UGI Corporation 2002 Annual Report
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FINANCIAL REVIEW
BUSINESS OVERVIEW
UGI Corporation ("UGI") is a holding company that, through subsidiaries and
joint-venture affiliates, distributes and markets energy products and related
services. We are a domestic and international distributor of propane; a provider
of natural gas and electricity service through regulated local distribution
utilities; a generator of electricity through our ownership interests in
electric generation facilities; a regional marketer of energy commodities; and a
provider of heating and cooling services.
We conduct a national propane distribution business through AmeriGas
Partners, L.P. ("AmeriGas Partners") and its principal operating subsidiaries
AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle
OLP"). At September 30, 2002, UGI, through its wholly owned second-tier
subsidiary AmeriGas Propane, Inc. (the "General Partner"), held an approximate
51% effective interest in the Partnership. We refer to AmeriGas Partners and its
subsidiaries together as "the Partnership" and the General Partner and its
subsidiaries, including the Partnership, as "AmeriGas Propane."
Our natural gas and electric distribution utilities and electric
generation businesses are conducted through UGI Utilities, Inc. and its
subsidiaries ("UGI Utilities"). UGI Utilities owns and operates a natural gas
distribution utility ("Gas Utility") in parts of eastern and southeastern
Pennsylvania and an electricity distribution utility ("Electric Utility") in
northeastern Pennsylvania. UGI Utilities also owns interests in electricity
generating facilities in Pennsylvania which, together with Electric Utility, are
referred to herein as "Electric Operations."
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") conducts
an energy marketing business primarily in the Middle Atlantic region of the
United States through its wholly owned subsidiary, UGI Energy Services, Inc.
("Energy Services"). Through other subsidiaries, Enterprises (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 in the Middle Atlantic states ("HVAC"); and
(3) participates in propane joint-venture businesses in France ("Antargaz") and
in the Nantong region of China.
This Financial Review should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the business segment information included in Note 21.
RESULTS OF OPERATIONS
2002 COMPARED WITH 2001
CONSOLIDATED RESULTS
Variance-
Favorable
2002 2001 (Unfavorable)
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Diluted
Earnings Diluted
DILUTED Net (Loss) Net Earnings
NET EARNINGS Income Per Income (Loss)
INCOME PER SHARE (Loss) Share (Loss) Per Share
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(Millions of dollars,
except per share)
AmeriGas Propane $ 17.4 $ 0.62 $ 13.5 $ 0.49 $ 3.9 $ 0.13
UGI Utilities 42.5 1.52 46.6 1.70 (4.1) (0.18)
Energy Services 6.5 0.23 4.0 0.15 2.5 0.08
International Propane 7.5 0.27 (4.4) (0.16) 11.9 0.43
Corporate & Other (a) 1.6 0.06 (7.7) (0.28) 9.3 0.34
Changes in accounting (b) -- -- 4.5 0.16 (4.5) (0.16)
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Total (c) $ 75.5 $ 2.70 $ 56.5 $ 2.06 $ 19.0 $ 0.64
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(a) Consists principally of UGI, HVAC, UGI Enterprises' corporate and general
expenses and in Fiscal 2001, Hearth USA(TM). Hearth USA(TM) ceased operations in
October 2001. Net loss in Fiscal 2001 includes after-tax shut-down costs of $5.5
million or $0.20 per share associated with Hearth USA(TM) (see Note 16 to
Consolidated Financial Statements).
(b) Fiscal 2001 amounts include cumulative effect of accounting changes
associated with (1) the Partnership's changes in accounting for tank fee revenue
and tank installation costs and (2) the Company's adoption of SFAS 133 (see Note
3 to Consolidated Financial Statements).
(c) Results for Fiscal 2002 reflect the elimination of goodwill amortization
resulting from the adoption of Statement of Financial Accounting Standards
("SFAS") No. 142, "Goodwill and Other Intangible Assets." Pro Forma net income
and diluted earnings per share for Fiscal 2001 as if the adoption of SFAS 142
had occurred as of October 1, 2000 is $70.5 million and $2.58, respectively. For
a detailed discussion of SFAS 142 and its impact on the Company's results, see
Note 1 to Consolidated Financial Statements.
Although significantly warmer than normal weather negatively affected UGI
Utilities' and AmeriGas Propane's Fiscal 2002 operating results, our Fiscal 2002
net income and earnings per share increased more than 30%. The increase in net
income reflects the elimination of goodwill amortization as a result of the
adoption of SFAS 142, a significant increase in income from our International
Propane businesses, and the benefit of higher growth-related earnings from our
Energy Services business. In addition, results in Fiscal 2001 were negatively
impacted by operating losses and shut-down costs associated with Hearth USA(TM).
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FINANCIAL REVIEW (continued)
The following table presents certain financial and statistical information
by reportable segment for Fiscal 2002 and Fiscal 2001:
Increase
2002 2001 (Decrease)
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(Millions of dollars)
AMERIGAS PROPANE:
Revenues $ 1,307.9 $ 1,418.4 $ (110.5) (7.8)%
Total margin (a) $ 675.8 $ 582.4 $ 93.4 16.0%
EBITDA (b) $ 210.7 $ 209.3 $ 1.4 0.7%
Operating income $ 144.3 $ 133.8 $ 10.5 7.8%
Retail gallons sold (millions) 932.8 820.8 112.0 13.6%
Degree days - % colder (warmer)
than normal (c) (10.0)% 2.6% -- --
GAS UTILITY:
Revenues $ 404.5 $ 500.8 $ (96.3) (19.2)%
Total margin (a) $ 162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
System throughput -
billions of cubic feet ("bcf") 70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal (17.4)% 2.0% -- --
ELECTRIC OPERATIONS:
Revenues $ 86.0 $ 83.9 $ 2.1 2.5%
Total margin (a) $ 32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 13.2 $ 10.7 $ 2.5 23.4%
Distribution sales - millions of
kilowatt hours ("gwh") 933.6 945.5 (11.9) (1.3)%
ENERGY SERVICES:
Revenues $ 332.3 $ 370.7 $ (38.4) (10.4)%
Total margin (a) $ 21.4 $ 13.4 $ 8.0 59.7%
Operating income $ 11.1 $ 7.3 $ 3.8 52.1%
INTERNATIONAL PROPANE:
Revenues $ 46.7 $ 50.9 $ (4.2) (8.3)%
Total margin (a) $ 24.1 $ 22.5 $ 1.6 7.1%
EBITDA (b) $ 7.1 $ 5.1 $ 2.0 39.2%
Operating income $ 3.9 $ 0.8 $ 3.1 387.5%
Income (loss) from equity investees $ 8.3 $ (1.5) $ 9.8 N.M.
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N.M. - Not meaningful.
(a) Total margin represents total revenues less cost of sales and, with respect
to Electric Operations, revenue-related taxes, i.e. Electric Utility gross
receipts taxes. For financial statement purposes, revenue-related taxes are
included in "taxes other than income taxes" on the Consolidated Statements of
Income.
b) EBITDA (earnings before interest expense, income taxes, depreciation and
amortization, minority interests, income (loss) from equity investees, and the
cumulative effect of accounting changes) should not be considered as an
alternative to net income (as an indicator of operating performance) or as an
alternative to cash flow (as a measure of liquidity or ability to service debt
obligations) and is not a measure of performance or financial condition under
accounting principles generally accepted in the United States. The Company's
definition of EBITDA may be different from that used by other companies.
(c) 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 United States.
AMERIGAS PROPANE. The Partnership's Fiscal 2002 operating results were
negatively impacted by significantly warmer than normal heating-season weather.
Fiscal 2002 temperatures based upon heating degree day data provided by NOAA
were approximately 10.0% warmer than normal and 12.3% warmer than Fiscal 2001.
Notwithstanding the impact of the warmer weather on heating-related sales and
the effects of a sluggish U.S. economy on commercial sales, retail gallons sold
increased 112.0 million gallons principally as a result of the full-year effect
of the Partnership's August 21, 2001, acquisition of Columbia Propane (see Note
2 to Consolidated Financial Statements) and, to a much lesser extent, greater
volumes from our PPX(R) grill cylinder exchange business. The increase in PPX(R)
sales principally reflects the effect on Fiscal 2002 grill cylinder exchanges
resulting from recently enacted National Fire Protection Association ("NFPA")
guidelines and, to a lesser extent, the full-year effects of Fiscal 2001
increases in the number of PPX(R) distribution outlets. The NFPA guidelines
require that propane grill cylinders refilled after April 1, 2002, be fitted
with overfill protection devices ("OPDs").
Retail propane revenues were $1,070.6 million in Fiscal 2002, a decrease
of $37.8 million from Fiscal 2001, reflecting a $189.0 million decrease as a
result of lower average selling prices partially offset by a $151.2 million
increase as a result of the greater retail volumes sold. Wholesale propane
revenues were $121.1 million in Fiscal 2002, a decrease of $93.5 million,
reflecting a $62.0 million decrease due to lower average selling prices and a
$31.5 million decrease as a result of lower wholesale volumes sold. The lower
Fiscal 2002 retail and wholesale selling prices resulted from lower Fiscal 2002
propane product costs. Revenues from other sales and services increased $20.8
million primarily due to the full-year impact of Columbia Propane. Total cost of
sales declined $203.9 million in Fiscal 2002 reflecting lower average propane
product costs and the lower wholesale sales partially offset by the higher
retail gallons sold.
Total margin increased $93.4 million reflecting the full-year volume
impact of the Columbia Propane acquisition and a $35.5 million increase in total
margin from PPX(R) reflecting higher volumes and unit margins. PPX(R) propane
unit margins in Fiscal 2002 were higher than in Fiscal 2001 reflecting increases
in sales prices to fund OPD valve replacement capital expenditures on
out-of-compliance grill cylinders. The extent to which this greater level of
PPX(R) margin is sustainable in the future will depend upon a number of factors,
including the continuing rate of OPD valve replacement and competitive market
conditions.
EBITDA (earnings before interest expense, income taxes, depreciation and
amortization, minority interests, income from equity investees, and the
cumulative effect of accounting changes) increased $1.4 million in Fiscal 2002
as the significant increase in total margin was substantially offset by an $88.8
million increase in Partnership operating and administrative expenses and a
decrease in other income. EBITDA of PPX(R) increased approximately $21 million
in Fiscal 2002 partially offsetting the effects of the significantly warmer
winter weather on our heating-related volumes. Although EBITDA is not a measure
of performance or financial condition under accounting principles generally
accepted
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UGI Corporation 2002 Annual Report
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in the United States, it is included in this analysis to provide additional
information for evaluating the Partnership's ability to pay and declare the
Minimum Quarterly Distribution of $0.55 ("MQD") and for evaluating the
Partnership's performance. The Partnership's definition of EBITDA may be
different from the definition of EBITDA used by other companies. The greater
operating and administrative expenses in Fiscal 2002 resulted primarily from the
full-year impact of the Columbia Propane acquisition and higher volume-driven
PPX(R) expenses. During Fiscal 2002, the Partnership completed its planned
blending of 90 Columbia Propane distribution locations with existing AmeriGas
Propane locations. As a result of these district consolidations and other cost
reduction activities, management believes that by September 30, 2002 it achieved
its anticipated $24 million reduction in annualized operating cost savings
subsequent to the acquisition of Columbia Propane. Operating income increased
$10.5 million, significantly more than the increase in EBITDA, principally due
to the cessation of goodwill amortization in Fiscal 2002 as a result of the
adoption of SFAS 142 (see Note 1 to Consolidated Financial Statements) partially
offset by higher depreciation and intangible asset amortization associated with
Columbia Propane and higher PPX(R) depreciation. Fiscal 2001 operating income
includes $23.8 million of goodwill amortization.
GAS UTILITY. Weather in Gas Utility's service territory during Fiscal 2002 based
upon heating degree days was 17.4% warmer than normal compared to weather that
was 2.0% colder than normal in Fiscal 2001. As a result of the significantly
warmer weather and the effects of a weak economy on commercial and industrial
natural gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in Fiscal 2002 Gas Utility revenue reflects the
impact of lower purchased gas cost ("PGC") rates, resulting from the pass
through of lower natural gas costs to firm-residential, commercial and
industrial (collectively, "core-market") customers, and the lower distribution
system throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002
compared to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and
the decline in core-market throughput in Fiscal 2002.
The decline in Gas Utility margin principally reflects a $6.0 million
decline in core-market margin due to the lower sales; a $6.6 million decline in
interruptible margin due principally to the flowback of certain interruptible
customer margin to core-market customers beginning December 1, 2001 pursuant to
the Gas Restructuring Order; and lower firm delivery service total margin due to
lower sales. Interruptible customers are those who have the ability to switch to
alternate fuels.
Gas Utility operating income declined $10.7 million in Fiscal 2002
reflecting the previously mentioned decline in total margin and a decrease in
pension income partially offset by lower operating expenses. Operating expenses
declined $4.1 million primarily as a result of lower charges for uncollectible
accounts and lower distribution system expenses. Depreciation expense declined
$1.2 million due to a change effective April 1, 2002 in the estimated useful
lives of Gas Utility's natural gas distribution assets resulting from an asset
life study required by the PUC.
ELECTRIC OPERATIONS. The decline in Electric Utility kilowatt-hour sales in
Fiscal 2002 reflects the effects on heating-related sales of significantly
warmer winter weather partially offset by the beneficial effect on air
conditioning sales of warmer summer weather. Notwithstanding the decrease in
total kilowatt-hour sales, revenues increased $2.1 million principally due to an
increase in state tax surcharge revenue and greater third-party sales of
electricity produced by our Pennsylvania-based electric generation facilities.
Electric Operations cost of sales was $48.6 million in Fiscal 2002 compared to
$51.9 million in Fiscal 2001 principally reflecting the impact of the lower
sales and lower purchased power unit costs partially offset by the full-period
increase to cost of sales resulting from the transfer of our Hunlock Creek
electricity generation assets to Hunlock Creek Energy Ventures ("Energy
Ventures") in December 2000. Energy Ventures is an electricity generation
joint venture with a subsidiary of Allegheny Energy, Inc. Subsequent to the
formation of Energy Ventures, our electric generating business purchases its
share of the power produced by Energy Ventures rather than producing this
electricity itself. As a result, the cost of this power is reflected in cost of
sales whereas prior to the formation of Energy Ventures such costs were
reflected as operating and administrative expenses.
Electric Operations total margin increased $4.2 million in Fiscal 2002 as
a result of lower purchased power unit costs partially offset by the winter
weather-driven decline in sales. Operating income increased $2.5 million
reflecting the greater total margin and lower operating costs subsequent to the
formation of Energy Ventures partially offset by a decline in other income.
ENERGY SERVICES. Revenues from Energy Services declined $38.4 million,
notwithstanding a 27% increase in natural gas volumes sold, reflecting
significantly lower natural gas prices. Total margin increased principally as a
result of the acquisition of the energy marketing businesses of PG Energy in
July 2001, income from providing winter storage services and higher average unit
margins. The increase in total margin was partially offset by higher operating
expenses subsequent to the PG Energy acquisition.
INTERNATIONAL PROPANE. FLAGA's revenues in Fiscal 2002 were lower than in the
prior year as a result of lower average selling prices reflecting lower average
propane product costs. Weather based upon heating degree days was approximately
10% warmer than normal in Fiscal 2002 compared to weather that was 12% warmer
than normal in Fiscal 2001. The increase in FLAGA's total margin reflects higher
average unit margins principally as a result of declining propane product costs.
FLAGA's operating results also benefited from lower operating expenses,
principally reduced payroll costs, and a $1.2 million decrease in goodwill
amortization resulting from the adoption of SFAS 142.
The significant increase in income from our international propane joint
ventures in Fiscal 2002 principally reflects the full-year benefits from our
debt and equity investments in AGZ Holdings ("AGZ"), the parent company of
Antargaz, acquired on March 27, 2001. Operating results of Antargaz in Fiscal
2002 benefited from higher than normal unit margins, principally as a
15
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FINANCIAL REVIEW (continued)
result of lower propane product costs, and the elimination of goodwill
amortization effective April 1, 2002. In addition, income from our debt
investments in AGZ in Fiscal 2002 includes $0.9 million of interest income and a
currency transaction gain of $1.6 million resulting from AGZ's early redemption
of this euro-denominated debt in July 2002. As a result of the redemption of AGZ
debt during Fiscal 2002 and an expected decrease in Antargaz unit margins to
more normal levels, we anticipate income from our investment in AGZ in Fiscal
2003 to decline significantly from Fiscal 2002. Loss from International Propane
joint ventures in Fiscal 2001 includes a loss of $1.1 million from the write-off
of our propane joint-venture investment located in Romania.
CORPORATE & OTHER. Corporate & Other operating income was $3.0 million in Fiscal
2002 compared to a loss of $11.0 million in Fiscal 2001. The prior-year results
include operating losses, and $8.5 million of shut-down costs, associated with
Hearth USA(TM), and a $2.0 million loss from the write-down of an investment in
a business-to-business e-commerce company.
INTEREST EXPENSE AND INCOME TAXES. The increase in interest expense principally
reflects higher Partnership long-term debt outstanding resulting from the
Columbia Propane acquisition partially offset by lower levels of UGI Utilities
and Partnership bank loans outstanding and lower short-term interest rates. The
lower effective income tax rate in Fiscal 2002 principally reflects the
elimination of nondeductible goodwill amortization resulting from the adoption
of SFAS 142 and greater equity income from Antargaz.
2001 COMPARED WITH 2000
CONSOLIDATED RESULTS
Variance-
Favorable
2001 2000 (Unfavorable)
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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 $ 13.5 $ 0.49 $ -- $ -- $ 13.5 $ 0.49
UGI Utilities 46.6 1.70 48.9 1.79 (2.3) (0.09)
Energy Services 4.0 0.15 1.6 0.06 2.4 0.09
International Propane (4.4) (0.16) (5.6) (0.20) 1.2 0.04
Corporate & Other (7.7) (0.28) (0.2) (0.01) (7.5) (0.27)
Changes in accounting 4.5 0.16 -- -- 4.5 0.16
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Total $ 56.5 $ 2.06 $ 44.7 $ 1.64 $ 11.8 $ 0.42
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The higher Fiscal 2001 net income and earnings per share reflect a significant
increase in the Partnership's and Energy Services' results. Excluding the
cumulative effect of accounting changes and one-time costs to close the Hearth
USA(TM) retail stores, diluted earnings per share increased 28% to $2.10 in
Fiscal 2001.
The following table presents certain financial and statistical information by
business segment for Fiscal 2001 and Fiscal 2000:
Increase
2001 2000 (Decrease)
=================================================================================
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $ 1,418.4 $ 1,120.1 $ 298.3 26.6%
Total margin $ 582.4 $ 491.8 $ 90.6 18.4%
EBITDA $ 209.3 $ 158.6 $ 50.7 32.0%
Operating income $ 133.8 $ 90.2 $ 43.6 48.3%
Retail gallons sold (millions) 820.8 771.2 49.6 6.4%
Degree days - % colder (warmer)
than normal 2.6% (13.7)% -- --
GAS UTILITY:
Revenues $ 500.8 $ 359.0 $ 141.8 39.5%
Total margin $ 177.9 $ 170.8 $ 7.1 4.2%
Operating income $ 87.8 $ 86.2 $ 1.6 1.9%
System throughput -
billions of cubic feet ("bcf") 77.3 79.7 (2.4) (3.0)%
Degree days - % colder (warmer)
than normal 2.0% (9.9)% -- --
ELECTRIC OPERATIONS:
Revenues $ 83.9 $ 77.9 $ 6.0 7.7%
Total margin $ 28.6 $ 40.8 $ (12.2) (29.9)%
Operating income $ 10.7 $ 15.1 $ (4.4) (29.1)%
Distribution sales - millions of
kilowatt hours ("gwh") 945.5 907.2 38.3 4.2%
ENERGY SERVICES:
Revenues $ 370.7 $ 146.9 $ 223.8 152.3%
Total margin $ 13.4 $ 6.2 $ 7.2 116.1%
Operating income $ 7.3 $ 2.8 $ 4.5 160.7%
INTERNATIONAL PROPANE:
Revenues $ 50.9 $ 50.5 $ 0.4 0.8%
Total margin $ 22.5 $ 20.8 $ 1.7 8.2%
EBITDA $ 5.1 $ 2.8 $ 2.3 82.1%
Operating income (loss) $ 0.8 $ (1.8) $ 2.6 144.4%
Loss from equity investees $ (1.5) $ (0.9) $ 0.6 66.7%
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AMERIGAS PROPANE. Retail propane gallons sold increased 49.6 million gallons
(6.4%) primarily due to the effects of colder weather and the impact of
acquisitions, including the August 21, 2001 acquisition of Columbia Propane.
Temperatures based upon heating degree days were 2.6% colder than normal in
Fiscal 2001 compared to temperatures that were 13.7% warmer than normal in
Fiscal 2000. The greater acquisition and weather-related sales were reduced by
customer conservation resulting from higher product costs and a slowing U.S.
economy. The wholesale price of propane at Mont Belvieu, Texas, a major U.S.
supply point, reached a high of 95 cents per gallon in Fiscal 2001 compared to a
high of 74 cents per gallon during Fiscal 2000.
Total revenues from retail propane sales increased $238.1 million
reflecting a $182.1 million increase as a result of higher average selling
prices and a $56.0 million increase as a result of the higher
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UGI Corporation 2002 Annual Report
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retail volumes sold. Wholesale propane revenues increased $61.9 million
principally reflecting higher average prices and greater sales associated with
product cost management activities. Cost of sales increased $207.7 million as a
result of higher per unit propane product costs and the greater retail and
wholesale volumes sold.
Total margin increased $90.6 million due to the impact of
higher-than-normal average retail unit margins and, to a lesser extent, the
greater retail propane volumes sold. Retail propane unit margins in Fiscal 2001
benefited from gains on derivative hedge instruments and favorably priced supply
arrangements.
The significant increase in EBITDA in Fiscal 2001 resulted from the
increase in margin partially offset by a $37.3 million increase in Partnership
operating and administrative expenses. Operating and administrative expenses of
the Partnership were $380.0 million in Fiscal 2001 compared to $342.7 million in
Fiscal 2000. Adjusting Fiscal 2000 expenses for the impact of the Partnership's
change in accounting for tank installation costs, operating and administrative
expenses of the Partnership increased $44.3 million. The higher Fiscal 2001
expenses reflect (1) higher employee-related costs, including greater overtime
and incentive compensation costs; (2) growth-related expenses, including the
impact of Columbia Propane and other acquisitions, and expenses associated with
our PPX(R) grill cylinder exchange business; and (3) higher distribution costs,
including vehicle fuel and lease expense. Depreciation and amortization expense
of the Partnership increased $7.4 million reflecting greater depreciation
associated with acquisitions and $4.4 million of depreciation expense resulting
from the change in accounting for tank installation costs.
GAS UTILITY. Although temperatures based upon heating degree days were colder in
Fiscal 2001, total system throughput declined 3.0% as the impact of the colder
weather was more than offset by lower interruptible and firm delivery service
volumes, the impact of price-induced customer conservation, and the effects of a
slowing economy. Natural gas prices were significantly higher in Fiscal 2001
than in the prior year. The higher prices resulted in fuel switching by many of
our interruptible customers, who have the ability to switch to alternate fuels,
and encouraged price-induced conservation by many of our firm customers.
Throughput to our core-market customers increased 3.3 bcf (10.6%) reflecting the
impact of the colder Fiscal 2001 weather.
The significant increase in Gas Utility revenues is primarily a result of
higher core-market revenues reflecting greater PGC rates and higher revenues
from sales to customers not on our distribution system ("off-system sales"). Gas
Utility's tariffs permit it to pass through prudently incurred gas costs to its
core-market customers through higher PGC rates.
Gas Utility cost of gas totaled $322.9 million in Fiscal 2001 compared
with $184.2 million in Fiscal 2000 principally reflecting the higher average PGC
rates and, to a lesser extent, higher core-market and off-system sales.
Gas Utility total margin increased $7.1 million reflecting a $12.1 million
increase in core-market margin partially offset by lower total margin from
interruptible customers. The decline in interruptible margin reflects lower
average interruptible unit margins due to a decline in the spread between oil
and natural gas prices and the lower interruptible throughput.
Gas Utility operating income increased $1.6 million as the previously
mentioned increase in total margin and an increase in pension income was
partially offset by higher operating and administrative expenses. The increase
in operating and administrative expenses includes, among other things, greater
allowances for uncollectible accounts, reflecting significantly higher Fiscal
2001 customer bills, and lower income from environmental insurance litigation
settlements. Such settlements totaled $0.9 million in Fiscal 2001 compared with
$4.5 million in Fiscal 2000. Depreciation expense increased $1.1 million
reflecting greater depreciation associated with distribution system capital
expenditures.
ELECTRIC OPERATIONS. Electric Utility distribution system sales in Fiscal 2001
increased 4.2% on favorable weather. Revenues increased as a result of the
higher distribution system sales as well as off-system sales of electricity
generated by Energy Ventures. Cost of sales totaled $51.9 million in Fiscal 2001
compared to $34.2 million in the prior year. The increase reflects higher
per-unit purchased power costs, the impact on cost of sales resulting from the
formation of Energy Ventures, and the higher Fiscal 2001 sales.
Electric Operations total margin decreased $12.2 million as a result of
the higher purchased power costs. Operating income declined less than the
decline in total margin reflecting lower power production and depreciation
expenses subsequent to the formation of Energy Ventures and lower utility realty
taxes.
ENERGY SERVICES. Revenues from Energy Services increased significantly
reflecting higher natural gas prices and acquisition-related volume growth.
Energy Services acquired the energy marketing businesses of Conectiv in October
2000 and PG Energy in July 2001. Total margin and operating income were also
substantially higher in Fiscal 2001 reflecting the greater acquisition-driven
sales volumes and higher average unit margins.
INTERNATIONAL PROPANE. FLAGA's results in Fiscal 2001 were adversely impacted by
weather that was approximately 12% warmer than normal. Propane volumes sold were
8.5% lower than in Fiscal 2000 reflecting the impact of the warm weather and
price-induced conservation. The increase in total margin, notwithstanding the
decline in sales volumes, reflects higher unit margins partially offset by the
impact of a weaker euro in Fiscal 2001. International Propane EBITDA increased
in Fiscal 2001 reflecting the greater total margin and a decline in FLAGA
operating expenses. International Propane loss from equity investees in Fiscal
2001 includes (1) a loss of $1.1 million from the write-off of our propane
joint-venture investment in Romania and (2) $0.5 million of income associated
with our investments in AGZ.
CORPORATE & OTHER. The increase in Corporate & Other revenues is principally a
result of HVAC, which was acquired in late Fiscal 2000. Corporate & Other
operating income in Fiscal 2001 declined $10.6 million principally reflecting an
$8.5 million provision for shut-down costs of Hearth USA(TM). Corporate & Other
operating loss in Fiscal 2001 also includes a $2.0 million loss resulting from
the write-down of an investment in a business-to-business e-commerce company,
lower interest and investment income, and greater incentive compensation costs.
17
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FINANCIAL REVIEW (continued)
INTEREST EXPENSE AND INCOME TAXES. Interest expense increased $6.3 million in
Fiscal 2001 primarily as a result of greater amounts of Partnership long-term
debt outstanding. The effective income tax rate was 45.9% in Fiscal 2001
compared to a rate of 46.4% in Fiscal 2000.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Our cash and cash equivalents totaled $194.3 million at September 30, 2002
compared with $87.5 million at September 30, 2001. These amounts include $114.0
million and $31.9 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 principal operating subsidiaries AmeriGas, Inc.
and UGI Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is largely
dependent upon distributions on AmeriGas Partners' limited partner units. During
Fiscal 2002, 2001 and 2000, AmeriGas, Inc. and UGI Utilities paid cash dividends
to UGI as follows:
Year Ended September 30, 2002 2001 2000
================================================================================
(Millions of dollars)
AmeriGas, Inc. $49.4 $41.0 $51.6
UGI Utilities 37.9 35.3 44.0
- --------------------------------------------------------------------------------
Total dividends to UGI $87.3 $76.3 $95.6
- --------------------------------------------------------------------------------
Dividends received by UGI from AmeriGas, Inc. and UGI Utilities, in
addition to dividends from UGI's other operating subsidiaries, are available to
pay dividends on UGI Common Stock and for investment purposes.
AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30, 2002
totaled $955.8 million. Included in this amount is $10 million outstanding under
AmeriGas OLP's Revolving Credit Facility.
In December 2001, AmeriGas Partners issued 1,843,047 Common Units to the
public through an underwritten public offering. In January 2002, the
underwriters exercised a portion of their overallotment option in the amount of
585,000 shares. The net proceeds from these Common Unit offerings of $49.7
million, $6.9 million of proceeds from an October 2001 sale of 350,000 Common
Units to the General Partner, and related capital contributions by the General
Partner in order to maintain its general partner interests, were contributed to
AmeriGas OLP and used to reduce Bank Credit Agreement borrowings and for working
capital.
The Partnership also completed a number of debt transactions during Fiscal
2002. In November 2001, AmeriGas Partners prepaid $15 million of 10.125% Senior
Notes at a redemption price of 103.375%. In April 2002, AmeriGas OLP repaid $60
million of maturing First Mortgage Notes from then-existing cash balances and
Revolving Credit Facility borrowings. In May 2002, AmeriGas Partners issued $40
million of Senior Notes due 2011 at an effective interest rate of 8.25%. The
proceeds were contributed to AmeriGas OLP and, along with related General
Partner capital contributions, used to reduce Revolving Credit Facility
borrowings and for working capital and general business purposes. On December 3,
2002, after the end of Fiscal 2002, AmeriGas Partners issued $88 million
principal amount of 8.875% Senior Notes due 2011 at an effective interest rate
of 8.30%. The net proceeds will be used to redeem in January 2003 the remaining
$85 million of 10.125% Senior Notes of AmeriGas Partners at a redemption price
of 102.25%.
In August 2002, AmeriGas OLP amended and restated its Bank Credit
Agreement. AmeriGas OLP's Bank Credit Agreement expires October 1, 2003 and
consists of (1) a $100 million Revolving Credit Facility and (2) a $75 million
Acquisition Facility. The Revolving Credit Facility may be used for working
capital and general purposes of AmeriGas OLP. There was $10 million outstanding
under this facility at September 30, 2002. Issued and outstanding letters of
credit under the Revolving Credit Facility, which reduce the amount available
for borrowings, totaled $19.8 million at September 30, 2002. AmeriGas OLP's
short-term borrowing needs are seasonal and are typically greatest during the
fall and winter heating-season months due to the need to fund higher levels of
working capital. AmeriGas OLP may borrow under its Acquisition Facility to
finance the purchase of propane businesses or propane business assets. In
addition to the $100 million available under the Revolving Credit Facility, the
Bank Credit Agreement allows up to $30 million of the Acquisition Facility to be
used for working capital purposes. There were no loans outstanding under the
Acquisition Facility at September 30, 2002. AmeriGas OLP could borrow up to
$67.7 million under the Acquisition Facility based upon eligible capital
expenditures made through September 30, 2002.
AmeriGas OLP also has a credit agreement with the General Partner to borrow
up to $20 million on an unsecured, subordinated basis, for working capital and
general purposes. UGI has agreed to contribute up to $20 million to the General
Partner to fund such borrowings.
AmeriGas Partners also has debt and equity shelf registration statements
with the U.S. Securities and Exchange Commission ("SEC").
The Partnership must maintain certain financial ratios in order to borrow
under the Bank Credit Agreement including a minimum interest coverage ratio and
a maximum debt to EBITDA ratio. The Partnership's ratios calculated as of
September 30, 2002 permit it to borrow up to the maximum amount available. For a
more detailed discussion of the Partnership's credit facilities, see Note 5 to
Consolidated Financial Statements. Based upon existing cash balances, cash
expected to be generated from operations, borrowings available under its Bank
Credit Agreement, and the expected refinancing of its maturing long-term debt,
the Partnership's management believes that the Partnership will be able to meet
its anticipated contractual commitments and projected cash needs in Fiscal 2003.
UGI UTILITIES. UGI Utilities' debt outstanding totaled $285.6 million at
September 30, 2002. Included in this amount is $37.2 million under revolving
credit agreements.
18
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
UGI Utilities may borrow up to a total of $97 million under its revolving
credit agreements. The revolving credit agreements contain financial covenants
including interest coverage ratios, debt service, and minimum tangible net
worth. In September 2002, UGI Utilities issued $40 million face value of Series
C Medium-Term notes under a shelf registration statement with the SEC. The
proceeds of the issuance were used after the end of Fiscal 2002 principally to
repay debt maturing in October 2002. UGI Utilities may issue up to an additional
$85 million of debt securities under the shelf registration statement.
Based upon cash expected to be generated from operations, the expected
ability to refinance all or a portion of long-term debt maturing in Fiscal 2003,
and borrowings available under revolving credit agreements, management believes
that UGI Utilities will be able to meet its anticipated contractual and
projected cash commitments in Fiscal 2003. For a more detailed discussion of UGI
Utilities' debt and credit facilities, see Note 5 to Consolidated Financial
Statements.
ENERGY SERVICES. Energy Services has a receivables purchase facility
("Receivables Facility") with an issuer of receivables-backed commercial paper
expiring November 30, 2004. Under the Receivables Facility, Energy Services
transfers, on an ongoing basis and without recourse, its trade accounts
receivable to its wholly owned, special purpose, bankruptcy-remote subsidiary,
Energy Services Funding Corporation ("ESFC") which is consolidated for financial
statement purposes. ESFC pays Energy Services for the receivables it purchases
as these receivables are collected from customers. In addition, from time to
time ESFC may sell an undivided interest in these receivables for up to $50
million in proceeds to a commercial paper conduit of a major bank. The proceeds
of these sales are less than the face amount of the accounts receivable sold by
an amount that approximates the purchaser's financing cost of issuing its own
receivables-backed commercial paper. ESFC was created and has been structured to
isolate its assets from creditors of Energy Services and its affiliates,
including UGI. In accordance with a servicing arrangement, Energy Services
continues to service, administer and collect trade receivables on behalf of the
commercial paper issuer and ESFC. This two-step transaction is accounted for as
a sale of receivables following the provisions of SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities."
At September 30, 2002, no receivables had been sold to the commercial
paper conduit and removed from the balance sheet. During Fiscal 2002, ESFC sold
a total of $34 million of receivables to the commercial paper conduit. Losses on
sales of receivables that occurred during Fiscal 2002 were not material.
FLAGA. FLAGA has a 15 million euro working capital loan commitment from a
European bank. Borrowings under the working capital facility totaled 8.7 million
euro ($8.6 million U.S. dollar equivalent) at September 30, 2002. Debt issued
under this agreement, as well as $75.1 million of acquisition and special
purpose debt of FLAGA, are subject to guarantees of UGI. For a more detailed
discussion of FLAGA's debt, see Note 5 to Consolidated Financial Statements.
FLAGA's management expects to repay long-term debt maturing in Fiscal 2003
principally through cash generated from operations as well as short-term
borrowings and capital contributions from UGI.
CASH FLOWS
OPERATING ACTIVITIES. Cash flow from operating activities was $247.5 million in
Fiscal 2002 compared to $203.5 million in Fiscal 2001. Cash flow from operating
activities before considering changes in working capital was $233.7 million in
Fiscal 2002 compared to $179.8 million in Fiscal 2001 principally reflecting
significantly higher noncash charges for income taxes and the impact of
settlement payments in Fiscal 2001 associated with the Energy Services'
exchange-traded natural gas derivative hedge contracts. In Fiscal 2002, changes
in operating working capital provided $13.8 million of operating cash flow
compared to $23.7 million of such cash flow in Fiscal 2001.
INVESTING ACTIVITIES. Cash spent for property, plant and equipment totaled $94.7
million in Fiscal 2002, an increase of $15.7 million from Fiscal 2001,
reflecting a $15.6 million increase in Partnership capital expenditures
principally for PPX(R), including expenditures for grill cylinder OPDs to comply
with NFPA guidelines, and to a much lesser extent the full-year effect of
capital expenditures associated with the Columbia Propane businesses. Cash flows
from investing activities in Fiscal 2002 also include $17.7 million of cash
proceeds from the early redemption of AGZ bonds in July 2002.
FINANCING ACTIVITIES. During Fiscal 2002, we paid cash dividends on UGI Common
Stock of $44.8 million compared to $53.2 million in Fiscal 2001. The higher
dividends paid in the prior year reflect the one-time impact of a change in the
timing of funding the quarterly dividend from the first day of the quarter to
the last day of the previous quarter. During Fiscal 2002, AmeriGas Partners
received net proceeds of $49.7 million from its public offering of 2.4 million
Common Units. During Fiscal 2002, AmeriGas OLP repaid $20 million of Acquisition
Facility borrowings and $60 million of maturing First Mortgage Notes, and
AmeriGas Partners redeemed prior to maturity $15 million of its 10.125% Senior
Notes. In addition, AmeriGas Partners issued $40 million face amount of 8.875%
Senior Notes and contributed the proceeds to AmeriGas OLP to reduce indebtedness
under its Revolving Credit Facility and for working capital and general business
purposes. In September 2002, UGI Utilities issued $40 million face amount of
19
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FINANCIAL REVIEW (continued)
Medium-Term Notes and used the proceeds, after the end of Fiscal 2002,
principally to repay maturing long-term debt.
DIVIDENDS AND DISTRIBUTIONS
In April 2002, our board of directors increased the annual dividend rate on UGI
Common Stock to $1.65 a share from $1.60. Dividends declared on our Common Stock
in Fiscal 2002 totaled $44.8 million.
At September 30, 2002, our approximate 51% effective ownership interest in
the Partnership consisted of (1) 14.6 million Common Units; (2) 9.9 million
Subordinated Units; and (3) a 2% general partner interest. The remaining
approximate 49% effective interest consisted of 24.9 million publicly held
Common Units. Approximately 45 days after the end of each fiscal quarter, the
Partnership distributes all of its Available Cash (as defined in the Amended and
Restated 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 could be made on
the Subordinated Units. Because certain cash-based performance and distribution
requirements were met in respect of the quarter ended September 30, 2002,
effective November 18, 2002 the remaining 9.9 million Subordinated Units held by
the General Partner were converted to Common Units (see "Conversion of
Subordinated Units" below).
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 Fiscal 2002,
2001 and 2000 was approximately $109 million, $99 million and $94 million,
respectively. Based upon the number of Partnership units outstanding on
September 30, 2002, the amount of Available Cash needed annually to pay the MQD
on all units and the general partner interests is approximately $111 million. A
reasonable proxy for the amount of cash available for distribution that is
generated by the Partnership can be calculated by subtracting from the
Partnership's EBITDA (1) cash interest expense and (2) capital expenditures
needed to maintain operating capacity. Partnership distributable cash flow as
calculated under this method for Fiscal 2002, 2001 and 2000 is as follows:
Year Ended September 30, 2002 2001 2000
================================================================================
(Millions of dollars)
EBITDA $210.4 $208.6 $157.6
Cash interest expense (a) (88.5) (82.0) (76.7)
Maintenance capital expenditures (20.7) (17.8) (11.6)
- --------------------------------------------------------------------------------
Distributable cash flow $101.2 $108.8 $ 69.3
- --------------------------------------------------------------------------------
(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, among other things, the
impact of changes in working capital, which can significantly affect cash
available for distribution, and is not a measure of performance or financial
condition under accounting principles generally accepted in the United States
but provides additional information for evaluating the Partnership's ability to
declare and pay the MQD. The Partnership's definition of distributable cash flow
may be different from the definition used by other companies. Although the
levels of distributable cash flow in Fiscal 2002 and 2000 were less than the
full MQD, other sources of cash, including cash from equity offerings and
borrowings, was more than sufficient to permit the Partnership to pay the full
MQD. The ability of the Partnership to 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, the cost of propane and changes in
capital market conditions.
CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS
Pursuant to the Agreement of Limited Partnership of AmeriGas Partners, the 9.9
million AmeriGas Partners Subordinated Units held by the General Partner as of
September 30, 2002 were 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 certain cash-based performance and distribution requirements
were met.
In December 2002, the General Partner determined that the cash-based
performance and distribution requirements in respect of the quarter ended
September 30, 2002 had been met and, as a result, the remaining 9.9 million
Subordinated Units held by the Company were converted to Common Units effective
November 18, 2002. Concurrent with the Subordinated Unit conversion, the Company
recorded an increase in common stockholders' equity and a decrease in minority
interest of approximately $160 million associated with gains from sales of
Common Units by AmeriGas Partners in conjunction with, and subsequent to, its
April 19, 1995 initial public offering in accordance with the accounting
guidance in SEC Staff Accounting Bulletin No. 51, "Accounting for Sales of
Common Stock by a Subsidiary." The gains result because the public offering
prices of the AmeriGas Partners Common Units at the dates of their sales
exceeded the associated carrying amount of our investment in the Partnership. No
deferred taxes were recorded related to the gains due to the Company's intent to
hold its investment in the Partnership indefinitely. The changes to the
Company's balance sheet resulting from the Subordinated Unit conversion had no
effect on the Company's net income or cash flow. The conversion of the
Subordinated Units did not result in an increase in the number of AmeriGas
Partners limited partner units outstanding.
REDEMPTION OF AGZ BONDS
In July 2002, the Company received $19.3 million in cash from AGZ representing
repayment of 18 million euro face value (90%), $17.7 million U.S. dollar
equivalent, of redeemable bonds of AGZ ("AGZ Bonds") held by the Company, plus
accrued interest. This repayment was funded from the proceeds of an AGZ
placement of high-yield debt. The Company purchased the AGZ Bonds on March 27,
2001 in conjunction with its joint-venture investment, through AGZ, in Antargaz,
a leading distributor of propane and related gases in France. Concurrent with
the repayment, the remaining 2.0 million
20
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
euro (10%) investment in AGZ Bonds was converted to additional shares of AGZ.
The Company recorded a pretax currency transaction gain of $1.6 million as a
result of the repayment of the AGZ Bonds. After these transactions, the Company
continues to hold an approximate 19.5% equity investment in AGZ.
UGI UTILITIES PENSION PLAN
UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI, UGI Utilities, and certain of UGI's other subsidiaries. During
Fiscal 2002 and 2001, the market value of plan assets was negatively affected by
persistent declines in the equity markets. Notwithstanding the significant
decline in the market value of plan assets during these years, at September 30,
2002 the Pension Plan's assets exceeded its accumulated benefit obligations by
approximately $7.2 million. The Company is in full compliance with regulations
governing defined benefit pension plans, including ERISA rules and regulations,
and does not anticipate it will be required to make a contribution to the
Pension Plan in Fiscal 2003. Pretax pension income reflected in Fiscal 2002,
2001 and 2000 was $4.0 million, $5.9 million, and $3.0 million, respectively.
Pension income in Fiscal 2003 is expected to decline to approximately $1.0
million principally as a result of the impact of declines through September 2002
in the market value of Pension Plan assets.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures (which include
expenditures for capital leases but exclude acquisitions) by business segment
for Fiscal 2002, 2001 and 2000. We also provide amounts we expect to spend in
Fiscal 2003. We expect to finance Fiscal 2003 capital expenditures principally
from cash generated by operations and borrowings under our credit facilities.
Year Ended September 30, 2003 2002 2001 2000
================================================================================
(Millions of dollars) (estimate)
AmeriGas Propane $ 52.2 $ 53.5 $ 39.2 $ 30.4
UGI Utilities 44.9 35.9 36.8 36.4
International Propane 5.9 4.0 2.7 1.8
Other 1.8 1.3 0.6 2.4
- --------------------------------------------------------------------------------
Total $ 104.8 $ 94.7 $ 79.3 $ 71.0
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CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The following table presents significant contractual cash obligations under
agreements existing as of September 30, 2002 (in millions).
Fiscal Fiscal
2003 & 2004 2005 & 2006 Thereafter Total
================================================================================
Long-term debt $207.0 $ 296.8 $771.9 $1,275.7
UGI Utilities preferred - 2.0 18.0 20.0
stock
Operating leases 71.7 50.8 63.6 186.1
Energy Services
supply contracts 157.5 - - 157.5
Gas and Electric
utility supply contracts 202.9 80.2 107.3 390.4
- --------------------------------------------------------------------------------
Total $639.1 $ 429.8 $960.8 $2,029.7
- --------------------------------------------------------------------------------
UTILITY REGULATORY MATTERS
The Pennsylvania Public Utility Commission ("PUC") approved a settlement
establishing rules for Electric Utility Provider of Last Resort ("POLR") service
on March 28, 2002, and a separate settlement that modified these rules on June
13, 2002 (collectively the "POLR Settlement"). Under the terms of the POLR
Settlement, Electric Utility terminated stranded cost recovery through its
Competitive Transition Charge ("CTC") from commercial and industrial ("C&I")
customers on July 31, 2002, and from residential customers on October 31, 2002,
and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I
customers and as of November 1, 2002 for residential customers. Stranded costs
are electric generation-related costs that traditionally would be recoverable in
a regulated environment but may not be recoverable in a competitive electric
generation market. Charges for generation service will (1) initially be set at a
level equal to the rates paid by Electric Utility customers for POLR service
under the statutory rate caps; (2) may be raised at certain designated times up
to certain specified caps through December 2004; and (3) may be set at market
rates thereafter. Electric Utility may also offer multiple year POLR contracts
to its customers. The POLR Settlement provides for annual shopping periods
during which customers may elect to remain on POLR service or choose an
alternate supplier. Customers who do not select an alternate supplier will be
obligated to remain on POLR service until the next shopping period. Residential
customers who return to POLR service at a time other than during the annual
shopping period must remain on POLR service until the date of the second open
shopping period after returning. C&I customers who return to POLR service at a
time other than during the annual shopping period must remain on POLR service
until the next open shopping period, and may, in certain circumstances, be
subject to generation rate surcharges.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act. Among other things, the implementation
of the Gas Restructuring Order resulted in an increase in Gas Utility's
core-market base rates effective October 1, 2000. This base rate increase was
designed to generate approximately $16.7 million in additional net annual
revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced
its core-market PGC rates by an annualized amount of $16.7 million in the first
14 months following the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its PGC
rates by amounts equal to the margin it receives from interruptible customers
using pipeline capacity contracted by Gas Utility for core-market customers. As
a result, Gas Utility operating results are more sensitive to the effects of
heating-season weather and less sensitive to the market prices of alternative
fuels.
MANUFACTURED GAS PLANTS
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities does not expect its costs for investigation and remediation of
hazardous substances at Pennsylvania MGP sites to be material to its results of
operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. UGI Utilities has been notified of several sites
outside
21
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FINANCIAL REVIEW (continued)
Pennsylvania on which (1) MGPs were formerly operated by it or owned or operated
by its former subsidiaries and (2) either environmental agencies or private
parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating two
claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be
liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities if a court were to conclude that the subsidiary's separate corporate
form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance companies
alleging that the defendants breached contracts of insurance by failing to
indemnify UGI Utilities for certain environmental costs. The suit seeks to
recover more than $11 million in such costs. During Fiscal 2002, 2001 and 2000,
UGI Utilities entered into settlement agreements with several of the insurers
and recorded pretax income of $0.4 million, $0.9 million and $4.5 million,
respectively, which amounts are included in operating and administrative
expenses in the Consolidated Statements of Income.
MARKET RISK DISCLOSURES
Our primary market risk exposures are (1) market prices for propane, natural gas
and electricity; (2) changes in interest rates; and (3) foreign currency
exchange rates.
The risk associated with fluctuations in the prices the Partnership and
our International Propane operations pay for propane is principally a result of
market forces reflecting changes in supply and demand for propane and other
energy commodities. The Partnership's profitability is sensitive to changes in
propane supply costs, and the Partnership generally attempts to pass on
increases in such costs to customers. The Partnership may not, however, always
be able to pass through product cost increases fully, particularly when product
costs rise rapidly. In order to reduce the volatility of the Partnership's
propane market price risk, it uses contracts for the forward purchase or sale of
propane, propane fixed-price supply agreements, and over-the-counter derivative
commodity instruments including price swap and option contracts. International
Propane's profitability is also sensitive to changes in propane supply costs. On
occasion, FLAGA uses derivative commodity instruments to reduce market risk
associated with a portion of its propane purchases. Over-the-counter derivative
commodity instruments utilized by the Partnership and FLAGA to hedge forecasted
purchases of propane are generally settled at expiration of the contract. In
order to minimize credit risk associated with its derivative commodity
contracts, the Partnership monitors established credit limits with the contract
counterparties. 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.
Gas Utility's tariffs contain clauses that permit recovery of
substantially all of the prudently incurred cost of natural gas it sells to its
customers. The recovery clauses provide for a periodic adjustment for the
difference between the total amount actually collected from customers and the
recoverable costs incurred. Because of this ratemaking mechanism, there is
limited commodity price risk associated with our Gas Utility operations.
During Fiscal 2002, 2001 and 2000, Electric Utility purchased all of its
electric power needs, in excess of the electric power it obtained from its
interests in electric generating facilities, under power supply arrangements of
various lengths and on the spot market. Beginning September 2002, Electric
Utility began purchasing its power needs from electricity suppliers under
fixed-price energy and capacity contracts and, to a much lesser extent, on the
spot market, and our electricity generation businesses began selling on the spot
market electric power produced from its interests in electricity generating
facilities to third parties. Prices for electricity can be volatile especially
during periods of high demand or tight supply. Although the generation component
of Electric Utility's rates is subject to various rate cap provisions as a
result of the Electricity Restructuring Order and the POLR Settlement, Electric
Utility's fixed-price contracts with electricity suppliers mitigate most risks
associated with offering customers a fixed price during the contract periods.
However, should any of the suppliers under these contracts fail to provide
electric power under the terms of the power and capacity contracts, increases,
if any, in the cost of replacement power or capacity would negatively impact
Electric Utility results. In order to reduce this non-performance risk, Electric
Utility has diversified its purchases across several suppliers and entered into
bilateral collateral arrangements with certain of them.
In order to manage market price risk relating to substantially all of
Energy Services' forecasted fixed-price sales of natural gas, we purchase
exchange-traded natural gas futures contracts or enter into fixed-price supply
arrangements. Exchange-traded natural gas futures contracts are guaranteed by
the New York Mercantile Exchange ("NYMEX") and have nominal credit risk. The
change in market value of these contracts generally requires daily cash deposits
in margin accounts with brokers. Although Energy Services' fixed-price supply
arrangements mitigate most risks associated with its fixed-price sales
contracts, should any of the natural gas suppliers under these arrangements fail
to perform, increases, if any, in the cost of replacement natural gas would
adversely impact Energy Services' results. In order to reduce this risk of
supplier nonperformance, Energy Services has diversified its purchases across a
number of suppliers.
We have both fixed-rate and variable-rate debt. Changes in interest rates
impact the cash flows of variable-rate debt but generally do not impact its fair
value. Conversely, changes in interest rates impact the fair value of fixed-rate
debt but do not impact their cash flows.
22
UGI Corporation 2002 Annual Report
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Our variable-rate debt includes borrowings under AmeriGas OLP's Bank
Credit Agreement, borrowings under UGI Utilities' revolving credit agreements,
and a substantial portion of FLAGA's debt. These debt agreements have interest
rates that are generally indexed to short-term market interest rates. At
September 30, 2002 and 2001, combined borrowings outstanding under these
agreements totaled $131.0 million and $162.3 million, respectively. Based upon
weighted average borrowings outstanding under these agreements during Fiscal
2002 and Fiscal 2001, an increase in short-term interest rates of 100 basis
points (1%) would have increased our interest expense by $1.4 million and $2.4
million, respectively.
The remainder of our debt outstanding is subject to fixed rates of
interest. A 100 basis point increase in market interest rates would result in
decreases in the fair value of this fixed-rate debt of $52.5 million and $57.9
million at September 30, 2002 and 2001, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $56.4 million and $58.8 million at September 30, 2002 and
2001, respectively.
Our long-term debt is typically issued at fixed rates of interest based
upon market rates for debt having similar terms and credit ratings. As these
long-term debt issues mature, we may 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. In order to reduce
interest rate risk associated with near-term forecasted issuances of fixed-rate
debt, from time to time we enter into interest rate protection agreements.
The primary currency for which the Company has exchange rate risk is the
U.S. dollar versus the euro. We do not currently use derivative instruments to
hedge foreign currency exposure associated with our international propane
businesses, principally FLAGA and Antargaz. 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. With respect to FLAGA, the net
effect of changes in foreign currency exchange rates on assets and liabilities
has been significantly limited because FLAGA's U.S. dollar denominated financial
instrument assets and liabilities are substantially equal in amount. With
respect to our equity investment in Antargaz, a 10% decline in the value of the
euro versus the U.S. dollar would reduce the book value of this investment by
approximately $2.0 million, which amount would be reflected in other
comprehensive income.
The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at September 30, 2002 and 2001. 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; and (3) interest rates on ten-year
U.S. treasury notes of 100 basis points.
Change in
Fair Value Fair Value
================================================================================
(Millions of dollars)
September 30, 2002:
Propane commodity price risk $ 9.8 $(11.1)
Natural gas commodity price risk 5.1 (6.0)
Interest rate risk (4.0) (6.6)
September 30, 2001:
Propane commodity price risk $(10.5) $(19.3)
Natural gas commodity price risk (1.5) (2.2)
Interest rate risk (3.0) (4.2)
- --------------------------------------------------------------------------------
Because the Company's derivative instruments generally qualify as hedges
under SFAS 133, we expect that changes in the fair value of derivative
instruments used to manage commodity or interest rate market risk would be
substantially offset by gains or losses on the associated anticipated
transactions.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding
Disclosure About Critical Accounting Policies," the Company has identified the
following critical accounting policies that are most important to the portrayal
of the Company's financial condition and results of operations. The following
policies require management's most subjective or complex judgments, as a result
of the need to make estimates regarding matters that are inherently uncertain.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved
in litigation regarding pending claims and legal actions that arise in the
normal course of our businesses. In addition, UGI Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be present. In accordance with accounting
principles generally accepted in the United States, the Company establishes
reserves for pending claims and legal actions or environmental remediation
obligations when it is probable that a liability exists and the amount or range
of amounts can be reasonably estimated. Reasonable estimates involve management
judgments based on a broad range of information and prior experience. These
judgments are reviewed quarterly as more information is received and the amounts
reserved are updated as necessary. Such estimated reserves may differ materially
from the actual liability, and such reserves may change materially as more
information becomes available and estimated reserves are adjusted.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility are subject
to regulation by the Pennsylvania Public Utility Commission ("PUC"). In
accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," we record the effects of rate regulation in our financial
statements as regulatory assets or regulatory liabilities. We continually assess
whether the regulatory assets are probable of future recovery by evaluating the
regulatory environment, recent rate orders and
23
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
public statements issued by the PUC and the status of any pending deregulation
legislation. If future recovery of regulatory assets ceases to be probable, the
elimination of those regulatory assets would adversely impact our results of
operations.
DEPRECIATION AND AMORTIZATION OF LONG-LIVED ASSETS. We compute depreciation on
UGI Utilities property, plant and equipment on a straight-line basis over the
average remaining lives of its various classes of depreciable property and on
other property, plant and equipment on a straight-line basis over estimated
useful lives generally ranging from two to 40 years. We also use amortization
methods and determine asset values of intangible assets other than goodwill
using reasonable assumptions and projections. Changes in the estimated useful
lives of property, plant and equipment and changes in intangible asset
amortization methods or values could have a material effect on our results of
operations. As of September 30, 2002, our regulatory assets totaled $62.0
million.
IMPAIRMENT OF GOODWILL. Certain of the Company's business units have goodwill
resulting from purchase business combinations. In accordance with SFAS 142, each
of our reporting units with goodwill is required to perform impairment tests
annually or whenever events or circumstances indicate that the value of goodwill
may be impaired. In order to perform these impairment tests, management must
determine the reporting unit's fair value using quoted market prices or, in the
absence of quoted market prices, valuation techniques which use discounted
estimates of future cash flows to be generated by the reporting unit. These cash
flow estimates involve management judgments based on a broad range of
information and historical results. To the extent estimated cash flows are
revised downward, the reporting unit may be required to write down all or a
portion of its goodwill which would adversely impact our results of operations.
As of September 30, 2002, our goodwill totaled $644.9 million.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No.
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144");
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146").
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using a
systematic and rational method over the related asset's useful life and adjust
the fair value of the liability resulting from the passage of time through
charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The
adoption of SFAS 143 did not have a material effect on our financial position or
results of operations. Our joint venture, AGZ Holdings, is required to adopt
SFAS 143 effective April 1, 2003. We are currently in the process of evaluating
the impact of SFAS 143 on AGZ Holdings.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," as it relates to the disposal of a segment of a business. SFAS
144 establishes a single accounting model for long-lived assets to be disposed
of based upon the framework of SFAS 121, and resolves significant implementation
issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption
of SFAS 144 did not affect our financial position or results of operations.
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"),
effective May 15, 2002. SFAS 4 had required that material gains and losses on
extinguishment of debt be classified as an extraordinary item. Under SFAS 145,
it is less likely that a gain or loss on extinguishment of debt would be
classified as an extraordinary item in our Consolidated Statement of Income.
Among other things, SFAS 145 also amends SFAS 13, "Accounting for Leases," to
require that certain lease modifications that have economic effects similar to
sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. The provisions of SFAS 145 relating to leases
became effective for transactions occurring after May 15, 2002. The adoption of
SFAS 145 did not affect our financial position or results of operations.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force ("EITF") No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity." Generally, SFAS 146 requires that a liability for costs
associated with an exit or disposal activity, including contract termination
costs, employee termination benefits and other associated costs, be recognized
when the liability is incurred. Under EITF No. 94-3, a liability was recognized
at the date of an entity's commitment to an exit plan. SFAS 146 will be
effective for disposal activities initiated after December 31, 2002.
FORWARD-LOOKING STATEMENTS
Information contained in this Financial Review and elsewhere in this Annual
Report may contain forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Such statements use forward-looking words such as "believe," "plan,"
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss plans, strategies, events or developments that
we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or
bases underlying the forward-looking statement. We believe that we have chosen
these assumptions or bases in good faith and that they are reasonable. However,
we caution you that
24
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
actual results almost always vary from assumed facts or bases, and the
differences between actual results and assumed facts or bases can be material,
depending on the circumstances. When considering forward-looking statements, you
should keep in mind the following important factors which could affect our
future results and could cause those results to differ materially from those
expressed in our forward-looking statements: (1) adverse weather conditions
resulting in reduced demand; (2) price volatility and availability of propane,
oil, electricity, and natural gas and the capacity to transport to market areas;
(3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) failure to acquire new customers thereby reducing or limiting any increase
in revenues; (6) liability for environmental claims; (7) customer conservation
measures and improvements in energy efficiency and technology resulting in
reduced demand; (8) adverse labor relations; (9) large customer, counterparty or
supplier defaults; (10) liability for personal injury and property damage
arising from explosions and other catastrophic events, including acts of
terrorism, resulting from operating hazards and risks incidental to generating
and distributing electricity and transporting, storing and distributing natural
gas and propane including liability in excess of insurance coverage; (11)
political, regulatory and economic conditions in the United States and 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.
- --------------------------------------------------------------------------------
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 of America and include
amounts that are based on management's best judgments and estimates.
The Company maintains a system of internal controls. Management believes
the system provides reasonable, but not absolute, 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
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 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 accountants and internal auditors.
The independent 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 of America, 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
25
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, stockholders' equity and cash flows present
fairly, in all material respects, the financial position of UGI Corporation and
its subsidiaries at September 30, 2002 and the results of their operations and
their cash flows for the year then ended in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion. The consolidated financial statements of UGI
Corporation and its subsidiaries as of September 30, 2001, and for each of the
two years in the period ended September 30, 2001, were audited by other
independent accountants who have ceased operations. Those independent
accountants expressed an unqualified opinion on those financial statements in
their report dated November 16, 2001.
As discussed in Note 1 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standards No. 142, Goodwill
and Other Intangible Assets, in fiscal 2002.
/S/ PRICEWATERHOUSECOOPERS LLP
Philadelphia, Pennsylvania
November 15, 2002,
except for Note 18 as to which
the date is December 16, 2002
- --------------------------------------------------------------------------------
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S REPORT OF
ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:
We have audited the accompanying consolidated balance sheets of UGI Corporation
and subsidiaries as of September 30, 2001 and 2000, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended September 30, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
UGI Corporation and subsidiaries as of September 30, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Notes 1 and 3 to the financial statements, effective
October 1, 2000, the Partnership changed its methods of accounting for tank
installation costs and nonrefundable tank fees and the Company adopted the
provisions of SFAS No. 133.
/S/ ARTHUR ANDERSEN LLP
Philadelphia, Pennsylvania
November 16, 2001
26
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30,
---------------------------------------------------------
2002 2001 2000
====================================================================================================================================
REVENUES
AmeriGas Propane $ 1,307.9 $ 1,418.4 $ 1,120.1
UGI Utilities 490.5 584.7 436.9
International Propane 46.7 50.9 50.5
Energy Services and other 368.6 414.1 154.2
- ------------------------------------------------------------------------------------------------------------------------------------
2,213.7 2,468.1 1,761.7
- ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
AmeriGas Propane cost of sales 632.1 836.0 628.3
UGI Utilities - gas, fuel and purchased power 290.3 374.8 218.1
International Propane cost of sales 22.6 28.4 29.7
Energy Services and other cost of sales 330.6 382.2 145.5
Operating and administrative expenses 597.5 517.8 461.2
Utility taxes other than income taxes 11.9 9.2 17.1
Depreciation and amortization 93.5 105.2 97.5
Provision for shut-down costs - Hearth USA(TM) -- 8.5 --
Other income, net (17.4) (23.0) (27.8)
- ------------------------------------------------------------------------------------------------------------------------------------
1,961.1 2,239.1 1,569.6
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 252.6 229.0 192.1
Income (loss) from equity investees 8.5 (1.6) (0.9)
Interest expense (109.1) (104.8) (98.5)
Minority interests in AmeriGas Partners (28.0) (23.6) (6.3)
- ------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES, SUBSIDIARY PREFERRED STOCK DIVIDENDS
AND ACCOUNTING CHANGES 124.0 99.0 86.4
Income taxes (46.9) (45.4) (40.1)
Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (1.6)
- ------------------------------------------------------------------------------------------------------------------------------------
Income before accounting changes 75.5 52.0 44.7
Cumulative effect of accounting changes, net -- 4.5 --
- ------------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 75.5 $ 56.5 $ 44.7
====================================================================================================================================
EARNINGS PER COMMON SHARE
Basic:
Income before accounting changes $ 2.74 $ 1.91 $ 1.64
Cumulative effect of accounting changes, net -- 0.17 --
- ------------------------------------------------------------------------------------------------------------------------------------
Net income $ 2.74 $ 2.08 $ 1.64
====================================================================================================================================
Diluted:
Income before accounting changes $ 2.70 $ 1.90 $ 1.64
Cumulative effect of accounting changes, net -- 0.16 --
- ------------------------------------------------------------------------------------------------------------------------------------
Net income $ 2.70 $ 2.06 $ 1.64
====================================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS)
Basic 27.550 27.163 27.219
====================================================================================================================================
Diluted 27.938 27.373 27.255
====================================================================================================================================
See accompanying notes to consolidated financial statements.
27
- --------------------------------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30,
----------------------------
ASSETS 2002 2001
====================================================================================================================================
CURRENT ASSETS
Cash and cash equivalents $ 194.3 $ 87.5
Accounts receivable (less allowances for doubtful accounts of $11.8 and $15.6, respectively) 157.7 180.8
Accrued utility revenues 8.1 11.1
Inventories 109.2 128.6
Deferred income taxes 10.4 25.2
Income taxes recoverable 1.7 --
Utility deferred fuel costs 4.3 --
Prepaid expenses and other current assets 44.3 25.7
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets 530.0 458.9
- ------------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 1,028.6 984.0
UGI Utilities 883.3 855.2
Other 80.5 74.3
- ------------------------------------------------------------------------------------------------------------------------------------
1,992.4 1,913.5
Accumulated depreciation and amortization (720.5) (645.5)
- ------------------------------------------------------------------------------------------------------------------------------------
Net property, plant, and equipment 1,271.9 1,268.0
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Goodwill and excess reorganization value 644.9 641.1
Intangible assets (less accumulated amortization of $10.3 and $5.8, respectively) 25.8 31.3
Utility regulatory assets 57.7 56.2
Other assets 84.1 94.7
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $2,614.4 $2,550.2
====================================================================================================================================
See accompanying notes to consolidated financial statements.
28
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
September 30,
-------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001
=============================================================================================================================
CURRENT LIABILITIES
Current maturities of long-term debt $ 148.7 $ 98.3
AmeriGas Propane bank loans 10.0 --
UGI Utilities bank loans 37.2 57.8
Other bank loans 8.6 10.0
Accounts payable 166.1 167.0
Employee compensation and benefits accrued 35.4 39.4
Dividends and interest accrued 41.5 38.4
Income taxes accrued -- 11.6
Deposits and advances 63.0 55.6
Other current liabilities 75.9 89.4
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 586.4 567.5
- -----------------------------------------------------------------------------------------------------------------------------
DEBT AND OTHER LIABILITIES
Long-term debt 1,127.0 1,196.9
Deferred income taxes 200.2 182.4
Deferred investment tax credits 8.4 8.8
Other noncurrent liabilities 79.1 72.8
Commitments and contingencies (note 13)
MINORITY INTERESTS
Minority interests in AmeriGas Partners 276.0 246.2
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) 396.6 395.0
Retained earnings 39.7 9.0
Accumulated other comprehensive income (loss) 6.6 (13.5)
- -----------------------------------------------------------------------------------------------------------------------------
442.9 390.5
Treasury stock, at cost (125.6) (134.9)
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 317.3 255.6
- -----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $2,614.4 $2,550.2
=============================================================================================================================
29
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30,
----------------------------------------------------
2002 2001 2000
====================================================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 75.5 $ 56.5 $ 44.7
Reconcile to net cash provided by operating activities:
Depreciation and amortization 93.5 105.2 97.5
Cumulative effect of accounting changes, net -- (4.5) --
Minority interests in AmeriGas Partners 28.0 23.6 6.3
Deferred income taxes, net 11.0 (5.5) 3.2
Net change in settled accumulated other comprehensive income 13.3 (16.9) --
Other, net 12.4 21.4 15.8
Net change in:
Accounts receivable and accrued utility revenues 12.6 (13.6) (63.4)
Inventories 19.7 (4.2) (26.1)
Deferred fuel costs (7.1) 9.9 (3.8)
Accounts payable (0.4) 5.8 52.0
Other current assets and liabilities (11.0) 25.8 6.5
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 247.5 203.5 132.7
- ------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (94.7) (78.0) (71.0)
Acquisitions of businesses, net of cash acquired (0.7) (209.1) (65.3)
Proceeds from redemption of AGZ Bonds 17.7 -- --
Net proceeds from disposals of assets 9.7 4.2 8.4
Investments in equity investees (0.3) (32.6) --
Other, net 1.9 2.2 6.4
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (66.4) (313.3) (121.5)
- ------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock (44.8) (53.2) (41.2)
Distributions on AmeriGas Partners publicly held Common Units (53.5) (44.3) (39.1)
Issuance of long-term debt 81.1 308.2 209.7
Repayment of long-term debt (105.0) (137.0) (95.4)
AmeriGas Propane bank loans increase (decrease) 10.0 (30.0) 8.0
UGI Utilities bank loans increase (decrease) (20.6) (42.6) 13.0
Other bank loans increase (decrease) (2.2) 6.2 (6.8)
Issuance of AmeriGas Partners Common Units 49.7 39.8 --
Proceeds from sale of AmeriGas OLP interest -- 50.0 --
Issuance of UGI Common Stock 11.0 7.6 3.8
Repurchases of UGI Common Stock -- (1.0) (9.6)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities (74.3) 103.7 42.4
- ------------------------------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH -- (0.3) (0.2)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents increase (decrease) $106.8 $ (6.4) $ 53.4
====================================================================================================================================
CASH AND CASH EQUIVALENTS:
End of year $194.3 $ 87.5 $ 93.9
Beginning of year 87.5 93.9 40.5
- ------------------------------------------------------------------------------------------------------------------------------------
Increase (decrease) $106.8 $ (6.4) $ 53.4
====================================================================================================================================
See accompanying notes to consolidated financial statements.
30
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Millions of dollars, except per share amounts)
Retained Accumulated Unearned
Earnings Other Compensation-
Common (Accumulated Comprehensive Restricted Treasury
Stock Deficit) Income (Loss) Stock Stock Total
=================================================================================================================================
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 gains
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 reacquired (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
Net income 56.5 56.5
Cumulative effect of change in
accounting principle - SFAS No. 133
(net of tax of $4.8) 7.1 7.1
Net loss on derivative instruments
(net of tax of $7.9) (10.5) (10.5)
Reclassification of net gains on
derivative instruments
(net of tax of $6.5) (10.3) (10.3)
Foreign currency translation
adjustments (net of tax of $0.1) 0.2 0.2
--------- --------- ---------
Comprehensive income 56.5 (13.5) 43.0
Cash dividends on Common Stock
($1.575 per share) (42.6) (42.6)
Common Stock issued:
Employee and director plans 0.3 5.5 5.8
Dividend reinvestment plan 0.2 2.3 2.5
Common Stock reacquired (1.0) (1.0)
Amortization of unearned compensation-
restricted stock awards 0.7 0.7
- ---------------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2001 395.0 9.0 (13.5) -- (134.9) 255.6
Net income 75.5 75.5
Net loss on derivative instruments
(net of tax of $0.4) (1.5) (1.5)
Reclassification of net losses on
derivative instruments
(net of tax of $11.6) 18.3 18.3
Foreign currency translation
adjustments (net of tax of $2.2) 4.4 4.4
Reclassification of foreign currency
translation gain
(net of tax of $0.5) (1.1) (1.1)
--------- --------- ---------
Comprehensive income 75.5 20.1 95.6
Cash dividends on Common Stock
($1.625 per share) (44.8) (44.8)
Common Stock issued:
Employee and director plans 1.0 7.4 8.4
Dividend reinvestment plan 0.6 2.0 2.6
Common Stock reacquired (0.1) (0.1)
- ---------------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2002 $ 396.6 $ 39.7 $ 6.6 $ -- $ (125.6) $ 317.3
=================================================================================================================================
See accompanying notes to consolidated financial statements.
31
- --------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. UGI Corporation ("UGI") is a holding company that owns and
operates natural gas and electric utility, electricity generation, propane
distribution, energy marketing and related businesses in the United States.
Through foreign subsidiaries and joint-venture affiliates, UGI also distributes
propane in Austria, the Czech Republic, Slovakia, France and China. We refer to
UGI and its consolidated subsidiaries collectively as "the Company" or "we."
Our utility business is conducted through our wholly owned subsidiary, UGI
Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates (1) a natural
gas distribution utility ("Gas Utility") in parts of eastern and southeastern
Pennsylvania and (2) an electricity distribution utility ("Electric Utility")
and electricity generation business (which together with Electric Utility are
referred to herein as "Electric Operations") in northeastern Pennsylvania.
We conduct a national propane distribution business through AmeriGas
Partners, L.P. ("AmeriGas Partners") and its principal operating subsidiaries
AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle
OLP"). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited
partnerships. UGI's wholly owned second-tier subsidiary AmeriGas Propane, Inc.
(the "General Partner") serves as the general partner of AmeriGas Partners and
AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as "the
Operating Partnerships") comprise the largest retail propane distribution
business in the United States serving residential, commercial, industrial, motor
fuel and agricultural customers from locations in 46 states. We refer to
AmeriGas Partners and its subsidiaries together as "the Partnership" and the
General Partner and its subsidiaries, including the Partnership, as "AmeriGas
Propane."
At September 30, 2002, the General Partner and its wholly owned subsidiary
Petrolane Incorporated ("Petrolane," a predecessor company of AmeriGas OLP)
collectively held a 1% general partner interest and a 49.1% limited partner
interest in AmeriGas Partners, and effective 50.6% and 50.5% ownership interests
in AmeriGas OLP and Eagle OLP, respectively. Our limited partnership interest in
AmeriGas Partners comprised 14,633,932 Common Units and 9,891,072 Subordinated
Units. The remaining 49.9% interest in AmeriGas Partners comprises 24,907,354
publicly held Common Units representing limited partner interests. Effective
November 18, 2002, the remaining 9,891,072 Subordinated Units held by us were
converted to Common Units (see Note 18).
The Partnership has no employees. Employees of the General Partner
conduct, direct and manage the activities of AmeriGas Partners and AmeriGas OLP.
The General Partner also provides management and administrative services to
AmeriGas Eagle Holdings, Inc., the general partner of Eagle OLP, under a
management services agreement. The General Partner is reimbursed monthly for all
direct and indirect expenses it incurs 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 the Partnership's significant minority interest; higher relative interest
charges; and, prior to 2002, higher effective income taxes associated with the
Partnership's pretax income resulting from nondeductible goodwill amortization.
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") conducts
an energy marketing business primarily in the Middle Atlantic region of the
United States through its wholly owned subsidiary, UGI Energy Services, Inc.
("Energy Services"). Through other subsidiaries, Enterprises (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 in the Middle Atlantic states ("HVAC"); and
(3) participates in propane joint-venture businesses in France and China.
UGI is exempt from registration as a holding company because it files an
annual exemption statement with the U.S. Securities and Exchange Commission
("SEC") 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").
CONSOLIDATION PRINCIPLES. The 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's limited partner interests in the Partnership as minority
interests. Entities in which we own 50 percent or less and in which we exercise
significant influence over operating and financial policies are accounted for by
the equity method (see Note 19). Investments in equity investees are included in
other assets in the Consolidated Balance Sheets.
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 (collectively,
"Utilities") are subject to regulation by the PUC. We account for Gas Utility
and Electric Utility in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of rate
regulation in the financial statements. If a separable portion of Gas Utility or
Electric Utility no longer meets the provisions of SFAS 71, we are required to
eliminate the financial statement effects of regulation for that portion of our
operations.
On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in
Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
provisions of the Gas Restructuring Order and the Gas Competition Act, we
believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS
71. For further information on the impact of
32
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
the Gas Competition Act and Pennsylvania's Electricity Customer Choice and
Competition Act ("Electricity Choice Act"), see Note 4.
DERIVATIVE INSTRUMENTS. Effective October 1, 2000, we adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. It requires that all
derivative instruments be recognized as either assets or liabilities and
measured at fair value. The accounting for changes in fair value depends upon
the purpose of the derivative instrument and whether it is designated and
qualifies for hedge accounting. To the extent a derivative instrument qualifies
and is designated as a hedge of the variability of cash flows associated with a
forecasted transaction ("cash flow hedge"), the effective portion of the gain or
loss on such derivative instrument is generally reported in other comprehensive
income and the ineffective portion, if any, is reported in net income. Such
amounts reported in other comprehensive income are reclassified into net income
when the forecasted transaction affects earnings. If a cash flow hedge is
discontinued because it is probable that the forecasted transaction will not
occur, the net gain or loss is immediately reclassified into net income. To the
extent derivative instruments qualify and are designated as hedges of changes in
the fair value of an existing asset, liability or firm commitment ("fair value
hedge"), the gain or loss on the hedging instrument is recognized in earnings
along with changes in the fair value of the hedged asset, liability or firm
commitment attributable to the hedged risk.
The adoption of SFAS 133 resulted 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. The increase in
accumulated other comprehensive income is attributable to net gains on
derivative instruments designated and qualifying as cash flow hedges on October
1, 2000. Prior to the adoption of SFAS 133, gains or losses on derivative
instruments associated with forecasted transactions generally were recorded in
net income when the forecasted transactions affected earnings. If it became
probable that the original forecasted transactions would not occur, we
immediately recognized in net income any gains or losses on the derivative
instruments.
For a detailed description of the derivative instruments we use, our
objectives for using them, and related supplemental information required by SFAS
133, see Note 14.
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 $106.2 million in 2002, $103.9 million in 2001,
and $96.9 million in 2000. We paid income taxes totaling $48.0 million in 2002,
$43.0 million in 2001, and $26.6 million in 2000.
REVENUE RECOGNITION. We recognize revenues from the sale of propane principally
as product is delivered to customers. Revenue from the sale of appliances and
equipment is recognized at the time of sale or installation. We record
Utilities' regulated revenues for service provided to the end of each month
which includes an accrual for certain unbilled amounts based upon estimated
usage.
We reflect the impact of Utilities' rate increases or decreases at the time they
become effective. Energy Services records revenues when energy products are
delivered to customers.
Effective October 1, 2000, the Partnership applied the guidance of SEC
Staff Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101")
with respect to its annually billed non-refundable tank fees. Under the new
accounting method, revenues from such fees are recorded on a straight-line basis
over one year. Prior to the change in accounting, such revenues were recorded
when billed. For a detailed description of this change in accounting and its
impact on our results, see Note 3.
INVENTORIES. Our inventories are stated at the lower of cost or market. We
determine cost principally on an average or first-in, first-out ("FIFO") method
except for appliances for which we use the specific identification method.
EARNINGS PER COMMON SHARE. Basic earnings per share reflect the weighted-average
number of common shares outstanding. Diluted earnings per share include the
effects of dilutive stock options and common stock awards. In the following
table, we present the shares used in computing basic and diluted earnings per
share for 2002, 2001 and 2000:
2002 2001 2000
==============================================================================
Denominator (millions of shares):
Average common shares
outstanding for basic computation 27.550 27.163 27.219
Incremental shares issuable for stock
options and awards 0.388 0.210 0.036
- ------------------------------------------------------------------------------
Average common shares outstanding for
diluted computation 27.938 27.373 27.255
- --------------------------------------------------------------------------------
INCOME TAXES. AmeriGas Partners and the Operating Partnerships 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 differences between
the book and tax bases of the Partnership's assets and liabilities. The
Operating Partnerships have subsidiaries which operate in corporate form and are
directly subject to federal income taxes.
Gas Utility and Electric Utility record deferred income taxes in the
Consolidated Statements of Income resulting from the use of accelerated
depreciation methods based upon amounts recognized for ratemaking purposes. They
also record a deferred tax liability for tax benefits that are flowed through to
ratepayers when temporary differences originate and record a regulatory income
tax asset for the probable increase in future revenues that will result when the
temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities'
plant additions over the service lives of the related property. Utilities
reduces its deferred income tax liability for the future tax benefits that will
occur when 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.
33
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 1 continued
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION. 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 and
equipment, we charge its original cost and the net cost of its removal to
accumulated depreciation for financial accounting purposes. We record
depreciation expense for Utilities' plant and equipment on a straight-line
method over the estimated average remaining lives of the various classes of its
depreciable property. Depreciation expense as a percentage of the related
average depreciable base for Gas Utility was 2.5% in 2002 and 2.6% in each of
2001 and 2000. Depreciation expense as a percentage of the related average
depreciable base for Electric Operations was 3.0% in each of 2002 and 2001, and
3.5% in 2000. 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 2
to 10 years for vehicles, equipment, and office furniture and fixtures.
Depreciation expense was $88.2 million in 2002, $75.7 million in 2001, and $69.3
million in 2000.
Effective October 1, 2000, the Partnership changed its method of
accounting for costs to install Partnership-owned tanks at customer locations.
Under the new accounting method, all costs to install such tanks, net of amounts
billed to customers, are capitalized and amortized over the estimated period of
benefit not exceeding ten years. For a detailed description of this change in
accounting and its impact on our results, see Note 3.
INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2002 2001
=================================================================
Subject to amortization:
Customer relationships, noncompete
agreements and other $ 36.1 $ 37.1
Accumulated amortization (10.3) (5.8)
- -----------------------------------------------------------------
$ 25.8 $ 31.3
- -----------------------------------------------------------------
Not subject to amortization:
Goodwill (a) $551.6 $547.8
Excess reorganization value 93.3 93.3
- -----------------------------------------------------------------
$644.9 $641.1
- -----------------------------------------------------------------
(a) The change in the carrying amount of goodwill from September 30, 2001 to
September 30, 2002 is principally the result of foreign currency translation.
Effective October 1, 2001, we early adopted the provisions of SFAS No.
142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the
financial accounting and reporting for acquired goodwill and other intangible
assets and supersedes Accounting Principles Board ("APB") Opinion No. 17,
"Intangible Assets." SFAS 142 addresses the financial accounting and reporting
for intangible assets acquired individually or with a group of other assets
(excluding those acquired in a business combination) at acquisition and also
addresses the financial accounting and reporting for goodwill and other
intangible assets subsequent to their acquisition. Under SFAS 142, an intangible
asset is amortized over its useful life unless that life is determined to be
indefinite. Goodwill, including excess reorganization value, and other
intangible assets with indefinite lives are not amortized but are subject to
tests for impairment at least annually. In accordance with the provisions of
SFAS 142, we ceased the amortization of goodwill and excess reorganization value
effective October 1, 2001.
We amortize customer relationship and noncompete agreement intangibles
over their estimated periods of benefit which do not exceed 15 years. Prior to
the adoption of SFAS 142, we amortized goodwill resulting from purchase business
combinations over 40 years, and excess reorganization value (resulting from
Petrolane's July 1993 reorganization under Chapter 11 of the U.S. Bankruptcy
Code) on a straight-line basis over 20 years. Amortization expense of intangible
assets was $4.6 million in 2002 including amortization expense associated with
customer contracts recorded in cost of sales. Amortization expense of intangible
assets in 2001 and 2000, which includes amortization of goodwill and excess
reorganization value prior to the adoption of SFAS 142, was $27.7 million and
$26.5 million, respectively. Estimated amortization expense of intangible assets
during the next five fiscal years is as follows: Fiscal 2003 - $3.8 million;
Fiscal 2004 - $3.4 million; Fiscal 2005 - $2.9 million; Fiscal 2006 - $2.4
million; Fiscal 2007 - $1.8 million.
The following table provides reconciliations of reported and adjusted
net income and diluted earnings per share as if SFAS 142 had been adopted as of
October 1, 2000. Basic earnings per share is not materially different from
diluted earnings per share and, therefore, is not presented:
Year Ended September 30,
2002 2001 2000
================================================================================
NET INCOME:
Reported income before
accounting changes $75.5 $ 52.0 $ 44.7
Add back goodwill and excess
reorganization value amortization - 25.2 24.7
Adjust minority interests in AmeriGas
Partners - (10.5) (9.7)
Adjust income tax expense - (0.7) (0.3)
- --------------------------------------------------------------------------------
Adjusted income before accounting changes 75.5 66.0 59.4
Cumulative effect of accounting changes - 4.5 -
- --------------------------------------------------------------------------------
Adjusted net income $75.5 $ 70.5 $ 59.4
- --------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE:
Reported income before accounting changes $2.70 $ 1.90 $ 1.64
Add back goodwill and excess
reorganization value amortization - 0.92 0.91
Adjust minority interests in AmeriGas
Partners - (0.38) (0.36)
Adjust income tax expense - (0.03) (0.01)
- --------------------------------------------------------------------------------
Adjusted income per share before
accounting changes 2.70 2.41 2.18
Cumulative effect of accounting changes - 0.17 -
- --------------------------------------------------------------------------------
Adjusted net income per share $2.70 $ 2.58 $ 2.18
- --------------------------------------------------------------------------------
34
UGI Corporation 2002 Annual Report
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In accordance with the provisions of SFAS 142, we were required to
perform transitional goodwill impairment tests for each of our reporting units
having goodwill by March 31, 2002. In addition, SFAS 142 requires that we
perform impairment tests annually or more frequently if events or circumstances
indicate that the value of goodwill might be impaired. No goodwill impairments
were recorded as a result of our SFAS 142 transitional impairment tests or our
annual impairment tests completed during the fourth quarter of fiscal 2002.
STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for
Stock-Based Compensation" ("SFAS 123"), we apply the provisions of APB 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. For a description of stock-based compensation and
related disclosures, see Note 10.
OTHER ASSETS. Included in other assets are net deferred debt issuance costs of
$14.8 million at September 30, 2002 and $15.9 million at September 30, 2001. We
are amortizing these costs over the term of the related debt.
COMPUTER SOFTWARE COSTS. We include in property, plant and equipment costs
associated with computer software we develop or obtain for use in our
businesses. We amortize computer software costs on a straight-line basis over
expected periods of benefit not exceeding ten years once the installed software
is ready for its intended use.
DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery
of certain purchased gas costs through the application of purchased gas cost
("PGC") rates. The clauses provide for periodic adjustments to PGC rates for the
difference between the total amount of purchased gas costs collected from
customers and the recoverable costs incurred. In accordance with SFAS 71, we
defer the difference between amounts recognized in revenues and the applicable
gas costs incurred until they are subsequently billed or refunded to customers.
ENVIRONMENTAL LIABILITIES. We accrue environmental investigation and cleanup
costs when it is probable that a liability exists and the amount or range of
amounts can be reasonably estimated. Our estimated liability for environmental
contamination is reduced to reflect anticipated participation of other
responsible parties but is not reduced for possible recovery from insurance
carriers. We do not discount to present value the costs of future expenditures
for environmental liabilities. We intend to pursue recovery of any incurred
costs through all appropriate means, including regulatory relief. Gas Utility is
permitted to amortize as removal costs site-specific environmental investigation
and remediation costs, net of related third-party payments, associated with
Pennsylvania sites. Gas Utility is currently permitted to include in rates,
through future base rate proceedings, a five-year average of such prudently
incurred removal costs.
FOREIGN CURRENCY TRANSLATION. Balance sheets of international subsidiaries and
investments in international propane joint ventures are translated into U.S.
dollars using the exchange rate at the balance sheet date. Income statements and
equity method results are translated into U.S. dollars using a weighted-average
exchange rate for each reporting period. Where the local currency is the
functional currency, translation adjustments are recorded in other comprehensive
income. Where the local currency is not the functional currency, translation
adjustments are recorded in net income.
COMPREHENSIVE INCOME (LOSS). Comprehensive income (loss) comprises net income
and other comprehensive income (loss). Other comprehensive income (loss)
principally results from gains and losses on derivative instruments qualifying
as cash flow hedges and foreign currency translation adjustments. The components
of accumulated other comprehensive income (loss) at September 30, 2001 and 2002
follows:
Derivative Foreign
Instruments Currency
Gains Translation
(Losses) Adjustments Total
=======================================================================================
Balance - September 30, 2001 $(13.7) $0.2 $(13.5)
Balance - September 30, 2002 $ 3.1 $3.5 $ 6.6
- ---------------------------------------------------------------------------------------
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. The Financial Accounting Standards
Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"); SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"); SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"); and SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" ("SFAS 146").
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using a
systematic and rational method over the related asset's useful life and adjust
the fair value of the liability resulting from the passage of time through
charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The
adoption of SFAS 143 did not have a material effect on our financial position or
results of operations. Our joint venture, AGZ Holdings, is required to adopt
SFAS 143 effective April 1, 2003. We are currently in the process of evaluating
the impact of SFAS 143 on AGZ Holdings.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," as it relates to the disposal of a segment
35
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 1 continued
of a business. SFAS 144 establishes a single accounting model for long-lived
assets to be disposed of based upon the framework of SFAS 121, and resolves
significant implementation issues of SFAS 121. We adopted SFAS 144 effective
October 1, 2002. The adoption of SFAS 144 did not affect our financial position
or results of operations.
SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"),
effective for fiscal years beginning after May 15, 2002. SFAS 4 had required
that material gains and losses on extinguishment of debt be classified as an
extraordinary item. Under SFAS 145, it is less likely that a gain or loss on
extinguishment of debt would be classified as an extraordinary item in the
Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS
No. 13, "Accounting for Leases," to require that certain lease modifications
that have economic effects similar to sale-leaseback transactions be accounted
for in the same manner as sale-leaseback transactions. The provisions of SFAS
145 relating to leases were effective for transactions occurring after May 15,
2002. The application of SFAS 145 did not affect our financial position or
results of operations during 2002.
SFAS 146 addresses accounting for costs associated with exit or
disposal activities and replaces the guidance in Emerging Issues Task Force
("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity." Generally, SFAS 146 requires that
a liability for costs associated with an exit or disposal activity, including
contract termination costs, employee termination benefits and other associated
costs, be recognized when the liability is incurred. Under EITF No. 94-3, a
liability was recognized at the date an entity committed to an exit plan. SFAS
146 will be effective for disposal activities initiated after December 31, 2002.
NOTE 2 - ACQUISITIONS
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the
propane distribution businesses of Columbia Energy Group ("Columbia Propane
Businesses") in a series of equity and asset purchases pursuant to the terms of
the Purchase Agreement dated January 30, 2001, and Amended and Restated August
7, 2001 ("Columbia Purchase Agreement") by and among Columbia Energy Group
("CEG"), Columbia Propane Corporation ("Columbia Propane"), Columbia Propane,
L.P. ("CPLP"), CP Holdings, Inc. ("CPH"), AmeriGas Partners, AmeriGas OLP, and
the General Partner. The acquired businesses comprised the seventh largest
retail marketer of propane in the United States with annual sales of over 300
million gallons from locations in 29 states. The acquired businesses were
principally conducted through Columbia Propane and its approximate 99% owned
subsidiary, CPLP (referred to after the acquisition as "Eagle OLP"). AmeriGas
OLP acquired substantially all of the assets of Columbia Propane, including an
indirect 1% general partner interest and an approximate 99% limited partnership
interest in Eagle OLP.
The purchase price of the Columbia Propane Businesses consisted of
$201.8 million in cash. In addition, AmeriGas OLP agreed to pay CEG for the
amount of working capital, as defined, in excess of $23 million. In April 2002,
the Partnership's management and CEG agreed upon the amount of working capital
acquired by AmeriGas OLP and AmeriGas OLP made an additional payment for working
capital and other adjustments totaling $0.7 million. The Columbia Purchase
Agreement also provided for the purchase by CEG of limited partnership interests
in AmeriGas OLP valued at $50 million for $50 million in cash, which interests
were exchanged for 2,356,953 Common Units of AmeriGas Partners having an
estimated fair value of $54.4 million. Concurrently with the acquisition,
AmeriGas Partners issued $200 million of 8.875% Senior Notes due May 2011, the
net proceeds of which were contributed to AmeriGas OLP to finance the
acquisition of the Columbia Propane Businesses, to fund related fees and
expenses, and to repay debt outstanding under AmeriGas OLP's Bank Credit
Agreement. The operating results of the Columbia Propane Businesses are included
in our consolidated results from August 21, 2001.
The following table identifies the components of the purchase price:
================================================================================
Cash paid $ 202.5
Cash received from sale of AmeriGas OLP limited partner interests (50.0)
Fair value of AmeriGas Partners' Common Units issued in exchange
for the AmeriGas OLP limited partner interests 54.4
Transaction costs and expenses 8.2
Involuntary employee termination benefits and relocation costs 2.6
Other liabilities and obligations incurred 1.0
- --------------------------------------------------------------------------------
Total $ 218.7
- --------------------------------------------------------------------------------
As of September 30, 2002, substantially all involuntary employee
termination benefits and relocation costs had been paid.
The purchase price of the Columbia Propane Businesses has been
allocated to the assets and liabilities acquired as follows:
================================================================================
Net current assets $ 16.7
Property, plant and equipment 182.8
Customer relationships and noncompete agreement
(estimated useful life of 15 and 5 years, respectively) 19.9
Other assets and liabilities (0.7)
- --------------------------------------------------------------------------------
Total $ 218.7
- --------------------------------------------------------------------------------
The following table presents unaudited pro forma income statement and
diluted per share data for 2001 and 2000 as if the acquisition of the Columbia
Propane Businesses had occurred as of the beginning of those years:
2001 2000
================================================================================
Revenues $2,838.3 $2,069.8
Income before accounting changes 50.8 39.5
Net income 55.3 39.5
Diluted earnings per share:
Income before accounting changes 1.86 1.45
Net income 2.02 1.45
- --------------------------------------------------------------------------------
36
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
The pro forma results of operations reflect the Columbia Propane
Businesses' historical operating results after giving effect to adjustments
directly attributable to the transaction that are expected to have a continuing
impact. They are not adjusted for, among other things, the impact of normal
weather conditions, operating synergies and anticipated cost savings. In our
opinion, the unaudited pro forma results are not necessarily indicative of the
actual results that would have occurred had the acquisition of the Columbia
Propane Businesses occurred as of the beginning of the years presented or of
future operating results under our management.
During 2001, Energy Services acquired two energy marketing businesses
and the Partnership acquired several small propane distribution businesses for
total cash consideration of $5.4 million. 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 allocated to the net assets acquired for the 2000
acquisitions was approximately $42 million. The operating results of these
businesses have been included in the consolidated results from their respective
dates of acquisition. The pro forma effect of these transactions was not
material to our 2001 and 2000 results of operations.
NOTE 3 - CHANGES IN ACCOUNTING
TANK FEE REVENUE RECOGNITION. In order to apply the guidance of SAB 101,
effective October 1, 2000, the Partnership changed its method of accounting for
annually billed nonrefundable tank fees. Prior to the change in accounting,
nonrefundable tank fees for installed Partnership-owned tanks were recorded as
revenue when billed. Under the new accounting method, revenues from such fees
are being recorded on a straight-line basis over one year. As a result of this
change in accounting, on October 1, 2000, we recorded an after-tax charge of
$2.1 million representing the cumulative effect of the change in accounting on
prior years. The change in accounting for nonrefundable tank fees did not have a
material impact on reported revenues in 2002 and 2001, and would not have had a
material impact on reported revenues in 2000. At September 30, 2002 and 2001,
deferred revenues relating to nonrefundable tank fees were $6.8 million and $6.2
million, respectively.
ACCOUNTING FOR TANK INSTALLATION COSTS. Effective October 1, 2000, the
Partnership changed its method of accounting for tank installation costs which
are not billed to customers. Prior to the change in accounting, costs to install
Partnership-owned tanks at a customer location were expensed as incurred. Under
the new accounting method, all such costs, net of amounts billed to customers,
are capitalized in property, plant and equipment and amortized over the
estimated period of benefit not exceeding ten years. The Partnership believes
that the new accounting method better matches the costs of installing
Partnership-owned tanks with the periods benefited. As a result of this change
in accounting, on October 1, 2000, we recorded after-tax income of $6.9 million
representing the cumulative effect of the change in accounting on prior years.
The change in accounting for tank installation costs did not have a material
effect on 2001 net income.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND PRO FORMA DISCLOSURE. The cumulative
effect reflected on the 2001 Consolidated Statement of Income and related
diluted per share amounts resulting from the above changes in accounting
principles, as well as the cumulative effect resulting from the adoption of SFAS
133 (see Note 1), comprise the following:
Diluted
Pre-Tax Income Tax After-Tax Earnings
Income (Expense) Income (Loss)
(Loss) Benefit (Loss) Per Share
================================================================================
Tank fees $(3.5) $ 1.4 $(2.1) $(0.08)
Tank installation costs 11.3 (4.4) 6.9 0.25
SFAS 133 (0.4) 0.1 (0.3) (0.01)
- --------------------------------------------------------------------------------
Total $ 7.4 $(2.9) $ 4.5 $ 0.16
- --------------------------------------------------------------------------------
The pro forma impact on 2000 net income and net income per share after
applying retroactively the changes in accounting for tank installation costs and
nonrefundable tank fees was not materially different from reported amounts.
NOTE 4 - UTILITY REGULATORY MATTERS
GAS UTILITY
GAS COMPETITION ACT. On June 22, 1999, the Gas Competition Act was signed into
law. The purpose of the Gas Competition Act is to provide all natural gas
consumers in Pennsylvania with the ability to purchase their gas supplies from
the supplier of their choice. Under the Gas Competition Act, local gas
distribution companies ("LDCs") like Gas Utility may continue to sell gas to
customers, and such sales of gas, as well as distribution services provided by
LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the
supplier of last resort for all residential and small commercial and industrial
("core-market") customers unless the PUC approves another supplier of last
resort. The Gas Competition Act requires energy marketers seeking to serve
customers of LDCs to accept assignment of a portion of the LDC's pipeline
capacity and storage contracts at contract rates, thus avoiding the creation of
stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC
to avoid such contract release or assignment. However, such petition may be
granted only if the LDC fully recovers the cost of contracts. The Gas
Competition Act, in conjunction with a companion bill, eliminated the gross
receipts tax on sales of gas effective January 1, 2000.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas
Competition Act. Among other things, the implementation of the Gas Restructuring
Order resulted in an increase in Gas Utility's core-market base rates effective
October 1, 2000. This base rate increase was designed to generate approximately
$16.7 million in additional net annual revenues. In accordance with the Gas
Restructuring Order, Gas Utility reduced its core-market PGC rates by an
annualized amount of $16.7 million in the first 14 months following the October
1, 2000 base rate increase.
37
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 4 continued
Effective December 1, 2001, Gas Utility was required to reduce its
core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
core-market customers. As a result, Gas Utility operating results are more
sensitive to the effects of heating-season weather and less sensitive to the
market prices of alternative fuels.
ELECTRIC UTILITY
ELECTRIC UTILITY RESTRUCTURING ORDER. On June 19, 1998, the PUC entered its
Opinion and Order ("Electricity Restructuring Order") in Electric Utility's
restructuring proceeding pursuant to the Electricity Choice Act. Under the terms
of the Electricity Restructuring Order, Electric Utility was authorized to
recover $32.5 million in stranded costs (on a full revenue requirements basis
which includes all income and gross receipts taxes) over a four-year period
beginning January 1, 1999 through a Competitive Transition Charge ("CTC")
(together with carrying charges on unrecovered balances of 7.94%) and to charge
unbundled rates for generation, transmission and distribution services. Stranded
costs are electric generation-related costs that traditionally would be
recoverable in a regulated environment but may not be recoverable in a
competitive electric generation market. Electric Utility's recoverable stranded
costs included $8.7 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 Choice Act, Electric
Utility generally could not increase the generation component of prices during
the period that stranded costs were being recovered through the CTC. Since
January 1, 1999, all of Electric Utility's customers have been permitted to
choose an alternative generation supplier. Customers choosing an alternative
supplier during the stranded cost recovery period received a "shopping credit."
The PUC approved a settlement establishing rules for Electric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively the "POLR
Settlement") under which Electric Utility terminated stranded cost recovery
through its CTC from commercial and industrial ("C&I") customers on July 31,
2002, and from residential customers on October 31, 2002, and is no longer
subject to the statutory rate caps as of August 1, 2002 for C&I customers and as
of November 1, 2002 for residential customers. Charges for generation service
will (1) initially be set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times up to certain specified caps through December 2004; and
(3) may be set at market rates thereafter. Electric Utility may also offer
multiple-year POLR contracts to its customers. The POLR Settlement provides for
annual shopping periods during which customers may elect to remain on POLR
service or choose an alternate supplier. Customers who do not select an
alternate supplier will be obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service at a time
other than during the annual shopping period must remain on POLR service until
the date of the second open shopping period after returning. C&I customers who
return to POLR service at a time other than during the annual shopping period
must remain on POLR service until the next open shopping period, and may, in
certain circumstances, be subject to generation rate surcharges.
FORMATION OF HUNLOCK CREEK ENERGY VENTURES. On December 8, 2000, a subsidiary of
UGI Utilities contributed its coal-fired Hunlock Creek generating station
("Hunlock") and certain related assets having a net book value of approximately
$4.2 million, and $6 million in cash, to Hunlock Creek Energy Ventures ("Energy
Ventures"), a general partnership jointly owned by us and a subsidiary of
Allegheny Energy, Inc. ("Allegheny"). The contribution was recorded at carrying
value and no gain was recognized by the Company. Also on December 8, 2000,
Allegheny contributed a newly constructed, gas-fired combustion turbine
generator to be operated at the Hunlock site. Under the terms of our arrangement
with Allegheny, each partner is entitled to purchase 50% of the output of the
joint venture at cost. Total purchases from Energy Ventures in 2002 and 2001
were $9.8 million and $8.0 million, respectively.
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
2002 2001
====================================================================
Regulatory assets:
Income taxes recoverable $54.7 $51.8
Power agreement buy-out - 1.3
Other postretirement benefits 2.4 2.6
Deferred fuel costs 4.3 -
Other 0.6 0.5
- --------------------------------------------------------------------
Total regulatory assets $62.0 $56.2
- --------------------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 4.3 $ 4.3
Deferred fuel costs - 2.8
- --------------------------------------------------------------------
Total regulatory liabilities $ 4.3 $ 7.1
- --------------------------------------------------------------------
Utilities' regulatory liabilities are included in "other current
liabilities" and "other noncurrent liabilities" on the Consolidated Balance
Sheets. The Company's regulatory assets do not earn a return.
38
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
NOTE 5 - DEBT
Long-term debt comprises the following at September 30:
2002 2001
===========================================================================================
AMERIGAS PROPANE:
AmeriGas Partners Senior Notes:
8.875%, due May 2011 (of which $40 in 2002
includes unamortized premium of $1.5,
effective rate - 8.25%) $ 241.6 $ 200.0
10%, due April 2006 (less unamortized discount of $0.2
and $0.3, respectively, effective rate - 10.125%) 59.8 59.7
10.125%, due April 2007 85.0 100.0
AmeriGas OLP First Mortgage Notes:
Series A, 9.34% - 11.71%, due April 2001 through
April 2009 (including unamortized premium of
$7.9 and $9.2, respectively, effective rate - 8.91%) 167.9 189.2
Series B, 10.07%, due April 2001 through April 2005
(including unamortized premium of $2.3 and $3.9,
respectively, effective rate - 8.74%) 122.3 163.9
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 $2.2 and $2.4,
respectively, effective rate - 6.52%) 72.2 72.4
Series E, 8.50%, due July 2010 (including unamortized
premium of $0.1 and $0.2, respectively, effective
rate - 8.47%) 80.1 80.2
AmeriGas OLP Acquisition Facility - 20.0
Other 6.9 10.5
- -------------------------------------------------------------------------------------------
Total AmeriGas Propane 945.8 1,005.9
- -------------------------------------------------------------------------------------------
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
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
7.14% Notes, due December 2005 (including
unamortized premium of $0.4 and $0.5,
respectively, effective rate - 6.64%) 30.4 30.5
7.14% Notes, due December 2005 20.0 20.0
5.53% Notes, due September 2012 40.0 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $0.1 in 2001) 50.0 49.9
- -------------------------------------------------------------------------------------------
Total UGI Utilities 248.4 208.4
- -------------------------------------------------------------------------------------------
OTHER:
FLAGA Acquisition Note, due September 2002
through September 2006 64.3 62.7
FLAGA euro special purpose facility 10.8 10.7
Other 6.4 7.5
- -------------------------------------------------------------------------------------------
Total long-term debt 1,275.7 1,295.2
Less current maturities (including net unamortized
premiums of $2.9 and $3.3, respectively) (148.7) (98.3)
- -------------------------------------------------------------------------------------------
Total long-term debt due after one year $ 1,127.0 $1,196.9
- -------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt due in fiscal years 2003 to
2007 follows:
2003 2004 2005 2006 2007
=============================================================================
AmeriGas Propane $ 57.5 $55.1 $54.9 $113.2 $138.7
UGI Utilities 76.0 - 20.0 50.0 20.0
Other 12.3 6.1 11.1 47.6 1.4
- -----------------------------------------------------------------------------
Total $145.8 $61.2 $86.0 $210.8 $160.1
- -----------------------------------------------------------------------------
AMERIGAS PROPANE
AMERIGAS PARTNERS SENIOR NOTES. The 8.875% Senior Notes generally cannot be
redeemed at our option prior to May 20, 2006. A redemption premium applies
thereafter through May 19, 2009. However, prior to May 20, 2004, AmeriGas
Partners may use the proceeds of a public offering of Common Units to redeem up
to 33% of the 8.875% Senior Notes at 108.875% plus accrued and unpaid interest.
The 10% Senior Notes generally cannot be redeemed at our option prior to their
maturity. The 10.125% Senior Notes are redeemable prior to their maturity date.
A redemption premium applies until April 15, 2004. In November 2001, AmeriGas
Partners prepaid $15 million of 10.125% Senior Notes at a redemption price of
103.375%. 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.
AMERIGAS OLP FIRST MORTGAGE NOTES. AmeriGas OLP's First Mortgage Notes are
collateralized by substantially all of its assets. The General Partner and
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.
AmeriGas OLP 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, AmeriGas OLP may be required to offer to prepay the First
Mortgage Notes, in whole or in part.
AMERIGAS OLP BANK CREDIT AGREEMENT. AmeriGas OLP's Second Amended and Restated
Credit Agreement ("Bank Credit Agreement") consists of (1) a Revolving Credit
Facility and (2) an Acquisition Facility. AmeriGas OLP'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, AmeriGas OLP may borrow up to $100
million (including a $35 million sublimit for letters of credit) subject to
restrictions in the AmeriGas Partners Senior Notes indentures (see "Restrictive
Covenants" below). The Revolving Credit Facility may be used for working capital
and general purposes of AmeriGas OLP. The Revolving Credit Facility expires
October 1, 2003, but may be extended for additional one-year periods with the
consent of the participating banks representing at least 80% of the commitments
thereunder. AmeriGas OLP had borrowings under the Revolving Credit Facility
totaling $10 million at September 30, 2002, which we classify as bank loans.
There were no borrowings outstanding under the Revolving Credit Facility at
September 30, 2001. Issued and outstanding letters of
39
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 5 continued
credit, which reduce available borrowings under the Revolving Credit Facility,
totaled $19.8 million and $9.5 million at September 30, 2002 and 2001,
respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to
borrow up to $75 million to finance the purchase of propane businesses or
propane business assets. In addition, up to $30 million of the Acquisition
Facility may be used for working capital purposes. The Acquisition Facility
operates as a revolving facility through October 1, 2003, at which time amounts
then outstanding will be immediately due and payable.
The Revolving Credit Facility and the Acquisition Facility permit
AmeriGas OLP to borrow at prevailing interest rates, including the base rate,
defined as the higher of the Federal Funds rate plus 0.50% or the agent bank's
prime rate (4.75% at September 30, 2002), or at two-week, one-, two-, three-, or
six-month Eurodollar Rate, as defined in the Bank Credit Agreement, plus a
margin. The margin on Eurodollar Rate borrowings (which ranges from 1.00% to
2.25%), and the Bank Credit Agreement commitment fee rate (which ranges from
0.25% to 0.50%) are dependent upon AmeriGas OLP'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 weighted-average
interest rate on Revolving Credit Facility borrowings at September 30, 2002 was
4.75%. The weighted-average interest rate on Acquisition Facility loans
outstanding at September 30, 2001 was 4.08%. AmeriGas OLP had the ability to
borrow an additional $67.7 million under the Acquisition Facility based upon
eligible propane business and asset expenditures made through September 30,
2002.
GENERAL PARTNER FACILITY. AmeriGas OLP also has a revolving credit agreement
with the General Partner under which it may borrow up to $20 million for working
capital and general purposes. This agreement is coterminous with, and generally
comparable to, AmeriGas OLP's Revolving Credit Facility except that borrowings
under the General Partner Facility are unsecured and subordinated to all senior
debt of AmeriGas OLP. Interest rates on borrowings are based upon one-month
offshore interbank offering rates. 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 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 indentures, 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.
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, 2002, such ratio was 2.41-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,
asset transfers, transactions with affiliates, sales of assets, acquisitions and
other transactions. The Bank Credit Agreement and First Mortgage Notes 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 4.75-to-1 with respect to the Bank Credit Agreement and
5.25-to-1 with respect to the First Mortgage Notes. In addition, the Bank Credit
Agreement requires that AmeriGas OLP 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, AmeriGas OLP 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, 2002, the Partnership was in compliance with
its financial covenants.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2002, UGI Utilities had revolving
credit agreements with four banks providing for borrowings of up to $97 million.
These agreements expire at various dates through September 2005. UGI Utilities
may borrow at various prevailing interest rates, including LIBOR. UGI Utilities
pays quarterly commitment fees on these credit lines. UGI Utilities had
borrowings under these agreements totaling $37.2 million at September 30, 2002
and $57.8 million at September 30, 2001, which we classify as bank loans. The
weighted-average interest rates on UGI Utilities bank loans were 2.35% at
September 30, 2002 and 3.75% at September 30, 2001.
RESTRICTIVE COVENANTS. UGI Utilities' credit agreements have restrictions on
such items as total debt, debt service, and payments for investments. They also
require consolidated tangible net worth of at least $125 million. At September
30, 2002, UGI Utilities was in compliance with its financial covenants.
OTHER
At September 30, 2002, FLAGA's multi-currency acquisition note ("Acquisition
Note") consisted of a $14.5 million U.S. dollar denominated obligation and a
50.5 million euro-denominated obligation. During 2002, a portion of the
euro-denominated acquisition note was converted to a $16.7 million U.S. dollar
denominated obligation. The Acquisition Note bears interest at a rate of 1.25%
over one- to twelve-month euribor rates (as chosen by FLAGA from time to time).
The effective interest rates on the Acquisition Note at September 30, 2002 and
September 30, 2001 were 4.86% and 5.42%, respectively. On or after September 10,
2003, FLAGA may prepay the Acquisition Note, in whole or in part. Prior to March
11, 2005, such prepayments shall be at a premium.
40
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
At September 30, 2002, FLAGA has a 15 million euro working capital loan
commitment from a European bank. The working capital facility expires in
September 2003, but may be extended with the bank's consent. Loans under the
working capital facility, as well as borrowings under FLAGA's special purpose
facility, bear interest at market rates. The weighted-average interest rate on
FLAGA's working capital facility at September 30, 2002 was 4.40%. Borrowings
under the euro working capital facility at September 30, 2002 and 2001 totaled
$8.6 million and $10.0 million, respectively, and are classified as bank loans.
The FLAGA Acquisition 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.
NOTE 6 - INCOME TAXES
Income before income taxes comprises the following:
2002 2001 2000
===========================================================================
Domestic $117.2 $103.0 $ 93.4
Foreign 6.8 (4.0) (7.0)
- ---------------------------------------------------------------------------
Total income before income taxes $124.0 $ 99.0 $ 86.4
- ---------------------------------------------------------------------------
The provisions for income taxes consist of the following:
2002 2001 2000
=============================================================================
Current expense:
Federal $26.5 $39.2 $28.6
State 9.3 11.7 8.3
Foreign 0.1 - -
- ------------------------------------------------------------------------------
Total current expense 35.9 50.9 36.9
Deferred (benefit) expense:
Federal 11.8 (2.9) 5.7
State (0.4) (1.2) (0.2)
Foreign - (1.0) (1.9)
Investment tax credit amortization (0.4) (0.4) (0.4)
- ------------------------------------------------------------------------------
Total deferred (benefit) expense 11.0 (5.5) 3.2
- ------------------------------------------------------------------------------
Total income tax expense $46.9 $45.4 $40.1
- ------------------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective tax
rate is as follows:
2002 2001 2000
=============================================================================
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal 5.3 7.3 7.5
Goodwill amortization - 4.4 5.8
Other, net (2.5) (0.8) (1.9)
- ------------------------------------------------------------------------------
Effective tax rate 37.8% 45.9% 46.4%
- ------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2002 2001
================================================================================
Excess book basis over tax basis of property, plant
and equipment $199.2 $180.3
Regulatory assets 23.7 23.3
Pension plan asset 10.5 8.9
Other 17.0 12.6
- ------------------------------------------------------------------------------
Gross deferred tax liabilities 250.4 225.1
- ------------------------------------------------------------------------------
Self-insured property and casualty liability (9.0) (8.2)
Employee-related benefits (16.2) (14.5)
Premium on long-term debt (2.5) (3.2)
Deferred investment tax credits (3.5) (3.6)
Hearth USA(TM)shut-down costs - (3.3)
Accumulated other comprehensive loss - (9.7)
Operating loss carryforwards (13.3) (8.9)
Allowance for doubtful accounts (2.4) (3.2)
Other (15.6) (15.1)
- ------------------------------------------------------------------------------
Gross deferred tax assets (62.5) (69.7)
- ------------------------------------------------------------------------------
Deferred tax assets valuation allowance 1.9 1.8
- ------------------------------------------------------------------------------
Net deferred tax liabilities $189.8 $157.2
- ------------------------------------------------------------------------------
Deferred income taxes of approximately $1.9 million have not been
provided on the excess of book basis over tax basis of our equity investment in
AGZ Holdings because the Company has no present intent to dispose of this
investment.
UGI Utilities had recorded deferred tax liabilities of approximately
$35.5 million as of September 30, 2002 and $33.9 million as of September 30,
2001, 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 $3.5 million at September 30, 2002 and $3.6
million at September 30, 2001, pertaining to utility deferred investment tax
credits. UGI Utilities had recorded regulatory income tax assets related to
these net deferred taxes of $54.7 million as of September 30, 2002 and $51.8
million as of September 30, 2001. These regulatory income tax assets represent
future revenues expected to be recovered through the ratemaking process. We will
recognize this regulatory income tax asset in deferred tax expense as the
corresponding temporary differences reverse and additional income taxes are
incurred.
Foreign net operating loss carryforwards of FLAGA totaled approximately
$33.0 million, $5.1 million of which expires through 2007 and $27.9 million of
which has no expiration date. At September 30, 2002, deferred tax assets
relating to operating loss carryforwards include those of FLAGA and $2.3 million
of deferred tax assets associated with state net operating loss carryforwards
expiring through 2022. Substantially all of our deferred tax valuation
allowances relate to state operating loss carryforwards.
NOTE 7 - 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
41
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 7 continued
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 domestic active and retired employees.
The following provides a reconciliation of benefit obligations, plan
assets, and funded status of these plans as of September 30:
Pension Other Postretirement
Benefits Benefits
----------------- --------------------
2002 2001 2002 2001
==============================================================================================
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $165.2 $150.9 $ 21.3 $ 19.7
Service cost 3.6 3.1 0.1 0.1
Interest cost 12.5 12.1 1.7 1.6
Plan amendments 0.4 - - -
Actuarial loss 18.6 7.9 5.8 1.8
Benefits paid (9.4) (8.8) (1.6) (1.9)
- ----------------------------------------------------------------------------------------------
Benefit obligations - end of year $190.9 $165.2 $ 27.3 $ 21.3
- ----------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -
beginning of year $183.7 $223.5 $ 7.0 $ 6.4
Actual return on plan assets (8.3) (31.0) 0.1 0.2
Employer contributions - - 2.3 2.2
Benefits paid (9.3) (8.8) (1.6) (1.8)
- ----------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $166.1 $183.7 $ 7.8 $ 7.0
- ----------------------------------------------------------------------------------------------
Funded status of the plans $(24.8) $ 18.5 $ (19.5) $(14.3)
Unrecognized net actuarial (gain) loss 50.2 4.2 4.7 (1.4)
Unrecognized prior service cost 3.0 3.3 - -
Unrecognized net transition (asset)
obligation (3.0) (4.6) 8.7 9.5
- ----------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 25.4 $ 21.4 $ (6.1) $ (6.2)
- ----------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.8% 7.7% 6.8% 7.7%
Expected return on plan assets 9.5% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5%
- ----------------------------------------------------------------------------------------------
Net periodic pension income and other postretirement benefit costs
include the following components:
Pension Other Postretirement
Benefits Benefits
----------------------------- --------------------------
2002 2001 2000 2002 2001 2000
==============================================================================================
Service cost $ 3.6 $ 3.1 $ 3.2 $ 0.1 $ 0.1 $ 0.1
Interest cost 12.5 12.1 11.8 1.7 1.6 1.4
Expected return on assets (19.1) (18.9) (17.0) (0.3) (0.3) (0.3)
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 - (1.2) - (0.1) (0.1) (0.2)
- ----------------------------------------------------------------------------------------------
Net benefit cost (income) (4.0) (5.9) (3.0) 2.3 2.2 1.9
Change in regulatory
assets and liabilities - - - 1.2 1.4 1.4
- ----------------------------------------------------------------------------------------------
Net expense (income) $ (4.0) $ (5.9) $ (3.0) $ 3.5 $ 3.6 $ 3.3
- ----------------------------------------------------------------------------------------------
UGI Utilities Pension Plan assets are held in trust and consist
principally of equity and fixed income mutual funds and a commingled bond fund.
UGI Common Stock comprised approximately 6% of trust assets at September 30,
2002. Although the UGI Utilities Pension Plan projected benefit obligation
exceeded plan assets at September 30, 2002, plan assets exceeded accumulated
benefit obligations by approximately $7.2 million.
Pursuant to orders issued by the PUC, UGI Utilities has established a
Voluntary Employees' Beneficiary Association ("VEBA") trust to pay retiree
health care and life insurance benefits and to fund the UGI Utilities'
postretirement benefit liability. UGI Utilities is required to fund its
postretirement benefit obligations by depositing into the VEBA the annual amount
of postretirement benefits costs determined under SFAS No. 106, "Employers
Accounting for Postretirement Benefits Other than Pensions." The difference
between such amounts and amounts included in UGI Utilities' rates is deferred
for future recovery from, or refund to, ratepayers. VEBA investments consist
principally of money market funds.
The assumed health care cost trend rates are 12.0% for fiscal 2003,
decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed
health care cost trend rate would change the 2002 postretirement benefit cost
and obligation as follows:
1% Increase 1% Decrease
====================================================================================
Effect on total service and interest costs $0.1 $(0.1)
Effect on postretirement benefit obligation $1.5 $(1.3)
- ------------------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key
employees. At September 30, 2002 and 2001, the projected benefit obligations of
these plans were not material. We recorded expense for these plans of $1.4
million in 2002, $1.2 million in 2001, and $0.9 million in 2000.
DEFINED CONTRIBUTION PLANS. We sponsor 401(k) savings plans for eligible
employees of UGI, UGI Utilities, AmeriGas Propane, HVAC and certain of UGI's
other wholly owned domestic subsidiaries. Generally, participants in these plans
may contribute a portion of their compensation on either a before-tax basis, or
on both a before-tax and after-tax basis. These plans also provide for either
mandatory or discretionary employer matching contributions at various rates. The
cost of benefits under the savings plans totaled $4.5 million in 2002, $6.2
million in 2001, and $5.9 million in 2000.
NOTE 8 - INVENTORIES
Inventories comprise the following at September 30:
2002 2001
=====================================================================
Propane gas $ 40.4 $ 54.8
Utility fuel and gases 36.6 45.6
Materials, supplies and other 32.2 28.2
- ---------------------------------------------------------------------
Total inventories $109.2 $128.6
- ---------------------------------------------------------------------
NOTE 9 - SERIES PREFERRED STOCK
The UGI Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 5,000,000
42
UGI Corporation 2002 Annual Report
- --------------------------------------------------------------------------------
shares authorized for issuance. We had no shares of UGI Series Preferred Stock
outstanding at September 30, 2002 or 2001.
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, 2002 and 2001, 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 are subject to mandatory redemption on October 1, 2009,
at a price of $100 per share.
NOTE 10 - COMMON STOCK AND INCENTIVE STOCK AWARD PLANS
Common Stock share activity for 2000, 2001 and 2002 follows:
Issued Treasury Outstanding
========================================================================================
Balance at 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
Issued:
Employee and director plans - 241,039 241,039
Dividend reinvestment plan - 98,812 98,812
Reacquired - (37,163) (37,163)
- ----------------------------------------------------------------------------------------
Balance September 30, 2001 33,198,731 (5,902,334) 27,296,397
Issued:
Employee and director plans - 321,863 321,863
Dividend reinvestment plan - 87,062 87,062
Reacquired - (3,592) (3,592)
- ----------------------------------------------------------------------------------------
Balance September 30, 2002 33,198,731 (5,497,001) 27,701,730
- ----------------------------------------------------------------------------------------
STOCK OPTION AND INCENTIVE PLANS. Under UGI's current employee stock option and
incentive plans, we may grant options to acquire shares of Common Stock, or
issue awards of restricted stock, to key employees. The exercise price for
options granted under these plans may not be less than the fair market value on
the grant date. Grants of stock options or awards of 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"), awards
representing up to 1,100,000 shares of Common Stock may be granted in connection
with stock options and awards of restricted stock. However, awards representing
no more than 500,000 shares of restricted stock may be issued. In addition, the
2000 Incentive Plan provides that both option grants and restricted stock awards
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. Awards of restricted
stock may be settled, at the option of the Company, in shares of Common Stock,
cash, or a combination of Common Stock and cash. The actual number of shares (or
their cash equivalent) ultimately issued, and the actual amount of dividend
equivalents paid, is dependent upon the achievement of objective performance
goals. During 2002 and 2001, the Company made restricted stock awards
representing 169,500 and 110,675 shares, respectively. At September 30, 2002,
awards representing 280,175 shares of restricted stock were outstanding.
At September 30, 2002, there remained available for grant options to
acquire 111,861 shares of Common Stock under the 1997 Stock Option and Dividend
Equivalent Plan ("1997 SODEP Plan"). Certain outstanding option grants under the
1997 SODEP Plan provided for the crediting of dividend equivalents subject to
UGI'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.
In addition to the 2000 Incentive Plan and the 1997 SODEP Plan, we have
non-qualified stock option plans under which we may grant options to acquire
shares of Common Stock to key employees other than executive officers of UGI.
In addition to these employee incentive plans, UGI may grant options to
acquire up to a total of 200,000 shares of Common Stock to each of UGI'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.
Stock option transactions under all of our plans for 2000, 2001, and
2002 follow:
Shares Average Option Price
================================================================================
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
- --------------------------------------------------------------------------------
Granted 33,600 25.875
Exercised (202,673) 20.807
Forfeited (12,333) 20.828
- --------------------------------------------------------------------------------
Shares under option - September 30, 2001 1,702,238 21.321
- --------------------------------------------------------------------------------
Granted 476,250 30.705
Exercised (291,978) 21.028
- --------------------------------------------------------------------------------
Shares under option - September 30, 2002 1,886,510 23.786
- --------------------------------------------------------------------------------
Options exercisable 2000 947,144 21.696
Options exercisable 2001 1,100,904 21.799
Options exercisable 2002 1,137,926 21.772
- --------------------------------------------------------------------------------
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 10 continued
The following table presents additional information relating to stock
options outstanding and exercisable at September 30, 2002:
Range of exercise prices
------------------------
$ 20.00 - $ 30.60 -
$ 25.875 $ 31.88
Options outstanding at September 30, 2002:
Number of options 1,410,260 476,250
Weighted average remaining
contractual life (in years) 6.25 9.29
Weighted average exercise price $ 21.379 $ 30.705
Options exercisable at September 30, 2002:
Number of options 1,109,926 28,000
Weighted average exercise price $ 21.583 $ 30.600
At September 30, 2002, 1,124,336 shares of Common Stock were available for
future option grants or restricted stock awards under all of our stock option
and incentive plans.
OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS. Under the AmeriGas Propane,
Inc. 2000 Long-Term Incentive Plan ("2000 Propane Plan"), the General Partner
may grant to key employees the right to receive a total of 500,000 AmeriGas
Partners Common Units, or cash equivalent to the fair market value of such
Common Units, upon the achievement of performance goals. In addition, the 2000
Propane Plan may provide for the crediting of Partnership distribution
equivalents to participants' accounts. Distribution equivalents will be paid
in cash and such payments may, at the participants' request, be deferred. The
actual number of Common Units (or their cash equivalent) ultimately issued, and
the actual amount of distribution equivalents paid, is dependent upon the
achievement of performance goals. Generally, each grant, unless paid, will
terminate when the participant ceases to be employed by the General Partner. We
also have a nonexecutive Common Unit plan under which the General Partner may
grant awards of up to a total of 200,000 Common Units to key employees who do
not participate in the 2000 Propane Plan. Generally, awards under the
nonexecutive plan vest at the end of a three-year period and will be paid in
Common Units and cash. The General Partner made awards under the 2000 Propane
Plan and the nonexecutive plan representing 43,250 and 66,075 Common Units in
2002 and 2001, respectively. At September 30, 2002 and 2001, awards representing
105,825 and 65,325 Common Units, respectively, were outstanding.
Under the 1997 UGI Corporation Directors' Equity Compensation Plan ("1997
Directors' Plan"), we make annual awards to our nonemployee 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. Through
December 31, 2002, 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 9,449, 11,556, and
12,017 in 2002, 2001 and 2000, respectively. At September 30, 2002 and 2001,
there were 63,185 and 53,736 Units, respectively, outstanding.
FAIR VALUE INFORMATION. The per share weighted-average fair value of stock
options granted under our option plans was $4.91 in 2002, $4.35 in 2001, and
$3.76 in 2000. 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 2002, 2001 and 2000 are
as follows:
2002 2001 2000
---- ---- ----
Expected life of option 6 YEARS 6 years 6 years
Expected volatility 28.8% 29.1% 26.5%
Expected dividend yield 6.7% 6.6% 6.2%
Risk free interest rate 4.7% 5.0% 6.6%
We use the intrinsic value method prescribed by APB 25 for our stock-based
employee compensation plans. We recognized total stock-based compensation
expense (income) of $5.7 million in 2002, $2.7 million in 2001, and $(0.8)
million in 2000. 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
2002, 2001 and 2000 would have been as follows:
2002 2001 2000
---- ---- ----
Net income:
As reported $75.5 $56.5 $44.7
Pro forma 74.5 55.7 44.2
Diluted earnings per share:
As reported $2.70 $2.06 $1.64
Pro forma 2.67 2.03 1.62
STOCK OWNERSHIP POLICY. Under the terms of our Stock Ownership Policy,
executives and certain key employees are required to own UGI Common Stock having
a fair value equal to approximately 40% to 450% of their base salaries. Prior to
the enactment of the Sarbanes-Oxley Act of 2002, we offered 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, 2002 and 2001,
loans outstanding totaled $3.5 million and $4.6 million, respectively. The
Company is no longer offering loans under this program.
NOTE 11 - 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. The rights expire in 2006. 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
44
UGI Corporation 2002 Annual Report
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:
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 12 - 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 have generally been made 98% to 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 was sufficient Available
Cash, the holders of Common Units had 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 all the
remaining Subordinated Units have been converted to Common Units pursuant to the
terms of the Partnership Agreement. Effective November 18, 2002, the remaining
Subordinated Units held by the General Partner as of September 30, 2002 were
converted to Common Units (see Note 18).
NOTE 13 - 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 $46.5 million in 2002, $38.4 million in 2001, and $34.1 million
in 2000.
Minimum future payments under operating leases that have initial or
remaining noncancelable terms in excess of one year are as follows:
After
2003 2004 2005 2006 2007 2007
---- ---- ---- ---- ---- ----
AmeriGas Propane $ 35.0 $ 29.5 $ 25.4 $ 20.9 $ 16.8 $ 41.2
UGI Utilities 2.8 2.6 2.1 1.8 1.6 4.0
International Propane
and other 1.1 0.7 0.4 0.2 -- --
------- ------- ------- ------- ------- -------
Total $ 38.9 $ 32.8 $ 27.9 $ 22.9 $ 18.4 $ 45.2
Gas Utility has gas supply agreements with producers and marketers with
terms of less than one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity, which Gas Utility may terminate at various
dates through 2015. Gas Utility's costs associated with transportation and
storage capacity agreements are included in its annual PGC filing with the PUC
and are recoverable through PGC rates. In addition, Gas Utility has short-term
gas supply agreements which permit it to purchase certain of its gas supply
needs on a firm or interruptible basis at spot-market prices.
Electric Utility purchases its capacity requirements and electric energy
needs under contracts with various suppliers and on the spot market. Contracts
with producers for capacity and energy needs expire at various dates through
December 2006.
Energy Services enters into fixed price contracts with suppliers to
purchase natural gas to meet its sales commitments. Generally, these contracts
have terms of less than two years.
The following table presents contractual obligations under Gas Utility,
Electric Utility and Energy Services supply contracts existing at September
30, 2002:
After
2003 2004 2005 2006 2007 2007
---- ---- ---- ---- ---- ----
Gas and electric
supply contracts $106.4 $ 96.5 $56.9 $23.3 $14.9 $92.4
Energy Services
supply contracts 145.8 11.7 -- -- -- --
------ ------ ----- ----- ----- -----
Total $252.2 $108.2 $56.9 $23.3 $14.9 $92.4
The Partnership also enters into contracts to purchase propane to meet a
portion of its supply requirements. Generally, these contracts are one- or
two-year agreements subject to annual review
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 13 continued
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 relating to Petrolane's divestiture of non-propane operations before
its 1989 acquisition by QFB Partners. Future lease payments under these leases
total approximately $20 million at September 30, 2002. 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. In December
1999, Texas Eastern filed for dissolution under the Delaware General Corporation
Law. In May 2001, Petrolane filed a declaratory judgment action in the Delaware
Chancery Court seeking confirmation of Texas Eastern's indemnification
obligations and judicial supervision of Texas Eastern's dissolution to ensure
that its indemnification obligations to Petrolane are paid or adequately
provided for in accordance with law. Those proceedings are pending. In a
Liquidation and Winding Up Agreement dated September 17, 2002, PanEnergy
Corporation ("PanEnergy"), Texas Eastern's sole stockholder, agreed to assume
all of Texas Eastern's liabilities as of December 20, 2002, to the extent of the
value of Texas Eastern's assets transferred to PanEnergy as of that date (which
is expected to exceed $94 million), and to the extent that such liabilities
arise within ten years from Texas Eastern's date of dissolution. Notwithstanding
the dissolution proceeding, and based on Texas Eastern previously having
satisfied directly defaulted lease obligations without the Partnership's
having to honor its guarantee, we believe that the probability that the
Partnership will be required to directly satisfy the lease obligations subject
to the indemnification agreement is remote.
Columbia Propane, CPLP, and CPH (collectively, the "Company Parties")
agreed to indemnify the former general partners of National Propane Partners,
L.P. and certain of their affiliates (collectively, "National General
Partners") against certain income tax and other losses that the National General
Partners may sustain as a result of the 1999 acquisition by CPLP of the National
Propane business (the "1999 Acquisition") or its operation of the business
after the 1999 Acquisition.
CEG has agreed to indemnify AmeriGas Partners, AmeriGas OLP, the General
Partner (collectively, the "Buyer Parties") and the Company Parties against any
losses that they sustain under the 1999 Acquisition Agreement and related
agreements ("Losses"), including claims asserted by the National General
Partners ("National Claims"), to the extent such claims are based on acts or
omissions of CEG or the Company Parties prior to the acquisition of the Columbia
Propane Businesses by AmeriGas OLP on August 21, 2001 (the "2001 Acquisition").
The Buyer Parties have agreed to indemnify CEG against Losses, including
National Claims, to the extent such claims are based on acts or omissions of the
Buyer Parties or the Company Parties after the 2001 Acquisition. The Seller and
Buyer Parties have agreed to apportion certain losses resulting from a National
Claim to the extent such losses result from the 2001 Acquisition itself.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities does not expect its costs for investigation and remediation
of hazardous substances at Pennsylvania MGP sites to be material to its results
of operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. UGI Utilities has been notified of several sites
outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or
operated by its former subsidiaries and (2) either environmental agencies or
private parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating two
claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be
liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI
Utilities directly operated, or that were owned or operated by former
subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's
separate corporate form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance companies
alleging that the defendants breached contracts of insurance by failing to
indemnify UGI Utilities for certain environmental costs. The suit seeks to
recover more than $11 million in such costs. During 2002, 2001 and 2000, UGI
Utilities entered into settlement agreements with several of the insurers and
recorded pretax income of $0.4 million, $0.9 million and $4.5 million,
respectively, which amounts are included in operating and administrative
expenses in the Consolidated Statements of Income.
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. We
believe, after consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a material
adverse effect on our financial position but could be material to our operating
results or cash flows in future periods depending on the nature and timing of
future developments with respect to these matters and the amounts of future
operating results and cash flows.
46
UGI Corporation 2002 Annual Report
NOTE 14 - FINANCIAL INSTRUMENTS
In accordance with its propane price risk management policy, the Partnership
uses derivative instruments, including price swap and option contracts and
contracts for the forward sale of propane, to manage the cost of a portion of
its forecasted purchases of propane and to manage market risk associated with
propane storage inventories. These derivative instruments have been designated
by the Partnership as cash flow or fair value hedges under SFAS 133. The fair
values of these derivative instruments are affected by changes in propane
product prices. In addition to these derivative instruments, the Partnership may
also enter into contracts for the forward purchase of propane as well as
fixed-price supply agreements to manage propane market price risk. These
contracts generally qualify for the normal purchases and normal sales exception
of SFAS 133 and therefore are not adjusted to fair value. FLAGA also uses
derivative instruments, principally price swap contracts, to reduce market risk
associated with purchases of propane. These contracts may or may not qualify for
hedge accounting under SFAS 133.
Energy Services uses exchange-traded natural gas futures contracts to
manage market risk associated with forecasted purchases of natural gas it sells
under firm commitments. These derivative instruments are designated as cash flow
hedges. The fair values of these futures contracts are affected by changes in
natural gas prices.
In addition, we have, on occasion, used 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. These contracts
are generally designated as cash flow hedges.
Gas Utility and Electric Utility are parties to a number of contracts
that have elements of a derivative instrument. These contracts include, among
others, binding purchase orders, contracts which provide for the delivery of
natural gas, and service contracts that require the counterparty to provide
commodity storage, transportation or capacity service to meet our normal sales
commitments. Although many of these contracts have the requisite elements of
a derivative instrument, these contracts are not subject to the accounting
requirements of SFAS 133 because they provide for the delivery of products or
services in quantities that are expected to be used in the normal course of
operating our business or the value of the contract is directly associated with
the price or value of a service.
On occasion, we enter into interest rate protection agreements ("IRPAs")
to reduce market interest rate risk associated with forecasted debt issuances.
We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are
included in other comprehensive income and are reclassified to interest
expense as the interest expense on the associated debt issue affects earnings.
During the year ended September 30, 2002, the net pre-tax loss recognized
in earnings representing cash flow hedge ineffectiveness was $2.1 million.
During the year ended September 30, 2001, such gain or loss was not material.
The amount of cash flow hedge gains reclassified to net income because it became
probable that the original forecasted transactions would not occur was $1.0
million in 2001. This amount is included in other income.
Gains and losses included in accumulated other comprehensive income at
September 30, 2002 relating to cash flow hedges will be reclassified into (1)
cost of sales when the forecasted purchase of propane or natural gas subject to
the hedges impacts net income and (2) interest expense when interest on
anticipated issuances of fixed-rate long-term debt is reflected in net income.
Included in accumulated other comprehensive income at September 30, 2002 are net
after-tax losses of approximately $3.8 million from IRPAs associated with
forecasted issuances of debt generally anticipated to occur during the next two
years. The amount of this net loss which is expected to be reclassified into net
income during the next twelve months is not material. Also included in
accumulated other comprehensive income at September 30, 2002 are net after-tax
gains of approximately $7.0 million principally associated with future purchases
of natural gas or propane generally anticipated to occur during the next twelve
months. The actual amount of gains or losses on unsettled derivative instruments
that ultimately is reclassified into net income will depend upon the value of
such derivative contracts when settled. The fair value of derivative instruments
is included in other current assets, other current liabilities and other
noncurrent liabilities in the Consolidated Balance Sheets.
The carrying amounts of financial instruments included in current assets
and current liabilities (excluding unsettled derivative instruments and 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
remaining financial instruments (including unsettled derivative instruments)
at September 30 are as follows:
Carrying Estimated
Amount Fair Value
------ ----------
2002:
Natural gas futures contracts $ 5.1 $ 5.1
Propane swap and option contracts 9.8 9.8
Interest rate protection agreements (4.0) (4.0)
Long-term debt 1,275.7 1,328.1
UGI Utilities Series Preferred Stock 20.0 20.4
2001:
Natural gas futures contracts $ (1.5) $ (1.5)
Propane swap, option and forward sales (10.5) (10.5)
contracts
Interest rate protection agreements (3.0) (3.0)
Available for sale securities 18.3 18.3
Long-term debt 1,295.2 1,386.5
UGI Utilities Series Preferred Stock 20.0 21.4
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. Fair values of derivative instruments reflect
the estimated amounts that we would receive or pay to terminate the contracts at
the reporting date based upon quoted market prices of comparable contracts at
September 30, 2002 and 2001.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 14 continued
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. We attempt to minimize
our credit risk associated with our derivative financial instruments through the
application of credit policies.
NOTE 15 - ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY
Energy Services has a receivables purchase facility ("Receivables Facility")
with an issuer of receivables-backed commercial paper expiring November 30,
2004. Under the Receivables Facility, Energy Services transfers, on an ongoing
basis and without recourse, its trade accounts receivable to its wholly owned,
special purpose, bankruptcy-remote subsidiary, Energy Services Funding
Corporation ("ESFC") which is consolidated for financial statement purposes.
ESFC, in turn, has sold, and subject to certain conditions, may from time to
time sell, an undivided interest in these receivables for up to $50 million in
proceeds to a commercial paper conduit of a major bank. The proceeds of these
sales are less than the face amount of the accounts receivable sold by an amount
that approximates the purchaser's financing cost of issuing its own
receivables-backed commercial paper. ESFC was created and has been structured
to isolate its assets from creditors of Energy Services and its affiliates,
including UGI. In accordance with a servicing arrangement, Energy Services
continues to service, administer and collect trade receivables on behalf of
the commercial paper issuer and ESFC. This two-step transaction is accounted
for as a sale of receivables following the provisions of SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities."
During 2002, Energy Services sold $302.4 million of trade receivables to
ESFC of which ESFC sold an aggregate $34.0 million to the commercial paper
conduit. At September 30, 2002, no receivables had been sold to the commercial
paper conduit and removed from the balance sheet. Losses on sales of receivables
to the commercial paper conduit that occurred during the year ended September
30, 2002, which losses are included in other income, net, were $0.1 million.
NOTE 16 - PROVISION FOR SHUT-DOWN COSTS - HEARTH USA(TM)
In September 2001, after evaluating the prospects for Hearth USA(TM) in light of
the weak retail environment and the capital required to expand beyond its
two-store pilot phase, we committed to close both of its stores and cease all
operations by the end of October 2001. Hearth USA(TM) sold, installed and
serviced hearth, grill and spa products and sold related accessories from two
superstores located in Rockville, Maryland and Springfield, Virginia. As a
result of this action, in September 2001 we recorded a pre-tax charge of $8.5
million. The pre-tax charge reflects $3.7 million associated with the impairment
of leasehold improvements; $3.2 million for estimated costs associated with
lease guaranty arrangements and the restoration of the leased facilities; $1.1
million associated with the write-down of inventory to net realizable value; and
$0.5 million associated with vehicle lease, severance and other costs directly
resulting from the decision to close the stores. These charges and accrued costs
have been reflected in the 2001 Consolidated Statement of Income as "Provision
for shut-down costs - Hearth USA(TM)." As of September 30, 2001, the $3.7
million of costs associated with lease guaranty arrangements, the restoration
of the leased facility and the vehicle lease, severance and other costs is
included in other current liabilities in the Consolidated Balance Sheet. At
September 30, 2002, all amounts had been settled.
NOTE 17 - OTHER INCOME, NET
Other income, net, comprises the following:
2002 2001 2000
---- ---- ----
Interest and interest-related income $ (3.1) $ (6.7) $ (9.3)
Utility non-tariff service income (5.7) (5.4) (3.2)
Gain on sales of fixed assets (1.6) (2.4) (3.6)
Pension income (3.9) (5.9) (3.0)
Other (3.1) (2.6) (8.7)
------- ------- -------
Total other income, net $ (17.4) $ (23.0) $ (27.8)
------- ------- -------
NOTE 18 - SUBSEQUENT EVENT
Pursuant to the Partnership Agreement, the 9,891,072 Subordinated Units
outstanding as of September 30, 2002, all of which are held by the General
Partner, were 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 (i) each of the two immediately
preceding nonoverlapping four-quarter periods and (ii) 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.
In December 2002, the General Partner determined that the cash-based
performance and distribution requirements had been met in respect of the quarter
ended September 30, 2002. As a result, the remaining 9,891,072 Subordinated
Units held by the Company were converted to Common Units effective November
48
UGI Corporation 2002 Annual Report
18, 2002. Concurrent with the Subordinated Unit conversion, the Company recorded
an increase in common stockholders' equity and a decrease in minority interest
of approximately $160 million associated with gains from sales of Common Units
by AmeriGas Partners in conjunction with, and subsequent to, the Partnership's
April 19, 1995 initial public offering in accordance with the guidance in SEC
Staff Accounting Bulletin No. 51, "Accounting for Sales of Common Stock by a
Subsidiary." The gains result because the public offering prices of the AmeriGas
Partners Common Units at the dates of their sales exceeded the associated
carrying amount of our investment in the Partnership. No deferred taxes were
recorded relating to this gain due to the Company's intent to hold its
investment in the Partnership indefinitely. The changes to the Company's balance
sheet resulting from the Subordinated Unit conversion had no effect on the
Company's net income or cash flow. The conversion of the Subordinated Units did
not result in an increase in the number of AmeriGas Partners limited partner
units outstanding.
NOTE 19 - INVESTMENTS IN EQUITY INVESTEES
Our principal investments accounted for using the equity method and our
approximate ownership interest in each at September 30, 2002 and 2001 are as
follows:
Company Percentage Ownership
- ------- --------------------
Atlantic Energy 50.0%
AGZ Holdings 19.5%
China Gas Partners 50.0%
Hunlock Creek Energy Ventures 50.0%
Income (loss) from our equity investees comprises the following:
2002 2001 2000
---- ---- ----
Equity in income (loss) of equity investees $ 6.0 $ (2.1) $ (0.9)
Interest income on AGZ Bonds 0.9 0.5 --
Currency gain from redemption of AGZ Bonds 1.6 -- --
------- ------- -------
Total $ 8.5 $ (1.6) $ (0.9)
------- ------- -------
Undistributed net earnings (loss) of our equity investees included in
consolidated retained earnings were $3.6 million and $(2.3) million at September
30, 2002 and 2001, respectively.
On March 27, 2001, UGI France, Inc. ("UGI France"), a wholly owned
indirect subsidiary of Enterprises, together with Paribas Affaires Industrielles
("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), acquired, through AGZ
Holdings ("AGZ"), the stock and certain related assets of Elf Antargaz, S.A.,
one of the largest distributors of liquefied petroleum gas in France (referred
to after the transaction and herein as "Antargaz"). Prior to the transaction,
Antargaz was a subsidiary of Total Fina Elf S.A., a French petroleum and
chemical company. Under the terms of the Shareholders' Funding Agreement among
UGI France, PAI and Medit, we acquired an approximate 19.5% equity interest in
Antargaz; PAI an approximate 68.1% interest; Medit an approximate 9.7%
interest; and certain members of management of Antargaz an approximate 2.7%
interest. PAI is a leading private equity fund manager in Europe and an
affiliate of BNP Paribas, 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.
Pursuant to the Shareholders' Funding Agreement, on March 27, 2001, UGI
France made a 29.8 million euro ($26.6 million U.S. dollar equivalent)
investment comprising a 9.8 million euro investment in shares of AGZ and a 20.0
million euro investment in redeemable bonds of AGZ ("AGZ Bonds"). In July 2002,
the Company received $19.3 million in cash from AGZ representing repayment of 18
million euro face value (90%), $17.7 million U.S. dollar equivalent, of the AGZ
Bonds held by the Company, plus accrued interest. This repayment was funded from
the proceeds of an AGZ placement of high-yield debt. Concurrent with the
repayment, the remaining 2.0 million euro (10%) investment in AGZ Bonds was
redeemed in the form of additional shares of AGZ. After these transactions, the
Company continues to hold an approximate 19.5% equity investment in shares of
AGZ. As a result of the redemption of AGZ Bonds, we recorded a pretax currency
transaction gain of $1.6 million. Because we believe we have significant
influence over operating and financial policies of Antargaz due, in part, to our
membership on its Board of Directors, our investment in AGZ shares is accounted
for by the equity method.
Summarized financial information for AGZ follows:
2002 2001(a)
---- -------
STATEMENT OF INCOME DATA:
Revenues $ 550.6 $ 243.8
------- -------
Operating income $ 79.4 $ 22.5
Interest, net (27.9) (13.9)
------- -------
Income before income taxes $ 51.5 $ 8.6
Income taxes $ (20.7) $ (5.1)
Net income $ 29.9 $ 2.9
------- -------
BALANCE SHEET DATA (AT SEPTEMBER 30):
Current assets $ 171.5 $ 195.1
Property, plant and equipment, net 259.5 233.8
Goodwill 378.8 355.7
Other assets 116.7 93.3
------- -------
Total assets $ 926.5 $ 877.9
------- -------
Current liabilities $ 106.1 $ 123.4
Long-term debt 436.2 458.1
Other liabilities 292.0 248.3
------- -------
Total liabilities $ 834.3 $ 829.8
------- -------
Equity $ 92.2 $ 48.1
------- -------
(a) Statement of income data is for the period March 27, 2001 to September 30,
2001. Summarized financial information for AGZ as of September 30, 2001 and for
the period March 27, 2001 to September 30, 2001 was not required to be disclosed
previously, but is being presented for comparative purposes only.
Summarized financial information for our other equity investments are not
presented because they are not material to our Consolidated Balance Sheets or
Consolidated Statements of Income.
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 20 - QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30,
2001 2000 2002 2001 2002 2001 2002(A) 2001(b)
-------- -------- -------- -------- -------- -------- -------- --------
Revenues $ 619.4 $ 737.1 $ 764.0 $ 943.8 $ 446.3 $ 411.9 $ 384.0 $ 375.3
Operating income (loss) $ 73.8 $ 92.2 $ 150.5 $ 143.9 $ 29.0 $ 8.4 $ (0.7) $ (15.5)
Income (loss) from equity investees $ 3.8 $ (0.2) $ 3.7 $ (1.3) $ 0.7 $ -- $ 0.3 $ (0.1)
Income (loss) before changes in
accounting $ 24.1 $ 27.1 $ 54.0 $ 45.5 $ 4.0 $ (4.3) $ (6.6) $ (16.3)
Cumulative effect of accounting
changes, net (c) -- 4.5 -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Net income (loss) $ 24.1 $ 31.6 $ 54.0 $ 45.5 $ 4.0 $ (4.3) $ (6.6) $ (16.3)
-------- -------- -------- -------- -------- -------- -------- --------
Earnings (loss) per share:
Basic:
Income (loss) before accounting
changes $ 0.88 $ 1.00 $ 1.96 $ 1.68 $ 0.14 $ (0.16) $ (0.24) $ (0.60)
Cumulative effect of accounting
changes, net (c) -- 0.17 -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Net income (loss) $ 0.88 $ 1.17 $ 1.96 $ 1.68 $ 0.14 $ (0.16) $ (0.24) $ (0.60)
-------- -------- -------- -------- -------- -------- -------- --------
Diluted:
Income (loss) before accounting
changes $ 0.87 $ 1.00 $ 1.92 $ 1.67 $ 0.14 $ (0.16) $ (0.24) $ (0.60)
Cumulative effect of accounting
changes, net (c) -- 0.16 -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Net income (loss) $ 0.87 $ 1.16 $ 1.92 $ 1.67 $ 0.14 $ (0.16) $ (0.24) $ (0.60)
-------- -------- -------- -------- -------- -------- -------- --------
The quarterly data above includes all adjustments (consisting only of normal
recurring adjustments with the exception of those indicated below) that we
consider necessary for a fair presentation. Our quarterly results fluctuate
because of the seasonal nature of our businesses.
(a) Includes euro currency transaction gain resulting from the redemption of AGZ
Bonds which increased income from equity investees by $1.6 million and decreased
net loss by $1.1 million or $0.04 per share.
(b) Includes shut-down costs associated with Hearth USA(TM) which increased
operating loss by $8.5 million and net loss by $5.5 million or $0.20 per share.
(c) Includes the impact of changes in accounting associated with (1) the
Partnership's changes in accounting for tank fee revenue and tank installation
costs, and (2) the Company's adoption of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities."
NOTE 21 - SEGMENT INFORMATION
We have organized our business units into five reportable segments generally
based upon products sold, geographic location (domestic or international) or
regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2)
Gas Utility; (3) Electric Operations, comprising Electric Utility and our
electricity generation business; (4) Energy Services; and (5) an international
propane segment comprising FLAGA and our international propane equity
investments ("International Propane").
AmeriGas Propane derives its revenues principally from the sale of propane
and related equipment and supplies to retail customers from locations in 46
states. Gas Utility's revenues are derived principally from the sale and
distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Operations derives its revenues principally from the sale
and distribution of electricity in two northeastern Pennsylvania counties.
Energy Services revenues are derived from the sale of natural gas and, to a
lesser extent, electricity and fuel oil to customers located primarily in the
Middle Atlantic region. Our International Propane segment's revenues are
derived principally from the distribution of propane to retail customers in
Austria, the Czech Republic and Slovakia.
The accounting policies of our reportable segments are 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, minority interests, income from
equity investees and cumulative effect of accounting changes ("EBITDA").
Although we use EBITDA to evaluate segment performance, it should not be
considered as an alternative to cash flow (as a measure of liquidity or ability
to service debt obligations) and is not a measure of performance or financial
condition under accounting principles generally accepted in the United States.
The Company's definition of EBITDA may be different from that used by other
companies. We evaluate the performance of our Gas Utility, Electric Operations
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 United States, and all of
our reportable segments' long-lived assets, other than those of our
International Propane segment, are located in the United States.
50
UGI Corporation 2002 Annual Report
Financial information by reportable business segment follows:
Reportable Segments
------------------------------------------------------
Inter-
Elimi- AmeriGas Gas Electric Energy national Corporate &
Total nations Propane Utility Operations Services Propane Other
-------- -------- -------- -------- ---------- -------- -------- -----------
2002
Revenues $2,213.7 $ (2.0) $1,307.9 $ 404.5 $ 86.0 $ 332.3 $ 46.7 $ 38.3
EBITDA $ 346.1 $ -- $ 210.7 $ 96.1 $ 16.4 $ 11.9 $ 7.1 $ 3.9
Depreciation and amortization (93.5) -- (66.4) (19.0) (3.2) (0.8) (3.2) (0.9)
-------- -------- -------- -------- -------- -------- -------- --------
Operating income 252.6 -- 144.3 77.1 13.2 11.1 3.9 3.0
Income (loss) from equity investees 8.5 -- 0.3 -- -- -- 8.3(a) (0.1)
Interest expense (109.1) -- (87.8) (14.2) (2.4) -- (4.2) (0.5)
Minority interest (28.0) -- (28.0) -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Income before income taxes $ 124.0 $ -- $ 28.8 $ 62.9 $ 10.8 $ 11.1 $ 8.0 $ 2.4
Total assets $2,614.4 $ (34.1) $1,492.2 $ 689.1 $ 109.0 $ 57.2 $ 141.1 $ 159.9
Capital expenditures $ 94.7 $ -- $ 53.5 $ 31.0 $ 4.9 $ 0.9 $ 3.9 $ 0.5
Investments in equity investees $ 35.5 $ -- $ 3.4 $ -- $ 10.0 $ -- $ 22.1 $ --
Goodwill and excess reorganization value $ 644.9 $ -- $ 589.1 $ -- $ -- $ -- $ 53.1 $ 2.7
======== ======== ======== ======== ======== ======== ======== ========
2001
Revenues $2,468.1 $ (2.8) $1,418.4 $ 500.8 $ 83.9 $ 370.7 $ 50.9 $ 46.2
EBITDA $ 334.2 $ (0.4) $ 209.3 $ 108.0 $ 14.3 $ 7.6 $ 5.1 $ (9.7)(b)
Depreciation and amortization (105.2) -- (75.5) (20.2) (3.6) (0.3) (4.3) (1.3)
-------- -------- -------- -------- -------- -------- -------- --------
Operating income (loss) 229.0 (0.4) 133.8 87.8 10.7 7.3 0.8 (11.0)
Loss from equity investees (1.6) -- -- -- -- -- (1.5)(a) (0.1)
Interest expense (104.8) 0.4 (80.3) (16.3) (2.7) (0.4) (4.9) (0.6)
Minority interest (23.6) -- (23.6) -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes $ 99.0 $ -- $ 29.9 $ 71.5 $ 8.0 $ 6.9 $ (5.6) $ (11.7)
Total assets $2,550.2 $ (43.3) $1,522.3 $ 678.9 $ 105.5 $ 44.7 $ 141.2 $ 100.9
Capital expenditures $ 79.3 $ -- $ 39.2(c) $ 31.8 $ 5.0 $ 0.2 $ 2.7 $ 0.4
Investments in equity investees $ 44.8 $ -- $ 3.2 $ -- $ 10.8 $ -- $ 30.8(d) $ --
Goodwill and excess reorganization value $ 641.1 $ -- $ 589.0 $ -- $ -- $ -- $ 48.6 $ 3.5
======== ======== ======== ======== ======== ======== ======== ========
2000
Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9 $ 50.5 $ 10.4
EBITDA $ 289.6 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0 $ 2.8 $ 0.3
Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2) (4.6) (0.7)
-------- -------- -------- -------- -------- -------- -------- --------
Operating income (loss) 192.1 -- 90.2 86.2 15.1 2.8 (1.8) (0.4)
Loss from equity investees (0.9) -- -- -- -- -- (0.9) --
Interest expense (98.5) -- (74.7) (16.2) (2.2) -- (4.8) (0.6)
Minority interest (6.3) -- (6.3) -- -- -- -- --
-------- -------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8 $ (7.5) $ (1.0)
Total assets $2,275.8 $ (19.0) $1,281.7 $ 653.7 $ 97.4 $ 36.2 $ 113.7 $ 112.1
Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1 $ 1.8 $ 2.3
Investments in equity investees $ 5.5 $ -- $ -- $ -- $ -- $ -- $ 5.5 $ --
Goodwill and excess reorganization value $ 668.1 $ -- $ 615.7 $ -- $ -- $ -- $ 47.6 $ 4.8
======== ======== ======== ======== ======== ======== ======== ========
(a) In addition to equity income (loss) of international propane equity
investees (1) 2002 amount includes a currency transaction gain of $1.6 million
from the redemption of AGZ Bonds and $0.9 million of interest income on AGZ
Bonds and (2) 2001 amount includes $0.5 million of interest income on AGZ Bonds.
(b) Includes Hearth USA(TM) shut-down costs of $8.5 million.
(c) Includes capital leases of $1.3 million.
(d) Includes investment in AGZ Bonds of $18.2 million.
51