantage over electricity.

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PRODUCTS, SERVICES AND MARKETING

         As of September 30, 2000, the Partnership distributed propane to
approximately 968,000 customers from approximately 550 district locations. The
Partnership's operations are located primarily in the Northeast, Southeast,
Great Lakes and West Coast regions of the United States. The Partnership also
sells, installs and services propane appliances, including heating systems. In
certain markets, the Partnership also installs and services propane fuel systems
for motor vehicles. Typically, district locations are found in suburban and
rural areas where natural gas is not available. Districts generally consist of
an office, appliance showroom, warehouse and service facilities, with one or
more 18,000 to 30,000 gallon storage tanks on the premises. As part of its
overall transportation and distribution infrastructure, the Partnership operates
as an interstate carrier in 48 states throughout the United States. It is also
licensed as a carrier in Canada.

         The Partnership sells propane primarily to five markets: residential,
commercial/industrial, motor fuel, agricultural and wholesale. Approximately 75%
of the Partnership's 2000 fiscal year sales (based on gallons sold) were to
retail accounts and approximately 25% were to wholesale customers. Sales to
residential customers in fiscal 2000 represented approximately 40% of retail
gallons sold, industrial/commercial customers 37%, motor fuel customers 15%, and
agricultural customers 8%. Residential customers represented 49% of the
Partnership's total propane margin. No single customer accounts for 1% or more
of the Partnership's consolidated revenues.

         In the residential market, which includes both conventional and
manufactured housing, propane is used primarily for home heating, water heating
and cooking purposes. Commercial users, which include motels, hotels,
restaurants and retail stores, generally use propane for the same purposes as
residential customers. The PPX Prefilled Propane Xchange program ("PPX(R)")
enables consumers to exchange their empty 20-pound propane grill cylinders for
filled cylinders at various retail locations such as home center and convenience
stores. Sales of our PPX(R) grill cylinders to retailers are included in the
commercial/industrial market. Industrial customers use propane to fire furnaces,
as a cutting gas and in other process applications. Other industrial customers
are large-scale heating accounts and local gas utility customers who use propane
as a supplemental fuel to meet peak load deliverability requirements. As a motor
fuel, propane is burned in internal combustion engines that power over-the-road
vehicles, forklifts and stationary engines. Agricultural uses include tobacco
curing and crop drying. In its wholesale operations, the Partnership principally
sells propane to large industrial end-users and other propane distributors.

         Retail deliveries of propane are usually made to customers by means of
bobtail and rack trucks. Propane is pumped from the bobtail truck, which
generally holds 2,400 to 3,000 gallons of propane, into a stationary storage
tank on the customer's premises. The Partnership owns most of these storage
tanks and leases them to its customers. The capacity of these tanks ranges from
approximately 100 gallons to approximately 1,200 gallons.

         The Partnership also delivers propane to retail customers in portable
cylinders with capacities of 4 to 30 gallons. Some of these deliveries are made
to the customer's location, where empty cylinders are either picked up for
replenishment or filled in place. The Partnership continues to expand its
PPX(R) program. At September 30, 2000, PPX(R) was available at
approximately 10,700 retail locations throughout the country.

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PROPANE SUPPLY AND STORAGE

         Supplies of propane from the Partnership's sources historically have
been readily available. During the year ended September 30, 2000, the
Partnership purchased approximately 65% of its propane from 10 suppliers,
including Enterprise Products Operating LP (approximately 18%), the BP companies
(approximately 17%) and Dynegy (approximately 13%). The availability of propane
supply is dependent upon, among other things, the severity of winter weather and
the price and availability of competing fuels such as natural gas and heating
oil. Although no assurance can be given that supplies of propane will be readily
available in the future, management currently expects to be able to secure
adequate supplies during fiscal year 2001. If supply from major sources were
interrupted, however, the cost of procuring product might be materially higher
and, at least on a short-term basis, margins could be affected. Aside from
Enterprise Products Operating LP, the BP companies and Dynegy, no single
supplier provided more than 10% of the Partnership's total propane supply in
fiscal year 2000. In certain market areas, however, some suppliers provide 70%
to 80% of the Partnership's requirements. Disruptions in supply in these areas
could also have an adverse impact on the Partnership's margins.

         The Partnership has over 200 sources of supply, and it also makes
purchases on the spot market. The Partnership purchases its propane supplies
from domestic and international suppliers. Over 90% of propane purchases by the
Partnership in fiscal year 2000 were on a contractual basis under one- or
two-year agreements subject to annual review. More than 90% of those contracts
provided for pricing based upon posted prices at the time of delivery or the
current prices established at major storage points such as Mont Belvieu, Texas,
or Conway, Kansas. In addition, some agreements provided maximum and minimum
seasonal purchase volume guidelines. The percentage of contract purchases, and
the amount of supply contracted for at fixed prices, will vary from year to year
as determined by the General Partner. The Partnership uses a number of
interstate pipelines, as well as railroad tank cars, delivery trucks and barges,
to transport propane from suppliers to storage and distribution facilities. The
Partnership stores propane at facilities in Arizona, Rhode Island and several
other states.

         Because the Partnership's profitability is sensitive to changes in
wholesale propane costs, the Partnership generally seeks to pass on increases in
the cost of propane to customers. There is no assurance, however, that the
Partnership will always be able to pass on product cost increases fully,
particularly when product costs rise rapidly. Product cost increases can be
triggered by periods of severe cold weather, supply interruptions, or other
unforeseen events. The General Partner has adopted supply acquisition and
product price risk management practices to reduce the effect of price volatility
on product costs. These practices currently include the use of summer storage,
forward purchases and derivative commodity instruments such as options and
propane price swaps. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Market Risk Disclosures."

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         The following graph shows the average prices of propane on the propane
spot market during the last five fiscal years at Mont Belvieu, Texas and Conway,
Kansas, two major storage areas.

              [PLOT POINTS FOR AVERAGE PROPANE SPOT MARKET PRICES]

LP History for Mt Be

                                                        Mont Belvieu   Conway

1995 October Avg.                            Oct-95         30.946    32.7784
1995 November Avg.                           Nov-95        30.9531    32.7406
1995 December Avg.                           Dec-95        35.3219    38.1719
1996 January Avg.                            Jan-96             36    36.2415
1996 February Avg.                           Feb-96        40.8563    37.7688
1996 March Avg.                              Mar-96        37.2292    36.0119
1996 April Avg.                              Apr-96        35.5744    34.1071
1996 May Avg.                                May-96        34.9233    34.4773
1996 June Avg.                               Jun-96         34.925    36.3531
1996 July Avg.                               Jul-96        35.6339    37.2679
1996 August Avg.                             Aug-96        38.4403    37.9773
1996 September Avg.                          Sep-96        47.0156    44.7844
1996 October Avg.                            Oct-96        51.5734    51.5272
1996 November Avg.                           Nov-96        58.0493    63.4112
1996 December Avg.                           Dec-96        61.0446    84.2917
1997 January Avg.                            Jan-97        47.4545     63.392
1997 February Avg.                           Feb-97        38.7105    39.0197
1997 March Avg.                              Mar-97           38.5    37.2563
1997 April Avg.                              Apr-97         34.875    35.2614
1997 May Avg.                                May-97        35.3095    36.4762
1997 June Avg.                               Jun-97        34.4286    35.8631
1997 July Avg.                               Jul-97        34.9063    34.6278
1997 August Avg.                             Aug-97        37.0268    36.5268
1997 September Avg.                          Sep-97        38.6786    37.9524
1997 October Avg.                            Oct-97        39.8261    37.3207
1997 November Avg.                           Nov-97        35.9479    35.0035
1997 December Avg.                           Dec-97         33.571    31.3636
1998 January Avg.                            Jan-98        30.0656    28.2063
1998 February Avg.                           Feb-98        29.7862    28.3237
1998 March Avg.                              Mar-98        27.3892    27.8381
1998 April Avg.                              Apr-98        29.0565    29.4702
1998 May Avg.                                May-98        27.4188    27.8231
1998 June Avg.                               Jun-98        24.4205    24.8409
1998 July Avg.                               Jul-98        24.5398    24.5483
1998 August Avg.                             Aug-98        24.1161    23.8661
1998 September Avg.                          Sep-98        24.8304    24.0417
1998 October Avg.                            Oct-98        25.7188    24.5682
1998 November Avg.                           Nov-98        24.7862    23.2007
1998 December Avg.                           Dec-98        20.8949    18.7188
1999 January Avg.                            Jan-99        21.7467    19.6086
1999 February Avg.                           Feb-99        22.4342    20.5822
1999 March Avg.                              Mar-99        24.1005    23.4022
1999 April Avg.                              Apr-99        28.2619    27.5774
1999 May Avg.                                May-99        28.3063    26.8813
1999 June Avg.                               Jun-99        30.9517     28.679
1999 July Avg.                               Jul-99        37.2619     34.622
1999 August Avg.                             Aug-99        40.5085    37.5597
1999 September Avg.                          Sep-99        43.1786    42.4048
1999 October Avg.                            Oct-99        45.4554    43.3899
1999 November Avg.                           Nov-99        43.4406    38.7781
1999 December Avg.                           Dec-99        42.8304    35.1012
2000 January Avg.                            Jan-00        56.1086    42.3191
2000 February Avg.                           Feb-00        59.7219    47.2625
2000 March Avg.                              Mar-00        51.1277    47.6495
2000 April Avg.                              Apr-00         46.875    43.6414
2000 May Avg.                                May-00        51.3068    50.8068
2000 June Avg.                               Jun-00        55.4716    56.2244
2000 July Avg.                               Jul-00         54.875    56.2862
2000 August Avg.                             Aug-00        58.5408    63.5245
2000 September Avg.                          Sep-00       64.20945    70.9466

COMPETITION

         Propane competes with other sources of energy, some of which are less
costly for equivalent energy value. Propane distributors compete for customers
against suppliers of electricity, fuel oil and natural gas, principally on the
basis of price, service, availability and portability. Electricity is a major
competitor of propane, but propane generally enjoys a competitive price
advantage over electricity for space heating, water heating and cooking. As
previously stated, we are unable to predict the ultimate impact that
deregulation of electric generation may have on propane's current competitive
price advantage. Since the 1970s, many new homes have been built to use
electrical heating systems and appliances. Fuel oil is also a major competitor
of propane and is generally less expensive than propane. Operating efficiencies
and other factors such as air quality and environmental advantages, however,
generally make propane competitive with fuel oil as a heating source. Furnaces
and appliances that burn propane will not operate on fuel oil, and vice versa,
and, therefore, a conversion from one fuel to the other requires the
installation of new equipment. Propane serves as an alternative to natural gas
in rural and suburban areas where natural gas is unavailable or portability of
product is required. Natural gas is generally a less expensive source of energy
than propane, although in areas where natural gas is available, propane is used
for certain industrial and commercial applications and as a standby fuel during
interruptions in natural gas service. The gradual expansion of the nation's
natural gas distribution systems has resulted in the availability of natural gas
in some areas that previously depended upon propane. However, natural gas
pipelines are not present in many regions of the country where propane is sold
for heating and cooking purposes.

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         The domestic propane retail distribution business is highly
competitive. The Partnership competes in this business with other large propane
marketers, including other full-service marketers, and thousands of small
independent operators. In recent years, some rural electric cooperatives and
fuel oil distributors have expanded their businesses to include propane
distribution and the Partnership competes with them as well. Based on the most
recent annual survey by the American Petroleum Institute, the 1998 domestic
retail market for propane (annual sales for other than chemical uses) was
approximately 9.5 billion gallons and, based on LP-GAS magazine rankings, 1999
sales volume of the ten largest propane companies (including AmeriGas Partners)
represented approximately 41% of domestic retail sales. Management believes the
Partnership's 2000 retail volume represents approximately 8% of the domestic
retail market. The ability to compete effectively depends on supplying customer
service, maintaining competitive retail prices and controlling operating
expenses.

         Competition can intensify in response to a variety of factors,
including significantly warmer-than-normal weather, higher prices resulting from
extraordinary increases in the cost of propane, and recessionary economic
factors. The Partnership may experience greater than normal customer losses in
certain years when competitive conditions reflect any of these factors.

         In the motor fuel market, propane competes with gasoline and diesel
fuel. When gasoline prices are high relative to propane, propane competes
effectively. Wholesale propane distribution is a highly competitive, low margin
business. Propane sales to other retail distributors and large-volume,
direct-shipment industrial end users are price sensitive and frequently involve
a competitive bidding process.

PROPERTIES

         As of September 30, 2000, the Partnership owned approximately 83% of
its district locations. In addition, the Partnership subleases three one-million
barrel underground storage caverns in Arizona to store propane and butane for
itself and third parties. The Partnership also leases a 600,000 barrel
refrigerated, above-ground storage facility in California, which could be used
in connection with waterborne imports or exports of propane or butane. The
California facility, which the Partnership operates, is currently subleased to
several refiners for the storage of butane. In Rhode Island, the Partnership
leases storage with a 400,000 barrel capacity.

         The transportation of propane requires specialized equipment. The
trucks and railroad tank cars utilized for this purpose carry specialized steel
tanks that maintain the propane in a liquefied state. As of September 30, 2000,
the Partnership operated a fleet of approximately 165 transport trucks,
approximately 40% of which were leased. It owned approximately 320 transport
trailers and leased 270 railroad tank cars. In addition, the Partnership fleet
included approximately 2,600 bobtail and rack trucks, and approximately 1,800
other delivery and service vehicles. The vehicle fleet is 62% leased. Other
assets owned at September 30, 2000 included approximately 1.0 million stationary
storage tanks with typical capacities of 100 to 1,000 gallons and approximately
1.3 million portable propane cylinders with typical capacities of 4 to 100
gallons. The Partnership also owned more than 2,200 large volume tanks which are
used for its own storage requirements. Most of the Partnership's debt is secured
by liens and mortgages on the Partnership's real and personal property.

TRADE NAMES, TRADE AND SERVICE MARKS

         The Partnership markets propane principally under the "AmeriGas(R),"
"America's Propane

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Company(R)" and "PPX Prefilled Propane Xchange(R)" trade names and related
service marks. UGI owns, directly or indirectly, all the right, title and
interest in the "AmeriGas" and related trade and service marks. The General
Partner owns all right, title and interest in the "America's Propane Company"
and "PPX Prefilled Propane Xchange" trade names and related service marks. The
Partnership has an exclusive (except for use by UGI, AmeriGas, Inc. and the
General Partner), royalty-free license to use these names and trade and service
marks. UGI and the General Partner each have the option to terminate its
respective license agreement (on 12 months prior notice in the case of UGI),
without penalty, if the General Partner is removed as general partner of the
Partnership other than for cause. If the General Partner ceases to serve as the
general partner of the Partnership for cause, the General Partner has the option
to terminate its license agreement upon payment of a fee equal to the fair
market value of the licensed trade names. UGI has a similar termination option,
however, UGI must provide 12 months prior notice in addition to paying the fee.

SEASONALITY

         Because many customers use propane for heating purposes, the
Partnership's retail sales volume is seasonal, with approximately 55% of the
Partnership's fiscal year 2000 retail sales volume and approximately 83% of its
earnings before interest expense, income taxes, depreciation and amortization
occurring during the five-month peak heating season from November through March.
As a result of this seasonality, sales are concentrated in the Partnership's
first and second fiscal quarters (October 1 through March 31). Cash receipts are
greatest during the second and third fiscal quarters when customers pay for
propane purchased during the winter heating season.

         Sales volume for the Partnership traditionally fluctuates from
year-to-year in response to variations in weather, prices, competition, customer
mix and other factors, such as conservation efforts and general economic
conditions. For historical information on national weather statistics, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

GOVERNMENT REGULATION

         The Partnership is subject to various federal, state and local
environmental, safety and transportation laws and regulations governing the
storage, distribution and transportation of propane. These laws include, among
others, the Resource Conservation and Recovery Act, the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or, the
"Superfund Law"), the Clean Air Act, the Occupational Safety and Health Act, the
Emergency Planning and Community Right to Know Act, the Clean Water Act and
comparable state statutes. CERCLA imposes joint and several liability on certain
classes of persons considered to have contributed to the release or threatened
release of a "hazardous substance" into the environment without regard to fault
or the legality of the original conduct. Propane is not a hazardous substance
within the meaning of federal and state environmental laws. However, the
Partnership owns and operates real property where such hazardous substances may
exist. See Notes 1 and 11 to the Company's Consolidated Financial Statements.

         All states in which the Partnership operates have adopted fire safety
codes that regulate the storage and distribution of propane. In some states
these laws are administered by state agencies, and in others they are
administered on a municipal level. The Partnership conducts training programs to
help ensure that its operations are in compliance with applicable governmental
regulations. With respect to general operations, National Fire Protection
Association Pamphlets No. 54 and No. 58, which establish a set of rules and
procedures governing the safe handling of

                                      -7-
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propane, or comparable regulations, have been adopted as the industry standard
in a majority of the states in which the Partnership operates. The Partnership
maintains various permits under environmental laws that are necessary to operate
certain of its facilities, some of which may be material to the operations of
the Partnership. Management believes that the procedures currently in effect at
all of its facilities for the handling, storage and distribution of propane are
consistent with industry standards and are in compliance in all material
respects with applicable environmental, health and safety laws.

         With respect to the transportation of propane by truck, the Partnership
is subject to regulations promulgated under the Federal Motor Carrier Safety
Act. These regulations cover the transportation of hazardous materials and are
administered by the United States Department of Transportation ("DOT"). During
1999, the Research and Special Programs Administration ("RSPA"), a division of
the DOT, issued new regulations applicable to cargo tanks used to transport
propane and procedures for loading propane on and off cargo tanks. Specific
provisions include, among other things, revised attendance requirements for
unloading propane and new requirements for emergency discharge control
equipment, such as remote control devices that enable the driver to stop the
unloading process at a distance from the vehicle and passive systems that will
shut down loading and unloading without human intervention. The Partnership is
in compliance with the new regulations and is evaluating the equipment that is
being developed to comply with the passive systems requirements that will become
effective in July 2001.

         The Natural Gas Safety Act of 1968 required the DOT to develop and
enforce minimum safety regulations for the transportation of gases by pipeline.
The DOT's pipeline safety code applies to, among other things, a propane gas
system which supplies 10 or more customers from a single source and a propane
gas system any portion of which is located in a public place. The code requires
operators of all gas systems to provide training and written instructions for
employees, establish written procedures to minimize the hazards resulting from
gas pipeline emergencies, and keep records of inspections and testing.

EMPLOYEES

         The Partnership does not directly employ any persons responsible for
managing or operating the Partnership. The General Partner provides these
services and is reimbursed for its direct and indirect costs and expenses,
including all compensation and benefit costs. At September 30, 2000, the General
Partner had 4,874 employees, including 311 temporary and part-time employees.
UGI also performs certain financial and administrative services for the General
Partner on behalf of the Partnership and is reimbursed by the Partnership for
its direct and indirect costs and expenses.

                                      -8-
   11

                               UTILITY OPERATIONS

         Our utility business is conducted by UGI Utilities, Inc. a wholly owned
subsidiary. Utilities operates its business through two divisions, the gas
division ("Gas Utility") and the electric division ("Electric Utility"). The
business conducted by each of these divisions is described below.

GAS UTILITY

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 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

                                      -9-
   12

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 20%, 25% and 24%, 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.

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.

                                      -10-
   13

         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 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'

                                      -11-
   14

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.

ELECTRIC UTILITY

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,

                                      -12-
   15

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.

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 4%, 5%
and 5%, 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.

                                      -13-
   16

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 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.

                                      -14-
   17

         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.

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

                                      -15-
   18

highways in its territories.

OTHER GOVERNMENT REGULATION

         In addition to regulation by the PUC, the gas and electric utility
operations of Utilities are subject to various federal, state and local laws
governing environmental matters, occupational health and safety, pipeline safety
and other matters. Certain of Utilities' activities involving the interstate
movement of natural gas, the transmission of electricity, transactions with
non-utility generators of electricity, like UGID, and other matters, are also
subject to the jurisdiction of FERC.

         Utilities is subject to the requirements of the federal Resource
Conservation and Recovery Act, CERCLA and comparable state statutes with respect
to the release of hazardous substances on property owned or operated by
Utilities. See ITEM 3. "LEGAL PROCEEDINGS - Environmental Matters-Manufactured
Gas Plants." The electric generation activities of Utilities are also subject to
the Clean Air Act Amendments, the Federal Water Pollution Control Act and
comparable state statutes and regulations. See "UTILITY OPERATIONS - Electric
Utility - Environmental Factors."

EMPLOYEES

         At September 30, 2000, Utilities and its subsidiaries had 1,120
employees.

                                      -16-
   19

                              UGI ENTERPRISES, INC.

         UGI Enterprises, Inc. is a wholly owned subsidiary of UGI that was
formed in 1994. Through its subsidiaries, Enterprises is developing the domestic
and international businesses described below.

DOMESTIC BUSINESSES

         NATURAL GAS AND ELECTRICITY MARKETING

         In 1995, the gas marketing business previously conducted by a
subsidiary of Utilities was transferred to UGI Energy Services, Inc. ("Energy
Services"), a wholly owned subsidiary of Enterprises. Energy Services conducts
this business under the trade name GASMARK(R). GASMARK(R) sells natural
gas directly to approximately 3,000 commercial and industrial customers in the
Mid-Atlantic region through the transportation systems of 16 utility systems.
Energy Services also sells electricity to over 200 commercial and industrial
customers in Pennsylvania. During fiscal year 2000, GASMARK(R) acquired the
gas marketing operations of two large regional energy marketers. These
acquisitions doubled GASMARK(R)'s customer base.

         RETAIL HEARTH PRODUCTS

         In September 1999, Enterprises opened the first Hearth USA(TM) retail
store in Rockville, Maryland. Hearth USA(TM) is the nation's first large-scale
retailer to offer a wide selection of hearth, grill and spa products together
with installation services. A second store opened in the Washington, DC area
during fiscal year 2000. Enterprises expects to refine the Hearth retail concept
further prior to scheduling openings in other markets.

         HVAC SERVICE

         Effective September 1, 2000, a subsidiary of Enterprises acquired a
heating, ventilation and air-conditioning service business serving portions of
Utilities' gas service area and adjacent market areas, including portions of
northern Delaware. In the prior year, this business generated over $40 million
in annual revenues and employed over 450 people.

INTERNATIONAL BUSINESSES

         ENERGY-RELATED JOINT VENTURES

         During 1996, Enterprises formed a partnership with affiliates of Energy
Transportation Group, Inc. ("ETG") and North American World Trade, Ltd. to
develop, build and operate a liquefied petroleum gas ("LPG") import project in
Romania. ETG has extensive experience in the transportation of liquefied natural
gas, and North American World Trade, Ltd. is a consulting firm with Romanian
expertise. The joint venture is known as Black Sea LPG Romania, S.A. The
Romanian partners in this venture are Regia Autonoma a Gazelor Naturale "Romgaz"
Medias, the Romanian national gas utility; Regia Autonoma de Electricitate
"Renel", the Romanian national electric utility; and Rompetrol, S.A., a
privately-held energy services company. The economic climate in Romania in
recent years has slowed project development.

         During 1998, Enterprises formed ChinaGas Partners, L.P. ("ChinaGas")
with affiliates of

                                      -17-
   20

ETG to develop, build and operate LPG projects in the People's Republic of
China. On October 28, 1998, ChinaGas and its wholly owned subsidiary together
acquired 50% of the shares of an existing Chinese company known as the Nantong
Huayang LPG Port Co., Ltd. ("Port Company") which operates an integrated LPG
business, including an import terminal and distribution business, serving the
provinces along the lower and middle reaches of the Yangtze River. At September
30, 2000, retail sales of propane represented over 25% of Port Company total
sales. The other shareholders in the Port Company are China National Chemical
Supply & Sales Corporation and two of its affiliates. Our effective ownership
interest in the Port Company is 25%.

         PROPANE DISTRIBUTION

         In September 1999, subsidiaries of Enterprises acquired all of the
stock of FLAGA GmbH, a privately-held company founded in 1947. FLAGA is the
largest retail propane distributor in Austria and a leading distributor in the
Czech Republic. FLAGA operates from 7 distribution locations in Austria, 8 in
the Czech Republic and 2 in Slovakia. FLAGA marketed approximately 39 million
gallons of propane in fiscal year 2000. Its assets totaled approximately $108
million at September 30, 2000.

                          BUSINESS SEGMENT INFORMATION

         The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to each of UGI's business segments for the
2000, 1999 and 1998 fiscal years appears in Note 17 to the Consolidated
Financial Statements contained in our 2000 Annual Report and is incorporated in
this Report by reference.

                                    EMPLOYEES

         At September 30, 2000, UGI and its subsidiaries had 6,966 employees.

                                      -18-
   21

ITEM 3.  LEGAL PROCEEDINGS

         With the exception of the matters set forth below, no material legal
proceedings are pending involving UGI, 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 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

                                      -19-
   22

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
11 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. See Note 11 to the Company's Consolidated Financial
Statements.

                                      -20-
   23

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.

                               EXECUTIVE OFFICERS

         Information regarding our executive officers is included in Part III of
this Report and is incorporated in Part I by reference.

PART II:  SECURITIES AND FINANCIAL INFORMATION

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY
         AND RELATED STOCKHOLDER MATTERS

MARKET INFORMATION

         Our Common Stock is traded on the New York and Philadelphia stock
exchanges under the symbol "UGI." The following table sets forth the high and
low sales prices for the Common Stock on the New York Stock Exchange Composite
Transactions tape as reported in The Wall Street Journal for each full quarterly
period within the two most recent fiscal years:

      2000 FISCAL YEAR                            HIGH                 LOW
                                                              
         4th Quarter                            $24.313             $20.563
         3rd Quarter                             22.625              19.750
         2nd Quarter                             22.313              18.188
         1st Quarter                             24.000              19.125

      1999 FISCAL YEAR                            HIGH                 LOW
                                                              
         4th Quarter                            $24.688             $19.750
         3rd Quarter                             21.000              16.563
         2nd Quarter                             24.375              15.000
         1st Quarter                             25.750              21.625

                                      -21-
   24

DIVIDENDS

         Quarterly dividends on our Common Stock were paid in the 2000 and 1999
fiscal years as follows:

       2000 FISCAL YEAR                                      AMOUNT
                                                          
         4th Quarter                                         $0.3875
         3rd Quarter                                          0.375
         2nd Quarter                                          0.375
         1st Quarter                                          0.375

       1999 FISCAL YEAR                                      AMOUNT
                                                          
         4th Quarter                                         $0.365
         3rd Quarter                                          0.365
         2nd Quarter                                          0.365
         1st Quarter                                          0.365

HOLDERS

         On December 1, 2000, UGI had 11,049 holders of record of Common Stock.

                                      -22-
   25

ITEM 6.  SELECTED FINANCIAL DATA

                                                                          Year Ended
                                                                         September 30,
                                                   ----------------------------------------------------------
                                                     2000        1999        1998         1997        1996
                                                   ---------   ---------   ---------    ---------   ---------
                                                        (Millions of dollars, except per share amounts)
                                                                                     
FOR THE PERIOD:

INCOME STATEMENT DATA:

     Revenues                                      $ 1,761.7   $ 1,383.6   $ 1,439.7    $ 1,642.0   $ 1,557.6
                                                   =========   =========   =========    =========   =========
     Net income                                       $ 44.7      $ 55.7      $ 40.3       $ 52.1      $ 39.5
                                                   =========   =========   =========    =========   =========
     Earnings per common share - diluted (a)          $ 1.64      $ 1.74      $ 1.22       $ 1.57      $ 1.19
                                                   =========   =========   =========    =========   =========
     Cash dividends declared per common share        $ 1.525      $ 1.47      $ 1.45       $ 1.43      $ 1.41
                                                   =========   =========   =========    =========   =========

AT PERIOD END:

BALANCE SHEET DATA:

     Total assets                                  $ 2,278.8   $ 2,140.5   $ 2,074.6    $ 2,151.7   $ 2,133.0
                                                   =========   =========   =========    =========   =========

     Capitalization:
         Debt:
           Bank loans - AmeriGas Propane              $ 30.0      $ 22.0      $ 10.0       $ 28.0      $ 15.0
           Bank loans - UGI Utilities                  100.4        87.4        68.4         67.0        50.5
           Bank loans - other                            4.3        11.6           -            -           -
           Long-term debt
            (including current maturities):
                AmeriGas Propane                       857.2       744.7       709.0        691.1       692.5
                UGI Utilities                          172.9       180.0       187.2        169.3       174.8
                Other                                   85.5        91.6         8.2          8.6         9.0
                                                   ---------   ---------   ---------    ---------   ---------
          Total debt                                 1,250.3     1,137.3       982.8        964.0       941.8
                                                   =========   =========   =========    =========   =========

          Minority interest in AmeriGas Partners       177.1       209.9       236.5        266.5       284.4
          UGI Utilities preferred stock subject
              to mandatory redemption                   20.0        20.0        20.0         35.2        35.2
          Common stockholders' equity                  247.2       249.2       367.1        376.1       377.6
                                                   ---------   ---------   ---------    ---------   ---------
     Total capitalization                          $ 1,694.6   $ 1,616.4   $ 1,606.4    $ 1,641.8   $ 1,639.0
                                                   =========   =========   =========    =========   =========

RATIO OF CAPITALIZATION:

     Total debt                                        73.8%       70.4%       61.2%        58.7%       57.5%
     Minority interest                                 10.5%       13.0%       14.7%        16.3%       17.4%
     UGI Utilities preferred stock                      1.2%        1.2%        1.2%         2.1%        2.1%
     Common stockholders' equity                       14.5%       15.4%       22.9%        22.9%       23.0%
                                                   ---------   ---------   ---------    ---------   ---------
                                                      100.0%      100.0%      100.0%       100.0%      100.0%
                                                   =========   =========   =========    =========   =========

      (a)   Basic earnings per share was $1.58 in 1997. For all other periods
            presented, basic earnings per share was the same as diluted earnings
            per share.

                                      -23-
   26

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF
         FINANCIAL CONDITION AND RESULTS OF OPERATIONS

         Management's Discussion and Analysis of Financial Condition and Results
of Operations, entitled "Financial Review" and contained on pages 13 through 23
of UGI's 2000 Annual Report to Shareholders, is incorporated in this report by
reference.

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" on page 20 of
the UGI 2000 Annual Report to Shareholders and are incorporated in this Report
by reference.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

         The Financial Statements and Financial Statement Schedules referred to
in the Index contained on pages F-2 and F-3 of this Report are incorporated in
this Report by reference.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
              ACCOUNTING AND FINANCIAL DISCLOSURE

         None.

                                      -24-
   27

PART III:   UGI MANAGEMENT AND SECURITY HOLDERS

ITEMS 10 THROUGH 13.

         In accordance with General Instruction G(3), and except as set forth
below, the information required by Items 10, 11, 12 and 13 is incorporated in
this Report by reference to the following portions of UGI's Proxy Statement,
which will be filed with the Securities and Exchange Commission by January 28,
2001:

                                                              CAPTIONS OF PROXY STATEMENT
         INFORMATION                                            INCORPORATED BY REFERENCE
                                                           
Item 10.  Directors and Executive                             Election of Directors - Nominees
              Officers of Registrant.

Item 11.  Executive Compensation.                             Compensation of Executive Officers
                                                              Compensation of Directors

Item 12.  Security Ownership of                               Securities Ownership of Management
              Certain Beneficial
              Owners and Management.

Item 13.  Certain Relationships                               Compensation of Executive Officers -
              and Related Transactions.                       Stock Ownership Policy and
                                                              Indebtedness of Management

         The information concerning the Company's executive officers required by
Item 10 is set forth below.

                               EXECUTIVE OFFICERS

               NAME                          AGE                      POSITION
               ----                          ---                      --------
                                                        
         Lon R. Greenberg                     50              Chairman, Director, President
                                                              and Chief Executive Officer

         Eugene V.N. Bissell                  47              President and Chief Executive
                                                              Officer, AmeriGas Propane, Inc.

         Robert J. Chaney                     58              President and Chief Executive
                                                              Officer, UGI Utilities, Inc.

         Brendan P. Bovaird                   52              Vice President and General Counsel

         Bradley C. Hall                      47              Vice President - New Business Development

         Anthony J. Mendicino                 52              Vice President - Finance
                                                              and Chief Financial Officer

                                      -25-
   28

         All officers are elected for a one-year term at the organizational
meetings of the respective Boards of Directors held each year.

         There are no family relationships between any of the officers or
between any of the officers and any of the directors.

Lon R. Greenberg

         Mr. Greenberg was elected Chairman of UGI effective August 1, 1996,
having been elected Chief Executive Officer effective August 1, 1995. He was
elected Director and President of UGI and a Director of UGI Utilities in July
1994. He was elected a Director of AmeriGas Propane, Inc. in 1994 and has been
Chairman since 1996. He also served as President and Chief Executive Officer of
AmeriGas Propane (1996 to 2000). Mr. Greenberg was Senior Vice President - Legal
and Corporate Development (1989 to 1994), and also served as Vice President -
Legal and Corporate Development (1987 to 1989). Previously, he was Vice
President - Legal (1984 to 1987), General Counsel (1983 to 1994) and Secretary
(1982 to 1988). He joined the Company in 1980 as Corporate Development Counsel.
Mr. Greenberg is also a director on the Mellon PSFS Advisory Board.

Eugene V.N. Bissell

         Mr. Bissell is President and Chief Executive Officer of AmeriGas
Propane, Inc. (since July 2000), having served as Senior Vice President - Sales
and Marketing (1999 to 2000) and Vice President - Sales and Operations (1995 to
1999). Previously, he was Vice President - Distributors and Fabrication, BOC
Gases (1995), having been Vice President - National Sales (1993 to 1995) and
Regional Vice President Southern Region for Distributor and Cylinder Gases
Division, BOC Gases (1989 to 1993). From 1981 to 1987, Mr. Bissell held various
positions with the Company and its subsidiaries, including Director, Corporate
Development.

Robert J. Chaney

         Mr. Chaney is President and Chief Executive Officer of UGI Utilities,
Inc., (since March 1999). He previously served as Executive Vice President (1998
to 1999), Vice President and General Manager - Gas Utility Division (1991 to
1998) and Vice President - Rates and Energy Utilization - Gas Utility Division
(1981 to 1991).

Brendan P. Bovaird

         Mr. Bovaird is Vice President and General Counsel of UGI (since April
1995). He is also Vice President and General Counsel of UGI Utilities, Inc., and
AmeriGas Propane, Inc. (since April 1995). Mr. Bovaird previously served as
Division Counsel and Member of the Executive and Operations Committees of
Wyeth-Ayerst International Inc. (1992 to 1995) and Senior Vice President,
General Counsel and Secretary of Orion Pictures Corporation (1990 to 1991).

Bradley C. Hall

         Mr. Hall was elected Vice President - New Business Development on
October 25, 1994, having been Vice President - Marketing and Rates, UGI
Utilities, Inc. Gas Division. He also serves as President of UGI Enterprises,
Inc. (since 1994). He joined the Company in 1982 and held

                                      -26-
   29

various positions in Gas Utility.

Anthony J. Mendicino

         Mr. Mendicino was elected Vice President - Finance and Chief Financial
Officer on September 8, 1998. He previously served as President and Chief
Operating Officer (July 1997 to June 1998) and as Senior Vice President (January
1997 to June 1997) of Eastwind Group, Inc., a holding company formed to acquire
and consolidate middle-market manufacturing businesses. Mr. Mendicino was Senior
Vice President and Chief Financial Officer and a director (1987 to 1996) of UTI
Energy Corp., a diversified oil field service company. From 1981 to 1987 Mr.
Mendicino held various positions with UGI, including Treasurer from 1984 to
1987.

                                      -27-
   30

PART IV:  ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
                AND REPORTS ON FORM 8-K

         (a)  DOCUMENTS FILED AS PART OF THIS REPORT:

                  (1), (2) The financial statements and financial statement
                  schedules incorporated by reference or included in this report
                  are listed in the accompanying Index to Financial Statements
                  and Financial Statement Schedules set forth on pages F-2
                  through F-3 of this report, which is incorporated herein by
                  reference.

                  (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):

                                      -28-
   31

- ---------------------------------------------------------------------------------------------------------------------------------
                                                   INCORPORATION BY REFERENCE
- ---------------------------------------------------------------------------------------------------------------------------------
    EXHIBIT NO.                         EXHIBIT                          REGISTRANT               FILING             EXHIBIT
- ---------------------------------------------------------------------------------------------------------------------------------
                                                                                                        
        3.1           (Second) Amended and Restated Articles of              UGI            Amendment No. 1 on      3.(3)(a)
                      Incorporation of the Company                                          Form 8 to Form 8-B
                                                                                                (4/10/92)

        3.2           Bylaws of UGI as in effect since October               UGI           Form 10-K (9/30/98)         3.2
                      27, 1998
- ---------------------------------------------------------------------------------------------------------------------------------
         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 long-term debt not
                      required to be filed pursuant to Item
                      601(b)(4) of Regulation S-K)
- ---------------------------------------------------------------------------------------------------------------------------------
        4.1           Rights Agreement, as amended as of August              UGI               Registration            4.3
                      18, 2000, between the Company and Mellon                                Statement No.
                      Bank, N.A., successor to Mellon Bank (East)                               333-49080
                      N.A., as Rights Agent, and Assumption
                      Agreement dated April 7, 1992
- ---------------------------------------------------------------------------------------------------------------------------------
        4.2           The description of the Company's Common                UGI           Form 8-B/A (4/17/96)       3.(4)
                      Stock contained in the Company's
                      registration statement filed under the
                      Securities Exchange Act of 1934, as amended
- ---------------------------------------------------------------------------------------------------------------------------------
        4.3           UGI's (Second) Amended and Restated
                      Articles of Incorporation and Bylaws
                      referred to in 3.1 and 3.2 above
- ---------------------------------------------------------------------------------------------------------------------------------
        4.4           Note Agreement dated as of April 12, 1995      AmeriGas Partners,         Form 10-Q             10.8
                      among The Prudential Insurance Company of             L.P.
                      America, Metropolitan Life Insurance                                      (3/31/95)
                      Company, and certain other institutional
                      investors and AmeriGas Propane, L.P., New
                      AmeriGas Propane, Inc. and Petrolane
                      Incorporated
- ---------------------------------------------------------------------------------------------------------------------------------
        4.5           First Amendment dated as of September 12,      AmeriGas Partners,    Form 10-K (9/30/97)         4.5
                      1997 to Note Agreement dated as of April              L.P.
                      12, 1995
- ---------------------------------------------------------------------------------------------------------------------------------
        4.6           Second Amendment dated as of September 15,     AmeriGas Partners,    Form 10-K (9/30/98)         4.6
                      1998 to Note Agreement dated as of April              L.P.
                      12, 1995
- ---------------------------------------------------------------------------------------------------------------------------------
        4.7           Third Amendment dated as of March 23, 1999     AmeriGas Partners,    Form 10-Q (3/31/99)        10.2
                      to Note Agreement dated as of April 12, 1995          L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
        4.8           Fourth Amendment dated as of March 16, 2000    AmeriGas Partners,    Form 10-Q (6/30/00)        10.2
                      to Note Agreement dated as of April 12, 1995          L.P.
- ---------------------------------------------------------------------------------------------------------------------------------

                                      -29-
   32

- ---------------------------------------------------------------------------------------------------------------------------------
                                                   INCORPORATION BY REFERENCE
- ---------------------------------------------------------------------------------------------------------------------------------
    EXHIBIT NO.                         EXHIBIT                          REGISTRANT               FILING             EXHIBIT
- ---------------------------------------------------------------------------------------------------------------------------------
                                                                                                        
        4.9           Second Amended and Restated Agreement of       AmeriGas Partners,          Form 8-K               1
                      Limited Partnership of AmeriGas Partners,             L.P.                (9/30/00)
                      L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
        10.1          Service Agreement (Rate FSS) dated as of               UGI           Form 10-K (9/30/95)        10.5
                      November 1, 1989 between Utilities and
                      Columbia, as 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)
- ---------------------------------------------------------------------------------------------------------------------------------
        10.2          Service Agreement (Rate FTS) dated June 1,          Utilities        Form 10-K (12/31/90)      (10)o.
                      1987 between Utilities and Columbia, as
                      modified by 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              Utilities        Form 10-K (12/31/90)      (10)p.
                      FTS-1) dated November 1, 1989 between
                      Utilities and Columbia Gulf 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          Amended and Restated Sublease Agreement                UGI           Form 10-K (9/30/94)        10.35
                      dated April 1, 1988 between Southwest Salt
                      Co. and AP Propane, Inc. (the "Southwest
                      Salt Co. Agreement")
- ---------------------------------------------------------------------------------------------------------------------------------
        10.5          Letter dated July 8, 1998 pursuant to                  UGI           Form 10-K (9/30/99)        10.5
                      Article 1, Section 1.2 of the Southwest
                      Salt Co. Agreement re: option to renew for
                      period of June 1, 2000 to May 31, 2005 and
                      related extension notice
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.6**         UGI Corporation Directors Deferred
                      Compensation Plan Amended and Restated as
                      of January 1, 2000
- ---------------------------------------------------------------------------------------------------------------------------------

                                      -30-
   33

- ---------------------------------------------------------------------------------------------------------------------------------
                                                INCORPORATION BY REFERENCE
- ---------------------------------------------------------------------------------------------------------------------------------
    EXHIBIT NO.                         EXHIBIT                       REGISTRANT             FILING             EXHIBIT
- ---------------------------------------------------------------------------------------------------------------------------------
                                                                                                    
       10.7**         UGI Corporation 1992 Stock Option and               UGI          Form 10-Q (6/30/92)       (10)ee
                      Dividend Equivalent Plan, as amended May
                      19, 1992
- ---------------------------------------------------------------------------------------------------------------------------------
       10.8**         UGI Corporation Annual Bonus Plan dated             UGI          Form 10-Q (6/30/96)        10.4
                      March 8, 1996
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.9**         UGI Corporation Directors' Equity
                      Compensation Plan Amended and Restated as
                      of January 1, 2000
- ---------------------------------------------------------------------------------------------------------------------------------
      10.10**         UGI Corporation 1997 Stock Option and               UGI          Form 10-Q (3/31/97)        10.2
                      Dividend Equivalent Plan
- ---------------------------------------------------------------------------------------------------------------------------------
      10.11**         UGI Corporation 1992 Directors' Stock Plan          UGI          Form 10-Q (6/30/92)       (10)ff
- ---------------------------------------------------------------------------------------------------------------------------------
      10.12**         UGI Corporation Senior Executive Employee           UGI          Form 10-K (9/30/97)       10.12
                      Severance Pay Plan effective January 1,
                      1997
- ---------------------------------------------------------------------------------------------------------------------------------
      10.13**         UGI Corporation 2000 Directors' Stock               UGI          Form 10-K (9/30/99)       10.13
                      Option Plan
- ---------------------------------------------------------------------------------------------------------------------------------
      10.14**         UGI Corporation 2000 Stock Incentive Plan           UGI          Form 10-Q (6/30/00)        10.1
- ---------------------------------------------------------------------------------------------------------------------------------
      10.15**         1997 Stock Purchase Loan Plan                       UGI          Form 10-K (9/30/97)       10.16
- ---------------------------------------------------------------------------------------------------------------------------------
      10.16**         UGI Corporation Supplemental Executive              UGI          Form 10-Q (6/30/98)         10
                      Retirement Plan Amended and Restated
                      effective October 1, 1996
- ---------------------------------------------------------------------------------------------------------------------------------
      10.17**         Summary of Terms of UGI Corporation 1999            UGI          Form 10-Q (6/30/99)         10
                      Restricted Stock Awards
- ---------------------------------------------------------------------------------------------------------------------------------
       10.18          Amended and Restated Credit Agreement            AmeriGas             Form 10-K             10.1
                      dated as of September 15, 1997 among          Partners, L.P.
                      AmeriGas Propane, L.P., AmeriGas Propane,                             (9/30/97)
                      Inc., Petrolane Incorporated, Bank of
                      America National Trust and Savings
                      Association, as Agent, First Union
                      National Bank, as Syndication Agent and
                      certain banks
- ---------------------------------------------------------------------------------------------------------------------------------
       10.19          First Amendment dated as of September 15,        AmeriGas        Form 10-K (9/30/98)        10.2
                      1998 to Amended and Restated Credit           Partners, L.P.
                      Agreement
- ---------------------------------------------------------------------------------------------------------------------------------
       10.20          Second Amendment dated as of March 25,           AmeriGas        Form 10-Q (3/31/99)        10.1
                      1999 to Amended and Restated Credit           Partners, L.P.
                      Agreement
- ---------------------------------------------------------------------------------------------------------------------------------
       10.21          Third Amendment dated as of March 22, 2000       AmeriGas        Form 10-Q (6/30/00)        10.3
                      to Amended and Restated Credit Agreement      Partners, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------

                                      -31-
   34

- ---------------------------------------------------------------------------------------------------------------------------------
                                                INCORPORATION BY REFERENCE
- ---------------------------------------------------------------------------------------------------------------------------------
    EXHIBIT NO.                        EXHIBIT                         REGISTRANT             FILING            EXHIBIT
- ---------------------------------------------------------------------------------------------------------------------------------
                                                                                                    
       10.22         Fourth Amendment dated as of June 6, 2000          AmeriGas       Form 10-Q (6/30/00)        10.4
                     to Amended and Restated Credit Agreement        Partners, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.23         Intercreditor and Agency Agreement dated as        AmeriGas       Form 10-Q (3/31/95)        10.2
                     of April 19, 1995 among AmeriGas Propane,       Partners, L.P.
                     Inc., Petrolane Incorporated, AmeriGas
                     Propane, L.P., Bank of America National
                     Trust and Savings Association ("Bank of
                     America") as Agent, Mellon Bank, N.A. as
                     Cash Collateral Sub-Agent, Bank of America
                     as Collateral Agent and certain creditors
                     of AmeriGas Propane, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.24         General Security Agreement dated as of             AmeriGas       Form 10-Q (3/31/95)        10.3
                     April 19, 1995 among AmeriGas Propane,          Partners, L.P.
                     L.P., Bank of America National Trust and
                     Savings Association and Mellon Bank, N.A.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.25         Subsidiary Security Agreement dated as of          AmeriGas       Form 10-Q (3/31/95)        10.4
                     April 19, 1995 among AmeriGas Propane,          Partners, L.P.
                     L.P., Bank of America National Trust and
                     Savings Association as Collateral Agent and
                     Mellon Bank, N.A. as Cash Collateral Agent
- ---------------------------------------------------------------------------------------------------------------------------------
       10.26         Restricted Subsidiary Guarantee dated as of        AmeriGas       Form 10-Q (3/31/95)        10.5
                     April 19, 1995 by AmeriGas Propane, L.P.        Partners, L.P.
                     for the benefit of Bank of America National
                     Trust and Savings Association, as
                     Collateral Agent
- ---------------------------------------------------------------------------------------------------------------------------------
       10.27         Trademark License Agreement dated April 19,        AmeriGas       Form 10-Q (3/31/95)        10.6
                     1995 among UGI Corporation, AmeriGas, Inc.,     Partners, L.P.
                     AmeriGas Propane, Inc., AmeriGas Partners,
                     L.P. and AmeriGas Propane, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.28         Trademark License Agreement, dated April           AmeriGas       Form 10-Q (3/31/95)        10.7
                     19, 1995 among AmeriGas Propane, Inc.,          Partners, L.P.
                     AmeriGas Partners, L.P. and AmeriGas
                     Propane, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.29         Agreement dated as of May 1, 1996 between          AmeriGas       Form 10-K (9/30/97)        10.2
                     TE Products Pipeline Company, L.P. and          Partners, L.P.
                     AmeriGas Propane, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
       10.30         Pledge Agreement dated September 1999                UGI          Form 10-K (9/30/99)       10.28
                     between Eastfield International Holdings,
                     Inc. and Reiffeisen Zentralbank Osterreich
                     Aktiengesellschaft ("RZB")
- ---------------------------------------------------------------------------------------------------------------------------------
       10.31         Pledge Agreement dated September 1999                UGI          Form 10-K (9/30/99)       10.29
                     between EuroGas Holdings, Inc. and RZB
- ---------------------------------------------------------------------------------------------------------------------------------

                                      -32-
   35

- ---------------------------------------------------------------------------------------------------------------------------------
                                                INCORPORATION BY REFERENCE
- ---------------------------------------------------------------------------------------------------------------------------------
    EXHIBIT NO.                        EXHIBIT                         REGISTRANT             FILING            EXHIBIT
- ---------------------------------------------------------------------------------------------------------------------------------
                                                                                                    
       10.32         Form of Guarantee Agreement dated September          UGI           Form 10-K (9/30/99)       10.30
                     1999 between UGI Corporation and RZB
                     relating to loan amount of EURO 74 million
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.33         Form of Guarantee Agreement dated September
                     2000 between UGI Corporation and RZB relating
                     to loan amount of EURO 14.9 million
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.34         Form of Guarantee Agreement dated September
                     2000 between UGI Corporation and RZB relating
                     to loan amount of EURO 9 million
- ---------------------------------------------------------------------------------------------------------------------------------
      10.35**        Description of Change of Control                     UGI           Form 10-K (9/30/99)       10.33
                     arrangements for Messrs. Greenberg, Bovaird
                     and Mendicino
- ---------------------------------------------------------------------------------------------------------------------------------
      10.36**        Description of Change of Control                     UGI           Form 10-K (9/30/99)       10.34
                     arrangement for Mr. Chaney
- ---------------------------------------------------------------------------------------------------------------------------------
      10.37**        Description of Change of Control                   AmeriGas        Form 10-K (9/30/99)       10.31
                     arrangement for Mr. Bissell                      Partners, L.P.
- ---------------------------------------------------------------------------------------------------------------------------------
     *10.38**        Consulting Services Agreement dated as of
                     August 1, 2000 between Stephen D. Ban and
                     UGI Corporation
- ---------------------------------------------------------------------------------------------------------------------------------
     *10.39**        1992 Non-Qualified Stock Option Plan, as
                     amended
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.40         Service Agreement for comprehensive
                     delivery service (Rate CDS) dated February
                     23, 1998 between UGI Utilities, Inc. and
                     Texas Eastern Transmission Corporation
- ---------------------------------------------------------------------------------------------------------------------------------
      *10.41         Service Agreement for comprehensive
                     delivery service (Rate CDS) dated February
                     23, 1999 between UGI Utilities, Inc. and
                     Texas Eastern Transmission Corporation
- ---------------------------------------------------------------------------------------------------------------------------------
        *13          Pages 13 through 47 of 2000 Annual Report
                     to Shareholders
- ---------------------------------------------------------------------------------------------------------------------------------
        *21          Subsidiaries of the Registrant
- ---------------------------------------------------------------------------------------------------------------------------------
        *23          Consent of Arthur Andersen LLP
- ---------------------------------------------------------------------------------------------------------------------------------
        *27          Financial Data Schedule
- ---------------------------------------------------------------------------------------------------------------------------------

        *      Filed herewith.
        **     As required by Item 14(a)(3), this exhibit is identified as a
        compensatory plan or arrangement.

        (b)    Reports on Form 8-K:
               The Company filed no Current Reports on Form 8-K during the last
        quarter of fiscal year 2000.

                                      -33-
   36

                                   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 CORPORATION

Date:  December 19, 2000                By:   Anthony J. Mendicino
                                              -------------------------------
                                              Anthony J. Mendicino
                                              Vice President - Finance
                                              and Chief Financial Officer

         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.

SIGNATURE                                   TITLE
- ---------                                   -----

Lon R. Greenberg                            Chairman, President
- -----------------------------               and Chief Executive Officer
Lon R. Greenberg                            (Principal Executive Officer)
                                            and Director

Anthony J. Mendicino                        Vice President - Finance
- -----------------------------               and Chief Financial Officer
Anthony J. Mendicino                        (Principal Financial Officer
                                            and Principal Accounting Officer)

Stephen D. Ban                              Director
- -----------------------------
Stephen D. Ban

Thomas F. Donovan                           Director
- -----------------------------
Thomas F. Donovan

                                      -34-
   37

         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.

SIGNATURE                                   TITLE
- ---------                                   -----

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

                                      -35-

   38
                        UGI CORPORATION AND SUBSIDIARIES

                              FINANCIAL INFORMATION

                   FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

                          YEAR ENDED SEPTEMBER 30, 2000

                                      F-1
   39
                        UGI CORPORATION AND SUBSIDIARIES

         INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The consolidated financial statements and supplementary data of UGI Corporation
and subsidiaries, together with the report thereon of Arthur Andersen LLP dated
November 10, 2000, listed in the following index, are included in UGI's 2000
Annual Report to Shareholders and are incorporated in this Form 10-K Annual
Report by reference. With the exception of the pages listed in this index and
information incorporated in Items 1, 2, 5, 7 and 8, the 2000 Annual Report to
Shareholders is not to be deemed filed as part of this Report.

                                                               Reference
                                                       -------------------------
                                                                       Annual
                                                                      Report to
                                                       Form 10-K    Shareholders
                                                         (page)        (page)
                                                       ---------    ------------
                                                              
Reports of Independent Public Accountants:

     On Consolidated Financial Statements                                24

     On Financial Statement Schedules                     F-4

Financial Statements:

     Consolidated Balance Sheets, September 30,
          2000 and 1999                                               26 and 27

     For the years ended September 30, 2000,
          1999 and 1998:

          Consolidated Statements of Income                              25

          Consolidated Statements of Cash Flows                          28

          Consolidated Statements of Stockholders'
               Equity                                                    29

Index                                 F-2
   40
                        UGI CORPORATION AND SUBSIDIARIES

  INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES (CONTINUED)

                                                               Reference
                                                       -------------------------
                                                                       Annual
                                                                      Report to
                                                       Form 10-K    Shareholders
                                                         (page)        (page)
                                                       ---------    ------------
                                                              
     Notes to Consolidated Financial Statements                       30 to 47

Supplementary Data (unaudited):

     Quarterly Data for the years ended
          September 30, 2000 and 1999                                    46

Financial Statement Schedules:

     For the years ended September 30, 2000,
          1999 and 1998:

          I    -    Condensed Financial
                      Information of Registrant
                      (Parent Company)                 S-1 to S-3

          II   -    Valuation and Qualifying
                      Accounts                         S-4 to S-5

Annual Reports on Form 10-K/A

     Annual Reports on Form 10-K/A for the UGI Utilities, Inc. and AmeriGas
     Propane, Inc. savings plans will be filed by amendment within the time
     period specified by Rule 15d-21(b).

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) the information required is included
elsewhere in the financial statements or related notes.

                                      F-3

   41
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of UGI Corporation:

We have audited, in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements included in UGI
Corporation's annual report to shareholders for the year ended September 30,
2000, incorporated by reference in this Form 10-K, and have issued our report
thereon dated November 10, 2000. Our audits were made for the purpose of forming
an opinion on those consolidated financial statements taken as a whole. The
schedules listed in the Index on pages F-2 and F-3 are the responsibility of UGI
Corporation's management and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state in all material respects the financial data required to be
set forth therein in relation to the basic financial statements taken as a
whole.

ARTHUR ANDERSEN LLP

Philadelphia, Pennsylvania
November 10, 2000

                                      F-4
   42
                        UGI CORPORATION AND SUBSIDIARIES
   SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

                                 BALANCE SHEETS
                              (Millions of dollars)

                                                                                                  September 30,
                                                                                            2000                 1999
                                                                                       --------------       --------------
                                                                                                      
ASSETS
- ------
Current assets:
     Cash and cash equivalents                                                         $         1.1        $         0.4
     Accounts receivable                                                                         0.1                  0.1
     Deferred income taxes                                                                       0.2                  0.2
     Prepaid expenses and other current assets                                                   0.3                  0.3
                                                                                       --------------       --------------
        Total current assets                                                                     1.7                  1.0

Investments in subsidiaries                                                                    315.9                271.3

Other assets                                                                                     2.4                  2.2
                                                                                       --------------       --------------

        Total assets                                                                   $       320.0        $       274.5
                                                                                       ==============       ==============

LIABILITIES  AND  COMMON  STOCKHOLDERS'  EQUITY

Current liabilities:
     Accounts and notes payable                                                        $         9.6        $        11.1
     Accrued liabilities                                                                        12.4                 10.7
                                                                                       --------------       --------------
        Total current liabilities                                                               22.0                 21.8

Noncurrent liabilities                                                                          50.3                  3.5

Commitments and contingencies

Common stockholders' equity:
     Common Stock, without par value (authorized - 100,000,000 shares;
        issued - 33,198,731 shares)                                                            394.5                394.8
     Accumulated deficit                                                                        (4.9)                (8.2)
     Accumulated other comprehensive income                                                        -                  0.5
     Unearned compensation - restricted stock                                                   (0.7)                (1.7)
                                                                                       --------------       --------------
                                                                                               388.9                385.4
        Less treasury stock, at cost                                                          (141.2)              (136.2)
                                                                                       --------------       --------------
          Total common stockholders' equity                                                    247.7                249.2
                                                                                       --------------       --------------

          Total liabilities and common stockholders' equity                            $       320.0        $       274.5
                                                                                       ==============       ==============

Commitments and Contingencies

         In addition to the guarantees of FLAGA debt described in Note 3 to
Consolidated Financial Statements, UGI Corporation is authorized to guarantee up
to $30 million of supplier and customer obligations of its wholly owned
second-tier subsidiary UGI Energy Services, Inc., and $5 million of lease
obligations of its wholly owned second-tier subsidiary Hearth USA, Inc.

                                      S-1

   43
                        UGI CORPORATION AND SUBSIDIARIES
   SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

                              STATEMENTS OF INCOME
                 (Millions of dollars, except per share amounts)

                                                                                            Year Ended
                                                                                           September 30,
                                                                        ----------------------------------------------------
                                                                           2000                 1999                 1998
                                                                        ----------           ----------           ----------
                                                                                                         
      Revenues                                                          $       -            $       -            $       -

      Costs and expenses:
          Operating and administrative expenses                               8.1                 10.4                 10.7
          Other income, net                                                  (8.4)               (10.5)               (10.4)
                                                                        ----------           ----------           ----------
                                                                             (0.3)                (0.1)                 0.3
                                                                        ----------           ----------           ----------

      Operating income (loss)                                                 0.3                  0.1                 (0.3)
      Interest expense on intercompany debt                                  (2.0)                   -                    -
                                                                        ----------           ----------           ----------

      Income (loss) before income taxes                                      (1.7)                 0.1                 (0.3)
      Income tax expense (benefit)                                           (1.1)                 0.3                 (0.1)
                                                                        ----------           ----------           ----------

      Loss before equity in income
          of unconsolidated subsidiaries                                     (0.6)                (0.2)                (0.2)
      Equity in income
          of unconsolidated subsidiaries                                     45.3                 55.9                 40.5
                                                                        ----------           ----------           ----------

      Net income                                                        $    44.7            $    55.7            $    40.3
                                                                        ==========           ==========           ==========

      Earnings per common share:
          Basic                                                         $    1.64            $    1.74            $    1.22
                                                                        ==========           ==========           ==========
          Diluted                                                       $    1.64            $    1.74            $   1.22
                                                                        ==========           ==========           ==========

      Average common shares outstanding (millions):
          Basic                                                            27.219               31.954               32.971
                                                                        ==========           ==========           ==========
          Diluted                                                          27.255               32.016               33.123
                                                                        ==========           ==========           ==========

                                       S-2
   44
                        UGI CORPORATION AND SUBSIDIARIES
   SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

                            STATEMENTS OF CASH FLOWS
                              (Millions of dollars)

                                                                                            Year Ended
                                                                                           September 30,
                                                                        ----------------------------------------------------
                                                                           2000                 1999                 1998
                                                                        ----------           ----------           ----------
                                                                                                         
NET CASH PROVIDED BY OPERATING
     ACTIVITIES (a)                                                     $     95.5           $   178.0            $    77.8

CASH  FLOWS  FROM  INVESTING  ACTIVITIES:
     Investments in unconsolidated subsidiaries                              (95.8)              (16.5)               (34.8)
     Other                                                                       -                   -                  2.5
                                                                        -----------          ----------           ----------
        Net cash used by investing activities                                (95.8)              (16.5)               (32.3)

CASH  FLOWS  FROM  FINANCING  ACTIVITIES:
     Payment of dividends on Common Stock                                    (41.2)              (47.9)               (47.6)
     Issuance of intercompany long-term debt                                  47.5                   -                    -
     Issuance of Common Stock                                                  3.8                 4.7                  8.5
     Repurchases of Common Stock                                              (9.1)             (133.1)               (11.3)
                                                                        -----------          ----------           ----------
        Net cash used by financing activities                                  1.0              (176.3)               (50.4)
                                                                        -----------          ----------           ----------

Cash and cash equivalents increase (decrease)                           $      0.7           $   (14.8)           $    (4.9)
                                                                        ===========          ==========           ==========

Cash and cash equivalents:
     End of period                                                      $      1.1           $     0.4            $    15.2
     Beginning of period                                                       0.4                15.2                 20.1
                                                                        -----------          ----------           ----------
         Increase (decrease)                                            $      0.7           $   (14.8)           $    (4.9)
                                                                        ===========          ==========           ==========

(a)  Includes dividends received from unconsolidated subsidiaries of $96.2,
     $176.7 and $77.6, respectively, for the years ended September 30, 2000,
     1999 and 1998.

                                       S-3
   45
                        UGI CORPORATION AND SUBSIDIARIES
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                              (Millions of dollars)

                                                                                 Charged
                                                             Balance at         (credited)                             Balance at
                                                             beginning         to costs and                              end of
                                                              of year            expenses             Other               year
                                                             ----------        ------------        -----------         ----------
                                                                                                           
YEAR ENDED SEPTEMBER 30, 2000
- -----------------------------
Reserves deducted from assets in
  the consolidated balance sheet:

      Allowance for doubtful accounts                        $      8.0          $   10.0          $     (8.9)(1)      $      9.3
                                                             ==========                                   0.2 (2)      ==========

      Allowance for amortization of deferred
         financing costs - AmeriGas Propane                  $      7.1          $    1.7          $        -          $      8.8
                                                             ==========                                                ==========

      Allowance for amortization of
        other deferred costs - AmeriGas Propane              $      2.1          $    0.4          $     (1.5)(2)      $      1.0
                                                             ==========                                                ==========

Other reserves:

      Self-insured property and casualty liability           $     38.7          $   14.1          $    (15.8)(3)      $     37.1
                                                             ==========                                   0.1 (2)      ==========

      Insured property and casualty liability                $      5.1          $   (3.0)                             $      2.1
                                                             ==========                                                ==========

      Environmental, litigation and other                    $     12.5                            $     (1.3)(3)      $     11.2
                                                             ==========                                                ==========

YEAR ENDED SEPTEMBER 30, 1999
- -----------------------------
Reserves deducted from assets in
  the consolidated balance sheet:

      Allowance for doubtful accounts                        $      7.9          $    7.8          $     (7.9)(1)      $      8.0
                                                             ==========                                   0.2 (2)      ==========

      Allowance for amortization of deferred
         financing costs - AmeriGas Propane                  $      5.4          $    1.7          $        -          $      7.1
                                                             ==========                                                ==========

      Allowance for amortization of
        other deferred costs - AmeriGas Propane              $      4.6          $    1.0          $     (3.5)(2)      $      2.1
                                                             ==========                                                ==========

Other reserves:

      Self-insured property and casualty liability           $     48.5          $   12.9          $    (22.9)(3)      $     38.7
                                                             ==========                                   0.2 (2)      ==========

      Insured property and casualty liability                $      4.3          $    0.8                              $      5.1
                                                             ==========                                                ==========

      Environmental, litigation and other                    $     13.9                            $     (1.5)(3)      $     12.5
                                                             ==========                            $      0.1 (2)      ==========

                                       S-4
   46
                        UGI CORPORATION AND SUBSIDIARIES
           SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (CONTINUED)
                              (Millions of dollars)

                                                                                 Charged
                                                             Balance at         (credited)                             Balance at
                                                             beginning         to costs and                              end of
                                                              of year            expenses             Other               year
                                                             ----------        ------------        -----------         ----------
                                                                                                           
YEAR ENDED SEPTEMBER 30, 1998
- -----------------------------
Reserves deducted from assets in
  the consolidated balance sheet:

      Allowance for doubtful accounts                        $     11.3          $    8.4          $    (11.8)(1)      $      7.9
                                                             ==========                                                ==========

      Allowance for amortization of deferred
         financing costs - AmeriGas Propane                  $      3.8          $    1.6          $        -          $      5.4
                                                             ==========                                                ==========

      Allowance for amortization of
        other deferred costs - AmeriGas Propane              $      3.9          $    0.7          $        -          $      4.6
                                                             ==========                                                ==========

Other reserves:

      Self-insured property and casualty liability           $     48.5          $   11.7          $    (11.7)(3)      $     48.5
                                                             ==========                                                ==========

      Insured property and casualty liability                $      1.8          $    2.9          $     (0.4)(3)      $      4.3
                                                             ==========                                                ==========

      Environmental, litigation and other                    $     22.6          $   (4.0)         $     (4.7)(3)      $     13.9
                                                             ==========                                                ==========

(1)   Uncollectible accounts written off, net of recoveries.
(2)   Other adjustments.
(3)   Payments, net.

                                       S-5
   47
                                  EXHIBIT INDEX

EXHIBIT NO.         DESCRIPTION
- -----------         -----------
                 
10.6                UGI Corporation Directors Deferred Compensation Plan Amended
                    and Restated as of January 1, 2000

10.9                UGI Corporation Directors Equity Compensation Plan Amended
                    and Restated as of January 1, 2000

10.33               Form of Guarantee Agreement dated September 2000 between UGI
                    Corporation and RZB relating to loan amount of EURO 14.9
                    million

10.34               Form of Guarantee Agreement dated September 2000 between UGI
                    Corporation and RZB relating to loan amount of EURO 9
                    million

10.38               Consulting Services Agreement dated as of August 1, 2000
                    between Stephen D. Ban and UGI Corporation

10.39               1992 Non-Qualified Stock Option Plan, as amended

10.40               Service Agreement dated February 23, 1998 between UGI
                    Utilities, Inc. and Texas Eastern Transmission Corporation

10.41               Service Agreement dated February 23, 1999 between UGI
                    Utilities, Inc. and Texas Eastern Transmission Corporation

13                  Pages 13 to 47 of the 2000 Annual Report

21                  Subsidiaries of the Registrant

23                  Consent of Arthur Andersen LLP

27                  Financial Data Schedule

   1
                                  EXHIBIT 10.6

                                UGI CORPORATION
                              AMENDED AND RESTATED
                     DIRECTORS' DEFERRED COMPENSATION PLAN

1.   Background and Purpose

     1.1  The Directors' Deferred Compensation Plan (the "Plan") was adopted
     effective as of June 20, 1984. The Plan was adopted and, until April 10,
     1992, maintained by UGI Utilities, Inc., which prior to April 10, 1992 was
     known as UGI Corporation ("UGI Utilities"). On April 10, 1992, UGI
     Utilities became a subsidiary of New UGI Corporation which was renamed, as
     of such date, UGI Corporation. As of April 10, 1992 UGI Corporation assumed
     sponsorship of the Plan and all obligations of UGI Utilities hereunder. In
     connection with the transfer of Plan sponsorship, pursuant to the authority
     granted under Section 6.4, the Plan was amended and restated in its
     entirety effective as of April 10, 1992. Pursuant to the authority granted
     under Section 6.4, the Plan is now amended and restated in its entirety
     effective as of January 1, 2000, to reflect certain changes approved by the
     Board of Directors on December 14, 1999.

     1.2  The Plan is intended to enable each Director of the Company to defer
     the payment of all or a specified portion of the compensation otherwise
     payable in cash for services rendered as a Director of the Company, until
     the cessation of the Director's services on the Board, the Director's
     attainment of a specified age, or the Director's death.

2.   Definitions

     For case of reference, the following definitions will be used in the Plan:

     2.1  "Affiliate" and "Associate" shall have the respective meanings
     ascribed to such terms in Rule 12b-2 of the General Rules and Regulations
     under the Exchange Act.

     2.2  "Beneficial Owner" means that a person shall be deemed the "Beneficial
     Owner" of any securities: (i) that such person or any of such person's
     Affiliates or Associates, directly or indirectly, has the right to acquire
     (whether such right is exercisable immediately or only after the passage of
     time) pursuant to any agreement, arrangement or understanding (whether or
     not in writing) or upon the exercise of conversion rights, exchange rights,
     rights, warrants, or options, or otherwise; provided, however, that a
     person shall not be deemed the "Beneficial Owner" of securities tendered
     pursuant to a tender or exchange offer made by such person or any of such
     person's Affiliates or Associates until such tendered securities are
     accepted for payment, purchase or exchange; (ii) that such person or any of
     such person's Affiliates or Associates, directly or indirectly, has the
     right to vote or dispose of or has "beneficial ownership" of (as determined
     pursuant to Rule 13d-3 of the General Rules and Regulations under the
     Exchange Act), including without limitation pursuant to any agreement,
     arrangement or understanding, whether or not in writing; provided, however,
     that a person shall not be deemed the "Beneficial Owner" of any security
     under this clause (ii) as a result of an oral or written agreement,
     arrangement or understanding to vote such security if such
   2
     agreement, arrangement or understanding (A) arises solely from a revocable
     proxy given in response to a public proxy or consent solicitation made
     pursuant to, and in accordance with, the applicable provisions of the
     General Rules and Regulations under the Exchange Act, and (B) is not then
     reportable by such person on Schedule 13D under the Exchange Act (or any
     comparable or successor report); or (iii) that are beneficially owned,
     directly or indirectly, by any other person (or any Affiliate or Associate
     thereof) with which such person (or any of such person's Affiliates or
     Associates) has any agreement, arrangement or understanding (whether or not
     in writing) for the purpose of acquiring, holding, voting (except pursuant
     to a revocable proxy as described in the proviso to clause (ii) above) or
     disposing of any voting securities of the Company; provided, however, that
     nothing in this section shall cause a person engaged in business as an
     underwriter of securities to be the "Beneficial Owner" of any securities
     acquired through such person's participation in good faith in a firm
     commitment underwriting until the expiration of forty days after the date
     of such acquisition.

     2.3  "Board of Directors", "Board", "Directors" or "Director" mean,
     respectively, the Board of Directors, the Directors or a Director of the
     Company.

     2.4  "Change of Control" of the Company means (i) any person (except the
     Director, his Affiliates and Associates, the Company, any subsidiary of the
     Company, any employee benefit plan of the Company or of any subsidiary of
     the Company, or any person or entity organized, appointed or established by
     the Company for or pursuant to the terms of any such employee benefit
     plan), together with all Affiliates and Associates of such person, becomes
     the Beneficial Owner in the aggregate of 20% or more of either (A) the then
     outstanding shares of Common Stock of the Company (the "Outstanding Company
     Common Stock") or (B) the combined voting power of the then outstanding
     voting securities of the Company entitled to vote generally in the election
     of directors (the "Company Voting Securities"); or (ii) individuals who, as
     of the beginning of any twenty-four month period, constitute the Board (the
     "Incumbent Board") cease for any reason to constitute at least a majority
     of the Board, provided that any individual becoming a director subsequent
     to the beginning of such period whose election or nomination for election
     by the Company's shareholders was approved by a vote of at least a majority
     of the directors then comprising the Incumbent Board shall be considered as
     though such individual were a member of the Incumbent Board, but excluding,
     for this purpose, any such individual whose initial assumption of office is
     in connection with an actual or threatened election contest relating to the
     election of the Directors of the Company (as such terms are used in Rule
     14a-11 of Regulation 14A promulgated under the Exchange Act); or (iii)
     consummation by the Company of a reorganization, merger or consolidation (a
     "Business Combination"), in each case, with respect to which all or
     substantially all of the individuals and entities who were the respective
     Beneficial Owners of the Outstanding Company Common Stock and Company
     Voting Securities immediately prior to such Business Combination do not,
     following such Business Combination, Beneficially Own, directly or
     indirectly, more than 50% of, respectively, the then outstanding shares of
     Common Stock and the combined voting power of the then outstanding voting
     securities entitled to vote generally in the election of directors, as the
     case may be, of the corporation resulting from such Business Combination in
     substantially the same proportion as their ownership immediately prior to
     such Business

                                      -2-
   3
Combination of the Outstanding Company Common Stock and Company Voting
Securities, as the case may be; or (iv) (A) Consummation of a complete
liquidation or dissolution of the Company or (B) sale or other disposition of
all or substantially all of the assets of the Company other than to a
corporation with respect to which, following such sale or disposition, more than
50% of, respectively, the then outstanding shares of Common Stock and the
combined voting power of the then outstanding voting securities entitled to vote
generally in the election of directors is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who were
the Beneficial Owners, respectively, of the Outstanding Company Common Stock and
Company Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding Company
Common Stock and Company Voting Securities, as the case may be, immediately
prior to such sale or disposition.

      2.5    The "Committee" means the Compensation and Management Development
      Committee of the Board of Directors as constituted from time to time.

      2.6    "Common Stock" means the common stock of the Company.

      2.7    The "Company" means, prior to April 10, 1992, UGI Utilities. From
      and after April 10, 1992, the term "Company" shall mean UGI Corporation, a
      Pennsylvania corporation (formerly named New UGI Corporation).

      2.8    "Deferred Compensation Account" or "Accounts" means the separate
      account established under the Plan for each Participant, as described in
      Section 4.1.

      2.9    "Exchange Act" means Securities Exchange Act of 1934, as amended.

      2.10   "Notice" means a written notice given to the Secretary, pursuant to
      Section 3.2 or a form substantially in the form of Exhibit A attached
      hereto.

      2.11   "Participant" means each Director of the Company who participates
      in the Plan.

      2.12   The "Plan" means the UGI Corporation Directors' Deferred
      Compensation Plan as set forth herein, or as it may be amended from time
      to time by the Committee or Board of Directors.

      2.13   The "Plan Year" means the calendar year.

      2.14   The "Secretary" means the Secretary of the Company who will have
      responsibility for those functions assigned to the Secretary under the
      Plan.

3.    Participation

      3.1    Each Director is eligible to participate in the Plan except a
      Director who is also an employee of the company or any of its subsidiaries
      or affiliates.

      3.2    The procedure to participate in the Plan is as follows:

                                      -3-
   4
      (a)    A Director, or a nominee for that office, may elect to participate
      in the Plan by giving a written Notice to the Secretary. The effective
      date for a Director's participation in the Plan will be either (i) the
      date of election to a first term as a Director; or (ii) the commencement
      of the earning period in any Plan Year, whichever first occurs following
      the giving of such Notice. Such election will remain in effect until (i)
      the termination of the Participant's services as a Director; or (ii) the
      Participant's further written Notice to the Secretary of the termination
      or the modification of such election.

      (b)    An election to terminate or modify a prior election to defer
      compensation will be effective at the start of the Plan Year and must be
      made by the Participant prior to the Plan Year to which such compensation
      pertains.

4.    Compensation Deferred

      4.1    A Participant may elect to defer the receipt of all or a specified
      portion of the compensation otherwise payable in cash for services
      rendered as a Director of the Company. Such compensation includes retainer
      fees for service on the Board and Board committees of the Company and fees
      for attendance at meetings of the Board and Board committees of the
      Company, but does not include travel expense allowances, other expense
      reimbursement, or non-cash compensation.

      4.2    An unfunded Deferred Compensation Account will be established for
      each Participant and the compensation that the Participant elects to defer
      under the Plan will be credited to that Account. Each such credit will be
      made to the Account as of the last day of the month during which such
      compensation would have otherwise been payable to the Participant in cash.

      4.3    Compensation deferred under the Plan is assumed to earn interest at
      a market rate determined by the Committee for each year during the period
      in which compensation is deferred. Each Participant will be notified of
      this rate annually. Notwithstanding the foregoing, the Committee may at
      any time or from time to time change or otherwise modify the basis or the
      method for calculating and crediting such interest, provided that the
      change or modification does not adversely affect the balance of any
      Participant's Account at the time of the change or modification.

      4.4    Each Participant will receive a statement of the balance in the
      Participant's Account at the end of each Plan Year as promptly as
      practicable thereafter.

5.    Payment of Deferred Compensation

      5.1    Upon the termination of a Participant's services as a Director, the
      balance in the Participant's Account will be paid in accordance with the
      method and at the time or times elected by the Participant by the Notice
      in effect at the time each portion of the Participant's compensation was
      deferred and credited to such Account.

      5.2    Notwithstanding Section 5.1, a Participant may elect, no later
      than the end of the Plan Year preceding the Plan Year in which the
      Participant's services as a Director terminates, periodic payments over a
      specified period of years or a lump sum

                                      -4-
   5
distribution, provided that (i) no payment may be made prior to January of the
calendar year following the calendar year during which the Participant's
services as a Director terminate, unless the payment is made pursuant to
Section 5.3, 5.4 or 5.5; (ii) a lump sum payment must be made or installment
payments must commence no later than January of the Plan Year following the
Participant's attainment of age 70 or January of the Plan Year following the
termination of the Participant's services as a Director, whichever is later;
and (iii) installment payments must be made at least annually and not more
frequently than quarterly for a period not to exceed 20 years.

5.3  Unless otherwise provided by the Committee, in the event of a Change of
Control of the Company, the Participant's Account will be paid in cash as soon
as practicable. A Participant may elect to defer receipt of such payment until
such Participant attains a specified age, not to exceed the age of the
Participant in January of the Plan Year following the Participant's attainment
of age 70. In addition, a Participant may elect to receive such payment in (i)
a single distribution or (ii) annual or quarterly installments over a period
not to exceed 20 years. Both such elections made hereunder must be made no
later than December 31st of the calendar year preceding the year of the Change
of Control.

5.4  Notwithstanding any other provisions of this Plan, if the Committee
determines, after consideration of a Participant's application, that the
Participant has a financial need of such a substantial nature that a
contemporaneous payment of compensation deferred under this Plan is warranted,
the Committee may, in its sole and absolute discretion, direct that all or a
portion of the balance of the Participant's Account be paid to the Participant.
The payment will be made in the manner and at the time specified by the
Committee. No Participant who is also a member of the Committee may in any way
take part in any decision pertaining to a request for payment made by that
Participant under this Section 5.4.

5.5  In the event of a Participant's death before the balance in the
Participant's Account is fully paid out:

(a)  Payment of such balance will be made to the beneficiary or beneficiaries
designated by the Participant or, if the Participant has made no such
designation or no beneficiary survives, to the Participant's estate. In either
case, such payment will be made in the same manner as provided with respect to
payments to the Participant; provided, that any lump sum payment must be made
and any installment payments must commence no later than January of the
calendar year following the Participant's death.

(b)  If the balance in such Account is to be paid to the estate of the
Participant in installments, the Committee may, in its sole and absolute
discretion and upon receipt of an application therefor from the duly appointed
Administrator or Executor of such estate, direct that the balance in the
Participant's Deferred Compensation Account be paid to the estate in a single
payment at such time as is specified by the Committee.

                                      -5-

   6
6.   General

     6.1  The right of any Participant, beneficiary or estate to receive
     payment of any unpaid balance in the Participant's Account will be an
     unsecured claim against the general assets of the Company.

     6.2  During a Participant's lifetime, any payment under the Plan will be
     made only to the Participant. No sum or other interest under the Plan
     shall be subject in any manner to anticipation, alienation, sale,
     transfer, assignment, pledge, encumbrance or charge, and any attempt by a
     Participant or any beneficiary under the Plan to do so shall be void. No
     interest under the Plan shall in any manner be liable for or subject to
     the debts, contracts, liabilities, engagements or torts of a Participant
     or beneficiary entitled thereto.

     6.3  Except as otherwise provided herein, the Plan will be administered
     by the Committee which will have the authority, subject to the express
     provisions of the Plan, to adopt, amend and rescind rules and regulations
     relating to the Plan, and to interpret, construe and implement the
     provisions of the Plan.

     6.4  The Plan may at any time or from time to time be amended, modified,
     or terminated by the Committee, provided that no amendment, modification
     or termination may (i) adversely affect the balance in a Participant's
     Account without the Participant's consent or (ii) permit payment of such
     balance prior to the date specified pursuant to Section 5.2 (except for
     payments provided for in Section 5.3, 5.4 or 5.5).

          IN WITNESS WHEREOF, and as evidence of its adoption of this Amended
and Restated Plan, the Company has caused the same to be executed by its duly
authorized officer and its corporate seal to be affixed hereto as of the 1st
day of January, 2000.

[Corporate Seal}                       UGI CORPORATION

                                       By:___________________________
                                       Title:

                                      -6-

   7
                                                                       Exhibit A

                     NOTICE TO DEFER UNDER UGI CORPORATION
                              AMENDED AND RESTATED
                     DIRECTORS' DEFERRED COMPENSATION PLAN

                              CALENDAR YEAR: 2001

     I hereby elect to defer, under the terms and conditions of the UGI
Corporation Directors' Deferred Compensation Plan (the "Plan"), the payment of
compensation (excluding travel expense allowances, other expense reimbursement,
or non-cash compensation) otherwise due to me on account of my future services
as a Director of UGI corporation as set forth below:

1.   AMOUNT OF DEFERRAL:

     ______ All     ______ %       $ ______

2.   METHOD OF PAYMENT: (CHOOSE ONE)

     ______ Lump Sum; or

     ______ Installments
               Payable:  ______ Quarterly    ______ Annually
               over      ______ Years (not more than 20)

3.   TIME OF PAYMENT (IF LUMP SUM), OR START OF PAYMENT (IF INSTALLMENTS):

     ______ January following the termination of my services as a Director, or

     ______ January following my attainment of age ______ (no later than 70),
            whichever is later.

4.   TIME OF PAYMENT UPON A CHANGE OF CONTROL OF COMPANY: IN THE EVENT OF A
     CHANGE CONTROL OF THE COMPANY, UNLESS OTHERWISE PROVIDED BY THE COMMITTEE,
     YOUR ACCOUNT WILL BE PAID IN CASH AS SOON AS PRACTICABLE. HOWEVER, YOU MAY
     ELECT TO DEFER RECEIPT OF PAYMENT AS FOLLOWS:

     ______ January following my attainment of age ______ (no later than 70).

     Method of Payment upon Change of Control: (Choose one)

     ______ Lump Sum; or

     ______ Installments
               Payable:  ______ Quarterly    ______ Annually
               over      ______ Years (not more than 20)

   8
5.   BENEFICIARY OR BENEFICIARIES TO WHOM PAYMENT IS TO BE MADE (AS ABOVE
     SPECIFIED) IN THE EVENT OF MY DEATH BEFORE RECEIVING PAYMENT OF THE ENTIRE
     BALANCE IN MY DEFERRED COMPENSATION ACCOUNT. IF MORE THAN ONE BENEFICIARY
     IS NAMED, PLEASE INDICATE THE PERCENTAGE TO BE PAID TO EACH.

                                                                     %
- ----------------------     -------------------------------     --------
         Name
                           -------------------------------
                                      Address

                                                                     %
- ----------------------     -------------------------------     --------
         Name
                           -------------------------------
                                      Address

     This election supersedes any prior election I have made under the Plan,
and is effective as to compensation otherwise due to me for my services as a
Director after (i) the date of my election to my first term in that office, or
(ii) the Commencement of the next Plan Year, whichever first occurs after the
date hereof. The beneficiary election is effective immediately.

     ----------------------------------     ----------------------------------
                    Date                                Signature

                                            ----------------------------------
                                                   Name [please print]

   1
                                  EXHIBIT 10.9

                                UGI CORPORATION
                              AMENDED AND RESTATED
                      DIRECTORS' EQUITY COMPENSATION PLAN

1. PURPOSE

     The purpose of the UGI Corporation Directors' Equity Compensation Plan is
to provide a means whereby  UGI Corporation (the "Company") may, through the
grant of common stock of the Company ("Common Stock") or deferred units
("Units") relating to such stock, offer a reward and an incentive to the members
of the board of directors of the Company, motivate such directors to exert their
best efforts on behalf of the Company and further to align the economic interest
of such individuals with those of the Company's shareholders. This Plan is
intended to constitute, in part, a non-qualified deferred compensation plan.
Pursuant to the authority granted under Section 8.06, the Plan is amended in its
entirety effective as of January 1, 2000, to reflect certain changes approved by
the Board of Directors on December 14, 1999.

2. DEFINITIONS

     Whenever used in this Plan, the following terms will have the respective
meanings set forth below:

          2.01 "Account" means the Company's record established pursuant to
Section 5 which reflects the number of Units and the amount of Dividend
Equivalents standing to the credit of a Participant under the Plan.

          2.02 "Affiliate" and "Associate" shall have the respective meanings
ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under
the Exchange Act.

          2.03 "Beneficial Owner" means that a person shall be deemed the
"Beneficial Owner" of any securities: (i) that such person or any of such
person's Affiliates or Associates, directly or indirectly, has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time) pursuant to any agreement, arrangement or understanding (whether or not
in writing) or upon the exercise of conversion rights, exchange rights, rights,
warrants or options, or otherwise; provided, however, that a person shall not be
deemed the "Beneficial Owner" of securities tendered pursuant to a tender or
exchange offer made by such person or any of such person's Affiliates or
Associates until such tendered securities are accepted for payment, purchase or
exchange; (ii) that such person or any of such person's Affiliates or
Associates, directly or indirectly, has the right to vote or dispose of or has
"beneficial ownership" of (as determined pursuant to Rule 13d-3 of the General
Rules and Regulations under the Exchange Act), including without limitation
pursuant to any agreement, arrangement or understanding, whether or not in
writing; provided, however, that a person shall not be deemed the "Beneficial
Owner" of any security under this clause (ii) as a result of an oral or written
agreement, arrangement or understanding to vote such security if such agreement,
arrangement or understanding (A) arises solely from a revocable proxy given in
response to a public proxy or consent solicitation made pursuant to, and in
accordance with, the applicable provisions of the
   2
General Rules and Regulations under the Exchange Act, and (B) is not then
reportable by such person on Schedule 13D under the Exchange Act (or any
comparable or successor report); or (iii) that are beneficially owned, directly
or indirectly, by any other person (or any Affiliate or Associate thereof) with
which such person (or any of such person's Affiliates or Associates) has any
agreement, arrangement or understanding (whether or not in writing) for the
purpose of acquiring, holding, voting (except pursuant to a revocable proxy as
described in the proviso to clause (ii) above) or disposing of any voting
securities of the Company; provided, however, that nothing in this section shall
cause a person engaged in business as an underwriter of securities to be the
"Beneficial Owner" of any securities acquired through such person's
participation in good faith in a firm commitment underwriting until the
expiration of forty days after the date of such acquisition.

          2.04 "Beneficiary" means the person(s) designated by a Participant to
receive any benefits payable under this Plan subsequent to the Participant's
death. The Committee shall provide a form for this purpose. In the event a
Participant has not filed a Beneficiary designation with the Company, the
Beneficiary shall be the Participant's estate.

          2.05 "Board" means the Board of Directors of the Company.

          2.06 "Change of Control" of the Company means (i) any person (except
the Director, his Affiliates and Associates, the Company, any subsidiary of the
Company, any employee benefit plan of the Company or of any subsidiary of the
Company, or any person or entity organized, appointed or established by the
Company for or pursuant to the terms of any such employee benefit plan),
together with all Affiliates and Associates of such person, becomes the
Beneficial Owner in the aggregate of 20% or more of either (A) the then
outstanding shares of common stock of the Company (the "Outstanding Company
Common Stock") or (B) the combined voting power of the then outstanding voting
securities of the Company entitled to vote generally in the election of
directors (the "Company Voting Securities"); or (ii) individuals who, as of the
beginning of any twenty-four month period, constitute the Board (the "Incumbent
Board") cease for any reason to constitute at least a majority of the Board,
provided that any individual becoming a director subsequent to the beginning of
such period whose election or nomination for election by the Company's
shareholders was approved by a vote of at least a majority of the directors then
comprising the Incumbent Board shall be considered as though such individual
were a member of the Incumbent Board, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual or
threatened election contest relating to the election of the Directors of the
Company (as such terms are used in Rule 14a-11 of Regulation 14A promulgated
under the Exchange Act); or (iii) consummation by the Company of a
reorganization, merger or consolidation (a "Business Combination"), in each
case, with respect to which all or substantially all of the individuals and
entities who were the respective Beneficial Owners of the Outstanding Company
Common Stock and Company Voting Securities immediately prior to such Business
Combination do not, following such Business Combination, Beneficially Own,
directly or indirectly, more than 50% of, respectively, the then outstanding
shares of common stock and the combined voting power of the then outstanding
voting securities entitled to vote generally in the election of directors, as
the case may be, of the corporation resulting from such Business Combination in
substantially the same proportion as their ownership immediately prior to such
Business Combination of the

                                       2
   3
Outstanding Company Common Stock and Company Voting Securities, as the case may
be; or (iv)(A) Consummation of a complete liquidation or dissolution of the
Company or (B) sale or other disposition of all or substantially all of the
assets of the Company other than to a corporation with respect to which,
following such sale or disposition, more than 50% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors is then owned beneficially, directly or indirectly, by all or
substantially all of the individuals and entities who were the Beneficial
Owners, respectively, of the Outstanding Company Common Stock and Company
Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding Company
Common Stock and Company Voting Securities, as the case may be, immediately
prior to such sale or disposition.

          2.07 "Committee" means the Compensation and Management Development
Committee of the Board and any successor thereto.

          2.08 "Common Stock" means the common stock of the Company.

          2.09 "Company" means UGI Corporation and any successor thereto.

          2.10 "Director" means a member of the Board who is not an employee of
the Company or any of its Affiliates.

          2.11 "Dividend Equivalent" means an amount determined by multiplying
the number of Units credited to a Participant's Account by the per share cash
dividend, or the per share fair market value (as determined by the Committee) of
any dividend in consideration other than cash, paid by the Company on its stock
on a dividend payment date.

          2.12 "Effective Date" means January 1, 1997.

          2.13 "Exchange Act" means Securities Exchange Act of 1934, as amended.

          2.14 "Fair Market Value" of Common Stock means the average, rounded
to the next highest one-eighth of a point (.125), of the highest and lowest
sales prices thereof on the New York Stock Exchange on the day on which Fair
Market Value is being determined, as reported on the Composite Tape for
transactions on the New York Stock Exchange. In the event that there are no
Common Stock transactions on the New York Stock Exchange on such day, the Fair
Market Value will be determined as of the immediately preceding day on which
there were Common Stock transactions on that exchange.

          2.15 "Participant" means any Director who is eligible to participate
in the Plan under Section 4. In the event of the death or incompetency of a
Participant, the term shall mean his personal representative or guardian. An
individual shall remain a Participant until that individual has received full
distribution of any amount credited to the Participant's Account.

          2.16 "Plan" means the UGI Corporation Directors' Equity Compensation
Plan as the same is set forth herein, and as it may be amended from time to
time.

                                       3
   4
          2.17 "Plan Year" means the calendar year.

          2.18 "Separates from Service" means the Director's termination of
service as a member of the Board for any reason other than death. Except as
otherwise provided herein, a Separation from Service shall be deemed to have
occurred on the last day of the month during which the Director's service to
the Company ceases and shall be determined without reference to any
compensation continuation arrangement that may be applicable.

          2.19 "Unit" means a single unit granted to a Participant which
represents a phantom interest equivalent to one share of Common Stock.

          2.20 "Unit Value" means, at any time, unless otherwise specified in
the Plan, the value of each Unit issued under the Plan, which value shall be
equal to the Fair Market Value of the Common Stock on such date.

3.   ADMINISTRATION

     The Plan shall be administered by the Committee which shall have full
power and authority to interpret the Plan, to prescribe, amend and rescind any
rules, forms and procedures as it deems necessary or appropriate for the proper
administration of the Plan and to make any other determinations, including
factual determinations, and take such other actions as it deems necessary or
advisable in carrying out its duties under the Plan. All decisions and
determinations by the Committee shall be final and binding on the Company,
Participants, Directors, Beneficiaries and any other persons having or claiming
an interest hereunder. Any other provisions of the Plan notwithstanding, the
Board may perform any function of the Committee under the Plan, including
without limitation for the purpose of ensuring that transactions under the
Plan  by Participants who are subject to Section 16 of the Exchange Act in
respect of the Company are exempt under Rule 16b-3. In any case in which the
Board is performing a function of the Committee under the Plan, each reference
to the Committee herein shall be deemed to refer to the Board (unless the
context shall otherwise require).

4.   PARTICIPATION

     Each Director of the Company shall become a Participant of the Plan on the
later of (i) the Effective Date or (ii) the date such individual first becomes
a Director.

5.   AWARD OF UNITS

          5.01 Initial Award of Units.  On the Effective Date, each Director
who is a Participant on January 1, 1997 shall be awarded the number of Units
equal to the present value of benefits accrued by that Director through
December 31, 1996 under the UGI Corporation Retirement Plan for Outside
Directors, as determined by an actuary appointed by the Committee. The value of
each Unit to be credited to a Participant's Account pursuant to this section
shall be equal to the average of the closing sales prices for the Common Stock
as reported on the New

                                       4
   5
York Stock Exchange Composite Tape for each trading day in the period October 1,
1996 through December 31, 1996.

     5.02 Annual Award of Units. On the first day of each Plan Year, each
Participant shall receive an award of 630 Units. Such awarded Units shall be
credited to each Participant's Account as specified in Section 5.04 below. Any
Participant who was not a Participant on the first day of the Plan Year shall
receive, on the date such individual becomes a Participant, a pro-rata share of
the annual award of Units determined based on the number of calendar quarters
during the Plan Year that such Participant is expected to serve as a Director. A
Director will be deemed to serve the entire quarter during which he is a
Director at least one day.

     5.03 Dividend Equivalents

          (a) Dividend Equivalent to be Credited. From the date of grant of each
Unit to a Participant until the Participant's Account has been fully
distributed, the Company shall credit to each Participant's Account on each
record date for the payment of a dividend by the Company on its Common Stock, an
amount equal to the Dividend Equivalent associated with the Units in the
Account.

          (b) Conversion to Units. On the last day of each Plan Year, the amount
of the Dividend Equivalents credited to the Participant's Account during that
Plan Year shall be converted to a number of Units, based on the Unit Value on
that day. Notwithstanding the foregoing, in the event of a Change of Control or
in the event the Participant dies or Separates from Service prior to the last
day of the Plan Year, as soon as practicable following such event and in no
event later that the date on which Units are redeemed in accordance with Section
6, the Company shall convert the amount of the Dividend Equivalents credited to
the Participant's Account as of the date of the Change of Control, death or
Separation from Service (the "Conversion Date") to the number of Units based on
the Unit Value on the Conversion Date.

     5.04 Accounts. The Company shall keep records to reflect the number of
Units and Dividend Equivalents credited to each Participant hereunder; provided,
however, that no Participant or any other person shall under any circumstances
acquire any property interest in any specific assets of the Company. Fractional
Units shall accumulate in the Participant's Account and shall be added to
fractional Units held in such Account to create whole Units. Nothing contained
in this Plan and no action taken pursuant hereto shall create or be construed to
create a fiduciary relationship between the Company and any Participant or any
other person. To the extent that any person acquires a right to receive payment
from the Company hereunder, such right shall be no greater than the right of any
unsecured general creditor of the Company.

6. EVENTS REQUIRING REDEMPTION OF UNITS

     The Company shall redeem Units credited to a Participant's Account only at
the times and in the manner prescribed by the further terms of this Section 6.
To determine the total amount to be paid, all redemptions shall be made by
providing a number of shares of Common Stock equal to the number of Units being
redeemed; provided, however, that any fractional Units credited to

                                       5

   6
a Participant's Account shall be paid in cash in an amount equal to the Unit
Value of such fractional Unit.

     6.01 Death. In the event a Participant dies, the Company shall redeem all
of the Units then credited to the Participant's Account. Any such redemption
shall be paid to the Participant's Beneficiary in the form of Common Stock.

     6.02 Separation from Service. In the event a Participant Separates from
Service, the Company shall redeem all of the Units then credited to the
Participant's Account as soon as practicable following such Separation from
Service. Any such redemption shall be paid in the form of Common Stock. A
Participant may elect to defer receipt of such payment until such Participant
attains a specific age, not to exceed the age of the Participant in January of
the Plan Year following the Participant's attainment of age seventy (70). In
addition, a Participant may elect to receive such payment in (i) a single
distribution or (ii) annual or quarterly installments over a period not to
exceed twenty (20) years. Both such elections made hereunder must be made no
later than December 31st of the Plan Year preceding the Plan Year of Separation
from Service. Dividend Equivalents will be credited to such Participant's
Account in accordance with Section 5 until the full amount of the Participant's
Account has been distributed. Each installment payment shall be calculated by
dividing the Participant's total Account balance as of such payment date by the
number of payments remaining in the installment period.

     6.03 Change of Control. Unless otherwise provided by the Committee, in the
event of a Change of Control of the Company, the Company shall redeem all of the
Units then credited to the Participant's Account. Any such redemption shall be
made in the form of cash. The amount paid shall equal the product of the number
of Units being redeemed multiplied by the then Unit Value. A Participant may
elect to defer receipt of such payment until such Participant attains a
specified age, not to exceed the age of the Participant in January of the Plan
Year following the Participant's attainment of age seventy (70). In addition, a
Participant may elect to receive such payment in (i) a single distribution or
(ii) annual or quarterly installments over a period not to exceed twenty (20)
years. Both such elections made hereunder must be made no later than December
31st of the calendar year preceding the year of the Change of Control.

7. RETAINER AWARDS

     7.01 Annual Grants. The Committee is authorized, subject to limitations
under applicable law, to grant to any Participant awards of Common Stock in lieu
of a portion of their annual retainer. Unless otherwise determined by the
Committee, the number of shares of Common Stock to be paid to Directors annually
under this Section 7.01 will be equal to (i) the amount by which the annual
retainer at the rates then in effect exceeds $18,500 divided by (ii) the Fair
Market Value of the Common Stock as of the first day of the Plan Year. The
shares of Common Stock to be paid pursuant to this section will become due on
the date of the first meeting of the Board of Directors during the Plan Year. No
fractional shares of Common Stock will be granted; instead, the amount remaining
will be paid to the Participant in cash. As promptly as practicable, the Company
will issue to the Participant shares of Common Stock registered in the name of
the Participant (or, if directed by the Participant, in joint names of the
Participant and his or her spouse). Any Participant who commences service during
the Plan Year

                                       6

   7
shall receive a pro-rata share of the annual retainer, the same proportion of
which will be paid in Common Stock as was paid to a Director serving a full Plan
Year, determined based on the number of calendar quarters during the Plan Year
that the Participant is expected to serve as a Director.

     7.02  Deferral of Retainers and Meeting Attendance Fees.   A Participant
may elect, no later than the end of the calendar year preceding the calendar
year of payment to convert all or any part of (i) the cash portion of the annual
retainer, (ii) Committee Chair annual retainer, and (iii) meeting attendance
fees, into Units under this Plan, payable in accordance with the terms of the
Plan. Dividend Equivalents will be credited and Units will be awarded to such
Participant's Account in accordance with the provisions of Section 5.03 during
such deferral period.

8.   MISCELLANEOUS

     8.01  Transferability.   No Unit awarded under this Plan shall be
transferred, assigned, pledged or encumbered by the Participant, and a Unit may
be redeemed during the lifetime of a Participant only from such Participant.

     8.02  No Rights as Shareholder.   No Participant shall have any rights as a
shareholder of the Company, including the right to any cash dividends, or the
right to vote, as a result of the grant to the Participant, or the Participant's
holding of, any Units.

     8.03  Adjustment Upon Acquisitions, Dispositions or other Events not in the
Ordinary Course of Business.   Notwithstanding anything herein to the contrary,
if the Company's financial performance is affected by any event that is of a
non-recurring nature including an acquisition or disposition of the assets or
stock of a business, the Committee, in its sole discretion, may make such
adjustments in the number of Units or the Unit Value of each Unit for the then
current Plan Year as it shall determine to be equitable and appropriate in order
to make the value of each Unit, as nearly as may be practicable, equivalent to
the value of the Unit immediately prior to such event.

     8.04  No Rights to Service.   Nothing in this Plan, and no action taken
pursuant hereto, shall affect the Participant's term of service as a Director.

     8.05  Notices.   Any notice hereunder to be given to the Company shall be
in writing and shall be delivered in person to the Secretary of the Company, or
shall be sent by registered mail, return receipt requested, to the Secretary of
the Company at the Company's executive offices, and any notice hereunder to be
given to the Participant shall be in writing and shall be delivered in person to
the Participant, or shall be sent by registered mail, return receipt requested,
to the Participant at his last address as shown in the employment records of the
Company. Any notice duly mailed in accordance with the preceding sentence shall
be deemed given on the date postmarked.

     8.06  Termination and Amendment of the Plan/Modification of Units.   The
Plan may be terminated, modified or amended by the Committee at any time, except
with respect to any Units then outstanding under the Plan; provided, however,
that the Committee may accelerate the

                                       7
   8
redemption of any Units then outstanding as if a redemption were then being made
under Section 6.

     8.07  Miscellaneous.

          (a)  If the Company shall find that any person to whom any payment is
payable under this Plan is unable to care for his affairs because of illness or
accident, or is a minor, any payment due (unless a prior claim therefor shall
have been made by a duly appointed guardian, committee or other legal
representative) may be paid to the spouse, a child, a parent, or a brother or
sister, or to any person deemed by the Company to have incurred expense for such
person otherwise entitled to payment, in such manner and proportions as the
Company may determine. Any such payment shall be a complete discharge of the
liabilities of the Company under this Plan.

          (b)  This Plan shall be binding upon and inure to the benefit of the
Company, its successors and assigns and the Participant and his heirs,
executors, administrators and legal representatives.

          (c)  This Plan shall be construed in accordance with, and governed by,
the law of the Commonwealth of Pennsylvania.

     8.08  Shareholder Approval.   This Plan shall be effective on the Effective
Date, subject to the approval by a majority of the shareholders of the Company
at the next annual meeting following the Effective Date.

     IN WITNESS WHEREOF, and as evidence of its adoption of this Amended and
Restated Plan, the Company has caused the same to be executed by its duly
authorized officer and its corporate seal to be affixed hereto as of the 1st day
of January, 2000.

                                             UGI CORPORATION

[Corporate Seal]

                                        By:
                                             -------------------------------
                                             Title

                                       8
   9
                                                                       Exhibit A

                          NOTICE UNDER UGI CORPORATION
                              AMENDED AND RESTATED
                      DIRECTORS' EQUITY COMPENSATION PLAN

                              CALENDAR YEAR:  2001

I.   ELECTION TO DEFER DISTRIBUTION OF COMMON STOCK UNDERLYING UNITS BEYOND
SEPARATION FROM SERVICE: The Plan automatically defers receipt of the Units
credited to your account until your Separation from Service. Please complete
Section III below to make your initial election or to change any prior
elections with respect to method and timing of payment of such Units as well
as the designation of your beneficiary.

II.  ELECTION TO DEFER CASH COMPENSATION INTO UNITS UNDER THE AMENDED AND
RESTATED DIRECTORS' EQUITY PLAN: The Plan allows you to elect to defer receipt
of cash compensation (including annual cash retainer, Board meeting fees,
Committee meeting fees and Committee Chair fees, but excluding expense
reimbursements and non-cash compensation) and to convert such cash deferrals
into Units. Those Units will be included in your total account of Units under
the Plan and paid in accordance with your elections in Section III below.

     I hereby elect to defer receipt of cash compensation payable in calendar
year 2001 into Units in my account under the Plan in the following manner:

     AMOUNT OF CASH COMPENSATION TO BE DEFERRED IN THE FORM OF UNITS:

                 _________ All     __________%     $_________

                        *     *     *     *     *     *

III.

     1.   METHOD OF PAYMENT OF ALL SHARES OF COMMON STOCK UNDERLYING DEFERRED
          UNITS: (CHOOSE ONE)

    _____ Lump Sum; or

    _____ Installments
               Payable:     _____ Quarterly                _____ Annually
               over:        _____ Years (not more than 20)

     2.   TIME OF RECEIPT OF SHARES OF COMMON STOCK UNDERLYING ALL DEFERRED
          UNITS (IF LUMP SUM), OR START OF PAYMENT (IF INSTALLMENTS):

     _____ January following the termination of my services as a Director, or

     _____ January following my attainment of age _____ (no later than 70),
           whichever is later.
   10
     3.   TIME OF PAYMENT UPON A CHANGE OF CONTROL OF COMPANY: IN THE EVENT OF A
          CHANGE CONTROL OF THE COMPANY, UNLESS OTHERWISE PROVIDED BY THE
          COMMITTEE, ALL DEFERRED UNITS IN YOUR ACCOUNT WILL BE PAID IN CASH AS
          SOON AS PRACTICABLE. HOWEVER, YOU MAY ELECT TO DEFER RECEIPT OF
          PAYMENT AS FOLLOWS:

     ____ January following my attainment of age _____ (no later than 70).

     METHOD OF PAYMENT UPON A CHANGE OF CONTROL: (CHOOSE ONE)

     ____ Lump Sum, or

     ____ Installments
             Payable:     _____ Quarterly     _____ Annually
             over         _____ Years (not more than 20)

     4.   DESIGNATION OF BENEFICIARY: Beneficiary or Beneficiaries to whom
          Payment is to be made (as above specified) in the event of my death
          before receiving payment of the entire balance in my Account. If more
          than one beneficiary is named, please indicate the percentage to be
          paid to each.

_______________________________     ______________________________     ________%
            Name                    _______________________________    ________%
                                               Address

_______________________________     ______________________________     ________%
            Name                    _______________________________    ________%
                                               Address

     These elections supersede any prior elections I have made under the Plan,
and are effective as to compensation otherwise due to me for my services as a
Director after (i) the date of my election to my first term in that office, or
(ii) the Commencement of the next Plan Year, whichever first occurs after the
date hereof. The beneficiary election is effective immediately.

     __________________________     ___________________________________________
               Date                                 Signature

                                    ___________________________________________
                                                 Name [please print]

   1
                                                                   Exhibit 10.33

                                 UGI Corporation
                              460 North Gulph Road
                                 King of Prussia
                               Pennsylvania 19406
                                       USA

Raiffeisen Zentralbank Osterreich
Aktiengesellschaft
Am Stadtpark 9
1030 Wien
Austria

Statement regarding Guarantee Agreement (B) dated 21 September 1999
- -------------------------------------------------------------------

Ladies and Gentlemen,

We have taken note of the attached amendment offer of Flaga GmbH (the "Offer").

We hereby irrevocably and unconditionally agree that the Offer be accepted by
your bank.

Moreover, we hereby irrevocably and unconditionally agree and confirm that the
Guarantee Agreement (B) as executed and concluded in Bratislava on 21 September
1999 by and between your bank as beneficiary and our company as guarantor shall
remain in full force and effect and fully applicable in accordance with its
terms in the event that you accept the Offer (such Guarantee Agreement (B) shall
of course also remain in full force and effect and fully applicable in
accordance with its terms in the event that you do not accept the Offer).

 ..........., dated 21.09.2000                        UGI Corporation

1 Attachment: Offer of Flaga GmbH dated 21.09.2000

We hereby accept the above statement of UGI Corporation:

Bratislava, dated 21.09.2000               Raiffeisen Zentralbank Osterreich
                                                  Aktiengesellschaft

                                                                          page 1

   2
                                   FLAGA GmbH
                             An der Bundesstrasse 6
                                 2100 Leobendorf
                                     Austria

Raiffeisen Zentralbank
Osterreich Aktiengesellschaft
Am Stadtpark 9
1030 Vienna
Austria
                                    ............, 21 September 2000

RE.: OFFER (B)

Dear Sirs,

we, FLAGA GmbH, An der Bundesstrasse 6, 2100 Leobendorf, Austria, herewith refer
to our previous Offer (B) (hereinafter the "Offer (B)") and propose to amend the
terms of Offer (B) as follows (Clauses referred to herein are Clauses of Offer
(B)):

The amount in Clause 1.1 shall be replaced by EURO 14,959,285.00
(fourteenmillionninehundredandfiftyninethousand-twohundredeightyfive).

The amounts in Clauses 1.2 (a), (b) and (c) shall be added up to one Tranche
("Tranche I") and reduced to the aggregate of EURO 6,959,285.00. The amounts in
Clause 1.2 (d) and (e) shall be added up to one Tranche ("Tranche II") in the
aggregate of EURO 8,000,000.00. Up to EURO 1,500,000.00, Tranche II can be used
for the issuance of guarantees. Provisions of the Offer (B) applying to Tranches
I, II and III shall now apply to Tranche I, and provisions of the Offer (B)
applying to Tranches IV and V shall now apply to Tranche II.

The date in Clause 2.1.(b) shall be replaced by 30 August 2003.

In Clause 4.1 (a) and (d), "clause 4.1 (e), (f), (g) and (h) shall be replaced
by: "clause 4.1 (e) and (f)".

Clause 4.1 (e) shall be replaced by the following: "The Final Maturity of
Tranche I shall be 31 August 2007"

Clause 4.1 (f) shall be replaced by the following: "The Final Maturity of
Tranche II shall be 30 September 2003; in August 2003, the parties shall enter
into negotiations for an extension of the Final Maturity of Tranche II for an
additional period of one year."

Clauses 4.1 (g) and (h) shall be deleted.

Clause 6.1 (a) and (b) shall be replaced by the following:

                                                                          page 1

   3
"6.1 Subject to clause 4.1 (e) and (f) as applicable to the respective Tranche,
repayments shall be made as follows:

(a) in respect of Tranche I, repayments have to be made on the date and in
amounts as follows:

Date              Amount in ATS      Amount in EUR
- ----------------------------------------------------------
                               
01.02.2001        11.320.500           822.693
01.08.2001        11.320.500           822.693
01.02.2002        11.320.500           822.693
01.08.2002        11.320.500           822.693
31.12.2002        10.789.250           784.085
01.02.2003         6.083.000           442.069
30.06.2003         6.087.000           442.360
01.02.2004         3.440.075           250.000
01.08.2004         3.440.075           250.000
01.02.2005         3.440.075           250.000
01.08.2005         3.440.075           250.000
01.02.2006         3.440.075           250.000
01.08.2006         3.440.075           250.000
01.02.2007         3.440.075           250.000
01.08.2007         3.440.075           250.000

(b) in respect of Tranche II, repayment shall be made on the respective Final
Maturity."

All other clauses of Offer (B) shall remain unchanged.

You can accept the present proposal by debiting our account no. 1-00.640.763
with an account fee in the amount of ATS 400.00, not later than 21 September
2001. You are hereby irrevocably authorized to make such debit.

If you accept the present proposal, the respective amendments shall also apply
to any agreement resulting from Offer (B).

                                          With kind regards,

                                             FLAGA GmbH

                                                                          page 2

   1
                                                                  Exhibit 10.34

                                 UGI Corporation
                              460 North Gulph Road
                                 King of Prussia
                               Pennsylvania 19406
                                       USA

Raiffeisen Zentralbank Osterreich
Aktiengesellschaft
Am Stadtpark 9
1030 Wien
Austria

Statement regarding Guarantee Agreement (C) dated 21 September 1999
- -------------------------------------------------------------------

Ladies and Gentlemen,

We have taken note of the attached amendment offer of Flaga GmbH (the "Offer").

We hereby irrevocably and unconditionally agree that the Offer be accepted by
your bank.

Moreover, we hereby irrevocably and unconditionally agree and confirm that the
Guarantee Agreement (C) as executed and concluded in Bratislava on 21 September
1999 by and between your bank as beneficiary and our company as guarantor shall
remain in full force and effect and fully applicable in accordance with its
terms in the event that you accept the Offer (such Guarantee Agreement (C) shall
of course also remain in full force and effect and fully applicable in
accordance with its terms in the event that you do not accept the Offer).

 ............., dated 21.09.2000                          UGI Corporation

1 Attachment: Offer of Flaga GmbH dated 21.09.2000

We hereby accept the above statement of UGI Corporation:

Bratislava, dated 21.09.2000              Raiffeisen Zentralbank Osterreich
                                                 Aktiengesellschaft

                                                                          page 1

   2
                                   FLAGA GmbH
                           An der Bundesstrasse 6
                                 2100 Leobendorf
                                     Austria

Raiffeisen Zentralbank
Osterreich Aktiengesellschaft
Am Stadtpark 9
1030 Vienna
Austria
                                        .........., 21 September 2000

RE.: OFFER (C)

Dear Sirs,

we, FLAGA GmbH, An der Bundesstrasse 6, 2100 Leobendorf, Austria, herewith refer
to our previous Offer (C) (hereinafter the "Offer (C)") and propose to amend the
terms of Offer (C) as follows (Clauses referred to herein are Clauses of Offer
(C)):

The amount in Clause 1.1. shall be replaced by EURO 9,000,000.00 (ninemillion).

The date in Clause 2.1. shall be replaced by 28 August 2001.

In Clause 4.1.(d) the first date shall be replaced by 28 September 2001, and
"spring 2000" shall be replaced by August 2001.

All other clauses of the afore mentioned offer shall remain unchanged.

You can accept the present proposal by debiting our account no. 1-00.640.763
with an account fee in the amount of ATS 300.00, not later than 21 September
2001. You are hereby irrevocably authorized to make such debit.

If you accept the present proposal, the respective amendments shall also apply
to any agreement resulting from Offer (C).

                                          With kind regards,

                                              FLAGA GmbH

                                                                          page 1
   1
                                                                   Exhibit 10.38

                          CONSULTING SERVICES AGREEMENT

      THIS CONSULTING SERVICES AGREEMENT (the "Agreement"), is entered into as
of August 1, 2000, by and between UGI Corporation, a Pennsylvania corporation,
("UGI") and Stephen D. Ban, an individual, ("Consultant").

      WHEREAS, UGI wishes to obtain the consulting services of Consultant, and
Consultant wishes to provide consulting services according to the terms and
conditions of this Agreement.

      NOW, THEREFORE, in consideration of the mutual promises hereinafter set
forth, and intending to be legally bound, UGI and Consultant agree as follows:

      1. Services to be Provided. During the term of this Agreement, Consultant
shall perform for UGI such consulting services as UGI may from time to time
request in connection with identifying, evaluating and providing advice relating
to growth opportunities in distributed generation ("Services").

      2. Term. The term of this Agreement is one year, beginning August 1, 2000
and ending July 31, 2001.

      3. Time Commitment and Compensation.

            (a)   Consultant shall provide up to four (4) days of Services per
                  month at the request of the Chairman of UGI and shall receive
                  an annual fee of $50,000, payable semiannually in arrears,
                  commencing February 1, 2001. In addition, if the Chairman of
                  UGI and the Consultant agree that more than four (4) days of
                  Services shall be performed in any month, Consultant shall be
                  paid $1,000 per day for each such additional day.

            (b)   Consultant will be reimbursed promptly for all reasonable and
                  necessary out-of-pocket expenses incurred in carrying out the
                  Services outlined above. Consultant will submit to UGI on a
                  monthly basis a written request for reimbursement together
                  with supporting documentation including, where practicable,
                  receipts for travel, lodging and meals.

      4. No Benefits. Consultant is not an employee of UGI and will not be
entitled to participate in or receive any benefit or right under any of UGI's
employee benefit and welfare plans, including, without limitation, insurance,
pension and savings plans, provided however, that the payments due hereunder
shall be in addition to and not in lieu of any payments or benefits to which
Consultant is entitled as a result of Consultant's service as an outside
director of UGI and its subsidiary, UGI Utilities, Inc.

      5. Independent Contract. For purposes of this Agreement and all Services
to be provided hereunder, Consultant shall not be considered a partner,
co-venturer, agent, employee, or representative of UGI, but shall remain in all
respects an independent contractor, and neither
   2
party shall have any right or authority to make or undertake any promise,
warranty or representation, to execute any contract, or otherwise to assume any
obligation or responsibility in the name of or on behalf of the other party.

      6. Confidentiality.

            (a) Services and Company Information. Consultant agrees not to
disclose to third parties during the term of this Agreement or at any time
thereafter any information concerning the Services. Consultant also agrees at
all times during the term of this Agreement and thereafter, to hold in strictest
confidence, and not to use, except in connection with Consultant's performance
of the Services, and not to disclose to any person or entity any Confidential
Information of UGI without the prior written authorization of UGI. As used
herein, "Confidential Information" means any proprietary or confidential
information, technical data, trade secrets or know-how, including, but not
limited to, research, sales and/or marketing plans and products, services,
business plans, acquisitions or strategies (past, present and/or prospective),
customer lists and customers, credit information, markets, software,
developments, inventions, processes, formulas, technology, designs, drawings,
engineering, distribution and sales methods and systems, sales and profit
figures, finances and other business information disclosed to Consultant or
otherwise learned, discovered or developed by Consultant, either directly or
indirectly in writing, orally or by drawings or inspection of documents or other
tangible property. Confidential Information does not include any of the
foregoing items which has become publicly known and made generally available
through no wrongful act of Consultant.

            (b) Third Party Information. Consultant recognizes that UGI has
received and in the future may continue to receive from third parties their
confidential or proprietary information subject to a duty on UGI's part to
maintain the confidentiality of such information and to use it only for certain
limited purposes. Consultant agrees at all times during the term of this
Agreement and thereafter, to hold in strictest confidence and not to use or
disclose such third-party information, except in connection with Consultant's
performance of the Services and in a manner consistent with UGI's agreement with
any such third party. UGI shall provide Consultant with a copy of any applicable
confidentiality agreements.

            (c) Survival. The provisions of this Section shall survive the
expiration of the term of this Agreement for a period of three (3) years.

      7. No Conflicting Agreements. Consultant represents that Consultant is not
a party to any existing agreement which would prevent Consultant from entering
into and performing this Agreement. Consultant will not enter into any other
agreement that is in conflict with Consultant's obligations under this Agreement
without the prior written approval of UGI.

      8. Entire Agreement, Amendment and Assignment. This Agreement is the sole
agreement between Consultant and UGI with respect to the Services to be
performed hereunder and it supersedes all prior agreements and understandings
with respect thereto, whether oral or written. No modification to any provision
of this Agreement shall be binding unless in writing and signed by both the
Consultant and UGI. No waiver of any rights under this agreement, will be
effective unless in writing signed by the party to be charged. All of the terms
and provisions

                                      -2-
   3
of this Agreement shall be binding upon and inure to the benefit of and be
enforceable by the respective heirs, executors, administrators, legal
representatives, successors and assigns of the parties hereto, except that the
duties and responsibilities of Consultant hereunder are of a personal nature and
shall not be assignable or delegable in whole or in part by Consultant.

      9. Governing Law. This Agreement shall be governed by and interpreted
under the laws of the Commonwealth of Pennsylvania without regard to its choice
of law provisions.

      10. Notices. All notices and other communications required or permitted
hereunder or necessary or convenient in connection herewith shall be in writing
and shall be deemed to have been given when hand delivered, sent by facsimile or
mailed by registered or certified mail, as follows (provided that notice of
change of address shall be deemed given only when received):

            If to UGI, to:          UGI Corporation
                                    Attention: Lon R. Greenberg, President
                                    P.O. Box 858
                                    Valley Forge, PA 19482
                                    Facsimile No.: (610) 992-3254

            If to Consultant, to:   Dr. Stephen D. Ban
                                    50 Woodland Drive
                                    Barrington, IL 60010

or to such other names or addresses as UGI or Consultant, as the case may be,
shall designate by notice to each other person entitled to receive notices in
the manner specified in this paragraph.

      IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
duly executed this Agreement as of the date first above written.

                                          UGI CORPORATION

                                       By:
                                          ----------------------------
                                          Lon R. Greenberg, President

                                          CONSULTANT

                                          ----------------------------
                                          Stephen D. Ban

                                      -3-
   1
                                                                   Exhibit 10.39

                                 UGI CORPORATION

                               AMENDMENT NO. 1 TO

                      1992 NON-QUALIFIED STOCK OPTION PLAN

      This Amendment No. 1 dated as of December 10, 1996 amends that
certain UGI Corporation 1992 Non-Qualified Stock Option Plan ("the Plan").

                                   BACKGROUND

      The Board of Directors of UGI Corporation approved a 1997 Stock Option and
Dividend Equivalent Plan (the "1997 SODEP") and also approved certain amendments
to the Plan to make its vesting provisions and its definition of "Fair Market
Value" conform to the corresponding provisions of the 1997 SODEP. The purpose of
this Amendment is to make those changes in the Plan.

      NOW THEREFORE, the Plan is amended as follows:

      Section 1. Amendment and Restatement. Sections 2(e), 7.3 and 7.4 of the
Plan are hereby amended and restated in their entirety as follows:

      2(e) "Fair Market Value" of Stock means the average, rounded to the next
highest one-eighth of a point (.125), of the highest and lowest sales prices
thereof on the New York Stock Exchange on the day on which Fair Market Value is
being determined, as reported on the Composite Tape for transactions on the New
York Stock Exchange; provided, however, in the case of a cashless exercise
pursuant to Section 7.4, the Fair Market Value shall be the actual sale price of
the shares issued upon exercise of the Option. In the event that there are no
Stock transactions on the New York Stock Exchange on such day, the Fair Market
Value will be determined as of the immediately preceding day on which there were
Stock transactions on that exchange.

      7.3 Exercise and Vesting.

            (a) Except as otherwise specified by the Committee, an Option shall
be fully and immediately exercisable on the date of grant. Notwithstanding the
foregoing, in the event that any such Options are not by their terms immediately
exercisable, the Committee may accelerate the exercisability of any or all
outstanding Options at any time for any reason. No Option shall be exercisable
on or after the tenth anniversary of the date of grant.

            (b) If a Participant holding an Option ceases to be an Employee, the
Option held by such Participant shall be exercisable only with respect to that
number of shares of Stock with respect to which it is already exercisable on the
date such Participant

                                      -1-

   2
ceases to be an Employee. However, if a Participant holding an Option ceases to
be an Employee by reason of a retirement under the Company's or a Subsidiary's
retirement plan, the Option held by any such participant shall thereafter become
exercisable with respect to that additional number of shares of Stock with
respect to which it becomes exercisable on any anniversary of the date on which
the Participant was granted the Option which occurs within thirteen (13) months
after the date of such retirement and such Option shall be exercisable during
such thirteen-month period. Notwithstanding the foregoing, the Committee shall
have the power, in the event of any merger or consolidation of any other
corporation with or into the Company, or the sale of all or substantially all of
the assets of the Company or an offer to purchase made by a party other than the
Company to all shareholders of the Company for all or any substantial portion of
the outstanding Stock, to amend any or all outstanding Options to permit the
exercise of all such Options prior to the effectiveness of any such merger,
consolidation or sale or the expiration of any such offer to purchase, and to
terminate such Options as of such effectiveness or expiration. Notwithstanding
anything contained in this Section 7.3 with respect to the number of shares with
respect to which an Option is or is to become exercisable, no Option, to the
extent that it has not previously been exercised, shall be exercisable after it
has terminated, including without limitation, after any termination of such
Option pursuant to Section 10 hereof.

      7.4 Payment of Option Price. The Option Price upon exercise of any Option
shall be payable to the Company in full (i) in cash or its equivalent, (ii) by
tendering shares of previously acquired Stock already beneficially owned by the
Participant for more than one year and having a Fair Market Value at the time of
exercise equal to the total Option Price, (iii) by payment through a broker in
accordance with procedures permitted by Regulation T of the Federal Reserve
Board, or (iv) by a combination of (i) (ii) and/or (iii). The cash proceeds from
such payment will be added to the general funds of the Company and shall be used
for its general corporate purposes. Any shares of previously acquired Stock
tendered to the Company in payment of the Option Price will be added by the
Company to its treasury stock to be used for its general corporate purposes.

      Section 2. Effect of Amendment. All other terms and conditions of the Plan
shall remain unaffected by this Amendment No. 1 and are ratified and confirmed.

      Section 3. Definitions. Capitalized terms used in this Amendment No. 1,
but not defined shall have the meanings ascribed to those terms in the Plan.

                                      -2-
   3
      IN WITNESS WHEREOF, and as evidence of the adoption of this Amendment, an
appropriate officer of the Company has caused this Amendment to be executed as
of December 10, 1996.

Attest:                                  UGI CORPORATION

By:  /s/  Barton D. Whitman              By  /s/  Brendan P. Bovaird
     -------------------------               --------------------------------
        Secretary                            Name:  Brendan P. Bovaird
                                             Title: Vice President and
                                                      General Counsel

                                      -3-
   1
                                                                   EXHIBIT 10.40

                                                             Contract #: 800239R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS

         This Service Agreement, made and entered into this 23rd day of February
1998, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called
"Customer", whether one or more),

                                   WITNESSETH:

         WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated December 8, 1995, under Pipeline's Rate Schedule CDS (Pipeline's
Contract No. 800239); and

         WHEREAS, Pipeline and Customer desire to enter into this Service
Agreement to supersede Pipeline's currently effective Contract No. 800239;

         NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements herein contained, the parties do covenant and agree as
follows:

                                    ARTICLE I

                               SCOPE OF AGREEMENT

         Subject to the terms, conditions and limitations hereof, of Pipeline's
Rate Schedule CDS, and of the General Terms and Conditions, transportation
service hereunder will be firm. Subject to the terms, conditions and limitations
hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified in Article IV
herein or available to Customer pursuant to Section 14 of the General Terms and
Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's
account, as requested for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:

              Maximum Daily Quantity (MDQ)       25,000 dth

         Subject to variances as may be permitted by Sections 2.4 of Rate
Schedule CDS or the General Terms and Conditions, Customer shall deliver to
Pipeline and Pipeline shall receive, for Customer's account, at those points on
Pipeline's system as specified in Article IV herein or available to Customer
pursuant to Section 14 of the General Terms and Conditions (hereinafter referred
to as Point(s) of Receipt) daily quantities of gas equal to the daily quantities
delivered to Customer pursuant to this Service Agreement up to Customer's MDQ,
plus Applicable Shrinkage as specified in the General Terms and Conditions.
   2
                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         Pipeline shall not be obligated to, but may at its discretion, receive
at any Point of Receipt on any day a quantity of gas in excess of the applicable
Maximum Daily Receipt obligation (MDRO) , plus Applicable Shrinkage, but shall
not receive in the aggregate at all Points of Receipt on any day a quantity of
gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any Point of Delivery
on any day a quantity of gas in excess of the applicable Maximum Daily Delivery
Obligation (MDDO), but shall not deliver in the aggregate at all Points of
Delivery on any day a quantity of gas in excess of the MDQ.

         In addition to the MDQ and subject to the terms, conditions and
limitations hereof, Rate Schedule CDS and the General Terms and Conditions,
Pipeline shall deliver within the Access Area under this and all other service
agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to
Customer's Operational Segment Capacity Entitlements, excluding those
Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for
Customer's account, as requested on any day.

                                   ARTICLE II

                                TERM OF AGREEMENT

         The term of this Service Agreement shall commence on the first day of
the first month after Customer fully executes this Service Agreement and shall
continue in force and effect until October 31, 2002 and year to year thereafter
unless this Service Agreement is terminated as hereinafter provided. This
Service Agreement may be terminated by either Pipeline or Customer upon two (2)
years prior written notice to the other specifying a termination date of October
31, 2002 or any October 31 thereafter. Subject to Section 22 of Pipeline's
General Terms and Conditions and without prejudice to such rights, this Service
Agreement may be terminated at any time by Pipeline in the event Customer fails
to pay part or all of the amount of any bill for service hereunder and such
failure continues for thirty (30) days after payment is due; provided, Pipeline
gives thirty (30) days prior written notice to Customer of such termination and
provided further such termination shall not be effective if, prior to the date
of termination, Customer either pays such outstanding bill or furnishes a good
and sufficient surety bond guaranteeing payment to Pipeline of such outstanding
bill.

         THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR
THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED
ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF
THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND
CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.

                                      -2-
   3
                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         Any portions of this Service Agreement necessary to correct or cash-out
imbalances under this Service Agreement as required by the General Terms and
Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other
parts of this Service Agreement until such time as such balancing has been
accomplished.

                                   ARTICLE III

                                  RATE SCHEDULE

         This Service Agreement in all respects shall be and remain subject to
the applicable provisions of Rate Schedule CDS and of the General Terms and
Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy
Regulatory Commission, all of which are by this reference made a part hereof.

         Customer shall pay Pipeline, for all services rendered hereunder and
for the availability of such service in the period stated, the applicable prices
established under Pipeline's Rate Schedule CDS as filed with the Federal Energy
Regulatory Commission, and as same may hereafter be legally amended or
superseded.

         Customer agrees that Pipeline shall have the unilateral right to file
with the appropriate regulatory authority and make changes effective in (a) the
rates and charges applicable to service pursuant to Pipeline's Rate Schedule
CDS, (b) Pipeline's Rate Schedule CDS pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and Conditions applicable to
Rate Schedule CDS. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.

                                   ARTICLE IV

                  POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY

         The Point(s) of Receipt and Point(s) of Delivery at which Pipeline
shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A
and B of the executed service agreement. Customer's Zone Boundary Entry Quantity
and Zone Boundary Exit Quantity, for each of Pipeline's zones shall be specified
in Exhibit C of the executed service agreement.

         Exhibit(s) A, B and C are hereby incorporated as part of this Service
Agreement for all intents and purposes as if fully copied and set forth herein
at length.

                                      -3-
   4
                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

                                    ARTICLE V

                                     QUALITY

         All natural gas tendered to Pipeline for Customer's account shall
conform to the quality specifications set forth in Section 5 of Pipeline's
General Terms and Conditions. Customer agrees that in the event Customer tenders
for service hereunder and Pipeline agrees to accept natural gas which does not
comply with Pipeline's quality specifications, as expressly provided for in
Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all
costs associated with processing of such gas as necessary to comply with such
quality specifications. Customer shall execute or cause its supplier to execute,
if such supplier has retained processing rights to the gas delivered to
Customer, the appropriate agreements prior to the commencement of service for
the transportation and processing of any liquefiable hydrocarbons and any PVR
quantities associated with the processing of gas received by Pipeline at the
Point(s) of Receipt under such Customer's service agreement. In addition,
subject to the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered for
transportation hereunder.

                                   ARTICLE VI

                                    ADDRESSES

         Except as herein otherwise provided or as provided in the General Terms
and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Service Agreement, or any notice
which any party may desire to give to the other, shall be in writing and shall
be considered as duly delivered when mailed by registered, certified, or regular
mail to the post office address of the parties hereto, as the case may be, as
follows:

         (a) Pipeline:   TEXAS EASTERN TRANSMISSION CORPORATION
                         5400 Westheimer Court
                         Houston, TX 77056-5310

         (b) Customer:   UGI UTILITIES, INC.
                         100 Kachel Blvd.
                         P.O. Box 12677
                         Reading, PA 19612-2677

or such other address as either party shall designate by formal written notice.

                                      -4-
   5
                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

                                   ARTICLE VII

                                   ASSIGNMENTS

         Any Company which shall succeed by purchase, merger, or consolidation
to the properties, substantially as an entirety, of Customer, or of Pipeline, as
the case may be, shall be entitled to the rights and shall be subject to the
obligations of its predecessor in title under this Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement under the
provisions of any mortgage, deed of trust, indenture, bank credit agreement,
assignment, receivable sale, or similar instrument which it has executed or may
execute hereafter; otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first shall have
obtained the consent thereto in writing of the other; provided further, however,
that neither Customer nor Pipeline shall be released from its obligations
hereunder without the consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms and Conditions.
To the extent Customer so desires, when it releases capacity pursuant to Section
3.14 of the General Terms and Conditions, Customer may require privity between
Customer and the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.

                                  ARTICLE VIII

                                 INTERPRETATION

         The interpretation and performance of this Service Agreement shall be
in accordance with the laws of the State of Texas without recourse to the law
governing conflict of laws.

         This Service Agreement and the obligations of the parties are subject
to all present and future valid laws with respect to the subject matter, State
and Federal, and to all valid present and future orders, rules, and regulations
of duly constituted authorities having jurisdiction.

                                   ARTICLE IX

                        CANCELLATION OF PRIOR CONTRACT(S)

         This Service Agreement supersedes and cancels, as of the effective date
of this Service Agreement, the contract(s) between the parties hereto as
described below:

service agreement dated December 8, 1995, between Pipeline and Customer under
Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800239).

                                      -5-
   6
                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         IN WITNESS WHEREOF, the parties hereto have caused this Service
Agreement to be signed, by their respective Presidents, Vice Presidents or other
duly authorized agents and their respective corporate seals to be hereto affixed
and attested by their respective Secretaries or Assistant Secretaries, the day
and year first above written.

                                  TEXAS EASTERN TRANSMISSION CORPORATION

                                  By:
                                      -----------------------------------------

ATTEST:

- ------------------------
Name:
Title:

                                  UGI UTILITIES, INC.

                                  By:
                                      -----------------------------------------
                                       Robert J. Chaney
                                       Executive Vice President

ATTEST:

- ------------------------
Brendan P. Bovaird
Secretary

                                      -6-
   7
                                                             Contract #: 800239R

                         EXHIBIT A, TRANSPORTATION PATHS
                       FOR BILLING PURPOSES, DATED 2/23/99
                TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
           BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
              AND UGI UTILITIES, INC. ("Customer"), DATED 2/23/99:

(1)      Customer's firm Point(s) of Receipt:

                                     Maximum Daily
 Point                            Receipt Obligation
  of                               (plus Applicable          Measurement
Receipt     Description              Shrinkage) dth        Responsibilities     Owner         Operator*
- -------     -----------              --------------        ----------------     -----         ---------

70011       COLUMBIA GAS                   0               TX EAST              TX EAST       COLUMBIA
            - EAGLE, PA,                                   TRAN                 TRAN          GAS
            CHESTER CO., PA

75577       COLUMBIA GAS-                  0               TX EAST              TX EAST       COLUMBIA
            PENNSBURG, PA                                  TRAN                 TRAN          GAS
            BUCKS CO., PA

                                                              *-Confirming Party

(2)      Customer shall have Pipeline's Master Receipt Point List ("MRPL").
         Customer hereby agrees that Pipeline's MRPL as revised and published by
         Pipeline from time to time is incorporated herein by reference.

Customer hereby agrees to comply with the Receipt Pressure Obligation as set
forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s)
of Receipt.

                                             Transportation
            Transportation Path           Path Quantity (Dth/D)
            -------------------           ---------------------

            M1 to M3                              25,000

SIGNED FOR IDENTIFICATION

PIPELINE:
         -----------------------------------

CUSTOMER:
           ---------------------------------

SUPERSEDES EXHIBIT A DATED:
                             ---------------

                                      A-1
   8
                                                             Contract #: 800239R

                 EXHIBIT B, POINT(S) OF DELIVERY, DATED 2/23/99
                TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
        BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
                        UGI UTILITIES, INC. ("Customer"),
                                 DATED 2/23/99:

                                                Maximum Daily      Delivery
    Point of                                    Delivery           Pressure          Measurement
    Delivery        Description                 Obligation (dth)   Obligation        Responsibilities   Owner          Operator*
    --------        -----------                 ----------------   ----------        ----------------   -----          ---------

1.  70069      UGI UTILITIES - COLUMBIA, PA          5,190         AS PROVIDED       TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               LANCASTER CO., PA                                   IN SECTION 6
                                                                   OF THE
                                                                   GENERAL TERMS
                                                                   AND
                                                                   CONDITIONS OF
                                                                   PIPELINE'S
                                                                   FERC GAS
                                                                   TARIFF

2.  70070      UGI UTILITIES - LANCASTER, PA         25,000        AS PROVIDED       TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               LANCASTER CO., PA                                   IN SECTION 6
                                                                   OF THE
                                                                   GENERAL TERMS
                                                                   AND
                                                                   CONDITIONS OF
                                                                   PIPELINE'S
                                                                   FERC GAS
                                                                   TARIFF

3.  71528      UGI UTILITIES - LANCASTER, PA         7,200         300 POUNDS        TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               LANCASTER CO., PA                                   PER SQUARE
                                                                   INCH GAUGE

4.  70519      UGI UTILITIES - DAUPHIN CO.,          25,000        400 POUNDS        TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               PA   DAUPHIN CO., PA                                PER SQUARE
                                                                   INCH GAUGE

5.  70321      UGI UTILITIES - LEBANON, PA           17,000        400 POUNDS        TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               LEBANON CO., PA                                     PER SQUARE
                                                                   INCH GAUGE

6.  70486      UGI UTILITIES - WOMELSDORF, PA        6,500         400 POUNDS        TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               BERKS CO., PA                                       PER SQUARE
                                                                   INCH GAUGE

                                      B-1
   9
                                                             Contract #: 800239R

                   EXHIBIT B, POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

                                                Maximum Daily       Delivery
    Point of                                        Delivery        Pressure          Measurement
    Delivery        Description                 Obligation (dth)   Obligation        Responsibilities   Owner          Operator*
    --------        -----------                 ----------------   ----------        ----------------   -----          ---------

7.  70322      UGI UTILITIES - READING, PA           25,000        400 POUNDS        TX EAST TRAN       TX EAST TRAN   UGI UTILITIES
               BERKS CO., PA                                       PER SQUARE
                                                                   INCH GAUGE

8.  72571      COLUMBIA GAS - BALLY, PA              5,190         400 POUNDS        TX EAST TRAN       COLUMBIA GAS   UGI UTILITIES
               BERKS CO., PA                                       PER SQUARE
                                                                   INCH GAUGE

9.  71461      COLUMBIA GAS - RICH HILL, PA          5,190         SUCH PRESSURE     TX EAST TRAN       COLUMBIA GAS   UGI UTILITIES
               BUCKS CO., PA                                       AS MAY BE
                                                                   AVAILABLE BY
                                                                   PIPELINE AT
                                                                   THE POINT OF
                                                                   DELIVERY

10. 70011      COLUMBIA GAS - EAGLE, PA              0             AS PROVIDED       TX EAST TRAN       TX EAST TRAN   COLUMBIA GAS
               CHESTER CO., PA                                     IN SECTION 6
                                                                   OF THE
                                                                   GENERAL TERMS
                                                                   AND
                                                                   CONDITIONS OF
                                                                   PIPELINE'S
                                                                   FERC GAS
                                                                   TARIFF

11. 75577      COLUMBIA GAS- PENNSBURG, PA,          0             AS PROVIDED       TX EAST TRAN       TX EAST TRAN   COLUMBIA GAS
               BUCKS CO., PA                                       IN SECTION 6
                                                                   OF THE
                                                                   GENERAL TERMS
                                                                   AND
                                                                   CONDITIONS OF
                                                                   PIPELINE'S
                                                                   FERC GAS
                                                                   TARIFF

                                      B-2
   10
                                                             Contract #: 800239R

                   EXHIBIT B, POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

* Confirming Party

provided, however, that Pipeline is not obligated to deliver under Rate
Schedules FT-1, CDS and FTS-5 on any one day an aggregate of more than 88,418
dth per day to points of delivery 70011, 70069, 70070 and 71528 during the
period November 16 through April 15, and further provided, that during this time
period Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and
FTS-5 on any one day an aggregate of more than 94,904 dth to points of delivery
70321, 70322, 70486, 70519, 71461 and 72571;

provided, however, that until changed by a subsequent agreement between Pipeline
and Customer, Pipeline's aggregate maximum daily delivery obligations under this
and all other Service Agreements existing between Pipeline and Customer shall in
no event exceed the following:

                  Point of              Aggregate Maximum Daily
                  Delivery                Delivery Obligation
                  --------                -------------------

                  No. 1                       5,190 dth

                  No. 2                      49,000 dth

                  No. 3                      17,200 dth

                  No. 4                      53,000 dth

                  No. 5                      17,000 dth

                  No. 6                       6,500 dth

                  No. 7                      65,880 dth

                  No. 8                       7,186 dth

                  No. 9                       5,190 dth

                  No. 10                     68,785 dth

Further, pursuant to Section 14. 9 of the General Terms and Conditions of
Pipeline's FERC Gas Tariff Sixth Revised Volume No. 1, Customer has been
allocated firm capacity at the Points of Delivery as shown below for deliveries
under Rate Schedules CDS, FT-1, SCT, and/or SS-1 at such pressure available in
Pipeline's facilities at the point of delivery, subject to receipt of such
quantities being acceptable to the Owner and Operator of the Point of Delivery:

                                      B-3
   11
                                                             Contract #: 800239R

                   EXHIBIT B, POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

                                                 Section 14.9
                                                     Firm
    Point of                                       Capacity          Measurement
    Delivery          Description                   (dth/d)        Responsibilities       Owner           Operator
    --------          -----------                   -------        ----------------       -----           --------

1.  70011      COLUMBIA GAS (MFGRS.) -               85,635        TX EAST TRAN      TX EAST TRAN       COLUMBIA GAS
               EAGLE, PA CHESTER CO., PA        4/1/97- 10/31/97
                                                     49,635
                                                11/l/97-10/31/98

2.  70069      UGI UTILITIES - COLUMBIA,             12,700        TX EAST TRAN      TX EAST TRAN       UGI UTILITIES
               PA LANCASTER CO. PA

3.  70070      UGI UTILITIES - COLUMBIA,             31,328        TX EAST TRAN      TX EAST TRAN       UGI UTILITIES
               PA LANCASTER, PA LANCASTER
               CO., PA

4.  70321      UGI UTILITIES - LEBANON,               1,253        TX EAST TRAN      TX EAST TRAN       UGI UTILITIES
               PA LEBANON CO., PA

5.  70486      UGI UTILITIES -                        3,670        TX EAST TRAN      TX EAST TRAN       UGI UTILITIES
               WOMELSDORF, PA BERKS CO.,
               PA

6.  71438      DAUPHIN CO. GAS -                      2,580        TX EAST TRAN      TX EAST TRAN       PENN FUEL
               ANNVILLE, LEBANON CO, PA

7.  71461      UGI UTILITIES - RICH HILL,               840        TX EAST TRAN      COLUMBIA GAS       COLUMBIA GAS
               BUCKS CO., PA

8.  72571      UGI UTILITIES - BERKS,                13,984        TX EAST TRAN      COLUMBIA GAS       COLUMBIA GA
               CO., PA

9   75577      UGI UTILITIES - PENNSBURG,            75,440        TX EAST TRAN      COLUMBIA GAS       COLUMBIA GAS
               PA BUCKS CO., PA

                                      B-4
   12
                                                             Contract #: 800239R

                   EXHIBIT B, POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

SIGNED FOR IDENTIFICATION

PIPELINE:
           ---------------------------------

CUSTOMER:
           ---------------------------------

SUPERSEDES EXHIBIT B DATED:
                             ---------------

                                      B-5
   13
                                                             Contract #: 800239R

     EXHIBIT C ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
         DATED 2/23/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
         BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
                UGI UTILITIES, INC. ("CUSTOMER"), DATED 2/23/99:

                          ZONE BOUNDARY ENTRY QUANTITY
                                      Dth/D

                                       To

============================================================================================================================
  FROM     STX   ETX    WLA    ELA    M1-24    M1-30    M1-TXG    M1-TGC    M2-24   M2-30    M2-TXG    M2-TGC    M2       M3
- ----------------------------------------------------------------------------------------------------------------------------
                                                                             
STX                                                                  709
- ----------------------------------------------------------------------------------------------------------------------------
ETX                                    3013               1073
- ----------------------------------------------------------------------------------------------------------------------------
WLA                                                        326       709
- ----------------------------------------------------------------------------------------------------------------------------
ELA                                            19576
- ----------------------------------------------------------------------------------------------------------------------------
M1-24                                                                       3013
- ----------------------------------------------------------------------------------------------------------------------------
M1-30                                                                               19576
- ----------------------------------------------------------------------------------------------------------------------------
M1-TXG                                                                                         1399
- ----------------------------------------------------------------------------------------------------------------------------
M1-TGC                                                                                                   1418
- ----------------------------------------------------------------------------------------------------------------------------
M2-24
- ----------------------------------------------------------------------------------------------------------------------------
M2-30
- ----------------------------------------------------------------------------------------------------------------------------
M2-TXG
- ----------------------------------------------------------------------------------------------------------------------------
M2-TGC
- ----------------------------------------------------------------------------------------------------------------------------
M2                                                                                                                     25000
- ----------------------------------------------------------------------------------------------------------------------------
M3
============================================================================================================================

                                      C-1
   14
                                                             Contract #: 800239R

                              EXHIBIT C (Continued)
                               UGI UTILITIES, INC.

                           ZONE BOUNDARY EXIT QUANTITY
                                      Dth/D

                                       To

============================================================================================================================
  FROM     STX   ETX    WLA    ELA    M1-24    M1-30    M1-TXG    M1-TGC    M2-24   M2-30    M2-TXG    M2-TGC    M2       M3
- ----------------------------------------------------------------------------------------------------------------------------
                                                                             
STX
- ----------------------------------------------------------------------------------------------------------------------------
ETX
- ----------------------------------------------------------------------------------------------------------------------------
WLA
- ----------------------------------------------------------------------------------------------------------------------------
ELA
- ----------------------------------------------------------------------------------------------------------------------------
M1-24                                                                        3013
- ----------------------------------------------------------------------------------------------------------------------------
M1-30                                                                               19576
- ----------------------------------------------------------------------------------------------------------------------------
M1-TXG                                                                                         1399
- ----------------------------------------------------------------------------------------------------------------------------
M1-TGC                                                                                                   1418
- ----------------------------------------------------------------------------------------------------------------------------
M2-24
- ----------------------------------------------------------------------------------------------------------------------------
M2-30
- ----------------------------------------------------------------------------------------------------------------------------
M2-TXG
- ----------------------------------------------------------------------------------------------------------------------------
M2-TGC
- ----------------------------------------------------------------------------------------------------------------------------
M2                                                                                                                     25000
- ----------------------------------------------------------------------------------------------------------------------------
M3
============================================================================================================================

SIGNED FOR IDENTIFICATION:

PIPELINE:
           ---------------------------------

CUSTOMER:
           ---------------------------------

SUPERCEDES EXHIBIT C DATED
                            ----------------

                                       C-2
   1
                                                                   EXHIBIT 10.41

                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS

         TMT Service Agreement made and entered into this, 23rd day of February,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called
"Customer", whether one or more),

                                   WITNESSETH:

         WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated December 8, 1995, under Pipeline's Rate Schedule CDS (Pipeline's
Contract No. 800397); and

         WHEREAS, Pipeline and Customer desire to enter into this Service
Agreement to supersede Pipeline's currently effective Contract No. 800397;

         NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements herein contained, the parties do covenant and agree as
follows:

                                    ARTICLE I

                               SCOPE OF AGREEMENT

         Subject to the terms, conditions and limitations hereof, of Pipeline's
Rate Schedule CDS,. and of the General Terms and Conditions, transportation
service hereunder will be firm. Subject to the terms, conditions and limitations
hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified in Article IV
herein or available to Customer pursuant to Section 14 of the General Terms and
Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's
account, as requested for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:

                   Maximum Daily Quantity (MDQ)     41,000 dth;

         provided, however, that Customer upon provision of two (2) years prior
         written notice to Pipeline may reduce the MDQ under this Service
         Agreement by an aggregate quantity not in excess of 41,000 dth, with
         any such reduction to be effective on November 1, 2001, or any
         subsequent November 1 thereafter.

         Subject to variances as may be permitted by Sections 2.4 of Rate
Schedule CDS or the General Terms and Conditions, Customer shall deliver to
Pipeline and Pipeline shall receive, for Customer's account, at those points on
Pipeline's system as specified in Article IV herein or available to Customer
pursuant to Section 14 of the General Terms and Conditions (hereinafter referred
to as Point(s) of Receipt) daily quantities of gas equal to the daily quantities
delivered to Customer pursuant to this Service Agreement up to Customer's MDQ,
plus Applicable Shrinkage as specified in the General Terms and Conditions.
   2
                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         Pipeline shall not be obligated to, but may at its discretion, receive
at any Point of Receipt on any day a quantity of gas in excess of the applicable
Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall
not receive in the aggregate at all Points of Receipt on any day a quantity of
gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any Point of Delivery
on any day a quantity of gas in excess of the applicable Maximum Daily Delivery
Obligation (MDDO) , but shall not deliver in the aggregate at all Points of
Delivery on any day a quantity of gas in excess of the MDQ.

         In addition to the MDQ and subject to the terms, conditions and
limitations hereof, Rate Schedule CDS and the General Terms and Conditions,
Pipeline shall deliver within the Access Area under this and all other service
agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to
Customer's Operational Segment Capacity Entitlements, excluding those
Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for
Customer's account, as requested on any day.

                                   ARTICLE II

                                TERM OF AGREEMENT

         The term of this Service Agreement shall commence on the first day of
the first month after Customer fully executes this Service Agreement and shall
continue in force and effect until October 31, 2001 and year to year thereafter
unless this Service Agreement is terminated as hereinafter provided. This
Service Agreement may be terminated by either Pipeline or Customer upon two (2)
years prior written notice to the other specifying a termination date of October
31, 2001 or any October 31 thereafter. Subject to Section 22 of Pipeline's
General Terms and Conditions and without prejudice to such rights, this Service
Agreement may be terminated at any time by Pipeline in the event Customer fails
to pay part or all of the amount of any bill for service hereunder and such
failure continues for thirty (30) days after payment is due; provided, Pipeline
gives thirty (30) days prior written notice to Customer of such termination and
provided further such termination shall not be effective if, prior to the date
of termination, Customer either pays such outstanding bill or furnishes a good
and sufficient surety bond guaranteeing payment to Pipeline of such outstanding
bill.

         THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR
THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED
ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF
THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND
CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.

                                      -2-
   3
                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         Any portions of this Service Agreement necessary to correct or cash-out
imbalances under this Service Agreement as required by the General Terms and
Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other
parts of this Service Agreement until such time as such balancing has been
accomplished.

                                   ARTICLE III

                                  RATE SCHEDULE

         This Service Agreement in all respects shall be and remain subject to
the applicable provisions of Rate Schedule CDS and of the General Terms and
Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy
Regulatory Commission, all of which are by this reference made a part hereof.

         Customer shall pay Pipeline, for all services rendered hereunder and
for the availability of such service in the period stated, the applicable prices
established under Pipeline's Rate Schedule CDS as filed with the Federal Energy
Regulatory Commission, and as same may hereafter be legally amended or
superseded.

         Customer agrees that Pipeline shall have the unilateral right to file
with the appropriate regulatory authority and make changes effective in (a) the
rates and charges applicable to service pursuant to Pipeline's Rate Schedule
CDS, (b) Pipeline's Rate Schedule CDS pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and Conditions applicable to
Rate Schedule CDS. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.

                                   ARTICLE IV

                  POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY

         The Point(s) of Receipt and Point(s) of Delivery at which Pipeline
shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A
and B of the executed service agreement. Customer's Zone Boundary Entry Quantity
and Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified
in Exhibit C of the executed service agreement.

                                      -3-
   4
                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

         Exhibit(s) A, B and C are hereby incorporated as part of this Service
Agreement for all intents and purposes as if fully copied and set forth herein
at length.

                                    ARTICLE V

                                     QUALITY

         All natural gas tendered to Pipeline for Customer's account shall
conform to the quality specifications set forth in Section 5 of Pipeline's
General Terms and Conditions. Customer agrees that in the event Customer tenders
for service hereunder and Pipeline agrees to accept natural gas which does not
comply with Pipeline's quality specifications, as expressly provided for in
Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all
costs associated with processing of such gas as necessary to comply with such
quality specifications. Customer shall execute or cause its supplier to execute,
if such supplier has retained processing rights to the gas delivered to
Customer, the appropriate agreements prior to the commencement of service for
the transportation and processing of any liquefiable hydrocarbons and any PVR
quantities associated with the processing of gas received by Pipeline at the
Point(s) of Receipt under such Customer's service agreement. In addition,
subject to the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered for
transportation hereunder.

                                   ARTICLE VI

                                    ADDRESSES

         Except as herein otherwise provided or as provided in the General Terms
and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Service Agreement, or any notice
which any party may desire to give to the other, shall be in writing and shall
be considered as duly delivered when mailed by registered, certified, or regular
mail to the post office address of the parties hereto, as the case may be, as
follows:

         (a)  Pipeline:    TEXAS EASTERN TRANSMISSION CORPORATION
                           5400 Westheimer Court
                           Houston, TX 77056-5310

         (b)  Customer:    UGI UTILITIES, INC.
                           100 Kachel Blvd.
                           P.O. Box 12677
                           Reading, PA 19612-2677

or such other address as either party shall designate by formal written notice.

                                   ARTICLE VII

                                      -4-
   5
                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

                                   ASSIGNMENTS

         Any Company which shall succeed by purchase, merger, or consolidation
to the properties, substantially as an entirety, of Customer, or of Pipeline, as
the case may be, shall be entitled to the rights and shall be subject to the
obligations of its predecessor in title under this Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement under the
provisions of any mortgage, deed of trust, indenture, bank credit agreement,
assignment, receivable sale, or similar instrument which it has executed or may
execute hereafter; otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first shall have
obtained the consent; thereto in writing of the other; provided further,
however, that neither Customer nor Pipeline shall be released from its
obligations hereunder without the consent of the other. In addition, Customer
may assign its rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it releases capacity
pursuant to Section 3.14 of the General Terms and Conditions, Customer may
require privity between Customer and the Replacement Customer, as further
provided in the applicable Capacity Release Umbrella Agreement.

                                  ARTICLE VIII

                                 INTERPRETATION

         The interpretation and performance of this Service Agreement shall be
in accordance with the laws of the State of Texas without recourse to the law
governing conflict of laws.

         This Service Agreement and the obligations of the parties are subject
to all present and future valid laws with respect to the subject matter, State
and Federal, and to all valid present and future orders, rules, and regulations
of duly constituted authorities having jurisdiction.

                                   ARTICLE IX

                        CANCELLATION OF PRIOR CONTRACT(S)

         This Service Agreement supersedes and cancels, as of the effective date
of this Service Agreement, the contract(s) between the parties hereto as
described below:

                  service agreement dated December 8, 1995, between Pipeline and
                  Customer under Pipeline's Rate Schedule CDS (Pipeline's
                  Contract No. 800397).

         IN WITNESS WHEREOF, the parties hereto have caused this Service
Agreement to be signed by their respective Presidents, Vice Presidents or other
duly authorized agents and their

                                      -5-
   6
                                                             Contract #: 800397R

                                SERVICE AGREEMENT
                              FOR RATE SCHEDULE CDS
                                   (Continued)

respective corporate seals to be hereto affixed and attested by their respective
Secretaries or Assistant Secretaries, the day and year first above written.

                                       TEXAS EASTERN TRANSMISSION CORPORATION

                                       By:
                                          --------------------------------------

ATTEST:

- --------------------------
Assistant Secretary

                                       UGI UTILITIES, INC.

                                       By:
                                          --------------------------------------
                                            Robert J. Chaney
                                            Executive Vice President

ATTEST:

- --------------------------
Brendan P. Bovaird
Secretary

                                      -6-
   7
                                                             Contract #: 800397R

                         EXHIBIT A, TRANSPORTATION PATHS
                       FOR BILLING PURPOSES, DATED 2/23/99
                TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
                 BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION
                        UGI UTILITIES, INC. ("Customer"),
                                 DATED 2/23/99:

(1)      Customer's firm Point(s) of Receipt:

                                                      Maximum Daily
                                                         Receipt
                                                     Obligation (plus
Point of                                                Applicable        Measurement
Receipt                Description                   Shrinkage) (dth)     Responsibilities     Owner       Operator *
- -------                -----------                   ----------------     ----------------     -----       ----------

71200         CHEVRON - VENICE, LA PLAQUEMINES            16,475          CHEVRON              CHEVRON     CHEVRON USA
              PA., LA                                                     USA                  USA

71750         COLUMBIA GULF - ST. LANDRY PA.,             24,525          COLUMBIA             COLUMBIA    COLUMBIA
              LA ST LANDRY PA, LA                                         GULF                 GULF        GULF

70011         COLUMBIA GAS - EAGLE, PA.,                       0          TX EAST              TX EAST     COLUMBIA
              CHESTER CO., PA                                             TRAN                 TRAN        GAS

75577         COLUMBIA GAS - PENNSBURG, PA.,                   0          TX EAST              TX EAST     COLUMBIA
              BUCKS CO., PA                                               TRAN                 TRAN        GAS

                                                              * Confirming Party

(2)      Customer shall have Pipeline's Master Receipt Point List ("MRPL").
         Customer hereby agrees that Pipeline's MRPL as revised and published by
         Pipeline from time to time is incorporated herein by reference.

Customer hereby agrees to comply with the Receipt Pressure obligation as set
forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s)
of Receipt.

                                       A-1
   8
                                                             Contract #: 800397R

                   EXHIBIT A, TRANSPORTATION PATHS, continued
                               UGI UTILITIES, INC.

                                        Transportation
Transportation Path                  Path Quantity-(Dth/D)
- -------------------                  ---------------------

Ml to M3                                     41,000

SIGNED FOR IDENTIFICATION

PIPELINE:
           ---------------------------------

CUSTOMER:
           ---------------------------------

SUPERSEDES EXHIBIT A DATED:
                             ---------------

                                       A-2
   9
                                                             Contract #: 800397R

               EXHIBIT B, POINT(S) OF DELIVERY, EFFECTIVE 2/23/99
                TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
        BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
                       UGI UTILITIES, INC. ("Customer"),
                                EFFECTIVE 2/23/99

                                                Maximum
                                                 Daily
Point of                                        Delivery         Delivery Pressure         Measurement
Delivery           Description                 Obligation            Obligation            Responsibilities   Owner       Operator *
- --------           -----------                 ----------            ----------            ----------------   -----       ----------
                                                  (dth)

1.  70011      COLUMBIA GAS - EAGLE,           41,000 dth     AS PROVIDED IN SECTION 6     TX EAST            TX EAST     COLUMBIA
               PA CHESTER CO., PA               during the    OF THE GENERAL TERMS AND     TRAN               TRAN        GAS
                                                    period    CONDITIONS OF PIPELINE'S
                                                  April 16    FERC GAS TARIFF
                                                   through
                                               November 15
                                                   of each
                                                    year -
                                                 otherwise
                                                35,593 dth

2.  70069      UGI UTILITIES -                     5,190      AS PROVIDED IN SECTION 6     TX EAST            TX EAST     UGI
               COLUMBIA, PA LANCASTER                         OF THE GENERAL TERMS AND     TRAN               TRAN        UTILITIES
               CO., PA                                        CONDITIONS OF PIPELINE'S
                                                              FERC GAS TARIFF

3.  70070      UGI UTILITIES-LANCASTER,           41,000      AS PROVIDED IN SECTION 6     TX EAST            TX EAST     UGI
               PA  LANCASTER CO., PA                          OF THE GENERAL TERMS AND     TRAN               TRAN        UTILITIES
                                                              CONDITIONS OF PIPELINE'S
                                                              FERC GAS TARIFF

4.  70321      UGI UTILITIES - LEBANON,           17,000                                   TX EAST            TX EAST     UGI
               PA LEBANON CO., PA                                                          TRAN               TRAN        UTILITIES

5.  70322      UGI UTILITIES - READING,           41,000      400 POUNDS PER SQUARE        TX EAST            TX EAST     UGI
               PA BERKS CO., PA                               INCH GAUGE                   TRAN               TRAN        UTILITIES

6.  70486      UGI UTILITIES -                     6,500      400 POUNDS PER SQUARE,       TX EAST            TX EAST     UGI
               WOMELSDORF, PA BERKS                           INCH GAUGE                   TRAN               TRAN        UTILITIES
               CO., PA

7.  70519      UGI UTILITIES - DAUPHIN            41,000      400 POUNDS PER SQUARE        TX EAST            TX EAST     UGI
                CO., PA DAUPHIN CO.,                          INCH GAUGE                   TRAN               TRAN        UTILITIES

                                      B-1
   10
                                                             Contract #: 800397R

                   EXHIBIT B POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

                                                 Maximum
                                                   Daily
Point of                                         Delivery           Delivery Pressure      Measurement
Delivery            Description                 Obligation              Obligation         Responsibilities   Owner       Operator *
- --------            -----------                 ----------              ----------         ----------------   -----       ----------
                                                  (dth)

 8.  71461      COLUMBIA GAS - RICH                  5,190    SUCH PRESSURE AS MAY BE      TX EAST            COLUMBIA    UGI
               HILL, BUCKS CO., PA                            AVAILABLE BY PIPELINE AT     TRAN               GAS         UTILITIES
               THE POINT OF DELIVERY

9.  71528      UGI UTILITIES -                      7,200     300 POUNDS PER SQUARE        TX EAST            TX EAST     UGI
               LANCASTER CO., PA                              INCH GAUGE                   TRAN               TRAN        UTILITIES

10. 72571      COLUMBIA GAS - BERKS                   519     400 POUNDS PER SQUARE        TX EAST            COLUMBIA    UGI
               CO., PA                                        INCH GAUGE                   TRAN               GAS         UTILITIES

11. 79513      SS-1 STORAGE POINT                   3,612     N/A                          N/A                N/A         N/A
                                              04/01-10/31
                                                    3,612
                                              11/01-03/31

12. 75577      COLUMBIA GAS -                           0     AS PROVIDED IN SECTION 6     TX EAST            TX EAST     COLUMBIA
               PENNSBURG, PA, BUCKS                           OF THE GENERAL TERMS AND     TRAN               TRAN        GAS
               CO., PA                                        CONDITIONS OF PIPELINE'S
                                                              FERC GAS TARIFF

                                                              * Confirming Party

provided, however, that Pipeline is not obligated to deliver under Rate
Schedules FT-1, CDS and FTS-5 on any one day an aggregate of more than 88,418
dth per day to points of delivery 70011, 70069, 70070 and 71528 during the
period November 16 through April 15, and further provided, that during this time
period Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and
FTS-5 on any one day an aggregate of more than 94,904 dth to points of delivery
70321, 70322, 70486, 70519, 71461 and 72571;

and further provided, however, that until changed by a subsequent Agreement
between Pipeline and Customer, Pipeline's aggregate maximum daily delivery
obligations under this and all other firm Service Agreements existing between
Pipeline and Customer, shall in no event exceed the following:

                                      B-2
   11
                                                             Contract #: 800397R

                   EXHIBIT B POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

                                                 Aggregate Maximum Daily
            Point of Delivery                    Delivery Obligation (dth)
            -----------------                    -------------------------

                  No. 1                                  68,785

                  No. 2                                   5,190

                  No. 3                                  49,000

                  No. 4                                  17,000

                  No. 5                                  65,880

                  No. 6                                   6,500

                  No. 7                                  53,000

                  No. 8                                   5,190

                  No. 9                                  17,200

                  No. 10                                  7,186

                  No. 11                                  3,612

Further, pursuant to Section 14.9 of the General Terms and Conditions of
Pipeline's FERC Gas Tariff Sixth Revised Volume No. 1, Customer has been
allocated firm capacity at the Points of Delivery as shown below for deliveries
under Rate 'Schedules CDS, FT-1, SCT, and/or SS-1 at such pressure available in
Pipeline's facilities at the point of delivery, subject to receipt of such
quantities being acceptable to the Owner and Operator of the Point of Delivery:

                                           Section 14.9
                                               Firm
Point of                                     Capacity           Measurement
Delivery           Description                 (dth/d)          Responsibilities     Owner           Operator
- --------           -----------                 -------          ----------------     -----           --------

1.  70011     COLUMBIA GAS (MFGRS.) -          85,635           TX EAST TRAN         TX EAST TRAN    COLUMBIA GAS
              EAGLE, PA CHESTER CO.,      4/l/97-0/31/97
              PA                               49,635
                                          11/l/97-0/31/98

2.  70069     UGI UTILITIES -                  12,700           TX EAST TRAN         TX EAST TRAN    UGI UTILITIES
              COLUMBIA PA LANCASTER
              CO., PA

                                      B-3
   12
                                                             Contract #: 800397R

                   EXHIBIT B POINT(S) OF DELIVERY (Continued)
                               UGI UTILITIES, INC.

                                            Section 14.9
                                                Firm
Point of                                      Capacity     Measurement
Delivery          Description                  (dth/d)     Responsibilities   Owner            Operator
- --------          -----------                  -------     ----------------   -----            --------

3.  70070    UGI UTILITIES -                   31,328      TX EAST TRAN       TX EAST TRAN     UGI
             COLUMBIA, PA LANCASTER,                                                           UTILITIES
             PA LANCASTER CO., PA

4.  70321    UGI UTILITIES - LEBANON,           1,253      TX EAST TRAN       TX EAST TRAN     UGI
             PA LEBANON CO., PA                                                                UTILITIES

5.  70486    UGI UTILITIES -                    3,670      TX EAST TRAN       TX EAST TRAN     UGI
             WOMELSDORF, PA BERKS                                                              UTILITIES
             CO., PA

6.  71438    DAUPHIN CO. GAS -                  2,580      TX EAST TRAN       TX EAST TRAN     PENN FUEL
             ANNVILLE, LEBANON CO, PA

7.  71461    UGI UTILITIES - RICH                 840      TX EAST TRAN       COLUMBIA GAS     COLUMBIA GAS
             HILL, BUCKS Co., PA

8.  72571    UGI UTILITIES - BERKS,            13,984      TX EAST TRAN       COLUMBIA GAS     COLUMBIA GAS
             CO., PA

9.  75577    UGI UTILITIES -                   75,440      TX EAST TRAN       COLUMBIA GAS     COLUMBIA GAS
             PENNSBURG, PA BUCKS
             CO., PA

SIGNED FOR IDENTIFICATION

PIPELINE:
           -------------------------------------

CUSTOMER:
           -------------------------------------

SUPERSEDES EXHIBIT B EFFECTIVE
                                ----------------

                                      B-4
   13
                                                             Contract #: 800397R

    EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
         DATED 2/23/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
         BETWEEN TEXAS' EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
                UGI UTILITIES, INC. ("CUSTOMER"), DATED 2/23/99:

                          ZONE BOUNDARY ENTRY QUANTITY
                                      Dth/D

                                       To

==========================================================================================================================
  FROM     STX    ETX    WLA    ELA    M1-24   M1-30   M1-TXG   M1-TGC   M2-24   M2-30   M2-TXG    M2-TGC       M2      M3
                                                                           
- --------------------------------------------------------------------------------------------------------------------------
STX                                                               1487
- --------------------------------------------------------------------------------------------------------------------------
ETX                                      194             2249
- --------------------------------------------------------------------------------------------------------------------------
WLA                                                       684     1487
- --------------------------------------------------------------------------------------------------------------------------
ELA                                            34899
- --------------------------------------------------------------------------------------------------------------------------
M1-24                                                                      194
- --------------------------------------------------------------------------------------------------------------------------
M1-30                                                                            34899
- --------------------------------------------------------------------------------------------------------------------------
M1-TXG                                                                                     2933
- --------------------------------------------------------------------------------------------------------------------------
M1-TGC                                                                                               2974
- --------------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------------
M2                                                                                                                   41000
- --------------------------------------------------------------------------------------------------------------------------
M3
==========================================================================================================================

                                      C-1
   14
                                                             Contract #: 800397R

                              EXHIBIT C (Continued)
                               UGI UTILITIES, INC.

                           ZONE BOUNDARY EXIT QUANTITY
                                      Dth/D

                                       To

==========================================================================================================================
  FROM     STX    ETX    WLA    ELA    M1-24   M1-30   M1-TXG   M1-TGC   M2-24   M2-30   M2-TXG    M2-TGC       M2      M3
                                                                           
- --------------------------------------------------------------------------------------------------------------------------
STX
- --------------------------------------------------------------------------------------------------------------------------
ETX
- --------------------------------------------------------------------------------------------------------------------------
WLA
- --------------------------------------------------------------------------------------------------------------------------
ELA
- --------------------------------------------------------------------------------------------------------------------------
M1-24                                                                      194
- --------------------------------------------------------------------------------------------------------------------------
M1-30                                                                            34899
- --------------------------------------------------------------------------------------------------------------------------
M1-TXG                                                                                     2933
- --------------------------------------------------------------------------------------------------------------------------
M1-TGC                                                                                               2974
- --------------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------------
M2                                                                                                                   41000
- --------------------------------------------------------------------------------------------------------------------------
M3
==========================================================================================================================

SIGNED FOR IDENTIFICATION:

PIPELINE:
           ---------------------------------

CUSTOMER:
           ---------------------------------

SUPERCEDES EXHIBIT C DATED
                            ----------------

                                      C-2
   1
                                                                      Exhibit 13

                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
FINANCIAL REVIEW

BUSINESS OVERVIEW

Our domestic propane business is conducted through AmeriGas Partners, L.P.
("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the
"Operating Partnership"). We refer to AmeriGas Partners and the Operating
Partnership together as "the Partnership." At September 30, 2000, we held an
effective 58.4% interest in the Operating Partnership.

   UGI Utilities, Inc. ("UGI Utilities") 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. Gas Utility and Electric Utility are
together referred to as "Utilities."

   UGI Enterprises, Inc. ("Enterprises"), our "new business" arm, conducts an
energy marketing business ("Energy Services") and through other subsidiaries (1)
owns and operates a propane distribution business in Austria, the Czech Republic
and Slovakia ("FLAGA"); (2) owns and operates a heating, ventilation and
air-conditioning service business ("HVAC") and a retail hearth, spa and grill
products business in the Middle Atlantic states ("Hearth USA(TM)"); and (3)
participates in international propane joint-venture projects.

   This Financial Review should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the business segment information in Note 17.

RESULTS OF OPERATIONS

2000 COMPARED WITH 1999

CONSOLIDATED RESULTS. Our 2000 results reflect improved earnings from Utilities
partially offset by a decline in net income from AmeriGas Propane and
International Propane losses. Excluding the effect of merger termination fee
income in 1999, earnings per share increased 22% in 2000 reflecting a 15%
decline in average shares outstanding and higher net income.

                                                                                                         Variance-
                                                                                                         Favorable
                                                       2000                     1999                   (Unfavorable)
                                               ---------------------------------------------------------------------------
                                                           DILUTED                  Diluted                     Diluted
                                                 NET       EARNINGS        Net      Earnings         Net        Earnings
                                               INCOME       (LOSS)       Income      (Loss)         Income       (Loss)
                                               (LOSS)      PER SHARE     (Loss)     Per Share       (Loss)      Per Share
- --------------------------------------------------------------------------------------------------------------------------
                                                                                              
(Millions of dollars, except per share)

AmeriGas Propane                               $   --       $    --      $  4.5      $  0.14       $  (4.5)     $  (0.14)

Utilities                                        48.9          1.79        37.4         1.17          11.5          0.62

Energy Services                                   1.6          0.06         1.5         0.05           0.1          0.01

International Propane                            (5.6)        (0.20)       (0.1)          --          (5.5)        (0.20)

Other Enterprises (a)                            (3.8)        (0.14)       (3.6)       (0.11)         (0.2)        (0.03)

Corporate & Other                                 3.6          0.13         3.1         0.09           0.5          0.04

Merger termination
   fee, net (b)                                    --            --        12.9         0.40         (12.9)        (0.40)
- --------------------------------------------------------------------------------------------------------------------------
Total                                          $ 44.7      $   1.64      $ 55.7      $  1.74       $ (11.0)     $  (0.10)
- --------------------------------------------------------------------------------------------------------------------------

(a) Comprised principally of Hearth USA(TM), HVAC, and Enterprises' corporate
    and general expenses.

(b) Represents after-tax merger termination fee income, net of related expenses,
    associated with the Company's terminated Merger Agreement with Unisource
    Worldwide, Inc. See Note 14 to Consolidated Financial Statements.

SEGMENT RESULTS. The following table presents certain financial and statistical
information by business segment for 2000 and 1999:

                                                                             Increase
                                                 2000         1999          (Decrease)
- -------------------------------------------------------------------------------------------
                                                                         
(Millions of dollars)

AMERIGAS PROPANE

Revenues                                       $1,120.1      $872.5      $247.6      28.4%

Total margin                                   $  491.8      $481.7      $ 10.1       2.1%

EBITDA (a)                                     $  158.6      $158.8      $ (0.2)     (0.1)%

Operating income                               $   90.2      $ 92.5      $ (2.3)     (2.5)%

Retail gallons sold (millions)                    771.2       783.2       (12.0)     (1.5)%

Degree days - % warmer than normal (b)             13.7%        9.9%          -         -

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 -

   billions of cubic feet ("bcf")                  79.7        76.1         3.6       4.7%

Degree days - % warmer than normal                  9.9%       12.8%          -         -

ELECTRIC UTILITY (c)

Revenues                                       $   77.9      $ 75.0      $  2.9       3.9%

Total margin                                   $   40.5      $ 38.6      $  1.9       4.9%

EBITDA (a)                                     $   19.6      $ 16.7      $  2.9      17.4%

Operating income                               $   15.1      $ 12.7      $  2.4      18.9%

Sales - millions of kilowatt hours ("gwh")        907.2       900.4         6.8       0.8%

ENERGY SERVICES

Revenues                                       $  146.9      $ 90.4      $ 56.5      62.5%

Total margin                                   $    6.2      $  6.0      $  0.2       3.3%

EBITDA (a)                                     $    3.0      $  2.7      $  0.3      11.1%

Operating income                               $    2.8      $  2.6      $  0.2       7.7%

INTERNATIONAL PROPANE

Revenues                                       $   50.5      $   -       $ 50.5       N.M.

Total margin                                   $   20.8      $    -      $ 20.8       N.M.

EBITDA (a)                                     $    1.9      $ (0.1)     $  2.0       N.M.

Operating loss                                 $   (2.7)     $ (0.1)     $  2.6       N.M.
- -------------------------------------------------------------------------------------------

    N.M. - Not Meaningful

(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 under generally accepted accounting principles.

(b) Deviation from average heating degree days during the 30-year period from
    1961 to 1990, based upon national weather statistics provided by the
    National Oceanic and Atmospheric Administration ("NOAA") for 335 airports in
    the continental U.S.

(c) Electric Utility comprises the Company's regulated electric utility
    distribution business and its nonutility electric generation operations.

                                                                              13
   2
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)

AMERIGAS PROPANE. Based upon national heating degree day information,
temperatures in 2000 were 13.7% warmer than normal and 3.8% warmer than in 1999.
Retail volumes of propane sold were 12 million gallons lower, primarily a result
of the warmer weather's effect on residential heating gallons and a decline in
agricultural gallons as a result of a poor crop drying season. Partially
offsetting these decreases were higher motor fuel sales, reflecting the
continuing effects of our expanding National Accounts program, the volume impact
of our growing grill cylinder exchange business, PPX Prefilled Propane Xchange
("PPX(R)"), and acquisition-related volume increases.

   Total revenues from retail propane sales increased $160.5 million in 2000 due
to higher average selling prices. The higher average selling prices resulted
from significantly higher propane product costs. Wholesale propane revenues
increased $77.4 million reflecting (1) a $50.7 million increase as a result of
higher average wholesale prices and (2) a $26.7 million increase as a result of
higher wholesale volumes sold. Nonpropane revenues increased $9.7 million in
2000 reflecting higher customer fees, hauling, and PPX(R) cylinder sales
revenue. Cost of sales increased $237.5 million primarily as a result of the
higher propane product costs and greater wholesale volumes sold.

   Total margin increased $10.1 million in 2000 due to (1) greater volumes sold
to higher margin PPX(R) customers; (2) slightly higher average retail unit
margins; and (3) an increase in total margin from customer fees, and ancillary
sales and services.

   EBITDA in 2000 was comparable to 1999 as the increases in total margin and
higher other income were offset by higher operating expenses. Other income
increased $3.1 million due to, among other things, higher income from sales of
assets and higher finance charge income. Operating expenses of the Partnership
were $342.7 million in 2000 compared with $329.6 million in 1999 reflecting
incremental expenses from growth and operational initiatives and higher vehicle
fuel costs. Our growth and operational initiatives in 2000 included
significantly expanding PPX(R), acquiring retail propane businesses, and
developing and implementing more efficient methods of operating the business.
Although EBITDA in 2000 was about equal to 1999, operating income declined $2.3
million reflecting higher PPX(R) and acquisition-related charges for
depreciation and amortization.

GAS UTILITY. Weather in Gas Utility's service territory was 9.9% warmer than
normal in 2000 but 3.8% colder than in 1999. The increase in system throughput
during 2000 resulted from higher interruptible delivery service volumes and
higher sales to our firm retail ("core market") customers.

   The increase in Gas Utility's revenues during 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 2000 compared with $172.0 million
in 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 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 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 2000 from $33.2 million in
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.

ENERGY SERVICES. Revenues increased $56.5 million during 2000 primarily as a
result of higher natural gas prices and to a lesser extent higher volumes sold.
Total margin, EBITDA and operating income in 2000 were slightly higher than in
1999 due to the impact of the higher sales on total margin.

14
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                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------

INTERNATIONAL PROPANE. International Propane results include equity in our joint
venture projects in Romania and China and, in 2000, the results of FLAGA. The
results of FLAGA during 2000 were adversely affected by weather that was 9.6%
warmer than normal and by higher propane supply costs. The higher propane supply
costs resulted in lower than normal unit margins and price-induced conservation.
Equity income in 2000 from our China propane joint venture partnership was also
negatively impacted by higher propane product costs and customer conservation.

CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income in
2000 was $5.1 million, a decrease of $0.8 million from 1999, primarily
reflecting lower interest income on cash investments. Other Enterprises' results
in 2000 primarily reflect start-up costs and initial operating losses of Hearth
USA(TM). Results in 1999 include due diligence expenses associated with
Enterprises' domestic and international new business activities and start-up
expenses associated with Hearth USA(TM).

INTEREST EXPENSE AND INCOME TAXES. The higher interest expense in 2000 is a
result of an increase in the Partnership's long-term debt, higher interest under
the Partnership's and UGI Utilities' bank credit agreements, and interest on
FLAGA debt in 2000. The effective income tax rate was 46.4% in 2000 compared to
43.0% in 1999 which rate reflected a lower tax rate on merger termination fee
income.

1999 COMPARED WITH 1998

CONSOLIDATED RESULTS. Our consolidated net income in 1999 increased $15.4
million compared to 1998. The improvement in net income was due to one-time net
merger termination fee income of $12.9 million and higher net income from UGI
Utilities and AmeriGas Partners, offset in part by costs associated with
Enterprises' new business activities.

                                                                                                         Variance-
                                                                                                         Favorable
                                                       1999                     1998                   (Unfavorable)
                                               ---------------------------------------------------------------------------
                                                           DILUTED                  Diluted                     Diluted
                                                 NET       EARNINGS        Net      Earnings         Net        Earnings
                                               INCOME       (LOSS)       Income      (Loss)         Income       (Loss)
                                               (LOSS)      PER SHARE     (Loss)     Per Share       (Loss)      Per Share
- --------------------------------------------------------------------------------------------------------------------------

(Millions of dollars, except per share)

AmeriGas Propane                               $  4.5       $  0.14      $  1.9      $  0.06       $   2.6      $   0.08

Utilities                                        37.4          1.17        33.0         1.00           4.4          0.17

Energy Services                                   1.5          0.05         1.1         0.03           0.4          0.02

International Propane                            (0.1)            -        (0.5)       (0.01)          0.4          0.01

Other Enterprises                                (3.6)        (0.11)       (1.3)       (0.04)         (2.3)        (0.07)

Corporate & Other                                 3.1          0.09         6.1         0.18          (3.0)        (0.09)

Merger termination

   fee, net                                      12.9          0.40           -            -          12.9          0.40
- --------------------------------------------------------------------------------------------------------------------------
Total                                          $ 55.7       $  1.74      $ 40.3      $  1.22       $  15.4      $   0.52
- --------------------------------------------------------------------------------------------------------------------------

SEGMENT RESULTS. The following table presents certain financial and statistical
information by business segment for 1999 and 1998:

                                                                             Increase
                                                  1999        1998          (Decrease)
- -------------------------------------------------------------------------------------------
                                                                         
(Millions of dollars)

AMERIGAS PROPANE

Revenues                                         $872.5      $914.4      $(41.9)     (4.6)%

Total margin                                     $481.7      $470.6      $ 11.1       2.4%

EBITDA                                           $158.8      $153.3      $  5.5       3.6%

Operating income                                 $ 92.5      $ 87.9      $  4.6       5.2%

Retail gallons sold (millions)                    783.2       785.3        (2.1)     (0.3)%

Degree days - % warmer than normal                  9.9%        8.7%          -         -

GAS UTILITY

Revenues                                         $345.6      $350.2      $ (4.6)     (1.3)%

Total margin                                     $160.6      $157.2      $  3.4       2.2%

EBITDA                                           $ 87.0      $ 83.0      $  4.0       4.8%

Operating income                                 $ 68.0      $ 64.8      $  3.2       4.9%

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                                           $ 16.7      $ 13.6      $  3.1      22.8%

Operating income                                 $ 12.7      $  9.7      $  3.0      30.9%

Sales - gwh                                       900.4       876.4        24.0       2.7%

ENERGY SERVICES

Revenues                                         $ 90.4      $103.0      $(12.6)    (12.2)%

Total margin                                     $  6.0      $  4.7      $  1.3      27.7%

EBITDA                                           $  2.7      $  2.1      $  0.6      28.6%

Operating income                                 $  2.6      $  2.0      $  0.6      30.0%

INTERNATIONAL PROPANE

EBITDA                                           $ (0.1)     $ (1.0)     $  0.9      90.0%

Operating loss                                   $ (0.1)     $ (1.0)     $ (0.9)    (90.0)%

AMERIGAS PROPANE. Based upon national weather data, temperatures in 1999 were
9.9% warmer than normal and 1.3% warmer than in 1998. Retail volumes of propane
sold were slightly lower in 1999 primarily as a result of a 7.3 million decline
in agricultural gallons as a dry autumn reduced demand for crop drying.
Partially offsetting the decrease in agricultural gallons were higher motor fuel
sales, increased gallons sold through PPX(R), and, notwithstanding the warmer
weather, higher sales to our targeted residential customer market.

   Total revenues from retail propane sales declined $36.3 million in 1999
primarily due to lower average selling prices. The lower

                                                                              15
   4
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FINANCIAL REVIEW (continued)

average selling prices resulted from lower propane product costs. Wholesale
propane revenues declined $13.2 million reflecting (1) a $6.9 million decrease
as a result of lower average wholesale prices and (2) a $6.3 million decrease as
a result of lower wholesale volumes sold. Nonpropane revenues increased $7.6
million in 1999 reflecting higher appliance and cylinder sales, increased
terminal and hauling revenues, and greater customer fee revenues. Cost of sales
declined $53.0 million primarily as a result of lower propane product costs.

   Total margin increased $11.1 million in 1999 due to (1) slightly higher
average retail unit margin per gallon; (2) greater total margin from PPX; and
(3) an increase in total margin from appliance sales, customer fees and hauling
and terminal revenue.

   EBITDA and operating income were higher in 1999 as a result of (1) the higher
total margin and (2) higher other income. These increases were partially offset
by an increase in operating expenses. Other income, net, in 1998 included a $4.0
million loss from two interest rate protection agreements. Operating expenses of
the Partnership were $329.6 million in 1999 compared with $320.2 million in
1998. Operating expenses in 1998 are net of (1) $2.7 million of income from
lower required accruals for environmental matters and (2) $2.0 million of income
from lower required accruals for property taxes. Excluding the impact of these
items in the prior year, operating expenses of the Partnership increased $4.7
million in 1999 principally due to expenses associated with new business
initiatives.

GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than
normal in 1999 but 4.2% colder than in 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 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 1999, a decrease of $7.6 million from 1998, reflecting the
impact of core market industrial customers switching to delivery service.

   The increase in Gas Utility total margin in 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 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
1999.

   Gas Utility operating income was higher in 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 1998 are net of $1.6 million of income from an insurance
recovery. Excluding the impact of the insurance recovery in 1998, total Gas
Utility operating and administrative expenses in 1999 were essentially
unchanged.

ELECTRIC UTILITY. The increase in 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 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 1999 represented electricity we distributed for alternate
suppliers. Notwithstanding the increase in Electric Utility sales in 1999, cost
of sales decreased $1.8 million to $33.2 million. The impact of the higher 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.

ENERGY SERVICES. Total revenues from energy marketing in 1999 declined $12.6
million as a result of lower average gas prices and, to a lesser extent, a
decrease in billed volumes. Total margin increased $1.3 million reflecting
higher average margins from gas marketing and greater income from power
marketing and other services. EBITDA and operating income increased $0.6 million
in 1999 as a result of the higher margin offset by slightly higher operating
expenses.

INTERNATIONAL PROPANE. Results for 1999 and 1998 principally reflect the equity
results in our international propane joint venture projects.

CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income
was $5.9 million in 1999 compared with $8.6 million in 1998. Income in both
years principally comprises inter-

16
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                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------

est income on short-term investments and, in 1998, income from the sale of
certain equity securities. The decrease in operating income from Other
Enterprises in 1999 resulted from start-up costs associated with Hearth USA(TM)
retail and due diligence expenses associated with international propane business
opportunities.

INTEREST EXPENSE AND INCOME TAXES. The Company's interest expense in 1999 was
$84.6 million, comparable to the $84.4 million recorded in 1998. The effective
income tax rate in 1999 was 43.0% compared to an effective tax rate of 44.7% in
1998. The lower effective tax rate in 1999 is principally a result of a lower
tax rate on the merger termination fee income.

FINANCIAL CONDITION AND LIQUIDITY

CAPITALIZATION AND LIQUIDITY

Our cash and short-term investments totaled $101.7 million at September 30, 2000
compared with $55.6 million at September 30, 1999. Included in these amounts are
$56.3 million and $23.3 million, respectively, of cash and short-term
investments held by UGI.

   The primary sources of UGI's cash and short-term investments are the cash
dividends it receives from its wholly owned subsidiaries, AmeriGas, Inc. and UGI
Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is dependent upon
the receipt of distributions on the Common and Subordinated units of AmeriGas
Partners that we own. During 2000, 1999 and 1998, AmeriGas, Inc. and UGI
Utilities paid cash dividends to UGI as follows:

Year Ended September 30,                  2000     1999    1998
- ---------------------------------------------------------------
                                                 
(Millions of dollars)
AmeriGas                                 $51.6    $47.6   $55.2
UGI Utilities                             44.0     29.0    22.6
- ---------------------------------------------------------------
Total dividends to UGI                   $95.6    $76.6   $77.8
- ---------------------------------------------------------------

THE PARTNERSHIP. The Operating Partnership's primary sources of cash since its
formation in 1995 have been (1) cash generated by operations; (2) borrowings
under its Bank Credit Agreement; and (3) the issuance of $80 million of
long-term debt in 2000 and $70 million of long-term debt in 1999. On September
22, 2000, a shelf registration statement for the issuance of 9 million AmeriGas
Common Units was declared effective by the Securities and Exchange Commission.
In October 2000, the Partnership issued 2.3 million of its registered Common
Units in an underwritten public offering and received $40.6 million in cash
proceeds, including related capital contributions from our wholly owned,
second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"). These
proceeds were used to reduce Bank Credit Agreement indebtedness and for working
capital purposes.

   The Operating Partnership's Bank Credit Agreement, as amended, consists of
(1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition
Facility. The Revolving Credit Facility may be used for (1) working capital; (2)
capital expenditures; and (3) interest and Partnership distribution payments.
Revolving Credit Facility loans were $30 million at September 30, 2000 and $22
million at September 30, 1999. The Operating Partnership may borrow under its
Acquisition Facility to finance the purchase of propane businesses or propane
business assets. Loans outstanding under the Acquisition Facility at September
30, 2000 and 1999 were $70 million and $23 million, respectively. During 2000,
the Bank Credit Agreement was amended to, among other changes, extend the
Acquisition Facility termination date to September 15, 2002. Then-outstanding
borrowings under the Acquisition Facility will be due in their entirety on such
date.

   The Operating Partnership also has a credit agreement with the General
Partner to borrow up to $20 million on an unsecured, subordinated basis, to fund
(1) working capital; (2) capital expenditures; and (3) interest and Partnership
distribution payments. UGI has agreed to contribute up to $20 million to the
General Partner to fund such borrowings.

   During 2000, the Operating Partnership issued $80 million of Series E First
Mortgage Notes at an effective interest rate of 8.47%. The proceeds were used
principally to reduce Acquisition Facility borrowings and $10 million of
maturing First Mortgage Note debt.

   The Partnership's management believes that cash flow from operations and Bank
Credit Agreement borrowings will be sufficient to satisfy its liquidity needs in
fiscal 2001. For a more detailed discussion of the Partnership's credit
facilities, including financial covenant ratios, see Note 3.

UGI UTILITIES. 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.

   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

                                                                              17
   6
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FINANCIAL REVIEW (continued)

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.

FLAGA. FLAGA has a 9 million EURO working capital loan commitment and a 15
million EURO special purpose commitment from a foreign bank. Borrowings under
these commitments totaled 4.9 million EUROs and 13.5 million EUROs,
respectively, at September 30, 2000. Management believes that cash flow from
operations and borrowings under its special purpose facility, working capital
facility and a short-term credit facility from UGI will satisfy FLAGA's cash
needs in fiscal 2001.

CASH FLOWS

OPERATING ACTIVITIES. Cash flow from operating activities was $132.7 million in
2000 compared to $141.9 million in 1999 which included $12.9 million of
after-tax proceeds from the merger termination fee. As a result of significantly
higher propane and natural gas costs, cash flows from operating activities in
2000 reflect significantly higher accounts receivable, inventories and accounts
payable. Cash flow from operating activities before changes in operating working
capital declined modestly from $170.3 million in 1999 to $167.5 million in 2000.

INVESTING ACTIVITIES. We spent $71.0 million for property, plant and equipment
in 2000 compared with $70.2 million in 1999. The increase in 2000 resulted from
expenditures of FLAGA. Net cash paid for acquisitions, principally comprising
Partnership propane and HVAC business acquisitions, totaled $65.3 million in
2000 compared to $77.6 million in 1999 including $73.7 million for the purchase
of FLAGA.

FINANCING ACTIVITIES. We paid cash dividends on our Common Stock of $41.2
million in 2000 compared to $47.9 million in 1999 on fewer shares outstanding.
In 2000 and 1999, the Partnership paid (1) distributions to its public
unitholders totaling approximately $39 million; (2) the full minimum quarterly
distribution of $0.55 ("MQD") on all units we hold totaling $53.2 million; and
(3) $1.1 million to the General Partner. During 2000, the Operating Partnership
borrowed $116 million under the Acquisition Facility, and made Acquisition
Facility repayments totaling $69 million. In 2000, we used $9.6 million to
repurchase 0.5 million shares of UGI Common Stock. In 1999, we spent $133.1
million (including transaction costs) for the repurchase of 5.9 million shares
of UGI Common Stock, including 4.5 million shares repurchased through our Dutch
auction tender offer.

DIVIDENDS AND DISTRIBUTIONS

In April 2000, our board of directors increased the annual dividend rate to
$1.55 a share from $1.50. Dividends declared in 2000 totaled $41.4 million.

   At September 30, 2000, our 58.4% effective interest in the Partnership
consisted of (1) 14.3 million Common Units; (2) 9.9 million Subordinated Units;
and (3) a 2% general partner interest. The remaining 41.6% effective interest
consists of 17.8 million publicly held Common Units. As a result of the
Partnership's October 2000 issue of 2.3 million Common Units pursuant to a
public offering, our effective interest in the Partnership declined to 55.5%.
Approximately 45 days after the end of each fiscal quarter, the Partnership
distributes all of its Available Cash (as defined in the Agreement of Limited
Partnership of AmeriGas Partners, the "Partnership Agreement") relating to such
fiscal quarter. Common Unitholders receive the MQD, plus any arrearages, before
a distribution of Available Cash can be made on the Subordinated Units.

   Since its formation in 1995, the Partnership has paid the MQD on all limited
partner units outstanding. The amount of Available Cash needed annually to pay
the MQD on all units and the general partner interests in 2000, 1999 and 1998
was approximately $94 million. In fiscal 2001, as a result of the additional
Common Units issued in October 2000, this amount will increase to approximately
$99 million. One measure of the amount of cash available for distribution that
is generated by the Partnership can be determined by subtracting (1) cash
interest expense and (2) capital expenditures needed to maintain operating
capacity, from the Partnership's EBITDA. Partnership distributable cash flow as
calculated for 2000, 1999 and 1998 is as follows:

Year Ended September 30,                  2000     1999     1998
- ------------------------------------------------------------------
                                                  
(Millions of dollars)
EBITDA                                   $157.6   $157.5   $151.1
Cash interest expense (a)                 (76.7)   (68.3)   (67.6)
Maintenance capital expenditures          (11.6)   (11.1)   (10.3)
- ------------------------------------------------------------------
Distributable cash flow                  $ 69.3   $ 78.1   $ 73.2
- ------------------------------------------------------------------

(a) Interest expense adjusted for noncash items.

   Although distributable cash flow is a reasonable estimate of the amount of
cash generated by the Partnership, it does not reflect the impact of changes in
working capital which can significantly affect cash available for distribution
and it is not a measure of performance or financial condition under generally
accepted accounting principles but provides additional information for
evaluating the Partnership's ability to declare and pay the MQD. Although the

18
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                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------

levels of distributable cash flow in these years were less than the full MQD,
borrowings in 2000 and 1999, and cash generated from changes in working capital
in 1998, were more than sufficient to permit the Partnership to declare and pay
the full MQD. The ability of the Partnership to declare and pay the MQD on all
units depends upon a number of factors. These factors include (1) the level of
Partnership earnings; (2) the cash needs of the Partnership's operations
(including cash needed for maintaining and increasing operating capacity); (3)
changes in operating working capital; and (4) the Partnership's ability to
borrow under its Bank Credit Agreement, to refinance maturing debt, and to
increase its long-term debt. Some of these factors are affected by conditions
beyond our control including weather, competition in markets we serve, and the
cost of propane.

CONVERSION OF SUBORDINATED UNITS

Pursuant to the Partnership Agreement, a total of 9,891,074 Subordinated Units
held by the General Partner were converted to Common Units on May 18, 1999
because certain historical and projected cash generation-based requirements were
achieved as of March 31, 1999. The Partnership's ability to attain the
cash-based performance and distribution requirements necessary to convert the
remaining 9,891,072 Subordinated Units depends upon a number of factors,
including highly seasonal operating results, changes in working capital, asset
sales and debt refinancings. Due to significantly warmer-than-normal weather and
the impact of higher propane product costs on working capital, we did not
achieve the cash-based performance requirements as of any relevant quarter
through September 30, 2000. Due to the historical "look-back" provisions of the
conversion test, the possibility is remote that the Partnership will satisfy the
cash-based performance requirements for conversion any earlier than in respect
of the quarter ending March 31, 2002.

CAPITAL EXPENDITURES

In the following table, we present capital expenditures of our consolidated
operations (which include expenditures for capital leases but exclude
acquisitions) for 2000, 1999 and 1998. We also provide amounts we expect to
spend in fiscal 2001. We expect to finance a substantial portion of fiscal 2001
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.

Year Ended September 30,         2001       2000       1999       1998
- ----------------------------------------------------------------------
                                                     
(Millions of dollars)         (estimate)

AmeriGas Propane                 $28.9     $30.4      $34.6      $31.9

Utilities                         40.9      36.4       36.4       37.2

International Propane              2.9       1.8          -          -

Other                              2.2       2.4        2.7        0.1
- ----------------------------------------------------------------------
Total                            $74.9     $71.0      $73.7      $69.2
- ----------------------------------------------------------------------

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 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 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 the 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, UGI Development Company ("UGIDC"), a subsidiary of UGI
Utilities, 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

                                                                              19
   8
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FINANCIAL REVIEW (continued)

to purchase 50% of the output of the joint venture at cost. The joint venture is
expected to become 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, 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 Public Utility Holding Company Act of 1935, UGI Utilities
divested all of its utility operations other than those which now constitute Gas
Utility and Electric Utility.

   UGI Utilities has been notified of several sites outside Pennsylvania on
which (1) gas plants were formerly operated by it or owned or operated by its
former subsidiaries and (2) either environmental agencies or private parties are
investigating the extent of environmental contamination or performing
environmental remediation. UGI Utilities is currently litigating two claims
against it relating to out-of state sites.

   Management believes that 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 (1) itself operated the facility causing the environmental
damage or (2) 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 (1) UGI
Utilities formerly conducted some MGP operations or (2) 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 2000, UGI Utilities entered
into settlement agreements with several of the insurers and recorded pre-tax
income of $4.5 million.

MARKET RISK DISCLOSURES

Our primary market risk exposures are (1) fluctuations in market prices for
propane, natural gas and electricity; (2) changes in interest rates; and (3)
foreign currency exchange rates.

   The Partnership's profitability is sensitive to changes in propane supply
costs, and the Partnership generally attempts to pass on promptly increases in
such costs to customers. There is no assurance, however, that the Partnership
will be able to do so. In order to manage a portion of the Partnership's propane
market price risk, it uses contracts for the forward purchase of propane,
propane fixed-price supply agreements, and derivative commodity instruments such
as price swap and option contracts. Due to competitive and business conditions
in the markets it serves, FLAGA is less able than the Partnership to recover
promptly increases in product costs. FLAGA does not currently use derivative
commodity instruments to hedge propane market risk. In order to manage market
price risk relating to substantially all of Energy Services' forecasted sales of
natural gas, we purchase exchange-traded natural gas futures contracts. In
addition, we occasionally utilize a managed program of derivative instruments
including natural gas and oil futures contracts to preserve gross margin
associated with certain of our natural gas customers. Although we use derivative
financial and commodity instruments to reduce market price risk associated with
forecasted transactions, we do not use derivative financial and commodity
instruments for speculative or trading purposes.

   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.

   Electric Utility purchases electricity it does not otherwise pro-

20
   9
                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------

duce, representing approximately 50% of its electric power needs in 2000, 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 contracts 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 electricity will negatively impact Electric
Utility's results.

   We have market risk exposure from changes in interest rates on floating rate
borrowings under the Operating Partnership's Bank Credit Agreement, UGI
Utilities' revolving credit agreements and substantially all of FLAGA's debt.
These debt agreements have interest rates that are generally indexed to
short-term market interest rates. At September 30, 2000 and 1999, combined
borrowings outstanding under these facilities totaled $282.1 million and $221.0
million, respectively. Based upon average borrowings under these agreements
during 2000 and 1999, an increase in short-term interest rates of 100 basis
points (1%) would have increased interest expense by $2.5 million and $1.2
million, respectively. We also use fixed-rate long-term debt as a source of
capital. As these fixed-rate long-term debt issues mature, we intend to
refinance such debt with new debt having interest rates reflecting then-current
market conditions. This debt may have an interest rate that is more or less than
the refinanced debt. On occasion, we enter into interest rate protection
agreements to reduce interest rate risk associated with a forecasted issuance of
debt.

   We do not currently use derivative instruments to hedge foreign currency
exposure associated with our investments in international propane operations,
principally FLAGA. As a result, the U.S. dollar value of our foreign denominated
assets and liabilities will fluctuate with changes in the associated foreign
currency exchange rates. Our exposure to changes in foreign currency exchange
rates has been significantly limited, however, because our net investment in
FLAGA, our principal international propane operation, was financed with EURO
denominated debt.

   The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at September 30, 2000 and 1999. It also
includes the changes in fair value that would result if there were an adverse
change in (1) the market price of propane of 10 cents a gallon; (2) the market
price of natural gas of 50 cents a dekatherm; (3) interest rates on ten-year
U.S. treasury notes of 100 basis points; and (4) the market price of oil of 10
cents a gallon:

                                                              Change in
                                              Fair Value      Fair Value
- ------------------------------------------------------------------------
                                                        
(Millions of dollars)
September 30, 2000:
   Propane commodity price risk                     $6.5          $(10.5)
   Natural gas commodity price risk                  4.2            (3.5)
   Interest rate risk                                2.5            (3.9)

September 30, 1999:
   Propane commodity price risk                     $2.9           $(2.5)
   Natural gas commodity price risk                  2.6            (5.2)
   Interest rate risk                                3.2            (3.8)
   Oil commodity price risk                         (0.2)           (0.5)
- ------------------------------------------------------------------------

We expect that adverse changes in the fair value of derivative instruments used
to manage commodity or interest rate market risk would be substantially offset
by gains on the associated underlying transactions.

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. To the extent derivative instruments qualify and are designated as
hedges of the variability in cash flows associated with forecasted transactions,
the effective portion of the gain or loss on such derivative instruments will
generally be reported in other comprehensive income and the ineffective portion,
if any, will be reported in net income. Such amounts recorded in accumulated
other comprehensive income will be reclassified into net income when the
forecasted transaction affects earnings. To the extent derivative instruments
qualify and are designated as hedges of changes in the fair value of an existing
asset, liability or firm commitment, the gain or loss on the hedging instrument
will be recognized currently in earnings along with changes in the fair value of
the hedged asset, liability or firm commitment attributable to the hedged risk.

                                                                              21
   10
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)

   The Company was required to adopt the provisions of SFAS 133 effective
October 1, 2000. Virtually all of the Company's derivative instruments
outstanding as of October 1, 2000 qualify and have been designated as hedging
the variability in cash flows associated with forecasted transactions. The
adoption of SFAS 133 will result in an after-tax cumulative effect charge to net
income of $0.3 million, and an after-tax cumulative effect increase to
accumulated other comprehensive income of $7.1 million. Because the Company's
derivative instruments historically have been highly effective in hedging the
exposure to changes in cash flows associated with forecasted purchases or sales
of natural gas and propane, changes in the fair value of propane inventories,
and changes in the risk-free rate of interest on anticipated issuances of
long-term debt, we do not expect the adoption of SFAS 133 to have a material
impact on our future results of operations.

   Although the Company expects the derivative instruments it currently uses to
hedge to continue to be highly effective, if they are determined not to be
highly effective in the future, or if the Company uses derivative instruments
that do not meet the stringent requirements for hedge accounting under SFAS 133,
our future earnings could reflect greater volatility. Additionally, if a cash
flow hedge is discontinued because the forecasted transaction is no longer
expected to occur, any gain or loss in accumulated comprehensive income
associated with the hedged transaction will be immediately recognized in net
income.

    In order to comply with the provisions of the Securities and Exchange
Commission Staff Accounting Bulletin No. 101 ("SAB 101") entitled "Revenue
Recognition", which is effective for the Company on October 1, 2000, the Company
will record a cumulative effect charge to net income of approximately $2.3
million related to the Partnership's method of recognizing revenue associated
with nonrefundable tank fees largely for residential customers. Consistent with
a number of its competitors in the propane industry, the Partnership receives
nonrefundable fees for installed Partnership-owned tanks. Historically, such
fees, which are generally received annually, were recorded as revenue when
billed. In accordance with SAB 101, effective October 1, 2000, the Partnership
will record such nonrefundable fees on a straight-line basis over one year. The
adoption of SAB 101 is not expected to have a material impact on the Company's
future financial condition or results of operations.

   Also, during fiscal 2001, the Partnership plans to change its method of
accounting for tank installation costs which are not billed to customers.
Currently, all direct costs to install Partnership-owned tanks at a customer
location are expensed as incurred. The Partnership believes that these costs
should now be capitalized and amortized over the period benefited. On date of
adoption, this change in accounting method will result in a cumulative effect
increase to net income. The Company is in the process of evaluating the impact
of such change on its financial condition and results of operations.

PROPOSED FOREIGN EQUITY INVESTMENT

On October 30, 2000, the Company, together with Paribas Affaires Industrielles
("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), submitted to Total Fina
Elf S. A. ("TFE"), a large French petroleum and chemical company, a bid to
acquire the stock and certain related assets of Elf AntarGaz S.A. ("EAZ"). EAZ,
a subsidiary of TFE, is one of the largest distributors of liquefied petroleum
gas in France with an approximate 24% market share. Under the terms of the bid,
the Company would acquire a 20% interest in EAZ; PAI a 70% interest; and Medit a
10% interest. PAI is a leading private equity fund manager in Europe and an
affiliate of BNP Partners. BNP Partners is one of Europe's largest commercial
and investment banks. Medit is a supplier of logistics services to the liquefied
petroleum gas industry in Europe, primarily Italy. The amount of the Company's
investment in EAZ is not expected to exceed $30 million. The bid is subject to
approval by the Commission of the European Communities. There can be no
assurance, however, that the bid will be approved or that other requirements for
consummation of the transaction will be met.

FORWARD-LOOKING STATEMENTS

Information contained in this Financial Review and elsewhere in this Annual
Report with respect to expected financial results and future events is
forward-looking, based on our estimates and assumptions and subject to risks 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 actual 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 propane, oil, electricity, and
natural gas and the capacity to transport product 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)

22
   11
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 transporting, storing and distributing natural
gas and propane including the risk of explosions and fires resulting in personal
injury and property damage; (10) regional economic conditions; (11) political,
regulatory and economic conditions in foreign countries; (12) interest rate
fluctuations and other capital market conditions, including foreign currency
rate fluctuations; (13) reduced distributions from subsidiaries; and (14) the
timing and success of the Company's efforts to develop new business
opportunities.

   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.

                                                                              23
   12
                                              UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
REPORT OF MANAGEMENT

The Company's consolidated financial statements and other financial information
contained in this Annual Report are prepared by management, which is responsible
for their fairness, integrity and objectivity. The consolidated financial
statements and related information were prepared in accordance with accounting
principles generally accepted in the United States and include amounts that are
based on management's best judgements and estimates.

   The Company maintains a system of internal controls. Management believes the
system provides reasonable assurance that assets are safeguarded and that
transactions are executed in accordance with management's authorization and are
properly recorded to permit the preparation of reliable financial information.
There are limits in all systems of internal control, based on the recognition
that the cost of the system should not exceed the benefits to be derived. We
believe that the Company's internal control system is cost effective and
provides reasonable assurance that material errors or irregularities will be
prevented or detected within a timely period. The internal control system and
compliance therewith are monitored by the Company's internal audit staff.

   The Audit Committee of the Board of Directors is composed of three members,
none of whom is an employee of the Company. This Committee is responsible for
overseeing the financial reporting process and the adequacy of controls, and for
monitoring the independence of the Company's independent public accountants and
the performance of the independent accountants and internal audit staff. The
Committee recommends to the Board of Directors the engagement of the independent
public accountants to conduct the annual audit of the Company's consolidated
financial statements. The Committee is also responsible for maintaining direct
channels of communication between the Board of Directors and both the
independent public accountants and internal auditors.

   The independent public accountants, who are appointed by the Board of
Directors and ratified by the shareholders, perform certain procedures,
including an evaluation of internal controls to the extent required by auditing
standards generally accepted in the United States, in order to express an
opinion on the consolidated financial statements and to obtain reasonable
assurance that such financial statements are free of material misstatement.

/s/ Lon. R. Greenberg

Lon. R. Greenberg

Chief Executive Officer

/s/ Anthony J. Mendicino

Anthony J. Mendicino

Chief Financial Officer

- --------------------------------------------------------------------------------
Report of Independent Public Accountants

TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:

We have audited the accompanying consolidated balance sheets of UGI Corporation
and subsidiaries as of September 30, 2000 and 1999, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended September 30, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based upon our audits.

   We conducted our audits in accordance with auditing standards generally
accepted in the United States. These 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 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 Corporation 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.

/s/ Arthur Andersen LLP

Philadelphia, Pennsylvania
November 10, 2000

24
   13

                                              UGI Corporation 2000 Annual Report

CONSOLIDATED STATEMENTS OF INCOME
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)

                                                                    Year Ended September 30,
                                                        ----------------------------------------------
                                                            2000              1999              1998
                                                        ----------        ----------        ----------
                                                                                   
REVENUES
AmeriGas Propane                                        $  1,120.1        $    872.5        $    914.4
UGI Utilities                                                436.9             420.6             422.3
International Propane                                         50.5              --                --
Energy Services and other                                    154.2              90.5             103.0
                                                        ----------        ----------        ----------
                                                           1,761.7           1,383.6           1,439.7
                                                        ----------        ----------        ----------
COSTS AND EXPENSES
AmeriGas Propane cost of sales                               628.3             390.8             443.8
UGI Utilities - gas, fuel and purchased power                218.1             205.2             214.6
International Propane cost of sales                           29.7              --                --
Energy Services and other cost of sales                      145.5              84.4              98.3
Operating and administrative expenses                        461.2             429.2             412.5
Utility taxes other than income taxes                         17.1              25.2              25.2
Depreciation and amortization                                 97.5              89.7              87.8
Other income, net                                            (26.9)            (16.8)            (12.7)
                                                        ----------        ----------        ----------
                                                           1,570.5           1,207.7           1,269.5
                                                        ----------        ----------        ----------
OPERATING INCOME                                             191.2             175.9             170.2
Merger fee income and expenses, net                           --                19.9              --
Interest expense                                             (98.5)            (84.6)            (84.4)
Minority interest in AmeriGas Partners                        (6.3)            (10.7)             (8.9)
                                                        ----------        ----------        ----------
INCOME BEFORE INCOME TAXES AND SUBSIDIARY
   PREFERRED STOCK DIVIDENDS                                  86.4             100.5              76.9
Income taxes                                                 (40.1)            (43.2)            (34.4)
Dividends on UGI Utilities Series Preferred Stock             (1.6)             (1.6)             (2.2)
                                                        ----------        ----------        ----------
NET INCOME                                              $     44.7        $     55.7        $     40.3
                                                        ----------        ----------        ----------
EARNINGS PER COMMON SHARE
Basic                                                   $     1.64        $     1.74        $     1.22
Diluted                                                 $     1.64        $     1.74        $     1.22

AVERAGE COMMON SHARES OUTSTANDING (MILLIONS)
Basic                                                       27.219            31.954            32.971
Diluted                                                     27.255            32.016            33.123
                                                        ==========        ==========        ==========

See accompanying notes to consolidated financial statements.

                                                                              25
   14
                                              UGI Corporation 2000 Annual Report

CONSOLIDATED BALANCE SHEETS
(Millions of dollars)

                                                                          September 30,
                                                                      ------------------------
ASSETS                                                                   2000          1999
                                                                      --------        --------
                                                                                
CURRENT ASSETS
Cash and cash equivalents                                             $   93.9        $   40.5
Short-term investments, at cost which approximates market value            7.8            15.1
Accounts receivable (less allowances for doubtful accounts of
   $9.3 and $8.0, respectively)                                          165.7           107.5
Accrued utility revenues                                                  10.5             6.9
Inventories                                                              117.4            87.1
Deferred income taxes                                                     11.8            13.7
Prepaid expenses and other current assets                                 19.0            24.7
                                                                      --------        --------
   Total current assets                                                  426.1           295.5
                                                                      --------        --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane                                                         722.1           680.7
UGI Utilities                                                            857.8           826.8
Other                                                                     72.2            91.5
                                                                      --------        --------
                                                                       1,652.1         1,599.0
Accumulated depreciation and amortization                               (578.9)         (514.9)
                                                                      --------        --------
   Net property, plant and equipment                                   1,073.2         1,084.1
                                                                      --------        --------
OTHER ASSETS
Intangible assets (less accumulated amortization of $190.2 and
   $165.9, respectively)                                                 675.5           653.1
Utility regulatory assets                                                 62.3            61.1
Other assets                                                              41.7            46.7
                                                                      --------        --------
   TOTAL ASSETS                                                       $2,278.8        $2,140.5
                                                                      ========        ========

See accompanying notes to consolidated financial statements.

26
   15
                                              UGI Corporation 2000 Annual Report

                                                                             September 30,
                                                                        -------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY                                       2000           1999
                                                                        --------        --------
                                                                                  
CURRENT LIABILITIES
Current maturities of long-term debt                                    $   85.9        $   26.7
Operating Partnership bank loans                                            30.0            22.0
UGI Utilities bank loans                                                   100.4            87.4
Other bank loans                                                             4.3            11.6
Accounts payable                                                           156.7           100.6
Employee compensation and benefits accrued                                  26.5            34.4
Dividends and interest accrued                                              47.3            44.1
Income taxes accrued                                                        10.3             0.6
Deposits and refunds                                                        39.0            40.2
Other current liabilities                                                   39.0            39.3
                                                                        --------        --------
   Total current liabilities                                               539.4           406.9
                                                                        --------        --------
DEBT AND OTHER LIABILITIES
Long-term debt                                                           1,029.7           989.6
Deferred income taxes                                                      172.9           174.3
Deferred investment tax credits                                              9.2             9.6
Other noncurrent liabilities                                                83.3            81.0

Commitments and contingencies (note 11)
                                                                        --------        --------
MINORITY INTEREST
Minority interest in AmeriGas Partners                                     177.1           209.9
                                                                        --------        --------
PREFERRED AND PREFERENCE STOCK
UGI Utilities Series Preferred Stock Subject to Mandatory
   Redemption, without par value                                            20.0            20.0
Preference Stock, without par value (authorized-5,000,000 shares)            --              --

COMMON STOCKHOLDERS' EQUITY
Common Stock, without par value
   (authorized-100,000,000 shares; issued-33,198,731 shares)               394.5           394.8
Accumulated deficit                                                         (4.9)           (8.2)
Accumulated other comprehensive income                                      --               0.5
Unearned compensation-restricted stock                                      (0.7)           (1.7)
                                                                        --------        --------
                                                                           388.9           385.4
Treasury stock, at cost                                                   (141.7)         (136.2)
                                                                        --------        --------
   Total common stockholders' equity                                       247.2           249.2
                                                                        --------        --------
   Total liabilities and stockholders' equity                           $2,278.8        $2,140.5
                                                                        ========        ========

                                                                              27
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                                              UGI Corporation 2000 Annual Report

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)

                                                                    Year Ended September 30,
                                                              -----------------------------------
                                                               2000          1999           1998
                                                              ------        ------        ------
                                                                                 
CASH FLOWS FROM OPERATING ACTIVITIES
Net income                                                    $ 44.7        $ 55.7        $ 40.3
Reconcile to net cash provided by operating activities:
   Depreciation and amortization                                97.5          89.7          87.8
   Minority interest in AmeriGas Partners                        6.3          10.7           8.9
   Deferred income taxes, net                                    3.2           7.7          10.1
   Other, net                                                   15.8           6.5           4.9
                                                              ------        ------        ------
                                                               167.5         170.3         152.0
   Net change in:
      Receivables and accrued utility revenues                 (63.4)        (25.1)         22.0
      Inventories and prepaid propane purchases                (26.1)         (5.0)         39.0
      Deferred fuel costs                                       (3.8)         (5.1)         (5.8)
      Accounts payable                                          52.0          17.4         (23.5)
      Other current assets and liabilities                       6.5         (10.6)         (5.2)
                                                              ------        ------        ------
   Net cash provided by operating activities                   132.7         141.9         178.5
                                                              ------        ------        ------

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment                 (71.0)        (70.2)        (69.2)
Acquisitions of businesses, net of cash acquired               (65.3)        (77.6)         (8.1)
Short-term investments (increase) decrease                       7.3          66.7         (16.4)
Net proceeds from disposals of assets                            8.4           4.9           7.9
Investments in joint venture partnerships                       --            (4.9)         (2.0)
Other, net                                                      (0.9)         (5.4)         (2.3)
                                                              ------        ------        ------
   Net cash used by investing activities                      (121.5)        (86.5)        (90.1)
                                                              ------        ------        ------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on Common Stock                                      (41.2)        (47.9)        (47.6)
Distributions on Partnership public Common Units               (39.1)        (39.0)        (39.0)
Issuance of long-term debt                                     209.7         173.7          58.0
Repayment of long-term debt                                    (95.4)        (70.9)        (22.3)
AmeriGas Propane bank loans increase (decrease)                  8.0          12.0         (18.0)
UGI Utilities bank loans increase                               13.0          19.0           1.4
Other bank loans decrease                                       (6.8)         --            --
Issuance of Common Stock                                         3.8           4.7           8.5
Repurchases of Common Stock                                     (9.6)       (133.1)        (11.3)
Redemption of UGI Utilities Series Preferred Stock              --            --           (15.5)
                                                              ------        ------        ------
   Net cash provided (used) by financing activities             42.4         (81.5)        (85.8)
                                                              ------        ------        ------
Effect of exchange rate changes on cash                         (0.2)         --            --
                                                              ------        ------        ------
Cash and cash equivalents increase (decrease)                 $ 53.4        $(26.1)       $  2.6
                                                              ======        ======        ======

CASH AND CASH EQUIVALENTS
End of period                                                 $ 93.9        $ 40.5        $ 66.6
Beginning of period                                             40.5          66.6          64.0
                                                              ------        ------        ------
   Increase (decrease)                                        $ 53.4        $(26.1)       $  2.6
                                                              ======        ======        ======

See accompanying notes to consolidated financial statements.

28
   17
                                              UGI Corporation 2000 Annual Report

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Millions of dollars, except per share amounts)

                                                                         Accumulated       Unearned
                                                                           Other         Compensation-
                                                Common     Accumulated   Comprehensive     Restricted    Treasury
                                                Stock        Deficit        Income          Stock          Stock           Total
                                               ------      -----------   -------------   -------------   ---------        ------
                                                                                                       
BALANCE SEPTEMBER 30, 1997                     $393.7         $ (9.2)        $ --         $ --            $ (8.4)         $376.1
Net income                                                      40.3                                                        40.3
Cash dividends on Common Stock
   ($1.45 per share)                                           (47.8)                                                      (47.8)
Common Stock issued:
   Employee and director plans                    0.5           (0.7)                                        6.3             6.1
   Dividend reinvestment plan                                                                                2.8             2.8
   Acquisition                                    0.1                                                        1.1             1.2
Redemption of UGI Utilities Series
   Preferred Stock                                              (0.3)                                                       (0.3)
Common Stock repurchased                                                                                   (11.3)          (11.3)
                                               ------         ------         -----        ------          -------         ------

BALANCE SEPTEMBER 30, 1998                      394.3          (17.7)          --           --              (9.5)          367.1
Net income                                                      55.7                                                        55.7
Net unrealized gain on available
   for sale securities                                                         0.5                                           0.5
                                                              ------         -----                                        ------
Comprehensive income                                            55.7           0.5                                          56.2
Cash dividends on Common Stock
   ($1.47 per share)                                           (45.8)                                                      (45.8)
Common Stock issued:
   Employee and director plans                    0.4           (0.1)                                        3.4             3.7
   Dividend reinvestment plan                     0.1           (0.3)                                        3.0             2.8
Common Stock repurchased                                                                                  (133.1)         (133.1)
Issuance of restricted stock awards                                                         (2.1)                           (2.1)
Amortization of unearned compensation-
   restricted stock awards                                                                   0.4                             0.4
                                               ------         ------         -----        ------          -------         ------

BALANCE SEPTEMBER 30, 1999                      394.8           (8.2)          0.5          (1.7)         (136.2)          249.2
Net income                                                      44.7                                                        44.7
Reclassification of unrealized gain on
   available for sale securities                                              (0.5)                                         (0.5)
                                                              ------         -----                                        ------
Comprehensive income                                            44.7          (0.5)                                         44.2
Cash dividends on Common Stock
   ($1.525 per share)                                          (41.4)                                                      (41.4)
Common Stock issued:
   Employee and director plans                   (0.1)                                                       1.5             1.4
   Dividend reinvestment plan                    (0.2)                                                       2.6             2.4
Common Stock repurchased                                                                                    (9.6)           (9.6)
Amortization of unearned compensation-
   restricted stock awards                                                                   1.0                             1.0
                                               ------         ------         -----        ------          -------         ------
BALANCE SEPTEMBER 30, 2000                     $394.5         $ (4.9)        $ --         $ (0.7)         $(141.7)        $247.2
                                               ======         ======         =====        ======          =======         ======

See accompanying notes to consolidated financial statements.

                                                                              29
   18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Millions of dollars, except per share amounts and where indicated otherwise)

NOTE                                                                      PAGE
- ----                                                                      ----
                                                                        
1. Organization and Significant Accounting Policies                        30
2. Utility Regulatory Matters                                              34
3. Debt                                                                    35
4. Income Taxes                                                            37
5. Employee Retirement Plans                                               38
6. Inventories                                                             39
7. Series Preferred Stock                                                  39
8. Common Stock and Incentive Stock Award Plans                            40
9. Preference Stock Purchase Rights                                        41
10. Partnership Distributions                                              42
11. Commitments and Contingencies                                          43
12. Financial Instruments                                                  44
13. Acquisitions                                                           45
14. Terminated Merger-Unisource Worldwide, Inc.                            45
15. Other Income, Net                                                      45
16. Quarterly Data (Unaudited)                                             46
17. Segment Information                                                    46

NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION. UGI Corporation ("UGI") is a holding company that operates gas and
electric utility, propane distribution, energy marketing and related businesses
through subsidiaries. Our utility business is conducted through a wholly owned
subsidiary, UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities 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 (together we refer to them as "Utilities").

   We conduct a national propane distribution business through AmeriGas
Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas
Propane, L.P. (the "Operating Partnership"), both of which are Delaware limited
partnerships. Our wholly owned second-tier subsidiary, AmeriGas Propane, Inc.
(the "General Partner"), serves as the general partner of AmeriGas Partners and
the Operating Partnership. At September 30, 2000, the General Partner and its
wholly owned subsidiary Petrolane Incorporated ("Petrolane") held an effective
2% general partner interest and a 56.4% limited partner interest in the
Operating Partnership. We refer to AmeriGas Partners and the Operating
Partnership together as "the Partnership," and the General Partner and its
subsidiaries, including the Partnership, as "AmeriGas Propane." The Operating
Partnership is one of the largest retail propane distributors in the United
States serving residential, commercial, industrial, motor fuel and agricultural
customers from locations in 45 states, including Alaska and Hawaii. At September
30, 2000, our limited partner interest in AmeriGas Partners consisted of
14,283,932 Common Units and 9,891,072 Subordinated Units. The remaining 41.6%
effective interest in the Partnership comprises 17,794,361 publicly held Common
Units representing limited partner interests. In October 2000, AmeriGas Partners
issued 2,300,000 Common Units in a public offering for net cash proceeds of
approximately $40 million. After this transaction, the General Partner and
Petrolane held an effective 2% general partner interest and 53.5% limited
partner interest in the Operating Partnership.

   AmeriGas Partners and the Operating Partnership have no employees. Employees
of the General Partner conduct, direct and manage the activities of the
Partnership. The General Partner does not receive management fees or other
compensation in connection with managing the Partnership, but is reimbursed for
direct and indirect expenses incurred on behalf of the Partnership, including
all General Partner employee compensation costs and a portion of UGI employee
compensation and administrative costs. Although the Partnership's operating
income represents a significant portion of our consolidated operating income,
the Partnership's impact on our consolidated net income is considerably less due
to (1) the Partnership's significant minority interest; (2) higher relative
interest charges; and (3) a higher effective income tax rate associated with the
Partnership's pre-tax income.

   Our wholly owned subsidiary, UGI Enterprises, Inc. ("Enterprises"), conducts
an energy marketing business through its wholly owned subsidiary, UGI Energy
Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (1)
owns and operates a propane distribution business, FLAGA GmbH ("FLAGA") in
Austria, the Czech Republic and Slovakia; (2) owns and operates a heating,
ventilation and air-conditioning service business ("HVAC") and a retail hearth,
spa and grill products business in the Middle Atlantic region of the U.S.; and
(3) participates in propane joint-venture projects in Romania and China.

   UGI is exempt from registration as a holding company and is not otherwise
subject to regulation under the Public Utility Holding Company Act of 1935
except for acquisitions under Section 9(a)(2). UGI is not subject to regulation
by the Pennsylvania Public Utility Commission ("PUC").

30
   19
CONSOLIDATION PRINCIPLES. Our consolidated financial statements include the
accounts of UGI and its majority-owned subsidiaries. We eliminate all
significant intercompany accounts and transactions when we consolidate. We
report the public unitholders' interest in AmeriGas Partners as minority
interest in the consolidated financial statements. The Company's investments in
international propane joint-venture projects are accounted for by the equity
method. Such investments did not materially impact the Company's results of
operations for the periods presented.

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 UTILITY OPERATIONS. Gas Utility and Electric Utility are subject to
regulation by the 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.

   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 No.
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.

DERIVATIVE INSTRUMENTS. We use derivative instruments, including futures
contracts, price swap agreements and option contracts, to hedge exposure to
market risk associated with (1) fluctuations in the price of forecasted
purchases of natural gas Energy Services sells under firm commitments and (2)
fluctuations in propane prices associated with a portion of our anticipated
propane purchases. On occasion we enter into interest rate protection agreements
to reduce interest rate risk associated with anticipated issuances of debt. In
addition, we occasionally utilize a managed program of derivative instruments
including natural gas and oil futures contracts to preserve gross margin
associated with certain of the Company's natural gas customers, which margin
otherwise could be affected by major energy commodity price movements.

   We defer gains or losses on futures contracts associated with forecasted
purchases of natural gas and record them in cost of sales when such purchases
affect earnings. We recognize gains or losses on derivative instruments
associated with forecasted purchases of propane or issuances of debt when such
transactions affect earnings. When it is probable that the original forecasted
transaction will not occur, we immediately recognize in earnings any gain or
loss on the related derivative instrument. If such derivative instrument is
terminated early for other economic reasons, we defer any gain or loss as of the
termination date until such time as the forecasted transaction affects earnings.

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 $96.9 million in 2000, $84.6 million in 1999,
and $83.5 million in 1998. We paid income taxes totaling $26.6 million in 2000,
$36.2 million in 1999, and $29.8 million in 1998.

REVENUE RECOGNITION. We recognize revenues from the sale of propane and related
equipment and supplies principally when shipped or delivered to customers. We
record Utilities' revenues for service provided to the end of each month. We
reflect Utilities' rate increases or decreases in revenues from effective dates
permitted by the PUC. Energy Services records revenues when product is delivered
to customers. See "Accounting Principles Not Yet Adopted" below.

INVENTORIES AND PREPAID PROPANE PURCHASES. 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.

   From time to time the Partnership enters into contracts with certain
suppliers requiring it to prepay all or a portion of the purchase price of a
fixed volume of propane for future delivery. These prepayments are included in
prepaid expenses and other current assets in the Consolidated Balance Sheets.

                                                                              31
   20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Millions of dollars, except per share amounts and where indicated otherwise)

EARNINGS PER COMMON SHARE. Basic earnings per share are based on the
weighted-average number of common shares outstanding. Diluted earnings per share
include the effects of dilutive stock options and awards. In the following
table, we present the shares used in computing basic and diluted earnings per
share for 2000, 1999 and 1998:

                                                      2000           1999          1998
                                                     ------         ------         ------
                                                                          
Denominator (millions of shares):
   Average common shares
      outstanding for basic computation              27.219         31.954         32.971
   Incremental shares issuable for stock
      options and awards                               .036           .062           .152
                                                     ------         ------         ------
Average common shares outstanding for
   diluted computation                               27.255         32.016         33.123
                                                     ------         ------         ------

INCOME TAXES. AmeriGas Partners and the Operating Partnership are not directly
subject to federal income taxes. Instead, their taxable income or loss is
allocated to the individual partners. We record income taxes on our share of (1)
the Partnership's current taxable income or loss and (2) the difference between
the book and tax basis of the Partnership's assets and liabilities. The
Operating Partnership does, however, have subsidiaries which operate in
corporate form and are directly subject to federal 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 records a deferred tax liability for tax benefits that are flowed
through to ratepayers when temporary differences originate and 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.

PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION.

We record property, plant and equipment at cost. The amounts we assign to
property, plant and equipment of businesses we acquire are based upon estimated
fair value at date of acquisition. When we retire Utilities' plant, we charge
its original cost and the net cost of its removal to accumulated depreciation
for financial accounting purposes. When we retire or dispose of other plant and
equipment, we remove from the accounts the cost and accumulated depreciation and
include in income any gains or losses.

   We record depreciation expense for Utilities' plant on a straight-line method
over the estimated average remaining lives of the various classes of its
depreciable property. Depreciation expense as a percentage of the related
average depreciable base for Gas Utility was 2.6% 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. We
compute depreciation expense on plant and equipment associated with our propane
operations using the straight-line method over estimated service lives generally
ranging from 15 to 40 years for buildings and improvements; 7 to 30 years for
storage and customer tanks and cylinders; and 5 to 10 years for vehicles,
equipment and office furniture and fixtures. Depreciation expense was $69.3
million in 2000, $63.6 million in 1999, and $61.4 million in 1998.

INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:

                                                                           2000           1999
                                                                          ------         ------
                                                                                   
Goodwill (less accumulated amortization of $126.6
   million and $109.8 million, respectively)                              $566.8         $538.4

Excess reorganization value (less accumulated
   amortization of $60.2 million and $52.3 million, respectively)          101.3          109.2

Other (less accumulated amortization of $3.4 million
   and $3.8 million, respectively)                                           7.4            5.5
                                                                          ------         ------
Total intangible assets                                                   $675.5         $653.1
                                                                          ======         ======

Substantially all of our goodwill is a result of propane purchase business
combinations. This goodwill is amortized on a straight-line basis over 40 years.
We amortize excess reorganization value (resulting from Petrolane's July 15,
1993 reorganization under Chapter 11 of the U.S. Bankruptcy Code) on a
straight-line basis over 20 years. We amortize other intangible assets over the
estimated periods of benefit which do not exceed ten years. Amortization expense
of intangible assets was $26.5 million in 2000, $24.3 million in 1999, and $24.9
million in 1998.

   We evaluate the impairment of long-lived assets, including intangibles,
whenever events or changes in circumstances indicate that the carrying amount of
such assets may not be recoverable. We evaluate recoverability based upon
undiscounted future cash flows expected to be generated by such assets.

STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for
Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"), in recording compensation expense for grants of stock, stock
options, and other equity instruments to employees.

32

   21

                                              UGI Corporation 2000 Annual Report

OTHER ASSETS. Included in other assets are net deferred debt issuance costs of
$10.8 million at September 30, 2000 and $10.9 million at September 30, 1999. We
are amortizing these costs over the term of the related debt.

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 periods of three to seven
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 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.

FOREIGN CURRENCY TRANSLATION. Financial statements of international subsidiaries
are translated into U.S. dollars using the exchange rate at each balance sheet
date for assets and liabilities and a weighted-average exchange rate for each
period for revenues and expenses. Where the local currency is the functional
currency, translation adjustments are recorded in accumulated other
comprehensive income. Where the local currency is not the functional currency,
translation adjustments are recorded in net income. Currency adjustments did not
materially impact the Company's results of operations or accumulated
comprehensive income in 2000, 1999 or 1998.

COMPREHENSIVE INCOME. Our comprehensive income principally includes net earnings
or loss and unrealized gains or losses on available for sale securities. In
1998, our comprehensive income was the same as our net income. The net changes
in accumulated comprehensive income in 1999 and 2000, which resulted principally
from changes in unrealized gains on securities, is reflected net of income taxes
of $0.3 million.

ACCOUNTING PRINCIPLES NOT YET ADOPTED. In June 1998, the FASB 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. To the extent derivative instruments qualify and are
designated as hedges of the variability in cash flows associated with forecasted
transactions, the effective portion of the gain or loss on such derivative
instruments will generally be reported in other comprehensive income and the
ineffective portion, if any, will be reported in net income. Such amounts
recorded in accumulated other comprehensive income will be reclassified into net
income when the forecasted transaction affects earnings. To the extent
derivative instruments qualify and are designated as hedges of changes in the
fair value of an existing asset, liability or firm commitment, the gain or loss
on the hedging instrument will be recognized currently in earnings along with
changes in the fair value of the hedged asset, liability or firm commitment
attributable to the hedged risk.

   The Company was required to adopt the provisions of SFAS 133 effective
October 1, 2000. Virtually all of the Company's derivative instruments
outstanding as of October 1, 2000 qualify and have been designated as hedging
the variability in cash flows associated with forecasted transactions. The
adoption of SFAS 133 will result in an after-tax cumulative effect charge to net
income of $0.3 million and an after-tax cumulative effect increase to
accumulated other comprehensive income of $7.1 million. Because the Company's
derivative instruments historically have been highly effective in hedging the
exposure to changes in cash flows associated with forecasted purchases or sales
of natural gas and propane, changes in the fair value of propane inventories,
and changes in the risk-free rate of interest on anticipated issuances of
long-term debt, we do not expect the adoption of SFAS 133 to have a material
impact on our future results of operations.

   Although the Company expects the derivative instruments it currently uses to
hedge to continue to be highly effective, if they are deemed not highly
effective in the future, or if the Company uses

                                                                              33
   22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

derivative instruments that do not meet the stringent requirements for hedge
accounting under SFAS 133, our future earnings could reflect greater volatility.
Additionally, if a cash flow hedge is discontinued because the original
forecasted transaction is no longer expected to occur, any gain or loss in
accumulated comprehensive income associated with the hedged transaction will be
immediately recognized in net income.

   In order to comply with the provisions of the Securities and Exchange
Commission Staff Accounting Bulletin No. 101 entitled "Revenue Recognition"
("SAB 101"), which is effective for the Company on October 1, 2000, the Company
will record a cumulative effect charge to net income of approximately $2.3
million related to the Partnership's method of recognizing revenue associated
with nonrefundable tank fees largely for residential customers. Consistent with
a number of its competitors in the propane industry, the Partnership receives
nonrefundable fees for installed Partnership-owned tanks. Historically, such
fees, which are generally received annually, were recorded as revenue when
billed. In accordance with SAB 101, effective October 1, 2000, the Partnership
will record such nonrefundable fees on a straight-line basis over one year. The
adoption of SAB 101 is not expected to have a material impact on the Company's
future financial condition or results of operations.

   Also, during fiscal 2001, the Partnership plans to change its method of
accounting for tank installation costs which are not billed to customers.
Currently, all direct costs to install Partnership-owned tanks at a customer
location are expensed as incurred. The Partnership believes that these costs
should now be capitalized and amortized over the period benefited. On date of
adoption, this change in accounting method will result in a cumulative effect
increase to net income. The Company is in the process of evaluating the impact
of such change on its financial condition and results of operations.

NOTE 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 $32.5 million 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 $8.7 million 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
its wholly owned nonregulated subsidiary, UGI Development Company ("UGIDC").

   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

34
   23
                                              UGI Corporation 2000 Annual Report

(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.

REGULATORY ASSETS AND LIABILITIES. The following regulatory assets and
liabilities are included in our accompanying balance sheets at September 30:

                                                2000       1999
- ---------------------------------------------------------------
                                                    
Regulatory assets:
   Income taxes recoverable                    $47.7      $46.9
   Power agreement buy-out                       3.5        6.8
   Other postretirement benefits                 2.9        3.1
   Deferred fuel costs                           7.2        3.4
   Other                                         1.0        0.9
- ---------------------------------------------------------------
Total regulatory assets                        $62.3      $61.1
- ---------------------------------------------------------------
Regulatory liabilities:
   Other postretirement benefits               $ 4.0       $2.8
   Refundable state taxes                         --        1.0
- ---------------------------------------------------------------
Total regulatory liabilities                   $ 4.0       $3.8
- ---------------------------------------------------------------

NOTE 3 - DEBT

Long-term debt comprises the following at September 30:

                                                                 2000          1999
- -----------------------------------------------------------------------------------
                                                                     
AmeriGas Propane:

   AmeriGas Partners Senior Notes, 10.125%,
      due April 2007                                         $  100.0      $  100.0
   Operating Partnership First Mortgage Notes:
      Series A, 9.34%-11.71%, due April 2000 through
         April 2009 (including unamortized premium
         of $10.6 and $12.1, respectively, calculated at
         an 8.91% effective rate)                               208.6         220.1
      Series B, 10.07%, due April 2001 through
         April 2005 (including unamortized premium
         of $5.9 and $8.0, respectively, calculated at
         an 8.74% effective rate)                               205.9         208.0
      Series C, 8.83%, due April 2003 through
         April 2010                                             110.0         110.0
      Series D, 7.11%, due March 2009
         (including unamortized premium of $2.7
         and $2.9, respectively, calculated at a
         6.52% effective rate)                                   72.7          72.9
      Series E, 8.50%, due July 2010
         (including unamortized premium of $0.2
         calculated at an 8.47% effective rate)                  80.2            --
   Operating Partnership Acquisition Facility                    70.0          23.0
   Other                                                          9.8          10.7
- -----------------------------------------------------------------------------------
Total AmeriGas Propane                                          857.2         744.7
- -----------------------------------------------------------------------------------
UGI Utilities:
   Medium-Term Notes:
      7.25% Notes, due November 2017                             20.0          20.0
      7.17% Notes, due June 2007                                 20.0          20.0
      6.17% Notes, due March 2001                                15.0          15.0
      7.37% Notes, due October 2015                              22.0          22.0
      6.73% Notes, due October 2002                              26.0          26.0
      6.62% Notes, due May 2005                                  20.0          20.0
   6.50% Senior Notes, due August 2003
      (less unamortized discount of $0.1)                        49.9          49.9
   9.71% Notes, due September 2000                                 --           7.1
- -----------------------------------------------------------------------------------
Total UGI Utilities                                             172.9         180.0
- -----------------------------------------------------------------------------------
Other:
   FLAGA EURO note, due September 2001
      through September 2006                                     65.5          77.0
   FLAGA Austrian shilling debt                                    --           6.8
   FLAGA EURO special purpose facility                           11.9            --
   Other                                                          8.1           7.8
- -----------------------------------------------------------------------------------
Total long-term debt                                          1,115.6       1,016.3
Less current maturities                                         (85.9)        (26.7)
- -----------------------------------------------------------------------------------
Total long-term debt due after one year                      $1,029.7      $  989.6
- -----------------------------------------------------------------------------------

                                                                              35
   24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

Long-term debt due in fiscal years 2001 to 2005 follows:

                        2001     2002     2003     2004    2005
- ---------------------------------------------------------------
                                          
AmeriGas Propane       $64.5    $66.5    $60.0    $56.7   $56.2
UGI Utilities           15.0       --     76.0       --    20.0
Other                    6.4     10.8     16.6      9.9    15.7
- ---------------------------------------------------------------
Total                  $85.9    $77.3   $152.6    $66.6   $91.9
- ---------------------------------------------------------------

AMERIGAS PROPANE

AMERIGAS PARTNERS SENIOR NOTES. The 10.125% Senior Notes of AmeriGas Partners
are redeemable prior to their maturity date. A redemption premium applies until
April 15, 2004. In addition, AmeriGas Partners may, under certain circumstances
following the disposition of assets or a change of control, be required to offer
to prepay the Senior Notes.

OPERATING PARTNERSHIP FIRST MORTGAGE NOTES. The Operating Partnership's First
Mortgage Notes are collateralized by substantially all of its assets. The
General Partner and its wholly owned subsidiary Petrolane are co-obligors of the
Series A, B, and C First Mortgage Notes, and the General Partner is co-obligor
of the Series D and E First Mortgage Notes. The Operating Partnership may prepay
the First Mortgage Notes, in whole or in part. These prepayments include a make
whole premium. Following the disposition of assets or a change of control, the
Operating Partnership may be required to offer to prepay the First Mortgage
Notes, in whole or in part.

OPERATING PARTNERSHIP BANK CREDIT AGREEMENT. The Operating Partnership's Bank
Credit Agreement consists of a Revolving Credit Facility and an Acquisition
Facility. The Operating Partnership's obligations under the Bank Credit
Agreement are collateralized by substantially all of its assets. The General
Partner and Petrolane are co-obligors of amounts outstanding under the Bank
Credit Agreement.

   Under the Revolving Credit Facility, the Operating Partnership may borrow up
to $100 million (including a $35 million sublimit for letters of credit) subject
to restrictions in the 10.125% Senior Notes of AmeriGas Partners (see
"Restrictive Covenants" below). The Revolving Credit Facility expires September
15, 2002, but may be extended for additional one-year periods with the consent
of the participating banks representing at least 80% of the commitments
thereunder. The Revolving Credit Facility permits the Operating Partnership to
borrow at various prevailing interest rates, including the Base Rate, defined as
the higher of the Federal Funds Rate plus 0.50% or the agent bank's reference
rate (9.50% at September 30, 2000), or at two-week, one-, two-, three-, or
six-month offshore interbank offering rates ("IBOR"), plus a margin. The margin
on IBOR borrowings (which ranges from 0.50% to 1.75%) and the Revolving Credit
Facility commitment fee rate are dependent upon the Operating Partnership's
ratio of funded debt to earnings before interest expense, income taxes,
depreciation and amortization ("EBITDA"), each as defined in the Bank Credit
Agreement. The Operating Partnership had borrowings under the Revolving Credit
Facility totaling $30 million at September 30, 2000 and $22 million at September
30, 1999, which we classify as bank loans. The weighted-average interest rates
on the bank loans outstanding were 8.11% as of September 30, 2000 and 6.26% as
of September 30, 1999. Issued outstanding letters of credit under the Revolving
Credit Facility totaled $1.5 million at September 30, 2000 and $5.9 million at
September 30, 1999.

   The Acquisition Facility provides the Operating Partnership with the ability
to borrow up to $75 million to finance the purchase of propane businesses or
propane business assets. The Acquisition Facility operates as a revolving
facility through September 15, 2002, at which time amounts then outstanding will
be immediately due and payable. The Acquisition Facility permits the Operating
Partnership to borrow at the Base Rate or at two-week, one-, two-, three-, or
six-month IBOR, plus a margin. The margin on IBOR borrowings and the Acquisition
Facility commitment fee rate are dependent upon the Operating Partnership's
ratio of funded debt to EBITDA, as defined. The weighted-average interest rates
on Acquisition Facility loans outstanding were 8.12% as of September 30, 2000
and 6.02% as of September 30, 1999.

GENERAL PARTNER FACILITY. The Operating Partnership also has a revolving credit
agreement with the General Partner under which it may borrow up to $20 million
to fund working capital, capital expenditures, and interest and Partnership
distribution payments. This agreement is coterminous with, and generally
comparable to, the Operating Partnership's Revolving Credit Facility except that
borrowings under the General Partner Facility are unsecured and subordinated to
all senior debt of the Partnership. Interest rates on borrowings are based upon
one-month IBOR. Commitment fees are determined in the same manner as fees under
the Revolving Credit Facility. UGI has agreed to contribute up to $20 million to
the General Partner to fund such borrowings.

RESTRICTIVE COVENANTS. The 10.125% Senior Notes of AmeriGas Partners restrict
the ability of the Partnership to, among other things, incur additional
indebtedness, make investments, incur liens, issue preferred interests, prepay
subordinated indebtedness, and effect mergers, consolidations and sales of
assets. Under the Senior Notes Indenture, AmeriGas Partners is generally
permitted to make cash distributions equal to available cash, as defined, as of
the end of the immediately preceding quarter, if certain conditions are met.

These conditions include:

   1. no event of default exists or would exist upon making such distributions
      and

   2. the Partnership's consolidated fixed charge coverage ratio, as defined, is
      greater than 1.75-to-1.

36
   25
                                              UGI Corporation 2000 Annual Report

If the ratio in item 2 above is less than or equal to 1.75-to-1, the Partnership
may make cash distributions in a total amount not to exceed $24 million less the
total amount of distributions made during the immediately preceding 16 fiscal
quarters. At September 30, 2000, such ratio was 2.14-to-1.

   The Bank Credit Agreement and the First Mortgage Notes restrict the
incurrence of additional indebtedness and also restrict certain liens,
guarantees, investments, loans and advances, payments, mergers, consolidations,
sales of assets and other transactions. They also require the ratio of total
indebtedness, as defined, to EBITDA, as defined (calculated on a rolling
four-quarter basis or eight-quarter basis divided by two), to be less than or
equal to 5.25-to-1. In addition, the Bank Credit Agreement requires that the
Operating Partnership maintain a ratio of EBITDA to interest expense, as
defined, of at least 2.25-to-1 on a rolling four-quarter basis. Generally, as
long as no default exists or would result, the Operating Partnership is
permitted to make cash distributions not more frequently than quarterly in an
amount not to exceed available cash, as defined, for the immediately preceding
calendar quarter. At September 30, 2000, the Partnership was in compliance with
its financial covenants.

UGI UTILITIES

REVOLVING CREDIT AGREEMENTS. At September 30, 2000, UGI Utilities had revolving
credit agreements with four banks providing for borrowings of up to $122 million
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
$100.4 million at September 30, 2000 and $87.4 million at September 30, 1999,
which we classify as bank loans. The weighted-average interest rates on UGI
Utilities bank loans were 7.12% at September 30, 2000 and 5.90% at September 30,
1999.

RESTRICTIVE COVENANTS. 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
million. At September 30, 2000, UGI Utilities was in compliance with its
financial covenants.

OTHER

FLAGA's EURO note bears interest at a rate of 1.25% over one- to twelve-month
EURIBOR rates (as chosen by the Company from time to time). The effective
interest rates on the EURO note at September 30, 2000 and September 30, 1999
were 5.71% and 5.00%, respectively. On or after September 10, 2003, the Company
may prepay the EURO note, in whole or in part. Prior to March 11, 2005, such
prepayments shall be at a premium.

   FLAGA has EURO loan commitments from a foreign bank in the form of (1) a 15
million EURO special purpose facility and (2) a 9 million EURO working capital
facility. Borrowings under the FLAGA special purpose facility can be used to
repay certain debt obligations of FLAGA existing at the acquisition date and for
general business purposes. The working capital facility expires September 28,
2001, but may be extended for an additional three-year period with the bank's
consent. Loans under the special purpose facility and the working capital
facility bear interest at market rates. The weighted-average interest rates on
FLAGA's working capital facility and special purpose facility at September 30,
2000 were 5.78% and 5.25%, respectively. Borrowings under the EURO working
capital facility at September 30, 2000, and FLAGA's now terminated Swiss franc
denominated bank loan facility at September 30, 1999, totaled $4.3 million and
$11.6 million, respectively.

   The FLAGA EURO note, special purpose facility and the working capital
facility are subject to guarantees of UGI. In addition, under certain conditions
regarding changes in the credit rating of UGI Utilities' long-term debt, the
lending bank may require UGI to grant additional security or may accelerate
repayment of the debt prior to its scheduled maturity.

NOTE 4 -- INCOME TAXES

Income before income taxes comprises the following:

                                          2000     1999    1998
- ----------------------------------------------------------------
                                                  
Domestic                                 $93.4   $100.5    $76.9
Foreign                                   (7.0)      --       --
- ----------------------------------------------------------------
Total income before income taxes         $86.4   $100.5    $76.9
- ----------------------------------------------------------------

The provisions for income taxes consist of the following:

                                          2000     1999    1998
- ----------------------------------------------------------------
                                                  
Current:
   Federal                               $28.6    $29.2    $19.6
   State                                   8.3      6.3      4.7
- ----------------------------------------------------------------
   Total current                          36.9     35.5     24.3
Deferred:
   Federal                                 5.7      6.8     10.0
   State                                  (0.2)     1.3      0.5
   Foreign                                (1.9)      --       --
   Investment tax credit amortization     (0.4)    (0.4)    (0.4)
- ----------------------------------------------------------------
   Total deferred                          3.2      7.7     10.1
- ----------------------------------------------------------------
Total income tax expense                 $40.1    $43.2    $34.4
- ----------------------------------------------------------------

                                                                              37
   26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:

                                                     2000         1999         1998
- -----------------------------------------------------------------------------------
                                                                     
Statutory federal tax rate                          35.0%        35.0%        35.0%
Difference in tax rate due to:
   State income taxes, net of federal benefit        7.5          5.2          6.1
   Nondeductible amortization of goodwill            5.8          4.6          6.2
Other, net                                          (1.9)        (1.8)        (2.6)
- -----------------------------------------------------------------------------------
Effective tax rate                                  46.4%        43.0%        44.7%
- -----------------------------------------------------------------------------------

Deferred tax liabilities (assets) comprise the following at September 30:

                                                                         2000         1999
- ------------------------------------------------------------------------------------------
                                                                             
Excess book basis over tax basis of property, plant and equipment     $ 172.5      $ 177.0
Regulatory assets                                                        25.6         25.3
Other                                                                    13.7         10.1
- ------------------------------------------------------------------------------------------
Gross deferred tax liabilities                                          211.8        212.4
- ------------------------------------------------------------------------------------------
Self-insured property and casualty liability                             (8.2)        (8.6)
Employee-related benefits                                               (12.0)       (12.3)
Premium on long-term debt                                                (4.4)        (5.2)
Deferred investment tax credits                                          (3.8)        (4.0)
Power purchase agreement liability                                       (2.2)        (3.2)
Operating loss carryforwards                                             (8.3)        (4.2)
Allowance for doubtful accounts                                          (2.6)        (2.5)
Other                                                                   (11.1)       (13.8)
- ------------------------------------------------------------------------------------------
Gross deferred tax assets                                               (52.6)       (53.8)
- ------------------------------------------------------------------------------------------
Deferred tax assets valuation allowance                                   1.9          2.0
- ------------------------------------------------------------------------------------------
Net deferred tax liabilities                                          $ 161.1      $ 160.6
- ------------------------------------------------------------------------------------------

   UGI Utilities had recorded deferred tax liabilities of approximately $31.7
million as of September 30, 2000 and $31.4 million 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 $3.8 million at September 30, 2000 and $4.0 million 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 $47.7 million as of September 30, 2000 and $46.9 million as of
September 30, 1999. This regulatory income tax asset represents future revenues
expected to be recovered through the ratemaking process. We will recognize this
regulatory income tax asset in deferred tax expense as the corresponding
temporary differences reverse and additional income taxes are incurred.

   At September 30, 2000, the amount of federal operating loss carryforwards
which were generated by a domestic subsidiary prior to its acquisition totaled
$5.2 million. These operating loss carryforwards expire through the year 2010.
The use of pre-acquisition operating loss carryforwards is subject to Internal
Revenue Code limitations. We do not believe these limitations will affect our
ability to utilize these carryforwards prior to their expiration.

   Foreign operating loss carryforwards of FLAGA totaled approximately $19.0
million at September 30, 2000. Approximately $3.0 million of these operating
loss carryforwards expire through 2005. The remaining approximately $16.0
million have no expiration date. The tax benefit of these foreign operating loss
carryforwards of $6.4 million has been reduced by a valuation allowance of $1.7
million due to the uncertainty of realizing certain of these operating loss
carryforwards.

NOTE 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:

                                                                                         Other
                                                            Pension                 Postretirement
                                                            Benefits                    Benefits
                                                   ---------------------       ---------------------
                                                      2000          1999          2000          1999
- ----------------------------------------------------------------------------------------------------
                                                                                 
CHANGE IN BENEFIT OBLIGATIONS:
   Benefit obligations - beginning of year         $ 149.5       $ 164.8       $  16.8       $  16.9
   Service cost                                        3.2           3.8           0.1           0.1
   Interest cost                                      11.8          11.2           1.4           1.2
   Actuarial (gain) loss                              (4.4)        (21.4)          3.0          (0.2)
   Benefits paid                                      (9.2)         (8.9)         (1.6)         (1.2)
- ----------------------------------------------------------------------------------------------------
   Benefit obligations - end of year               $ 150.9       $ 149.5       $  19.7       $  16.8
- ----------------------------------------------------------------------------------------------------

CHANGE IN PLAN ASSETS:
   Fair value of plan assets -
      beginning of year                            $ 202.1       $ 183.3       $   4.9       $   4.9
   Actual return on plan assets                       30.6          27.7           0.3           0.2
   Employer contributions                               --            --           2.2           1.0
   Benefits paid                                      (9.2)         (8.9)         (1.0)         (1.2)
- ----------------------------------------------------------------------------------------------------
   Fair value of plan assets - end of year         $ 223.5       $ 202.1       $   6.4       $   4.9
- ----------------------------------------------------------------------------------------------------

Funded status of the plans                         $  72.6       $  52.6       $ (13.3)      $ (11.9)
Unrecognized net actuarial gain                      (54.8)        (36.8)         (3.0)         (5.8)
Unrecognized prior service cost                        4.0           4.7            --            --
Unrecognized net transition (asset) obligation        (6.3)         (7.9)         10.5          11.4
- ----------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year       $  15.5       $  12.6       $  (5.8)      $  (6.3)
- ----------------------------------------------------------------------------------------------------

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
- ----------------------------------------------------------------------------------------------------

38
   27
                                              UGI Corporation 2000 Annual Report

Net periodic pension income and other postretirement benefit costs include the
following components:

                                            Pension                                 Other
                                            Benefits                       Postretirement Benefits
                              ---------------------------------      ---------------------------------
                                 2000         1999         1998         2000         1999         1998
- ------------------------------------------------------------------------------------------------------
                                                                             
Service cost                  $   3.2      $   3.8      $   3.4      $   0.1      $   0.1      $   0.1
Interest cost                    11.8         11.2         10.9          1.4          1.2          1.2
Expected return on assets       (17.0)       (16.3)       (15.2)        (0.3)        (0.2)        (0.2)
Amortization of:
   Transition (asset)
      obligation                 (1.6)        (1.6)        (1.6)         0.9          0.9          0.9
   Prior service cost             0.6          0.6          0.6           --           --           --
   Actuarial (gain) loss           --           --           --         (0.2)        (0.2)        (0.3)
- ------------------------------------------------------------------------------------------------------
Net postretirement
   cost (income)                 (3.0)        (2.3)        (1.9)         1.9          1.8          1.7
Change in regulatory
   assets & liabilities            --           --           --          1.4          1.7          1.9
- ------------------------------------------------------------------------------------------------------
Net expense (income)          $  (3.0)     $  (2.3)     $  (1.9)     $   3.3      $   3.5      $   3.6
- ------------------------------------------------------------------------------------------------------

   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% 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:

                                                  1%             1%
                                               Increase       Decrease
- ----------------------------------------------------------------------
                                                        
Effect on total service and interest costs       $0.1          $(0.1)
Effect on postretirement benefit obligation      $1.1          $(1.1)
- ----------------------------------------------------------------------

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 $0.9 million in 2000,
$1.6 million in 1999, and $2.4 million in 1998.

DEFINED CONTRIBUTION PLANS

We sponsor a 401(k) savings plan for eligible employees of UGI, UGI Utilities,
and certain of UGI's other wholly owned subsidiaries ("UGI Utilities Savings
Plan"). Generally, participants in the UGI 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. We also sponsor
a 401(k) savings plan for eligible employees of the General Partner ("AmeriGas
Propane Savings Plan"). Participants in the AmeriGas Propane Savings Plan may
contribute a portion of their compensation on a before-tax basis. We match
employee contributions to the AmeriGas Propane Savings Plan on a
dollar-for-dollar basis up to 5% of eligible compensation. The cost of benefits
under the savings plans totaled $5.9 million in 2000, $4.8 million in 1999, and
$5.1 million in 1998.

NOTE 6 -- INVENTORIES

Inventories comprise the following at September 30:

                                                2000       1999
- ----------------------------------------------------------------
                                                     
Propane gas                                   $ 47.3       $38.1
Utility fuel and gases                          33.6        24.5
Materials, supplies and other                   36.5        24.5
- ----------------------------------------------------------------
Total inventories                             $117.4       $87.1
- ----------------------------------------------------------------

NOTE 7 -- SERIES PREFERRED STOCK

The UGI Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 5,000,000 shares authorized for issuance.
We had no shares of UGI Series Preferred Stock outstanding at September 30, 2000
or 1999.

   UGI Utilities 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 UGI Utilities Series Preferred Stock have the
right to elect a majority of UGI Utilities' 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 UGI Utilities Series Preferred Stock.

   At September 30, 2000 and 1999, UGI Utilities had outstanding 200,000 shares
of $7.75 Series cumulative preferred stock. UGI Utilities is required to
establish a sinking fund to redeem on October 1 in each year, commencing October
1, 2004, 10,000 shares of its $7.75 Series at a price of $100 per share. The
$7.75 Series is redeemable, in whole or in part, at the option of UGI Utilities
on or after October 1, 2004, at a price of $100 per share. All outstanding
shares of $7.75 Series Preferred Stock are subject to mandatory redemption on
October 1, 2009, at a price of $100 per share.

                                                                              39
   28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

NOTE 8 -- COMMON STOCK AND INCENTIVE STOCK AWARD PLANS

On September 7, 1999, pursuant to strategic and financial initiatives announced
on July 28, 1999, we repurchased 4.5 million shares of Common Stock through a
"Dutch auction" tender offer for $109.1 million, or $24.25 per share. The
repurchased shares are held in treasury. In addition, during 1999, in
conjunction with the Company's proposed merger with Unisource (see Note 14), we
purchased 1.4 million shares of Common Stock for $23.2 million.

   Common Stock share activity for 1998, 1999 and 2000 follows:

                                         Issued           Treasury         Outstanding
======================================================================================
                                                                 
Balance September 30, 1997            33,198,731          (336,715)        32,862,016
Issued:
   Employee and director plans                --           243,915            243,915
   Dividend reinvestment plan                 --           108,353            108,353
   Acquisitions                               --            42,078             42,078
Reacquired                                    --          (433,100)          (433,100)
- -------------------------------------------------------------------------------------
Balance September 30, 1998            33,198,731          (375,469)        32,823,262
Issued:
   Employee and director plans                --           175,040            175,040
   Dividend reinvestment plan                 --           136,587            136,587
Reacquired                                    --        (5,864,496)        (5,864,496)
- -------------------------------------------------------------------------------------
Balance September 30, 1999            33,198,731        (5,928,338)        27,270,393
Issued:
   Employee and director plans                --            62,525             62,525
   Dividend reinvestment plan                 --           114,430            114,430
Reacquired                                    --          (453,639)          (453,639)
- -------------------------------------------------------------------------------------
Balance September 30, 2000            33,198,731        (6,205,022)        26,993,709
- -------------------------------------------------------------------------------------

STOCK OPTION PLANS

Under UGI's current employee stock option and incentive plans, we may grant
options to acquire shares of Common Stock, or issue shares of restricted stock,
to key employees. The exercise price for options granted under all plans may not
be less than the fair market value on the grant date. Grants of stock options or
restricted stock under these plans may vest immediately, or ratably over a
period of years, and stock options generally can be exercised no later than ten
years from the grant date.

   Under the 2000 Stock Incentive Plan ("2000 Incentive Plan"), up to 1,100,000
shares of Common Stock may be issued in connection with stock options and grants
of restricted stock. However, no more than 500,000 shares of restricted stock
may be granted. In addition, the 2000 Incentive Plan provides that both option
grants and restricted stock grants may provide for the crediting of Common Stock
dividend equivalents to participants' accounts. Dividend equivalents will be
paid in cash, and such payments may, at the participants' request, be deferred.
Grants of restricted stock will be contingent upon the achievement of objective
performance goals. At September 30, 2000, no grants have been made under the
2000 Incentive Plan.

   Under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP Plan"),
we may grant options to acquire a total of 1,500,000 shares of Common Stock.
Certain option grants under the 1997 SODEP Plan provided for the crediting of
dividend equivalents subject to the Company's total shareholder return relative
to a peer group of companies during the three-year period ended December 31,
1999. Based upon such performance, no dividend equivalent payments were made.

   Under the 1992 Non-Qualified Stock Option Plan, we may grant options to
acquire a total of 500,000 shares of Common Stock to key employees who do not
participate in the 2000 Incentive Plan or the 1997 SODEP Plan.

   In addition to these employee incentive plans, the Company may grant options
to acquire up to a total of 200,000 shares of Common Stock to each of the
Company's nonemployee Directors. No Director may be granted options to acquire
more than 10,000 shares of Common Stock in any calendar year, and the exercise
price may not be less than the fair market value of the Common Stock on the
grant date. Generally all options will be fully vested on the grant date and
exercisable only while the participant is a Director.

   Stock option transactions under all of our plans for 1998, 1999 and 2000
follow:

                                                  Shares    Average Option Price
================================================================================
                                                      
Shares under option - September 30, 1997        1,175,001        $21.670
- -------------------------------------------------------------------------
Granted                                            54,583         22.469
Exercised                                        (198,121)        20.650
Forfeited                                          (1,708)        23.962
- -------------------------------------------------------------------------
Shares under option - September 30, 1998        1,029,755         21.905
- -------------------------------------------------------------------------
Granted                                           231,806         20.406
Exercised                                         (27,250)        21.978
Forfeited                                         (18,750)        21.152
- -------------------------------------------------------------------------
Shares under option - September 30, 1999        1,215,561         21.632
- -------------------------------------------------------------------------
Granted                                           794,750         20.683
Exercised                                         (30,000)        22.625
Forfeited                                         (96,667)        22.302
- -------------------------------------------------------------------------
Shares under option - September 30, 2000        1,883,644         21.181
- -------------------------------------------------------------------------
Options exercisable 1998                        1,014,755         21.921
Options exercisable 1999                          984,061         21.725
Options exercisable 2000                          947,144         21.696
- -------------------------------------------------------------------------

   For options outstanding as of September 30, 2000, the exercise prices range
from $18.625 to $26.25. The weighted-average remaining contractual life of these
options is 7.1 years. At September 30, 2000, 1,453,103 shares of Common Stock
were available for future option grants under all of our stock option plans.

OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS

On December 13, 1999, the General Partner adopted the AmeriGas Propane, Inc.
2000 Long-Term Incentive Plan ("2000 Propane Plan"). Under the 2000 Propane
Plan, the General Partner may

40
   29
                                              UGI Corporation 2000 Annual Report

grant to key employees the right to receive a total of 500,000 AmeriGas Partners
Common Units, or cash generally equivalent to the fair market value of such
Common Units, upon the achievement of objective performance goals. In addition,
the 2000 Propane Plan provides that grants may provide for the crediting of
Partnership distribution equivalents to participants' accounts. Distribution
equivalents will be paid in cash, and such payment may, at the participant's
request, be deferred. Generally, each grant, unless paid, will terminate when
the participant ceases to be employed by the General Partner. At September 30,
2000, no grants have been made under the 2000 Propane Plan.

   Under the 1997 AmeriGas Propane, Inc. Long-Term Incentive Plan ("1997 Propane
Plan"), the General Partner granted to key employees the right to receive
AmeriGas Partners Common Units, or cash generally equivalent to their fair
market value, on the payment date. The 1997 Propane Plan also provided for the
crediting of dividend equivalents to participant's accounts. The actual number
of Common Units (or their cash equivalent) awarded, and the amount of the
distribution equivalent, depended upon the date when the cash generation-based
requirements for early conversion of AmeriGas Partners Subordinated Units were
met. Because such requirements were achieved at March 31, 1999, 81,226 Common
Units were issued, and $1.1 million in cash payments were made, in May 1999.

   Under the 1997 UGI Corporation Directors' Equity Compensation Plan ("1997
Directors' Plan"), we make annual awards to our nonemployee Board Directors of
(1) "Units," each representing an interest equivalent to one share of Common
Stock, and (2) Common Stock for a portion of their annual retainer. Board
Directors may also elect to receive the cash portion of their retainer fee and
all or a portion of their meeting fees in the form of Units. The 1997 Directors'
Plan also provides for the crediting of dividend equivalents in the form of
additional Units. Units and dividend equivalents are fully vested when credited
to a Director's account and will be converted to shares of Common Stock and paid
upon retirement or termination of service. Units issued relating to annual
awards and deferred compensation totaled 12,017, 9,137 and 7,043 in 2000, 1999
and 1998, respectively. At September 30, 2000 and 1999, there were 53,294 and
41,277 Units, respectively, outstanding.

   In June 1999, we awarded 103,000 shares of restricted stock to key
executives. These awards vest four years from date of issuance but may vest
earlier if certain Common Stock performance goals are met. Recipients have the
right to vote the shares and to receive dividends during the restriction period.

FAIR VALUE INFORMATION

The per share weighted-average fair value of stock options granted under our
option plans was $3.76 in 2000, $2.58 in 1999, and $1.98 in 1998. These amounts
were determined using the Black-Scholes option pricing model, which values
options based on the stock price at the grant date, the expected life of the
option, the estimated volatility of the stock, expected dividend payments, and
the risk-free interest rate over the expected life of the option. The
assumptions we used for option grants during 2000, 1999 and 1998 are as follows:

                                    2000        1999       1998
- ---------------------------------------------------------------
                                               
Expected life of option          6 years     6 years    6 years
Expected volatility                26.5%       19.3%      16.2%
Expected dividend yield             6.2%        6.2%       6.0%
Risk free interest rate             6.6%        5.9%       4.6%
- ---------------------------------------------------------------

   We use the intrinsic value method prescribed by APB 25 for our stock-based
employee compensation plans. We recognized, under the provisions of APB 25,
total stock-based compensation expense (income) of $(0.8) million in 2000, $1.9
million in 1999, and $1.0 million in 1998. Stock-based compensation income in
2000 reflects the reversal of $2.1 million of accrued dividend equivalent
payments relating to the 1997 SODEP Plan. If we had determined compensation
expense under the fair value method prescribed by SFAS 123, net income and
diluted earnings per share for 2000, 1999 and 1998 would have been as follows:

                                    2000        1999       1998
- ---------------------------------------------------------------
                                                 
Net earnings:
   As reported                     $44.7       $55.7      $40.3
   Pro forma                        44.2        55.3       40.2
Diluted earnings per share:
   As reported                     $1.64       $1.74      $1.22
   Pro forma                        1.62        1.73       1.21
- ---------------------------------------------------------------

STOCK OWNERSHIP POLICY

The Company has a stock ownership policy ("Stock Ownership Policy") for
executives and key employees. Under the terms of the Stock Ownership Policy,
executives and certain key employees are required to own UGI Common Stock having
a fair value equal to 40% to 450% of their base salaries. Participants have from
three months to three years to comply with the Stock Ownership Policy. We offer
full recourse, interest-bearing loans to employees in order to assist them in
meeting the ownership requirements. Each loan may not exceed ten years and is
collateralized by the Common Stock purchased. At September 30, 2000 and 1999,
loans outstanding totaled $5.2 million and $4.1 million, respectively.

NOTE 9 - PREFERENCE STOCK PURCHASE RIGHTS

Holders of our Common Stock own one-half of one right (as described below) for
each outstanding share of Common Stock. Each right entitles the holder to
purchase one one-hundredth of a share of First Series Preference Stock, without
par value, at an exercise price of $120 per one one-hundredth of a share or,
under the circumstances summarized below, to purchase the common stock described
in the following paragraph. The rights are exercisable only if a person or
group, other than certain underwriters:

                                                                              41
   30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

   1. acquires 20% or more of our Common Stock ("Acquiring Person") or

   2. announces or commences a tender offer for 30% or more of our Common Stock.

We are entitled to redeem the rights at five cents per right at any time before
the earlier of:

   1. the expiration of the rights in April 2006 or

   2. ten days after a person or group has acquired 20% of our Common Stock if a
      majority of continuing Directors concur and, in certain circumstances,
      thereafter.

Each holder of a right, other than an Acquiring Person, is entitled to purchase,
at the exercise price of the right, Common Stock having a market value of twice
the exercise price of the right if:

   1. an Acquiring Person merges with UGI or engages in certain other
      transactions with us or

   2. a person acquires 40% or more of our Common Stock.

In addition, if, after UGI (or an Acquiring Person) publicly announces that an
Acquiring Person has become such, UGI engages in a merger or other business
combination transaction in which:

   1. we are not the surviving corporation, or

   2. we are the surviving corporation, but our Common Stock is changed or
      exchanged, or

   3. 50% or more of our assets or earning power is sold or transferred, then
      each holder of a right is entitled to purchase, at the exercise price of
      the right, common stock of the acquiring company having a market value of
      twice the exercise price of the right.

The rights have no voting or dividend rights and, until exercisable, have no
dilutive effect on our earnings.

NOTE 10 - PARTNERSHIP DISTRIBUTIONS

The Partnership makes distributions to its partners approximately 45 days after
the end of each fiscal quarter in a total amount equal to its Available Cash for
such quarter. Available Cash generally means:

   1. all cash on hand at the end of such quarter,

   2. plus all additional cash on hand as of the date of determination resulting
      from borrowings after the end of such quarter,

   3. less the amount of cash reserves established by the General Partner in its
      reasonable discretion.

The General Partner may establish reserves for the proper conduct of the
Partnership's business and for distributions during the next four quarters. In
addition, certain of the Partnership's debt agreements require reserves be
established for the payment of debt principal and interest.

   Distributions of Available Cash will generally be made 98% to the Common and
Subordinated unitholders and 2% to the General Partner. The Partnership may pay
an incentive distribution if Available Cash exceeds the Minimum Quarterly
Distribution of $0.55 ("MQD") on all units. If there is sufficient Available
Cash, the holders of Common Units have the right to receive the MQD, plus any
arrearages, before the distribution of Available Cash to holders of Subordinated
Units. Common Units will not accrue arrearages for any quarter after the
Subordination Period (as defined below), and Subordinated Units will not accrue
arrearages for any quarter.

   Pursuant to the Agreement of Limited Partnership of AmeriGas Partners
("Partnership Agreement"), because the required cash generation-based objectives
were achieved as of March 31, 1999, a total of 9,891,074 Subordinated Units held
by the General Partner and its wholly owned subsidiary, Petrolane, were
converted into Common Units on May 18, 1999. The remaining outstanding 9,891,072
Subordinated Units, all of which are held by the General Partner, are eligible
to convert to Common Units on the first day after the record date for any
quarter ending on or after March 31, 2000 in respect of which:

   1. distributions of Available Cash from Operating Surplus (as defined in the
      Partnership Agreement) equal or exceed the MQD on each of the outstanding
      Common and Subordinated units for each of the four consecutive
      nonoverlapping four-quarter periods immediately preceding such date,

   2. the Adjusted Operating Surplus (as defined in the Partnership Agreement)
      generated during both (1) each of the two immediately preceding
      nonoverlapping four-quarter periods and (2) the immediately preceding
      sixteen-quarter period, equals or exceeds the MQD on each of the Common
      and Subordinated units outstanding during those periods, and

   3. there are no arrearages on the Common Units.

The ability of the Partnership to attain the cash-based performance and
distribution requirements will depend upon a number of factors including highly
seasonal operating results, changes in working capital, asset sales and debt
refinancings. Due to the historical "look-back" provisions of the conversion
test, the possibility is remote that the Partnership will satisfy the cash-based
performance requirements for conversion any earlier than in respect of the
quarter ending March 31, 2002.

42
   31
                                              UGI Corporation 2000 Annual Report

NOTE 11 - 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 $34.1 million in 2000, $35.3 million in 1999, and $33.5 million
in 1998.

   Minimum future payments under operating leases that have initial or remaining
noncancelable terms in excess of one year are as follows:

                                                                                        After
                             2001        2002        2003        2004        2005        2005
- ---------------------------------------------------------------------------------------------
                                                                    
AmeriGas Propane          $  27.2     $  22.0     $  16.8     $  13.7     $  11.3     $  24.7
UGI Utilities                 3.6         3.1         2.5         1.7         0.9         0.7
International Propane         0.1         0.1         0.1          --          --          --
Other                         2.4         2.3         2.1         1.8         1.7         6.7
- ---------------------------------------------------------------------------------------------
Total                     $  33.3     $  27.5     $  21.5     $  17.2     $  13.9     $  32.1
- ---------------------------------------------------------------------------------------------

   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 other
power supply agreements with PP&L and other power producers having various
length terms expiring through December 2001. In high usage months, Electric
Utility meets its additional 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.

   The Partnership enters into contracts to purchase propane and Energy Services
enters into contracts to purchase natural gas to meet a portion of their supply
requirements. Generally, such contracts have terms of less than one year and
call for payment based on either fixed prices or market prices at date of
delivery.

   The Partnership has succeeded to certain lease guarantee obligations of
Petrolane, a predecessor company of the Partnership, relating to Petrolane's
divestiture of nonpropane operations before its 1989 acquisition by QFB
Partners. Future lease payments under these leases total approximately $32
million at September 30, 2000. The leases expire through 2010, and some of them
are currently in default. The Partnership has succeeded to the indemnity
agreement of Petrolane by which Texas Eastern Corporation ("Texas Eastern"), a
prior owner of Petrolane, agreed to indemnify Petrolane against any liabilities
arising out of the conduct of businesses that do not relate to, and are not a
part of, the propane business, including lease guarantees. To date, Texas
Eastern has directly satisfied defaulted lease obligations without the
Partnership's having to honor its guarantee.

   In addition, the Partnership has succeeded to Petrolane's agreement to
indemnify Shell Petroleum N.V. ("Shell") for various scheduled claims, including
claims related to antitrust actions, that were pending against Tropigas de
Puerto Rico ("Tropigas"). Petrolane had entered into this indemnification
agreement in conjunction with its sale of the international operations of
Tropigas to Shell in 1989. The Partnership also succeeded to Petrolane's right
to seek indemnity on these claims first from International Controls Corp., which
sold Tropigas to Petrolane, and then from Texas Eastern. To date, neither the
Partnership nor Petrolane has paid any sums under this indemnity. In 1999, a
case brought by an unsuccessful entrant into the Puerto Rican propane market was
dismissed by the Supreme Court of Puerto Rico for lack of subject matter
jurisdiction, with the Court concluding that the Public Service Commission of
Puerto Rico has exclusive jurisdiction over the matter. In the only pending
litigation, the Supreme Court of Puerto Rico denied the motion of the defendants
to dismiss, remanding the matter to the trial court for proceedings consistent
with its ruling. In this case the plaintiff seeks treble damages in excess of
$11.7 million.

   We believe that the probability the Partnership will be required to directly
satisfy the above lease obligations and the remaining claim subject to the
indemnification agreements is remote.

   We, along with other companies, have been named as a potentially responsible
party ("PRP") in several administrative proceedings and private party recovery
actions for the cleanup, or recovery of costs associated with cleanup, of
various waste sites, including some Superfund sites. In addition, we have
identified environmental contamination at several of our properties and have
voluntarily undertaken investigation and, as appropriate, remediation of these
sites in cooperation with appropriate environmental agencies or private parties.

                                                                              43
   32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

   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 Public Utility Holding Company Act of 1935, UGI Utilities
divested all of its utility operations other than those which now constitute Gas
Utility and Electric Utility.

   UGI Utilities has been notified of several sites outside Pennsylvania on
which (1) gas plants were formerly operated by it or owned or operated by its
former subsidiaries and (2) either environmental agencies or private parties are
investigating the extent of environmental contamination or performing
environmental remediation. UGI Utilities is currently litigating two claims
against it relating to out-of state sites.

   Management believes that 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 (1) itself operated the facility causing the environmental
damage or (2) 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 (1) UGI
Utilities formerly conducted some MGP operations or (2) 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 2000, UGI Utilities entered
into settlement agreements with several of the insurers and recorded pre-tax
income of $4.5 million which amount is included in operating and administrative
expenses in the 2000 Consolidated Statement of Income.

   In addition to these 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.

NOTE 12 -- 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 carrying amounts and
estimated fair values of our long-term debt and UGI Utilities Series Preferred
Stock at September 30 are as follows:

                                             Carrying    Estimated
                                              Amount    Fair Value
- ------------------------------------------------------------------
                                                  
2000:
   Long-term debt:
      AmeriGas Propane                        $857.2       $882.5
      UGI Utilities                            172.9        167.8
      Other                                     85.5         85.6
   UGI Utilities Series Preferred Stock         20.0         21.0

1999:
   Long-term debt:
      AmeriGas Propane                        $744.7       $761.3
      UGI Utilities                            180.0        174.8
      Other                                     91.6         91.1
   UGI Utilities Series Preferred Stock         20.0         20.9
- -----------------------------------------------------------------

   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 UGI Utilities Series Preferred Stock is based
on the fair value of redeemable preferred stock with similar credit ratings and
redemption features.

   We have financial instruments such as short-term investments and trade
accounts receivable which could expose us to concentrations of credit risk. We
limit our credit risk from short-term investments by investing only in
investment-grade commercial paper and in U.S. Government securities. The credit
risk from trade accounts receivable is limited because we have a large customer
base which extends across many different U.S. markets.

44
   33
                                              UGI Corporation 2000 Annual Report

   We utilize derivative instruments to hedge market risk resulting from changes
in the price of natural gas and propane, and changes in interest rates. We
attempt to minimize our credit risk with our counterparties through the
application of credit policies.

   At September 30, 2000 and 1999, the Partnership was a party to an interest
rate protection agreement covering $50 million of long-term debt to be issued in
fiscal 2001. The counterparty to this agreement is a large financial
institution. The estimated fair value of this agreement was $2.5 million at
September 30, 2000 and $3.2 million at September 30, 1999.

   At September 30, 2000 and 1999, Energy Services held exchange traded natural
gas futures contracts with total notional amounts of $30.2 million and $26.6
million, respectively. Net deferred gains on settled and unsettled contracts
totaled $6.6 million at September 30, 2000 and $3.3 million at September 30,
1999. At September 30, 1999, Energy Services also held exchange traded heating
oil futures and option contracts with a total notional amount of $6.5 million
and an estimated fair value of $(0.2) million.

   At September 30, 2000 and 1999, the Partnership was a party to propane price
swap and option agreements with private counterparties with total notional
amounts of $74.8 million and $12.9 million, respectively. Agreements outstanding
at September 30, 2000 mature through March 2001. The estimated fair values of
these swap and option agreements were $6.5 million and $2.9 million at September
30, 2000 and 1999, respectively.

NOTE 13 - ACQUISITIONS

During 2000, the Partnership acquired several propane distribution businesses,
and Enterprises acquired an HVAC business, for net cash consideration of $65.3
million. The excess of the purchase price over the amount preliminarily
allocated to the net assets acquired was approximately $42 million. During 1999
and 1998, the Partnership acquired several retail propane distribution
businesses for net cash consideration of $3.9 million and $8.1 million,
respectively. These acquisitions were recorded using the purchase method of
accounting. Under the purchase method, the purchase price has been allocated to
assets acquired and liabilities assumed based upon estimated fair values. The
operating results of these businesses have been included in the consolidated
results from their respective dates of acquisition. In addition to these
acquisitions, during 1999 the Company paid $4.9 million for a 25% equity
interest in a propane distribution business in Nantong, China, which is being
accounted for on the equity method of accounting.

   On September 21, 1999, Enterprises, through subsidiaries, acquired all of the
outstanding stock of FLAGA for net cash consideration of $73.7 million and the
assumption of approximately $18 million of debt. The cash purchase price was
financed through the issuance of EURO denominated debt. The acquisition of FLAGA
has been accounted for using the purchase method of accounting. The excess of
the purchase price over the amount allocated to the net assets acquired totaled
$57.5 million. For accounting convenience only, September 30, 1999 was deemed to
be the acquisition date. As a result, the acquisition of FLAGA did not impact
the Company's 1999 results of operations.

   The unaudited pro forma revenues, net income and diluted earnings per share
of the Company for 1999, as if the acquisition of FLAGA had occurred as of
October 1, 1998, are $1,434.0 million, $52.0 million, and $1.62, respectively.
The pro forma results of operations give effect to FLAGA's historical operating
results in accordance with U.S. generally accepted accounting principles and
adjustments for interest expense, goodwill amortization and depreciation
expense, and income taxes, but do not adjust for normal weather conditions and
anticipated operating efficiencies. In management's opinion, the unaudited pro
forma results are not indicative of the actual results that would have occurred
had the acquisition of FLAGA occurred as of October 1, 1998, or of future
operating results under the ownership and management of the Company. The pro
forma effect of the other businesses acquired during 2000, 1999 and 1998 was not
material to our results of operations.

NOTE 14 - TERMINATED MERGER - UNISOURCE WORLDWIDE, INC.

On May 25, 1999, the Company announced that Unisource Worldwide, Inc.
("Unisource") had entered into a merger agreement with Georgia-Pacific Corp.
("GP") and that it would allow Unisource to terminate the previously announced
Agreement and Plan of Merger (the "Merger Agreement") among Unisource, UGI and
Vulcan Acquisition Corp. (a wholly owned subsidiary of UGI) which would have
provided for the merger of the Company and Unisource. Because the board of
directors of Unisource decided to enter into a merger agreement with GP,
Unisource was required to pay the Company a $25 million merger termination fee
pursuant to the terms of the Merger Agreement. The Company received the
termination fee on May 28, 1999. The fee, net of related merger expenses, is
classified as merger fee income and expenses, net, in the 1999 Consolidated
Statement of Income.

NOTE 15 - OTHER INCOME, NET

Other income, net, comprises the following:

                                            2000         1999         1998
- ---------------------------------------------------------------------------
                                                          
Interest and interest-related income     $  (9.3)     $  (8.5)     $  (8.6)
Loss on Partnership's interest rate
   protection agreements                      --           --          4.0
Gain on sales of investments                (1.8)          --         (2.3)
Gain on sales of fixed assets               (3.6)        (2.2)        (2.0)
Pension income                              (3.0)        (2.3)        (1.9)
Other                                       (9.2)        (3.8)        (1.9)
- ---------------------------------------------------------------------------
Total other income, net                  $ (26.9)     $ (16.8)     $ (12.7)
- ---------------------------------------------------------------------------

                                                                              45
   34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)

NOTE 16-- QUARTERLY DATA (UNAUDITED)

                                      December 31,                March 31,                 June 30,              September 30,
                                    1999       1998       2000(a)       1999(b)        2000      1999(c)      2000(d)         1999
- ----------------------------------------------------------------------------------------------------------------------------------
                                                                                                  
Revenues                        $  466.6   $  373.7     $  610.4      $  499.2     $  335.9     $  259.3    $  348.8      $  251.4
Operating income (loss)             70.7       61.5        117.9         115.6          8.7          9.4        (6.1)        (10.6)
Net income (loss)                   21.1       18.0         38.8          37.5         (4.7)        11.4       (10.5)        (11.2)
Net income (loss) per share-
   Basic                            0.77       0.55         1.42          1.15        (0.17)        0.36       (0.39)        (0.37)
   Diluted                          0.77       0.55         1.42          1.14        (0.17)        0.36       (0.39)        (0.37)
- ----------------------------------------------------------------------------------------------------------------------------------

The quarterly data above includes all adjustments (consisting only of normal
recurring adjustments with the exception of those indicated below) which we
consider necessary for a fair presentation.

Our quarterly results fluctuate because of the seasonal nature of our
businesses.

(a) Includes income from a litigation settlement which increased operating
income by $2.4 million and net income by $1.4 million or $0.05 per share.

(b) Includes merger expenses of $1.6 million which decreased net income by $1.1
million or $0.03 per share.

(c) Includes merger termination fee income of $25 million, less $3.5 million of
merger related expenses, which increased net income by $14.0 million or $0.44
per share.

(d) Includes income from a litigation settlement which decreased operating loss
by $2.1 million and net loss by $1.2 million or $0.04 per share.

NOTE 17 -- 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
Company has five such business segments: (1) AmeriGas Propane; (2) Gas Utility;
(3) Electric Utility; (4) Energy Services; and (5) an international propane
segment comprising FLAGA and our equity investments in China and Romania.

   AmeriGas Propane derives its revenues principally from the sale of propane
and related equipment and supplies principally to retail customers from
locations in 45 states. 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. Energy Services
revenues are derived from the sale of natural gas and, to a lesser extent,
electricity to customers located primarily in the Middle Atlantic and New
England states. Our International Propane segment revenues result principally
from the distribution of propane to retail customers in Austria, the Czech
Republic and Slovakia.

   The accounting policies of our reportable segments are substantially the same
as those described in Note 1. We evaluate our AmeriGas Propane and International
Propane segments' performance principally based upon earnings before interest
expense, income taxes, depreciation and amortization ("EBITDA"). We evaluate the
performance of our Gas Utility, Electric Utility and Energy Services 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, other than those of our International
Propane segment, are derived from sources within the U.S., and all of our
reportable segments' long-lived assets, other than those of our International
Propane segment, are located in the U.S.

   Financial information by business segment follows:

46
   35

                                                                          AmeriGas             Gas        Electric       Energy
                                               Total       Eliminations   Propane            Utility      Utility       Services
- ----------------------------------------------------------------------------------------------------------------------------------
                                                                                                      
2000
Revenues                                     $1,761.7       $   (3.1)     $1,120.1          $  359.0      $   77.9      $  146.9
EBITDA                                       $  288.7       $     --      $  158.6          $  105.3      $   19.6      $    3.0
Depreciation and amortization                   (97.5)            --         (68.4)            (19.1)         (4.5)         (0.2)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss)                         191.2             --          90.2              86.2          15.1           2.8
Interest expense                                (98.5)            --         (74.7)            (16.2)         (2.2)           --
Minority interest                                (6.3)            --          (6.3)               --            --            --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes            $   86.4       $     --      $    9.2          $   70.0      $   12.9      $    2.8
Total assets                                 $2,278.8       $  (19.0)     $1,281.7          $  656.7      $   97.4      $   36.2
Capital expenditures                         $   71.0       $     --      $   30.4          $   31.7      $    4.7      $    0.1
Investments in foreign equity investees      $    5.5       $     --      $     --          $     --      $     --      $     --
==================================================================================================================================
1999

Revenues                                     $1,383.6       $   (2.3)     $  872.5          $  345.6      $   75.0      $   90.4
EBITDA                                       $  265.6       $     --      $  158.8          $   87.0      $   16.7      $    2.7
Depreciation and amortization                   (89.7)            --         (66.3)            (19.0)         (4.0)         (0.1)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss)                         175.9             --          92.5              68.0          12.7           2.6
Merger fee income, net                           19.9             --            --                --            --            --
Interest expense                                (84.6)            --         (66.5)            (15.2)         (2.3)           --
Minority interest                               (10.7)            --         (10.7)               --            --            --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes            $  100.5       $     --      $   15.3          $   52.8      $   10.4      $    2.6
Total assets                                 $2,140.5       $  (15.6)     $1,221.9          $  620.4      $   95.3      $   17.4
Capital expenditures                         $   73.7       $     --      $   34.6(a)       $   31.9      $    4.5      $    0.2
Investments in foreign equity investees      $    6.3       $     --      $     --          $     --      $     --      $     --
==================================================================================================================================
1998

Revenues                                     $1,439.7       $   (3.0)     $  914.4          $  350.2      $   72.1      $  103.0
EBITDA                                       $  258.0       $     --      $  153.3          $   83.0      $   13.6      $    2.1
Depreciation and amortization                   (87.8)            --         (65.4)            (18.2)         (3.9)         (0.1)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss)                         170.2             --          87.9              64.8           9.7           2.0
Interest expense                                (84.4)            --         (66.1)            (15.3)         (2.3)           --
Minority interest                                (8.9)            --          (8.9)               --            --            --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes            $   76.9       $     --      $   12.9          $   49.5      $    7.4      $    2.0
Total assets                                 $2,074.6       $  (17.1)     $1,238.2          $  594.4      $   95.6      $   14.3
Capital expenditures                         $   69.2       $     --      $   31.9          $   32.0      $    5.2      $    0.1
Investments in foreign equity investees      $    2.1       $     --      $     --          $     --      $     --      $     --
==================================================================================================================================

                                             International    Other      Corporate &
                                                Propane     Enterprises     Other
- ------------------------------------------------------------------------------------
                                                                 
2000
Revenues                                      $   50.5      $    7.3      $    3.1
EBITDA                                        $    1.9      $   (5.0)     $    5.3
Depreciation and amortization                     (4.6)         (0.5)         (0.2)
- ------------------------------------------------------------------------------------
Operating income (loss)                           (2.7)         (5.5)          5.1
Interest expense                                  (4.8)           --          (0.6)
Minority interest                                   --            --            --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes             $   (7.5)     $   (5.5)     $    4.5
Total assets                                  $  113.7      $   28.2      $   83.9
Capital expenditures                          $    1.8      $    2.3      $     --
Investments in foreign equity investees       $    5.5      $     --      $     --
==================================================================================
1999

Revenues                                      $     --      $    0.1      $    2.3
EBITDA                                        $   (0.1)     $   (5.7)     $    6.2
Depreciation and amortization                       --            --          (0.3)
- ------------------------------------------------------------------------------------
Operating income (loss)                           (0.1)         (5.7)          5.9
Merger fee income, net                              --            --          19.9
Interest expense                                    --            --          (0.6)
Minority interest                                   --            --            --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes             $   (0.1)     $   (5.7)     $   25.2
Total assets                                  $  143.2      $    3.7      $   54.2
Capital expenditures                          $     --      $    2.5      $     --
Investments in foreign equity investees       $    6.3      $     --      $     --
==================================================================================
1998

Revenues                                      $     --      $     --      $    3.0
EBITDA                                        $   (1.0)     $   (1.8)     $    8.8
Depreciation and amortization                       --            --          (0.2)
- ------------------------------------------------------------------------------------
Operating income (loss)                           (1.0)         (1.8)          8.6
Interest expense                                    --            --          (0.7)
Minority interest                                   --            --            --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes             $   (1.0)     $   (1.8)     $    7.9
Total assets                                  $    2.3      $    0.1      $  146.8
Capital expenditures                          $     --      $     --      $     --
Investments in foreign equity investees       $    2.1      $     --      $     --
==================================================================================

(a) Includes capital leases of $3.5 million.

                                                                              47

   1
                                                                      Exhibit 21

                          UGI CORPORATION SUBSIDIARIES

SUBSIDIARY                                                                    OWNERSHIP   STATE OF INCORPORATION
- ----------                                                                    --------    ----------------------
                                                                                    
AMERIGAS, INC.                                                                     100%          PA
     FOUR FLAGS DRILLING COMPANY, INC.                                             100%          PA
         Four Flags Holding Company                                                100%          DE
     AMERIGAS PROPANE, INC. *                                                      100%          PA
         AmeriGas Partners, L.P.                                                    (1)          DE
              AmeriGas Finance Corp.                                               100%          DE
              AmeriGas Propane L.P.                                            98.9899%          DE
                  AmeriGas Propane Parts & Service, Inc.                           100%          PA
                  Petrolane Offshore Limited                                       100%          BERMUDA
         AmeriGas Technology Group, Inc.                                           100%          PA
         Petrolane Incorporated                                                    100%          PA
ASHTOLA PRODUCTION COMPANY                                                         100%          PA
     UGI ETHANOL DEVELOPMENT CORPORATION                                           100%          PA
NORTHFIELD HOLDING COMPANY                                                         100%          DE
UGI ENTERPRISES, INC.                                                              100%          PA
     CFN ENTERPRISES, INC.                                                         100%          DE
         CF Networks LLC                                                            60%          DE
     EASTFIELD INTERNATIONAL HOLDINGS, INC.                                        100%          DE
                  Flaga GmbH                                                       100%          AUSTRIA
                     Flaga Energievorsorgung                                       100%          GERMANY
                     Flaga Plyn, spol. s r.o.                                      100%          CZECH REPUBLIC
                     Flaga Slovplyn, spol. s r.o.                                  100%          SLOVAKIA
                     Flaga Tech Trade GmbH                                         100%          AUSTRIA
                     Osterreichische Flussiggas-Gesellschaft m.b.H.                 40%          AUSTRIA
                     T.S.G.- Transport - und Speditionsgesellschaft m.b.H.          50%          AUSTRIA
                     G.T.P. Gas Trans Praha spol. s r.o.                            60%          CZECH REPUBLIC
                     GTE Gastrans-Erfurt-GmbH                                       90%          GERMANY
     EUROGAS HOLDINGS, INC.                                                        100%          DE
     UGI ENERGY SERVICES, INC.                                                     100%          PA
         Energy Services Holding Company                                           100%          DE
     UGI POWER SUPPLY, INC.                                                        100%          PA
     UGI INTERNATIONAL ENTERPRISES, INC.                                           100%          PA
     UGI BLACK SEA ENTERPRISES, INC.                                               100%          PA
     UGI INTERNATIONAL (ROMANIA), INC.                                             100%          PA
     UGI ROMANIA, INC.                                                             100%          PA
     UGI INTERNATIONAL (CHINA), INC.                                               100%          DE
     UGI CHINA, INC.                                                               100%          DE
     UGI SOUTHWEST CHINA DEVELOPMENT COMPANY, LLC                                  100%          DE
     HEARTH USA, INC.                                                              100%          DE
        UGI HVAC ENTERPRISES, INC.                                                 100%          DE
UGI PROPERTIES, INC.                                                               100%          PA
UGI UTILITIES, INC.                                                                100%          PA
     UGI DEVELOPMENT COMPANY                                                       100%          PA
               UGID Holding Company                                                100%          DE
               UGI Hunlock Development Company                                     100%          PA
UNITED VALLEY INSURANCE COMPANY                                                    100%          VT
VULCAN ACQUISITION CORP.                                                           100%          DE

   2

(1) AmeriGas Propane, Inc. and its subsidiary, Petrolane Incorporated, hold a
combined 55% interest in AmeriGas Partners, L.P. and its subsidiary AmeriGas
Propane, L.P.

* Sole General Partner of each of AmeriGas Partners, L.P. and AmeriGas Propane,
L.P.

   1
                                                                    Exhibit (23)

                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

To UGI Corporation:

As independent public accountants, we hereby consent to the incorporation of our
reports included or incorporated by reference in this Form 10-K, into this
Company's previously filed S-8 Registration Statement Nos. 33-47319, 33-61722,
333-22305, 333-37093, 333-49080 and Form S-3 Registration Statement Nos.
33-78776 and 333-42296.

Arthur Andersen LLP
Philadelphia, Pennsylvania
December 22, 2000

 5

THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONDENSED CONSOLIDATED BALANCE SHEET AND INCOME STATEMENT OF UGI CORPORATION AND
SUBSIDIARIES AS OF AND FOR THE YEAR ENDED SEPTEMBER 30, 2000 AND IS QUALIFIED IN
ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS IN UGI CORPORATION'S
ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30,2000

 0000884614
 UGI CORPORATION
 1,000

                   YEAR
                          SEP-30-2000
                             OCT-01-1999
                               SEP-30-2000
                                          93,900
                                     7,800
                                  185,500
                                     9,300
                                    117,400
                               426,100
                                       1,652,100
                                 578,900
                               2,278,800
                          539,400
                                      1,029,700
                           20,000
                                          0
                                       394,500
                                   (147,300)
                 2,278,800
                                      1,761,700
                             1,761,700
                                        1,021,600
                                1,021,600
                                     0
                                     0
                              98,500
                                 86,400
                                    40,100
                             44,700
                                       0
                                      0
                                            0
                                    44,700
                                       1.64
                                     1.64