EXHIBIT 99.2
UGI Corporation 2003 Annual Report
FINANCIAL REVIEW
BUSINESS OVERVIEW
UGI Corporation ("UGI") is a holding company that distributes and markets energy
products and related services through subsidiaries and joint-venture affiliates.
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, 2003, UGI, through its wholly owned second-tier
subsidiary AmeriGas Propane, Inc. (the "General Partner"), held an approximate
48% 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 are conducted
through UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates a
natural gas distribution utility ("Gas Utility") in parts of eastern and
southeastern Pennsylvania and an electricity distribution utility ("Electric
Utility") in northeastern Pennsylvania. Gas Utility and Electric Utility are
subject to regulation by the Pennsylvania Public Utility Commission ("PUC").
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises")
conducts an energy marketing business primarily in the Eastern region of the
United States through its wholly owned subsidiary, UGI Energy Services, Inc.
("Energy Services"). Energy Services' wholly owned subsidiary UGI Development
Company ("UGID") and UGID's joint-venture affiliate Hunlock Creek Energy
Ventures ("Energy Ventures") own interests in Pennsylvania-based electricity
generation assets. Prior to its transfer to Energy Services in June 2003, UGID
was a wholly owned subsidiary of UGI Utilities. 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
2003 COMPARED WITH 2002
CONSOLIDATED RESULTS
Variance -
Favorable
2003 2002 (Unfavorable)
--------------------------- --------------------------- ---------------------------
DILUTED Diluted Diluted
NET EARNINGS Net Earnings Net Earnings
INCOME PER SHARE Income Per Share Income Per Share
----------------------------------------------------------------------------------------
(Millions of dollars, except per
share)
AmeriGas Propane $ 23.2 $ 0.55 $ 17.4 $ 0.42 $ 5.8 $ 0.13
Gas Utility 48.0 1.11 36.4 0.87 11.6 0.24
Electric Utility 10.6 0.24 5.3 0.12 5.3 0.12
Energy Services 11.2 0.26 7.3 0.17 3.9 0.09
International Propane 3.6 0.08 7.5 0.18 (3.9) (0.10)
Corporate & Other 2.3 0.05 1.6 0.04 0.7 0.01
---------- ---------- ---------- ---------- ---------- ----------
Total $ 98.9 $ 2.29 $ 75.5 $ 1.80 $ 23.4 $ 0.49
---------- ---------- ---------- ---------- ---------- ----------
Net income and earnings per share were higher in Fiscal 2003 reflecting
the effects of colder heating-season weather in our Gas Utility, Electric
Utility and AmeriGas Propane service territories and the effects of acquisitions
and other growth initiatives in our electricity generation and Energy Services
businesses. This improved performance was partially offset by a decline in
FLAGA's Fiscal 2003 results and the absence of income from our debt investments
in Antargaz redeemed in July 2002.
13
FINANCIAL REVIEW (continued)
The following table presents certain financial and statistical
information by reportable segment for Fiscal 2003 and Fiscal 2002:
Increase
2003 2002 (Decrease)
---------- ---------- ------------------------
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $ 1,628.4 $ 1,307.9 $ 320.5 24.5%
Total margin (a) $ 718.1 $ 654.8 $ 63.3 9.7%
Partnership EBITDA (b) $ 234.4 $ 209.6 $ 24.8 11.8%
Operating income $ 164.5 $ 145.0 $ 19.5 13.4%
Retail gallons sold (millions) (c) 1,074.9 987.5 87.4 8.9%
Degree days - % colder (warmer)
than normal (d) 0.2% (10.0)% - -
GAS UTILITY:
Revenues $ 539.9 $ 404.5 $ 135.4 33.5%
Total margin (a) $ 196.9 $ 162.9 $ 34.0 20.9%
Operating income $ 96.1 $ 77.1 $ 19.0 24.6%
Income before income taxes $ 80.7 $ 62.9 $ 17.8 28.3%
System throughput -
billions of cubic feet ("bcf") 83.8 70.5 13.3 18.9%
Degree days - % colder (warmer)
than normal 7.0% (17.4)% - -
ELECTRIC UTILITY:
Revenues $ 88.8 $ 83.5 $ 5.3 6.3%
Total margin (a) $ 40.3 $ 30.2 $ 10.1 33.4%
Operating income $ 20.3 $ 11.7 $ 8.6 73.5%
Income before income taxes $ 18.0 $ 9.3 $ 8.7 93.5%
Distribution sales - millions of
kilowatt hours ("gwh") 980.0 933.6 46.4 5.0%
ENERGY SERVICES:
Revenues $ 668.0 $ 344.8 $ 323.2 93.7%
Total margin (a) $ 35.6 $ 24.1 $ 11.5 47.7%
Income before income taxes $ 19.2 $ 12.6 $ 6.6 52.4%
INTERNATIONAL PROPANE:
Revenues $ 54.5 $ 46.7 $ 7.8 16.7%
Total margin (a) $ 27.1 $ 24.1 $ 3.0 12.4%
Operating income $ 0.7 $ 3.9 $ (3.2) (82.1)%
Income from equity investees $ 5.9 $ 8.3 $ (2.4) (28.9)%
Income before income taxes $ 2.5 $ 8.0 $ (5.5) (68.8)%
---------- ---------- ---------- ------
(a) Total margin represents total revenues less total cost of sales and, with
respect to Electric Utility, revenue-related taxes, i.e. Electric Utility
gross receipts taxes, of $4.8 million and $4.6 million in 2003 and 2002,
respectively. For financial statement purposes, revenue-related taxes are
included in "taxes other than income taxes" on the Consolidated Statements of
Income.
(b) Partnership EBITDA (earnings before interest expense, income taxes,
depreciation and amortization) should not be considered as an alternative to net
income (as an indicator of operating performance) or as an alternative to cash
flow (as a measure of liquidity or ability to service debt obligations) and is
not a measure of performance or financial condition under accounting
principles generally accepted in the United States of America. Management uses
Partnership EBITDA as the primary measure of segment profitability for the
AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements).
(c) Retail gallons sold in 2003 include certain bulk gallons previously
considered wholesale gallons. Prior-year gallon amounts have been adjusted to
conform to the current year classification.
(d) Deviation from average heating degree days based upon national weather
statistics provided by the National Oceanic and Atmospheric Administration
("NOAA") for 335 airports in the United States, excluding Alaska.
AMERIGAS PROPANE. Weather based upon heating degree days was
essentially normal during Fiscal 2003 compared to weather that was 10.0% warmer
than normal in Fiscal 2002. Although temperatures nationwide averaged near
normal during Fiscal 2003, our overall results reflect weather that was
significantly warmer in the West and generally colder than normal in the East.
Retail propane volumes sold increased 87.4 million gallons in Fiscal 2003 due
principally to the effects of the colder weather and, to a much lesser extent,
volume growth from acquisitions and customer growth. These increases were
achieved notwithstanding the effects of price-induced customer conservation and,
with respect to commercial and industrial customers, continuing economic
weakness.
Retail propane revenues increased $272.7 million reflecting (1) a
$175.1 million increase due to higher average selling prices and (2) a $97.6
million increase due to the higher retail volumes sold. Wholesale propane
revenues increased $38.3 million reflecting (1) a $31.7 million increase due to
higher average selling prices and (2) a $6.6 million increase due to the higher
volumes sold. The higher retail and wholesale selling prices reflect
significantly higher propane product costs during Fiscal 2003 resulting from,
among other things, higher crude oil and natural gas prices and lower propane
inventories. Other revenues from ancillary sales and services were $125.8
million in Fiscal 2003 and $116.3 million in Fiscal 2002. Total cost of sales
increased $257.2 million reflecting the higher propane product costs and higher
volumes sold.
The $63.3 million increase in total margin is principally due to the
higher propane gallons sold and, to a lesser extent, slightly higher average
retail propane unit margins. Notwithstanding the previously mentioned
significant increase in the commodity price of propane, retail propane unit
margins were slightly higher than the prior year reflecting the effects of the
higher average selling prices and the benefits of favorable propane product cost
management activities. Beginning in Fiscal 2002 and continuing in Fiscal 2003,
unit margins associated with the Partnership's Prefilled Propane Xchange program
("PPX(R)") were higher than historical levels reflecting increases in PPX(R)
sales prices to fund cylinder valve replacement capital expenditures. These
capital expenditures resulted from National Fire Protection Association ("NFPA")
guidelines enacted in Fiscal 2002 requiring propane grill cylinders be fitted
with overfill protection devices ("OPDs"). The extent to which this 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.
Partnership EBITDA increased $24.8 million in Fiscal 2003 reflecting
the previously mentioned increase in total margin and a $4.6 million increase in
other income partially offset by a $40.6 million increase in Partnership
operating and administrative expenses and a $2.3 million increase in losses
associated with early extinguishments of long-term debt. Operating and
administrative expenses increased principally due to higher medical and general
insurance expenses, higher distribution expenses as a result of the previously
mentioned greater retail volumes, and higher incentive compensation and
uncollectible accounts expenses. In addition, the Partnership incurred $3.8
million of costs during Fiscal 2003 associated with a realign-
14
UGI Corporation 2003 Annual Report
ment of the Partnership's management structure announced in June 2003. Other
income in Fiscal 2003 includes a gain of $1.1 million from the settlement of
certain hedge contracts and greater income from finance charges and asset sales
while other income in the prior year was reduced by a $2.1 million loss from
declines in the value of propane commodity option contracts. Operating income in
Fiscal 2003 increased less than the increase in Partnership EBITDA due to higher
depreciation expense principally associated with PPX(R) partially offset by the
previously mentioned increase in losses associated with early extinguishments of
long-term debt.
GAS UTILITY. Weather in Gas Utility's service territory based upon heating
degree days was 7.0% colder than normal during Fiscal 2003 compared to weather
that was 17.4% warmer than normal during Fiscal 2002. The significantly colder
weather resulted in higher heating-related sales to firm- residential,
commercial and industrial ("retail core-market") customers and, to a lesser
extent, greater volumes transported for residential, commercial and industrial
delivery service customers. System throughput in Fiscal 2003 also benefited from
a year-over-year increase in the number of customers.
Gas Utility revenues increased principally as a result of the
previously mentioned greater retail core-market and delivery service volumes and
higher average retail core-market purchased gas cost ("PGC") rates resulting
from higher natural gas costs. Gas Utility cost of gas was $343.0 million in
Fiscal 2003, an increase of $101.3 million from the prior year, reflecting the
higher retail core-market volumes sold and the higher retail core-market PGC
rates.
The increase in Gas Utility total margin principally reflects a $27.1
million increase in retail core-market total margin due to the higher retail
core-market sales and increased margin from greater delivery service volumes.
The increase in Gas Utility operating income principally reflects the
increase in total margin partially offset by a $12.7 million increase in
operating and administrative expenses and lower other income. Fiscal 2003
operating and administrative expenses include higher costs associated with
litigation-related costs and expenses, greater distribution system maintenance
expenses, higher uncollectible accounts expenses and increased incentive
compensation costs. Other income declined $3.2 million principally reflecting a
$2.2 million decrease in pension income and lower interest income on PGC
undercollections. The increase in Gas Utility income before income taxes
reflects the increase in operating income offset by higher interest expense on
PGC overcollections and, beginning July 1, 2003, dividends on preferred shares.
ELECTRIC UTILITY. Electric Utility's Fiscal 2003 kilowatt-hour distribution
sales increased principally as a result of weather that was 8.4% colder than
normal compared to weather that was 14.5% warmer than normal in the prior year.
The higher Electric Utility revenues reflect the previously mentioned
increase in Electric Utility kilowatt-hour distribution sales. Beginning
September 2002, Electric Utility began purchasing its power needs exclusively
from third-party electricity suppliers under fixed-price energy and capacity
contracts and, to a much lesser extent, on the spot market. Notwithstanding the
increase in Electric Utility revenues, cost of sales decreased $5.0 million in
Fiscal 2003 due to lower Electric Utility per-unit purchased power costs.
The increase in Electric Utility total margin principally reflects
lower Electric Utility per-unit purchased power costs and the increase in
Electric Utility sales. The higher Fiscal 2003 operating income reflects the
greater total margin partially offset by higher operating and administrative
expenses resulting from higher transmission and distribution expenses and a $0.4
million decrease in other income. The increase in Electric Utility income before
income taxes reflects the increase in operating income and slightly lower
interest expense.
ENERGY SERVICES. The increase in Energy Services' revenues in Fiscal 2003
resulted from higher natural gas prices and, to a lesser extent, a more than 40%
increase in natural gas volumes sold due in large part to the March 2003
acquisition of the northeastern U.S. gas marketing business of TXU Energy Retail
Company, L.P., a subsidiary of TXU Energy (the "TXU Energy Acquisition") and
greater sales of electricity produced by UGID's electricity generation assets to
third parties. Prior to September 2002, UGID sold substantially all of the
electricity it produced to Electric Utility with the associated revenue and
margin eliminated in our consolidated results. Beginning September 2002, UGID
began selling electric power produced from its interests in electricity
generating facilities to third parties on the spot market. Additionally, the
greater Fiscal 2003 UGID sales and revenues reflect UGID's June 26, 2003
purchase of an additional 4.9% (83 megawatt) interest in the Conemaugh
electricity generation station located near Johnstown, Pennsylvania
("Conemaugh"). The greater Energy Services' Fiscal 2003 total margin reflects
the increase in natural gas volumes sold partially offset by slightly lower
average unit margins and margin from the greater sales of electricity produced
by UGID's electricity generation assets to third parties. The increase in total
margin was partially offset by higher operating expenses resulting principally
from the TXU Energy Acquisition, growth initiatives and our purchase of the
additional interest in Conemaugh.
INTERNATIONAL PROPANE. FLAGA's revenues increased $7.8 million, notwithstanding
a 5% decline in volumes sold, primarily reflecting the currency translation
effects of a stronger euro and, to a lesser extent, higher average selling
prices. Volumes were lower in Fiscal 2003 principally due to the loss of a
high-volume, low unit margin customer and, to a lesser extent, price-induced
conservation and continued weak economic activity. The increase in Fiscal 2003
total margin reflects the translation effects of the stronger euro. The decline
in FLAGA operating income, notwithstanding the increase in total margin, is
substantially the result of the translation effects of the stronger euro on
operating and administrative expenses and, to a lesser extent, higher
base-currency expenses.
The decline in Fiscal 2003 earnings from our equity investees is
principally a result of the July 2002 redemption of our debt investments in AGZ
Holdings ("AGZ"), the parent company of Antargaz. Income from our debt
investments in AGZ in Fiscal 2002 includes $0.9 million of interest income and a
currency transaction
FINANCIAL REVIEW (continued)
gain of $1.6 million resulting from the early redemption of this
euro-denominated debt in July 2002. Equity income from AGZ in Fiscal 2003 was
comparable with Fiscal 2002, notwithstanding a decline in Antargaz'
base-currency results, reflecting the effects of the stronger euro. The decline
in International Propane income before income taxes reflects the combined
decrease in FLAGA operating income and in our income from equity investees
offset by slightly lower interest expense.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $109.2 million in Fiscal
2003 compared to $109.1 million in Fiscal 2002 as slightly higher UGI Utilities
interest expense was partially offset by slightly lower Partnership interest
expense. The Company's effective income tax rate was 37.8% in Fiscal 2003 and
Fiscal 2002.
2002 COMPARED WITH 2001
CONSOLIDATED RESULTS
Variance -
Favorable
2002 2001 (Unfavorable)
------------------------- ------------------------ ------------------------
Diluted Diluted
Diluted Net Earnings Net Earnings
Net Earnings Income (Loss) Income (Loss)
Income Per Share (Loss) Per Share (Loss) Per Share
------------ ---------- ---------- ---------- ---------- ----------
(Millions of dollars, except per share)
AmeriGas Propane $ 17.4 $ 0.42 $ 13.5 $ 0.33 $ 3.9 $ 0.09
Gas Utility 36.4 0.87 41.9 1.02 (5.5) (0.15)
Electric Utility 5.3 0.12 1.7 0.04 3.6 0.08
Energy Services 7.3 0.17 7.0 0.17 0.3 -
International Propane 7.5 0.18 (4.4) (0.11) 11.9 0.29
Corporate & Other (a) 1.6 0.04 (7.7) (0.18) 9.3 0.22
Changes in accounting (b) - - 4.5 0.11 (4.5) (0.11)
---------- ---------- ---------- ---------- ---------- ----------
Total (c) $ 75.5 $ 1.80 $ 56.5 $ 1.38 $ 19.0 $ 0.42
---------- ---------- ---------- ---------- ---------- ----------
(a) Net loss in Fiscal 2001 includes after-tax shut-down costs of $5.5 million
or $0.13 per share associated with Hearth USA(TM) (see Note 16 to Consolidated
Financial Statements) and a $1.2 million loss or $0.03 per share associated with
the write-down of an investment in a business-to-business e-commerce company.
(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
15 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 $1.72, 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).
The following table presents certain financial and statistical
information by reportable segment for Fiscal 2002 and Fiscal 2001:
Increase
2002 2001 (Decrease)
---------- ---------- ------------------------
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $ 1,307.9 $ 1,418.4 $ (110.5) (7.8)%
Total margin $ 654.8 $ 571.4 $ 83.4 14.6%
Partnership EBITDA $ 209.6 $ 220.3 $ (10.7) (4.9%)
Operating income $ 145.0 $ 133.8 $ 11.2 8.4%
Retail gallons sold (millions) (a) 987.5 866.8 120.7 13.9%
Degree days - % colder (warmer)
than normal (10.0)% 2.6% - -
GAS UTILITY:
Revenues $ 404.5 $ 500.8 $ (96.3) (19.2)%
Total margin $ 162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
Income before income taxes $ 62.9 $ 71.5 $ (8.6) (12.0)%
System throughput - bcf 70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal (17.4)% 2.0% - -
ELECTRIC UTILITY:
Revenues $ 83.5 $ 81.9 $ 1.6 2.0%
Total margin (b) $ 30.2 $ 23.3 $ 6.9 29.6%
Operating income $ 11.7 $ 5.7 $ 6.0 105.3%
Income before income taxes $ 9.3 $ 3.0 $ 6.3 210.0%
Distribution sales - gwh 933.6 945.5 (11.9) (1.3)%
ENERGY SERVICES:
Revenues $ 344.8 $ 386.0 $ (41.2) (10.7)%
Total margin $ 24.1 $ 18.7 $ 5.4 28.9%
Operating income $ 12.6 $ 12.3 $ 0.3 2.4%
Income before income taxes $ 12.6 $ 11.9 $ 0.7 5.9%
INTERNATIONAL PROPANE:
Revenues $ 46.7 $ 50.9 $ (4.2) (8.3)%
Total margin $ 24.1 $ 22.5 $ 1.6 7.1%
Operating income $ 3.9 $ 0.8 $ 3.1 387.5%
Income (loss) from equity investees $ 8.3 $ (1.5) $ 9.8 N.M.
Income before income taxes $ 8.0 $ (5.6) $ 13.6 N.M.
N.M. -- Not Meaningful
(a) Retail gallons sold in 2002 and 2001 have been adjusted to include certain
bulk gallons previously considered wholesale gallons.
(b) Electric Utility total margin represents total revenues less cost of
sales and Electric Utility gross receipts taxes of $4.6 million and $3.4 million
in 2002 and 2001, respectively.
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 120.7 million gallons principally as a result of the full-
UGI Corporation 2003 Annual Report
year effect of the Partnership's August 21, 2001 acquisition of Columbia Propane
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 the previously mentioned
NFPA guidelines requiring grill cylinders be fitted with OPDs and, to a lesser
extent, the full-year effects of Fiscal 2001 increases in the number of PPX(R)
distribution outlets.
Retail propane revenues were $1,102.8 million in Fiscal 2002, a
decrease of $44.5 million from Fiscal 2001, reflecting a $204.3 million decrease
as a result of lower average selling prices partially offset by a $159.8 million
increase as a result of the greater retail volumes sold. Wholesale propane
revenues were $88.8 million in Fiscal 2002, a decrease of $86.8 million,
reflecting a $50.2 million decrease due to lower average selling prices and a
$36.6 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 the Columbia Propane
acquisition. Total cost of sales declined $193.9 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 $83.4 million reflecting the full-year volume
impact of the Columbia Propane acquisition and a $25.5 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.
Partnership EBITDA increased $1.8 million (excluding the $12.5 million
cumulative effect of the Partnership's changes in accounting for tank fee
revenue and tank installation costs and the adoption of SFAS 133 in Fiscal 2001)
as the significant increase in total margin was substantially offset by a $78.9
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. 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
$11.2 million principally due to the cessation of goodwill amortization in
Fiscal 2002 as a result of the adoption of SFAS 142 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 PGC rates, resulting from the pass through of lower natural
gas costs to retail core-market customers, and the lower distribution system
throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared
to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and the
decline in retail core-market throughput in Fiscal 2002.
The decline in Gas Utility margin principally reflects a $6.0 million
decline in retail core-market margin due to the lower sales; a $6.6 million
decline in interruptible margin due principally to the flowback of certain
interruptible customer margin to retail core-market customers beginning December
1, 2001 pursuant to the Gas Restructuring Order; and lower firm delivery service
total margin due to lower delivery service volumes. Interruptible customers are
those who have the ability to switch to alternate fuels.
Gas Utility operating income declined $10.7 million in Fiscal 2002
reflecting the previously mentioned decline in total 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. The decline in Gas Utility income before income
taxes reflects the decrease in operating income offset by lower interest expense
resulting from lower levels of UGI Utilities bank loans outstanding and lower
short-term interest rates.
ELECTRIC UTILITY. 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 $1.6 million principally due to an
increase in state tax surcharge revenue. Electric Utility cost of sales was
$48.7 million in Fiscal 2002 compared to $55.2 million in Fiscal 2001
principally reflecting the impact of the lower sales and lower purchased power
unit costs.
Electric Utility total margin increased $6.9 million in Fiscal 2002
as a result of lower purchased power unit costs partially offset by the warmer
winter weather-driven decline in sales. Operating income increased $6.0 million
reflecting the
17
FINANCIAL REVIEW (continued)
greater total margin partially offset by higher operating and administrative
costs and a decline in other income. The increase in Electric Utility income
before income taxes reflects the increase in operating income and lower interest
expense.
ENERGY SERVICES. Revenues from Energy Services declined $41.2 million,
notwithstanding a 27% increase in natural gas volumes sold, reflecting
significantly lower natural gas prices and lower sales of electricity produced
by UGID's electric generation facilities. 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 partially offset by the previously mentioned lower sales of electricity
produced. The increase in total margin was principally offset by higher
operating expenses subsequent to the PG Energy acquisition and a decline in
other income. The increase in Energy Services income before income taxes
reflects the increase in operating income and the absence of interest expense on
debt under its financing agreement with UGI that was repaid in Fiscal 2002.
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 acquired on March 27, 2001.
Operating results of Antargaz in Fiscal 2002 benefited from higher than normal
unit margins, principally as a 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. 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. The increase in International Propane income before income taxes
reflects the combined increase in FLAGA operating income and in our income from
equity investees and lower interest expense resulting from lower short-term
interest rates.
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.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Total cash, cash equivalents and short-term investments were $192.1 million at
September 30, 2003 compared with $194.3 million at September 30, 2002. These
amounts include $116.3 million and $114.0 million, respectively, of cash, cash
equivalents 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., UGI Utilities and, to a lesser extent, Enterprises. AmeriGas, Inc.'s
ability to pay dividends to UGI is largely dependent upon distributions it
receives from AmeriGas Partners. At September 30, 2003, our approximate 48%
effective ownership interest in the Partnership consisted of 24.5 million Common
Units and a 2% general partner interest. Approximately 45 days after the end of
each fiscal quarter, the Partnership distributes all of its Available Cash (as
defined in the Second Amended and Restated Agreement of Limited Partnership of
AmeriGas Partners, the "Partnership Agreement") relating to such fiscal quarter.
Since its formation in 1995, the Partnership has paid the Minimum Quarterly
Distribution of $0.55 ("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 2003, 2002 and 2001 was approximately $112
million, $109 million and $99 million, respectively. Based upon the number of
Partnership units outstanding on September 30, 2003, the amount of Available
Cash needed annually to pay the MQD on all units and the general partner
interests is approximately $117 million. 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 ability of the
Partnership to borrow under its 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.
During Fiscal 2003, 2002 and 2001, AmeriGas, Inc., UGI Utilities and
Enterprises paid cash dividends to UGI as follows:
Year Ended September 30, 2003 2002 2001
- ----------------------------------- ---------- ---------- ----------
(Millions of dollars)
AmeriGas, Inc. $ 44.7 $ 49.4 $ 41.0
UGI Utilities 33.9 37.9 35.3
Enterprises 7.1 23.6(a) -
---------- ---------- ----------
Total dividends to UGI $ 85.7 $ 110.9 $ 76.3
---------- ---------- ----------
(a) Includes $17.0 of the proceeds related to the redemption of AGZ Bonds.
Dividends received by UGI are available to pay dividends on UGI Common
Stock and for investment purposes.
On January 28, 2003, UGI's Board of Directors approved a 3-for-2 split
of UGI's Common Stock. On April 1, 2003, UGI issued one additional common share
for every two common shares outstanding to shareholders of record on February
28,
18
UGI Corporation 2003 Annual Report
2003. Also on January 28, 2003, UGI's Board of Directors approved an increase in
the quarterly dividend rate on UGI Common Stock to $0.285 per post-split share,
or $1.14 per post-split share on an annual basis, commencing April 1, 2003.
AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30, 2003
totaled $927.3 million. There were no amounts outstanding under AmeriGas OLP's
Credit Agreement at September 30, 2003.
AmeriGas OLP's Credit Agreement expires on October 15, 2006 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. 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 or, to the extent it
is not so used, may be used for working capital and general purposes. Issued and
outstanding letters of credit under the Revolving Credit Facility, which reduce
the amount available for borrowings, totaled $33.4 million at September 30,
2003. 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 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 periodically issues debt and equity securities and
expects to continue to do so. It has effective debt and equity shelf
registration statements with the U.S. Securities and Exchange Commission ("SEC")
under which it may issue up to an additional (1) $28 million principal amount of
8.875% Senior Notes due 2011, (2) 1.4 million AmeriGas Partners Common Units and
(3) up to $500 million of debt or equity pursuant to an unallocated shelf
registration statement.
AmeriGas OLP must maintain certain financial ratios in order to borrow
under its Credit Agreement including a minimum interest coverage ratio and a
maximum debt to EBITDA ratio, as defined. AmeriGas OLP's ratios calculated as of
September 30, 2003 permit it to borrow up to the maximum amount available. For a
more detailed discussion of the Partnership's credit facilities, see Note 4 to
Consolidated Financial Statements. Based upon existing cash balances, cash
expected to be generated from operations, borrowings available under its 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 during Fiscal 2004.
UGI UTILITIES. UGI Utilities' total debt outstanding was $258.0 million at
September 30, 2003. Included in this amount is $40.7 million under revolving
credit agreements.
UGI Utilities has revolving credit commitments under which it may borrow up to a
total of $107 million. These agreements are currently scheduled to expire in
June 2005 and 2006. The revolving credit agreements have restrictions on such
items as total debt, debt service and payments for investments. At September 30,
2003, UGI Utilities was in compliance with these covenants. UGI Utilities has a
shelf registration statement with the SEC under which it may issue up to an
additional $40 million of Medium-Term Notes or other debt securities. Based upon
cash expected to be generated from Gas Utility and Electric Utility operations
and borrowings available under revolving credit agreements, management believes
that UGI Utilities will be able to meet its anticipated contractual and
projected cash commitments during Fiscal 2004. For a more detailed discussion of
UGI Utilities' long-term debt and revolving credit facilities, see Note 4 to
Consolidated Financial Statements.
ENERGY SERVICES. Energy Services has a $100 million receivables purchase
facility ("Receivables Facility") with an issuer of receivables-backed
commercial paper expiring on August 26, 2006, although the Receivables Facility
may terminate prior to such date due to the termination of the commitments of
the Receivables Facility back-up purchasers. Under the Receivables Facility,
Energy Services transfers, on an ongoing basis and without recourse, its trade
accounts receivable to its wholly owned, special purpose 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 the receivables to a
commercial paper conduit of a major bank. The maximum level of funding available
at any one time from this facility is $100 million. 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. 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." Energy
Services continues to service, administer and collect trade receivables on
behalf of the commercial paper issuer and ESFC. At September 30, 2003, the
outstanding balance of ESFC receivables was $38.5 million which amount is net of
$17 million in trade receivables sold to the commercial paper conduit. Based
upon cash expected to be generated from operations and borrowings available
under its Receivables Facility, management believes that Energy Services will be
able to meet its anticipated contractual and projected cash commitments during
Fiscal 2004.
In addition, a major bank has committed to issue up to $50 million of
standby letters of credit, secured by cash or marketable securities ("LC
Facility"). Energy Services expects to fund the collateral requirements with
borrowings under its Receivables Facility. The LC Facility expires on September
13, 2004.
FLAGA. FLAGA has a 15 million euro working capital loan commitment from a
European bank expiring in November 2004. Borrowings under the working capital
facility totaled 13.6 million euro ($15.9 million U.S. dollar equivalent) at
September 30, 2003. Debt issued under this agreement, as well as $73.1 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 4 to Consolidated
Financial Statements.
19
FINANCIAL REVIEW (continued)
FLAGA's management expects to repay long-term debt maturing in Fiscal 2004 of
$5.7 million principally through cash generated from operations and capital
contributions from UGI.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of the Company's businesses,
cash flows from operating activities are generally strongest during the second
and third fiscal quarters when customers pay for natural gas, propane and
electricity consumed during the heating season months. Conversely, operating
cash flows are generally at their lowest levels during the first and fourth
fiscal quarters when the Company's investment in working capital, principally
inventories and accounts receivable, is generally greatest. The Company's major
business units use revolving credit facilities, or in the case of Energy
Services its Receivables Facility, to satisfy their seasonal operating cash flow
needs. Cash flow from operating activities was $249.1 million in Fiscal 2003,
$247.5 million in Fiscal 2002, and $203.5 million in Fiscal 2001. Cash flow from
operating activities before changes in operating working capital was $256.3
million in Fiscal 2003, $233.7 million in Fiscal 2002, and $179.8 million in
Fiscal 2001. Changes in operating working capital used $7.2 million of cash in
Fiscal 2003, and provided $13.8 million and $23.7 million of cash in Fiscal 2002
and Fiscal 2001, respectively. Cash needed to fund Fiscal 2003 increases in
accounts receivable and inventories resulting from higher natural gas and
propane commodity prices was substantially offset by cash provided from changes
in accounts payable, Gas Utility fuel cost overcollections, and accrued income
taxes.
INVESTING ACTIVITIES. Cash flow used in investing activities was $226.1 million
in Fiscal 2003, $66.4 million in Fiscal 2002, and $313.3 million in Fiscal 2001.
Investing activity cash flow is principally affected by capital expenditures and
investments in property, plant and equipment, cash paid for acquisitions of
businesses, investments in and distributions from our equity investees, and
proceeds from sales of assets. During Fiscal 2003, we spent $100.9 million for
property, plant and equipment, an increase of $6.2 million from Fiscal 2002,
principally reflecting higher Gas Utility and FLAGA capital expenditures. Cash
paid for business acquisitions in Fiscal 2003 principally reflects Partnership
business acquisitions and Energy Services' TXU Energy Acquisition. Additionally,
during Fiscal 2003 the Company purchased an additional 4.9% interest in
Conemaugh for $51.3 million and received a cash dividend from AGZ of $5.6
million. Also during Fiscal 2003, UGI invested $50 million of its cash and cash
equivalents in short-term investments.
FINANCING ACTIVITIES. Cash flow used by financing activities was $75.3 million
in Fiscal 2003 and $74.3 million in Fiscal 2002 compared to cash flow provided
by financing activities of $103.7 million in Fiscal 2001. Financing activity
cash flow changes are primarily due to issuances and repayments of long-term
debt, net borrowings under revolving credit facilities, dividends and
distributions on UGI Common Stock and AmeriGas Partners Common Units, and
proceeds from public offerings of AmeriGas Partners Common Units and issuances
of UGI Common Stock.
In June 2003, AmeriGas Partners sold 2.9 million Common Units in an
underwritten public offering at a public offering price of $27.12 per unit. The
net proceeds of the public offering totaling $75.0 million, and associated
capital contributions from the General Partner totaling $1.5 million, were
contributed to AmeriGas OLP and used to reduce indebtedness under its bank
credit agreement and for general partnership purposes. The underwriters'
overallotment option expired unexercised. Concurrent with this sale of Common
Units, the Company recorded a gain in the amount of $22.6 million, which is
reflected as an increase in common stockholders' equity, in accordance with the
guidance in SEC Staff Accounting Bulletin, No. 51, "Accounting for Sales of
Common Stock by a Subsidiary" ("SAB 51"). The gain had no effect on the
Company's net income or cash flow.
The Partnership also completed a number of debt transactions during
Fiscal 2003. In December 2002, AmeriGas Partners issued $88 million face amount
of 8.875% Senior Notes due 2011 at an effective interest rate of 8.30%. The net
proceeds of $89.1 million were used in January 2003 to redeem prior to maturity
AmeriGas Partners' $85 million face amount of 10.125% Senior Notes due April
2007 at a redemption price of 102.25%, plus accrued interest. The Company
recognized a pre-tax loss, net of minority interests, of $1.5 million relating
to the redemption premium and other associated costs and expenses. In April
2003, AmeriGas OLP repaid $53.8 million of maturing First Mortgage Notes. In
conjunction with this repayment, in April 2003 AmeriGas Partners issued $32
million face amount of 8.875% Senior Notes due 2011 at an effective interest
rate of 7.72% and contributed the net proceeds of $33.7 million, including debt
premium, to AmeriGas OLP.
In August 2003, UGI Utilities issued $25 million of ten-year notes at
an interest rate of 5.37% and $20 million of 30-year notes at an interest rate
of 6.50% under its Medium-Term Note program. The net proceeds along with
existing cash balances were used to repay $50 million of 6.50% Senior Notes that
matured in August 2003.
During Fiscal 2003 we paid cash dividends on UGI Common Stock of $47.7
million and the Partnership paid the MQD on all limited partner units. The
increase in cash flow from the issuance of UGI Common Stock in Fiscal 2003 is
principally the result of greater employee stock option exercise activity.
CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS
In December 2002, the General Partner determined that the cash-based performance
and distribution requirements for the conversion of the then-remaining 9,891,072
Subordinated Units of AmeriGas Partners, all of which were held by the General
Partner, had been met in respect of the quarter ended September 30, 2002. As a
result, in accordance with the Second Amended and Restated Agreement of Limited
Partnership of AmeriGas Partners, L.P., the Subordinated Units were converted to
an equivalent number of Common Units effective November 18, 2002. Concurrent
with the Subordinated Unit conversion, the Company recorded a $157.0 million
increase in common stockholders' equity, and a corresponding decrease in
minority interests in AmeriGas Partners, 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. These gains
20
UGI Corporation 2003 Annual Report
were determined in accordance with the guidance in SAB 51. The gains resulted
because the public offering prices of the AmeriGas Partners Common Units
exceeded the associated carrying amount of our investment in the Partnership on
the dates of their sale. Due to the preference nature of the Common Units, the
Company was precluded from recording these gains until the Subordinated Units
converted to Common Units. No deferred income taxes were recorded on these 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 and did not result in an increase in the number of AmeriGas Partners
limited partner units outstanding.
UGI UTILITIES PENSION PLAN
UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI Utilities, UGI, and certain of UGI's other subsidiaries. During
Fiscal 2002 and 2001, the market value of plan assets was negatively affected by
declines in the equity markets. Equity market performance improved in Fiscal
2003 and, as a result, the fair value of Pension Plan assets increased to $183.9
million at September 30, 2003 compared to $166.1 million at September 30, 2002.
At September 30, 2003 and 2002, the Pension Plan's assets exceeded its
accumulated benefit obligations by $7.3 million and $7.2 million, respectively.
The Company is in full compliance with regulations governing defined benefit
pension plans, including ERISA rules and regulations, and does not anticipate it
will be required to make a contribution to the Pension Plan in Fiscal 2004.
Pre-tax pension income reflected in Fiscal 2003, 2002 and 2001 results was $1.1
million, $4.0 million and $5.9 million, respectively. The decrease in pension
income during this period reflects the significant declines in the market value
of Pension Plan assets and decreases in the discount rate assumption. Pension
expense in Fiscal 2004 is expected to be approximately $1.2 million compared to
pension income of $1.1 million in Fiscal 2003 due to decreases in the discount
rate and expected return on Pension Plan assets assumptions.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures (which include
expenditures for capital leases but exclude acquisitions) by business segment
for Fiscal 2003, 2002 and 2001. We also provide amounts we expect to spend in
Fiscal 2004. We expect to finance Fiscal 2004 capital expenditures principally
from cash generated by operations and borrowings under our credit facilities.
Year Ended September 30, 2004 2003 2002 2001
- ------------------------ -------- -------- -------- --------
(Millions of dollars) (estimate)
AmeriGas Propane $ 58.1 $ 53.4 $ 53.5 $ 39.2
Gas Utility 38.0 37.2 31.0 31.8
Electric Utility 4.9 4.1 4.6 4.7
Energy Services 1.3 1.0 1.2 0.5
International Propane 4.2 4.5 3.9 2.7
Other 1.0 1.2 0.5 0.4
-------- -------- -------- --------
Total $ 107.5 $ 101.4 $ 94.7 $ 79.3
-------- -------- -------- --------
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The Company has certain contractual cash obligations that extend beyond Fiscal
2003 including scheduled repayments of long-term debt and UGI Utilities
preferred shares subject to mandatory redemption, operating lease payments and
unconditional purchase obligations for pipeline capacity, pipeline
transportation and natural gas storage services, and commitments to purchase
natural gas, propane and electricity. The following table presents significant
contractual cash obligations under agreements existing as of September 30, 2003
(in millions).
Payments Due by Period
--------------------------------------------------------
less than 2 - 3 4 - 5 After
Total 1 year years years 5 years
-------- --------- ------ ------ -------
Long-term debt $1,207.2 $ 61.9 $307.9 $132.8 $704.6
UGI Utilities preferred
shares subject to
mandatory redemption 20.0 - 2.0 2.0 16.0
Operating leases 189.3 40.1 63.0 43.3 42.9
AmeriGas Propane
supply contracts 16.7 16.7 - - -
Energy Services supply
contracts 510.4 435.3 73.7 1.4 -
Gas Utility and Electric
Utility supply, storage
and service contracts 406.9 157.1 136.0 39.8 74.0
-------- --------- ------- ------ -------
Total $2,350.5 $711.1 $582.6 $219.3 $837.5
-------- --------- ------- ------ -------
RELATED PARTY TRANSACTIONS
During Fiscal 2003, 2002 and 2001, the Company did not enter into any related
party transactions that had a material effect on its financial condition or
results of operations.
OFF-BALANCE SHEET ARRANGEMENTS
We lease various buildings and other facilities and transportation, computer and
office equipment. We account for these arrangements as operating leases. These
off-balance sheet arrangements enable us to lease facilities and equipment from
third parties rather than, among other options, purchasing the equipment and
facilities using on-balance sheet financing. For a summary of scheduled future
payments under these lease arrangements, see "Contractual Cash Obligations and
Commitments."
UTILITY REGULATORY MATTERS
As a result of Pennsylvania's Natural Gas Choice and Competition Act ("Gas
Competition Act") signed into law on June 22, 1999, all natural gas consumers in
Pennsylvania have the 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 rate regulation by the PUC. LDCs serve as the supplier of last resort
for all residential and small commercial and industrial customers. As of
FINANCIAL REVIEW (continued)
September 30, 2003, less than five percent of Gas Utility's retail customers
purchase their gas from alternative suppliers.
On June 29, 2000, the PUC issued its order ("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 retail core-market
base rates effective October 1, 2000. This base rate increase was designed to
generate approximately $16.7 million in additional net annual revenues. In
accordance with the Gas Restructuring Order, Gas Utility reduced its retail
core-market PGC rates by an annualized amount of $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
retail core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
retail core-market customers. As a result, Gas Utility operating results are
more sensitive to the effects of heating-season weather and less sensitive to
the market prices of alternative fuels.
The PUC approved a settlement establishing rules for Electric Utility
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively, the "POLR
Settlement"). Under the terms of the POLR Settlement, Electric Utility
terminated stranded cost recovery from commercial and industrial ("C&I")
customers on July 31, 2002, and from residential customers on October 31, 2002,
and is no longer subject to the statutory generation rate caps as of August 1,
2002 for C&I customers and as of November 1, 2002 for residential customers.
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 (1) were
initially set at a level equal to the rates paid by Electric Utility customers
for POLR service under the statutory rate caps; (2) may be raised at certain
designated times by up to 5% of the total rate for distribution, transmission
and generation through December 2004; and (3) may be set at market rates
thereafter. Electric Utility may also offer multiple-year POLR contracts to its
customers. The POLR Settlement provides for annual shopping periods during which
customers may elect to remain on POLR service or choose an alternate supplier.
Customers who do not select an alternate supplier will be obligated to remain on
POLR service until the next shopping period. Residential customers who return to
POLR service at a time other than during the annual shopping period must remain
on POLR service until the date of the second open shopping period after
returning. C&I customers who return to POLR service at a time other than during
the annual shopping period must remain on POLR service until the next open
shopping period, and may, in certain circumstances, be subject to generation
rate surcharges. Consistent with the terms of the POLR Settlement, Electric
Utility's POLR rates for commercial and industrial customers will increase
beginning January 2004, and for residential customers beginning June 2004. Also,
Electric Utility has offered and entered into multiple-year POLR contracts with
certain of its customers. Additionally, pursuant to the requirements of the
Electricity Choice Act, the PUC is currently developing post-rate cap POLR
regulations that are expected to further define post-rate cap POLR service
obligations and pricing. As of September 30, 2003, less than 1% of Electric
Utility's customers have chosen an alternative electricity generation supplier.
We account for the operations of 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
allows us to defer expenses and revenues on the balance sheet as regulatory
assets and liabilities when it is probable that those expenses and income will
be allowed in the ratemaking process in a period different from the period in
which they would have been reflected in the income statement of an unregulated
company. These deferred assets and liabilities are then flowed through the
income statement in the period in which the same amounts are included in rates
and recovered from or refunded to customers. As required by SFAS 71, we monitor
our regulatory and competitive environments to determine whether the recovery of
our regulatory assets continues to be probable. If we were to determine that
recovery of these regulatory assets is no longer probable, such assets would be
written off against earnings.
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 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 three 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 owned or 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 (i) the
subsidiary's separate corporate form should be disregarded or (ii) UGI Utilities
should be considered to have
22
UGI Corporation 2003 Annual Report
been an operator because of its conduct with respect to its subsidiary's MGP.
With respect to a manufactured gas plant site in Manchester, New
Hampshire, EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI
Utilities seeking contribution from UGI Utilities for response and remediation
costs associated with the contamination on the site of a former MGP allegedly
operated by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth
agreed to a settlement of this matter in June 2003. UGI Utilities recorded its
estimated liability for contingent payments to EnergyNorth under the terms of
the settlement agreement which did not have a material effect on Fiscal 2003 net
income.
In April 2003, Citizens Communications Company ("Citizens") served a
complaint naming UGI Utilities as a third party defendant in a civil action
pending in United States District Court for the District of Maine. In that
action, the plaintiff, City of Bangor, Maine ("City") sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant
allegedly operated by Citizens' predecessors at a site on the Penobscot River.
Citizens subsequently joined UGI Utilities and ten other third party defendants
alleging that the third party defendants are responsible for an equitable share
of costs Citizens may be required to pay to the City for cleaning up tar
deposits in the Penobscot River. The City believes that it could cost as much as
$50 million to clean up the river. UGI Utilities believes that it has good
defenses to the claim.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served
UGI Utilities with a complaint filed in the United States District Court for the
Middle District of Florida in which AGL alleges that UGI Utilities is
responsible for 20% of approximately $8.0 million incurred by AGL in the
investigation and remediation of a former MGP site in St. Augustine, Florida.
UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner
and operator of the MGP. UGI Utilities believes that it has good defenses to the
claim and is defending the suit.
On September 20, 2001, Consolidated Edison Company of New York
("ConEd") filed suit against UGI Utilities in the United States District Court
for the Southern District of New York, seeking contribution from UGI Utilities
for an allocated share of response costs associated with investigating and
assessing gas plant related contamination at former MGP sites in Westchester
County, New York. The complaint alleges that UGI Utilities "owned and operated"
the MGPs prior to 1904. The complaint also seeks a declaration that UGI
Utilities is responsible for an allocated percentage of future investigative and
remedial costs at the sites. ConEd believes that the cost of remediation for all
of the sites could exceed $70 million. UGI Utilities believes that it has good
defenses to the claim and is defending the suit. In November 2003, the court
granted UGI Utilities' motion for summary judgement in part, dismissing all
claims premised on a disregard of the separate corporate form of UGI Utilities'
former subsidiaries and dismissing claims premised on UGI Utilities' operation
of three of the MGPs under operating leases with ConEd's predecessors. The court
reserved decision on the remaining theory of liability, that UGI Utilities was a
direct operator of the remaining MGPs.
MARKET RISK DISCLOSURES
Our primary market risk exposures include (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.
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 costs of natural gas it sells to its
customers. The recovery clauses provide for a periodic adjustment for the
difference between the total amounts actually collected from customers through
PGC rates and the recoverable costs incurred. Because of this ratemaking
mechanism, there is limited commodity price risk associated with our Gas Utility
operations. Gas Utility uses exchange-traded natural gas call option contracts
to reduce volatility in the cost of gas it purchases for its retail core-market
customers. The cost of these call option contracts, net of associated gains, is
included in Gas Utility's PGC recovery mechanism.
Prior to September 2002, Electric Utility purchased its electric power
needs from UGID and under third-party power supply arrangements of various
lengths and on the spot market. Beginning September 2002, Electric Utility began
purchasing its power needs exclusively from third-party electricity suppliers
under fixed-price energy and capacity contracts and, to a much lesser extent, on
the spot market, and UGID began selling electric power produced from its
interests in electricity generating facilities to third parties on the spot
market. Prices for electricity can be volatile especially during periods of high
demand or tight supply. Although the generation component of Electric Utility's
rates is subject to various rate cap provisions as a result of the POLR
Settlement, Electric Utility's fixed-price contracts
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FINANCIAL REVIEW (continued)
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.
UGID has entered into fixed-price sales agreements for a portion of the
electricity expected to be generated by its interests in electricity generating
assets. In the unlikely event that these generation assets would not be able to
produce all of the electricity needed to supply electricity under these
agreements, UGID would be required to purchase such electricity on the spot
market or under contract with other electricity suppliers. Accordingly,
increases in the cost of replacement power could negatively impact the Company's
results.
In order to manage market price risk relating to substantially all of
Energy Services' forecasted fixed-price sales of natural gas, Energy Services
purchases exchange-traded natural gas futures contracts or enters 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.
Our variable-rate debt includes borrowings under AmeriGas OLP's 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, 2003 and 2002, combined borrowings outstanding under these agreements
totaled $119.7 million and $131.0 million, respectively. Based upon
weighted-average borrowings outstanding under these agreements during Fiscal
2003 and Fiscal 2002, an increase in short-term interest rates of 100 basis
points (1%) would have increased our interest expense by $1.8 million and $1.4
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 $57.1 million and $52.5
million at September 30, 2003 and 2002, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $61.7 million and $56.4 million at September 30, 2003 and
2002, 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 their U.S. dollar
denominated assets and liabilities would not be material because FLAGA's U.S.
dollar denominated financial instrument assets and liabilities are not
materially different in amount. With respect to our net investments in FLAGA and
Antargaz, a 10% decline in the value of the euro versus the U.S. dollar would
reduce their aggregate net book value by approximately $5.7 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, 2003 and 2002. 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 50 basis points.
Change in
Fair Value Fair Value
------------ ----------
(Millions of dollars)
September 30, 2003:
Propane commodity price risk $(0.6) $(24.3)
Natural gas commodity price risk (1.0) (9.2)
Interest rate risk 0.2 (2.4)
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)
----- ------
Gas Utility's exchange traded natural gas call option contracts are
excluded from the table above because any associated net gains or losses are
included in Gas Utility's PGC recovery mechanism. 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.
24
UGI Corporation 2003 Annual Report
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with generally accepted accounting principles requires the selection and
application of appropriate accounting principles to the relevant facts and
circumstances of the Company's operations and the use of estimates made by
management. The Company has identified the following critical accounting
policies that are most important to the portrayal of the Company's financial
condition and results of operations. Changes in these policies could have a
material effect on the financial statements. The application of these accounting
policies necessarily requires management's most subjective or complex judgments
regarding estimates and projected outcomes of future events which could have a
material impact on the financial statements. Management has reviewed these
critical accounting policies, and the estimates and assumptions associated with
them, with its Audit Committee. In addition, management has reviewed the
following disclosures regarding the application of these critical accounting
policies with the Audit Committee.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved
in litigation regarding pending claims and legal actions that arise in the
normal course of our businesses. In addition, 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 of America, 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 PUC. In accordance with SFAS No. 71, 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 public statements issued by the PUC, and the status of any
pending deregulation legislation. If future recovery of regulatory assets ceases
to be probable, the elimination of those regulatory assets would adversely
impact our results of operations. As of September 30, 2003, our regulatory
assets totaled $60.3 million.
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
our other property, plant and equipment on a straight-line basis over estimated
useful lives generally ranging from 2 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.
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, 2003, our goodwill totaled $671.5 million.
DEFINED BENEFIT PENSION PLAN. The costs of providing benefits under our Pension
Plan are dependent on historical information such as employee age, length of
service, level of compensation and the actual rate of return on plan assets. In
addition, certain assumptions relating to the future are utilized including, the
discount rate applied to benefit obligations, the expected rate of return on
plan assets and the rate of compensation increase. Pension Plan assets are held
in trust and consist principally of equity and fixed income mutual funds and a
commingled bond fund. Changes in plan assumptions as well as fluctuations in
actual equity or bond market returns could have a material impact on future
pension costs.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure" ("SFAS 148"). SFAS 148 provides
alternative methods of transition for an entity that voluntarily changes to a
fair value based method of accounting for stock-based employee compensation. In
addition, SFAS 148 amends SFAS No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), to require more prominent disclosure about the
effects on reported net income of stock-based employee compensation. As
permitted by SFAS 148 and SFAS 123, the Company expects to continue to account
for stock-based compensation in accordance with Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," and will continue to
provide the prominent disclosures required in its annual and interim financial
statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging
25
FINANCIAL REVIEW(continued)
Activities" ("SFAS 149"). SFAS 149 is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. SFAS 149 (1) clarifies under what circumstances a contract with an
initial net investment meets the characteristic of a derivative, (2) clarifies
when a derivative contains a financing component, (3) amends the definition of
an underlying- rate, price or index to conform it to language used in FASB
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others," and (4)
amends certain other existing pronouncements. SFAS 149 did not change the
methods the Company uses to account for and report its derivatives and hedging
activities.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity"
("SFAS 150"). SFAS 150 is effective at the beginning of the first interim period
beginning after June 15, 2003. SFAS 150 establishes guidelines on how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. SFAS 150 further defines and requires that certain
instruments within its scope be classified as liabilities on the financial
statements. The adoption of SFAS 150 resulted in the Company presenting UGI
Utilities preferred shares subject to mandatory redemption in the liabilities
section of the balance sheet, and reflecting dividends paid on these shares as a
component of interest expense, for all periods presented after June 30, 2003.
Because SFAS 150 specifically prohibits the restatement of financial statements
prior to its adoption, prior period amounts have not been reclassified.
In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities" ("FIN 46"), which clarifies
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46
is effective immediately for variable interest entities created or obtained
after January 31, 2003. For variable interests created or acquired before
February 1, 2003, FIN 46 is effective for the first fiscal or interim period
beginning after December 15, 2003. If certain conditions are met, FIN 46
requires the primary beneficiary to consolidate certain variable interest
entities in which the other equity investors lack the essential characteristics
of a controlling financial interest or their investment at risk is not
sufficient to permit the variable interest entity to finance its activities
without additional subordinated financial support from other parties. The
Company has not created or obtained any variable interest entities after January
31, 2003, and is currently in the process of evaluating the impact of FIN 46,
which is not expected to have a material effect on its financial position or
results of operations.
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 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 them to our 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 except as required by federal securities laws.
26