EXHIBIT 13
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. UGID's electricity generation assets along with Electric
Utility are collectively referred to herein as "Electric Operations." 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 Operations 13.9 0.32 6.1 0.14 7.8 0.18
Energy Services 7.9 0.18 6.5 0.15 1.4 0.03
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 OPERATIONS:
Revenues $ 108.1 $ 86.0 $ 22.1 25.7%
Total margin (a) $ 47.4 $ 32.8 $ 14.6 44.5%
Operating income $ 25.9 $ 13.2 $ 12.7 96.2%
Income before income taxes $ 23.6 $ 10.8 $ 12.8 118.5%
Distribution sales - millions of
kilowatt hours ("gwh") 980.0 933.6 46.4 5.0%
Third-party generation sales - gwh 471.8 24.0 447.8 N.M
ENERGY SERVICES:
Revenues $ 648.7 $ 332.3 $ 316.4 95.2%
Total margin (a) $ 28.5 $ 21.4 $ 7.1 33.2%
Income before income taxes $ 13.6 $ 11.1 $ 2.5 22.5%
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)%
---------- ---------- ---------- ------
N.M. - Not meaningful
(a) Total margin represents total revenues less total cost of sales and, with
respect to Electric Operations, 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 OPERATIONS. 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 Operations' revenues reflect greater sales of
electricity produced by UGID's electric generation assets to third parties and
the previously mentioned increase in Electric Utility kilowatt-hour distribution
sales. 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, 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. 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"). Notwithstanding the significant increase
in Electric Operations' revenues, cost of sales increased only $7.3 million in
Fiscal 2003 due in part to lower Electric Utility per-unit purchased power
costs.
The increase in Electric Operations' total margin principally reflects
lower Electric Utility per-unit purchased power costs, the increase in Electric
Utility sales, and margin from the greater sales of electricity produced by
UGID's electricity generation assets to third parties. The higher Fiscal 2003
operating income reflects the greater total margin and a $0.5 million increase
in other income partially offset by higher operating and administrative expenses
resulting principally from the additional investment in Conemaugh and, to a
lesser extent, higher Electric Utility transmission and distribution expenses.
The increase in Electric Operations 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"). The
greater Energy Services' Fiscal 2003 total margin reflects the increase in
natural gas volumes sold partially offset by slightly lower average unit
margins. The increase in total margin was partially offset by higher operating
expenses resulting principally from the TXU Energy Acquisition and growth
initiatives.
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
15
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 Operations 6.1 0.14 4.7 0.11 1.4 0.03
Energy Services 6.5 0.15 4.0 0.10 2.5 0.05
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 OPERATIONS:
Revenues $ 86.0 $ 83.9 $ 2.1 2.5%
Total margin (b) $ 32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 13.2 $ 10.7 $ 2.5 23.4%
Income before income taxes $ 10.8 $ 8.0 $ 2.8 35.0%
Distribution sales - gwh 933.6 945.5 (11.9) (1.3)%
Third-party generation sales - gwh 24.0 - 24.0 N.M.
ENERGY SERVICES:
Revenues $ 332.3 $ 370.7 $ (38.4) (10.4)%
Total margin $ 21.4 $ 13.4 $ 8.0 59.7%
Operating income $ 11.1 $ 7.3 $ 3.8 52.1%
Income before income taxes $ 11.1 $ 6.9 $ 4.2 60.9%
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 Operations 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-
16
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 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 UGID's 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 in
cost of sales resulting from the December 2000 transfer of our Hunlock Creek
electricity generation assets to our electricity generation joint venture,
Energy Ventures. Subsequent to the formation of Energy Ventures, our electricity
generating business purchases its share of the power produced by Energy Ventures
rather than producing this electricity itself. As a result, the purchased cost
of this power is reflected in cost of sales whereas prior to the formation of
Energy Ventures electricity generation costs were reflected in 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 warmer
winter weather-driven decline in sales. Operating income increased $2.5 million
reflecting the
17
FINANCIAL REVIEW (continued)
greater total margin and lower operating and administrative costs subsequent to
the formation of Energy Ventures partially offset by a decline in other income.
The increase in Electric Operations income before income taxes reflects the
increase in operating income and lower interest expense.
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. 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 Operations 4.9 4.1 4.9 5.0
Energy Services 1.3 1.0 0.9 0.2
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
21
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
23
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
UGI Corporation 2003 Annual Report
REPORT OF MANAGEMENT
The Company's consolidated financial statements and other financial information
contained in this Annual Report are prepared by management, which is responsible
for their fairness, integrity and objectivity. The consolidated financial
statements and related information were prepared in accordance with accounting
principles generally accepted in the United States 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 appoints 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, whose appointment is 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
/s/ Michael J. Cuzzolina
- ---------------------------
Michael J. Cuzzolina
Chief Accounting Officer
27
REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of UGI
Corporation and its subsidiaries at September 30, 2003 and 2002, and the results
of their operations and their cash flows for each of the two years in the period
ended September 30, 2003 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 audits. We conducted our
audits 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 audits provide a reasonable basis for our opinion. The
consolidated financial statements of UGI Corporation and its subsidiaries for
the year ended September 30, 2001, prior to the revisions discussed in Note 1,
were audited by other independent auditors who have ceased operations. Those
independent auditors 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.
As discussed above, the consolidated financial statements of UGI
Corporation and its subsidiaries for the year ended September 30, 2001, were
audited by other independent auditors who have ceased operations. As described
in Note 1, these financial statements have been restated to reflect a 3-for-2
common stock split. We audited the adjustments described in Note 1 that were
applied to restate the 2001 consolidated financial statements for the 3-for-2
common stock split. In our opinion, such adjustments are appropriate and have
been properly applied. As described in Note 1, these financial statements have
also been revised to include the transitional disclosures required by Statement
of Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets" which was adopted by the Company as of October 1, 2001. We audited the
transitional disclosures described in Note 1. In our opinion, the transitional
disclosures for 2001 in Note 1 are appropriate. However, we were not engaged to
audit, review or apply procedures to the 2001 consolidated financial statements
of the Company other than with respect to such adjustments and, accordingly, we
do not express an opinion or any other form of assurance on the 2001
consolidated financial statements taken as a whole.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 17, 2003
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 state-
ment 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.
ARTHUR ANDERSEN LLP
Philadelphia, Pennsylvania
November 16, 2001
28
UGI Corporation 2003 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30,
------------------------------------------------
2003 2002 2001
--------- -------- --------
REVENUES
AmeriGas Propane $ 1,628.4 $1,307.9 $1,418.4
Utilities 628.7 488.0 582.7
International Propane 54.5 46.7 50.9
Energy Services and other 714.5 371.1 416.1
--------- -------- --------
3,026.1 2,213.7 2,468.1
--------- -------- --------
COSTS AND EXPENSES
Cost of sales 1,984.3 1,296.6 1,632.4
Operating and administrative expenses 643.3 576.5 506.8
Utility taxes other than income taxes 13.0 11.9 9.2
Depreciation and amortization 103.0 93.5 105.2
Provision for shut-down costs - Hearth USA(TM) - - 8.5
Other income, net (19.8) (18.1) (23.0)
--------- -------- --------
2,723.8 1,960.4 2,239.1
--------- -------- --------
OPERATING INCOME 302.3 253.3 229.0
Income (loss) from equity investees 5.3 8.5 (1.6)
Loss on extinguishments of debt (3.0) (0.7) -
Interest expense (109.2) (109.1) (104.8)
Minority interests in AmeriGas Partners (34.6) (28.0) (23.6)
--------- -------- --------
INCOME BEFORE INCOME TAXES, SUBSIDIARY PREFERRED STOCK DIVIDENDS
AND ACCOUNTING CHANGES 160.8 124.0 99.0
Income taxes (60.7) (46.9) (45.4)
Dividends on UGI Utilities preferred shares subject to
mandatory redemption (1.2) (1.6) (1.6)
--------- -------- --------
Income before accounting changes 98.9 75.5 52.0
Cumulative effect of accounting changes, net - - 4.5
--------- -------- --------
NET INCOME $ 98.9 $ 75.5 $ 56.5
========= ======== ========
EARNINGS PER COMMON SHARE
Basic:
Income before accounting changes $ 2.34 $ 1.83 $ 1.28
Cumulative effect of accounting changes, net - - 0.11
--------- -------- --------
Net income $ 2.34 $ 1.83 $ 1.39
========= ======== ========
Diluted:
Income before accounting changes $ 2.29 $ 1.80 $ 1.27
Cumulative effect of accounting changes, net - - 0.11
--------- -------- --------
Net income $ 2.29 $ 1.80 $ 1.38
========= ======== ========
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS):
Basic 42.220 41.325 40.745
========= ======== ========
Diluted 43.236 41.907 41.060
========= ======== ========
See accompanying notes to consolidated financial statements.
29
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30,
----------------------------
ASSETS 2003 2002
------ -------- --------
CURRENT ASSETS
Cash and cash equivalents $ 142.1 $ 194.3
Short-term investments (at cost, which approximates fair value) 50.0 -
Accounts receivable (less allowances for doubtful accounts
of $14.8 and $11.8, respectively) 199.2 157.7
Accrued utility revenues 7.4 8.1
Inventories 136.6 109.2
Deferred income taxes 23.5 10.4
Income taxes recoverable - 1.7
Utility regulatory assets - 4.3
Prepaid expenses and other current assets 28.6 37.9
-------- --------
Total current assets 587.4 523.6
-------- --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 1,076.2 1,028.6
UGI Utilities 907.9 883.3
Other 157.9 80.5
-------- --------
2,142.0 1,992.4
Accumulated depreciation and amortization (805.2) (720.5)
-------- --------
Net property, plant, and equipment 1,336.8 1,271.9
-------- --------
OTHER ASSETS
Goodwill and excess reorganization value 671.5 644.9
Intangible assets (less accumulated amortization
of $16.4 and $10.3, respectively) 34.7 25.8
Utility regulatory assets 60.3 57.7
Other assets 91.0 90.5
-------- --------
Total assets $2,781.7 $2,614.4
======== ========
See accompanying notes to consolidated financial statements.
30
UGI Corporation 2003 Annual Report
September 30,
----------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2003 2002
------------------------------------ -------- --------
CURRENT LIABILITIES
Current maturities of long-term debt $ 65.0 $ 148.7
AmeriGas Propane bank loans - 10.0
UGI Utilities bank loans 40.7 37.2
Other bank loans 15.9 8.6
Accounts payable 202.5 166.1
Employee compensation and benefits accrued 41.9 35.4
Dividends and interest accrued 40.1 41.5
Income taxes accrued 8.9 -
Deposits and advances 69.1 68.8
Other current liabilities 86.2 70.1
-------- --------
Total current liabilities 570.3 586.4
-------- --------
DEBT AND OTHER LIABILITIES
Long-term debt 1,158.5 1,127.0
Deferred income taxes 223.1 200.2
Deferred investment tax credits 8.0 8.4
UGI Utilities preferred shares subject to mandatory redemption, without par value 20.0 -
Other noncurrent liabilities 97.4 79.1
-------- --------
Total liabilities 2,077.3 2,001.1
-------- --------
Commitments and contingencies (note 12)
Minority interests in AmeriGas Partners 134.6 276.0
UGI Utilities preferred shares subject to mandatory redemption, without par value - 20.0
Preference Stock, without par value (authorized - 5,000,000 shares) - -
COMMON STOCKHOLDERS' EQUITY
Common Stock, without par value
(authorized - 150,000,000 shares; issued - 49,798,097 shares) 582.4 396.6
Retained earnings 90.9 39.7
Accumulated other comprehensive income 4.7 6.6
-------- --------
678.0 442.9
Treasury stock, at cost (108.2) (125.6)
-------- --------
Total common stockholders' equity 569.8 317.3
-------- --------
Total liabilities and stockholders' equity $2,781.7 $2,614.4
======== ========
31
UGI Corporation 2003 Annual Report
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30,
------------------------------------------------
2003 2002 2001
--------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 98.9 $ 75.5 $ 56.5
Reconcile to net cash provided by operating activities:
Depreciation and amortization 103.0 93.5 105.2
Cumulative effect of accounting changes, net - - (4.5)
Minority interests in AmeriGas Partners 34.6 28.0 23.6
Deferred income taxes, net (2.8) 11.0 (5.5)
Provision for uncollectible accounts 18.5 14.2 18.3
Net change in settled accumulated other comprehensive income (5.2) 13.3 (16.9)
Other, net 9.3 (1.8) 3.1
Net change in:
Accounts receivable and accrued utility revenues (55.7) 12.6 (13.6)
Inventories (25.3) 19.7 (4.2)
Deferred fuel costs 19.0 (7.1) 9.9
Accounts payable 34.9 (0.4) 5.8
Other current assets and liabilities 19.9 (11.0) 25.8
--------- -------- --------
Net cash provided by operating activities 249.1 247.5 203.5
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (100.9) (94.7) (78.0)
Acquisitions of businesses, net of cash acquired (38.6) (0.7) (209.1)
Acquisition of additional interest in Conemaugh Station (51.3) - -
Proceeds from redemption of AGZ Bonds - 17.7 -
Net proceeds from disposals of assets 5.9 9.7 4.2
Investments in equity investees (0.4) (0.3) (32.6)
Increase in short-term investments (50.0) - -
Other, net 9.2 1.9 2.2
--------- -------- --------
Net cash used by investing activities (226.1) (66.4) (313.3)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock (47.7) (44.8) (53.2)
Distributions on AmeriGas Partners publicly held Common Units (56.4) (53.5) (44.3)
Issuance of long-term debt 167.8 81.1 308.2
Repayment of long-term debt (236.5) (105.0) (137.0)
AmeriGas Propane bank loans (decrease) increase (10.0) 10.0 (30.0)
UGI Utilities bank loans increase (decrease) 3.5 (20.6) (42.6)
Other bank loans increase (decrease) 5.4 (2.2) 6.2
Issuance of AmeriGas Partners Common Units 75.0 49.7 39.8
Proceeds from sale of AmeriGas OLP interest - - 50.0
Issuance of UGI Common Stock 23.7 11.0 7.6
Repurchases of UGI Common Stock (0.1) - (1.0)
--------- -------- --------
Net cash (used) provided by financing activities (75.3) (74.3) 103.7
--------- -------- --------
EFFECT OF EXCHANGE RATE CHANGES ON CASH 0.1 - (0.3)
--------- -------- --------
Cash and cash equivalents (decrease) increase $ (52.2) $ 106.8 $ (6.4)
========= ======== ========
CASH AND CASH EQUIVALENTS:
End of year $ 142.1 $ 194.3 $ 87.5
Beginning of year 194.3 87.5 93.9
--------- -------- --------
(Decrease) increase $ (52.2) $ 106.8 $ (6.4)
========= ======== ========
See accompanying notes to consolidated financial statements.
32
UGI Corporation 2003 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, 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
($1.05 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
($1.083 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
Net income 98.9 98.9
Net gain on derivative instruments
(net of tax of $9.1) 13.5 13.5
Reclassification of net gains on
derivative instruments (net of tax of $14.0) (20.7) (20.7)
Foreign currency translation adjustments
(net of tax of $3.1) 5.3 5.3
------ ------- -------
Comprehensive income 98.9 (1.9) 97.0
Cash dividends on Common Stock
($1.13 per share) (47.7) (47.7)
Common Stock issued:
Employee and director plans 5.0 16.0 21.0
Dividend reinvestment plan 1.2 1.5 2.7
Gain in connection with issuances of units
by AmeriGas Partners 179.6 179.6
Common Stock reacquired (0.1) (0.1)
------ ------ ------- ----- ------- -------
BALANCE SEPTEMBER 30, 2003 $582.4 $ 90.9 $ 4.7 $ - $(108.2) $ 569.8
====== ====== ======= ===== ======= =======
See accompanying notes to consolidated financial Statements.
33
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, retail
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 natural gas and electric distribution utility businesses are
conducted through our wholly owned subsidiary UGI Utilities, Inc. ("UGI
Utilities"). UGI Utilities owns and operates a natural gas distribution utility
("Gas Utility") in parts of eastern and southeastern Pennsylvania and an
electricity distribution utility ("Electric Utility") in northeastern
Pennsylvania. Gas Utility and Electric Utility (collectively, "Utilities") are
subject to regulation by the Pennsylvania Public Utility Commission ("PUC").
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 OLP's subsidiary, 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, 2003, the General Partner and its wholly
owned subsidiary Petrolane Incorporated ("Petrolane") collectively held a 1%
general partner interest and a 46.4% limited partner interest in AmeriGas
Partners, and effective 47.9% and 47.8% ownership interests in AmeriGas OLP and
Eagle OLP, respectively. Our limited partnership interest in AmeriGas Partners
comprised 24,525,004 Common Units. The remaining 52.6% interest in AmeriGas
Partners comprises 27,808,204 publicly held Common Units representing limited
partner interests.
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 resulting from
nondeductible goodwill amortization.
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 subsidiaries and joint-venture affiliate Hunlock
Creek Energy Ventures ("Energy Ventures"), own and operate interests in
Pennsylvania-based electricity generation assets. Prior to their transfer to
Energy Services in June 2003, UGID and its subsidiaries were wholly owned
subsidiaries 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
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 PUC.
CONSOLIDATION PRINCIPLES. The consolidated financial statements include the
accounts of UGI and its controlled subsidiary companies, which, except for the
Partnership, are majority owned. 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. In order to more appropriately classify direct costs
associated with the Partnership's Prefilled Propane Xchange ("PPX(R)") program,
for the year ended September 30, 2003, certain costs previously considered
operating and administrative expenses have been included in cost of sales. We
have reclassified $21.0 and $11.0 of such costs incurred during the years ended
September 30, 2002 and 2001, respectively, to conform to the current-year
presentation.
In January 2003, the Partnership recorded a loss of $3.0 resulting from
an early extinguishment of long-term debt. This loss has been reflected in the
2003 Consolidated Statement of Income as "loss on extinguishments of debt." A
loss of $0.7 associated with a November 2001 early extinguishment of Partnership
long-term debt previously included in other income, net, in the 2002
Consolidated Statement of Income has been reclassified to conform to the
current-year presentation (see Note 4).
We have reclassified certain other prior-year balances to conform to
the current-year 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
34
UGI Corporation 2003 Annual Report
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. 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 requires us to record the effects of rate regulation in the
financial statements. Certain expenses and credits subject to utility regulation
and normally reflected in income as incurred are deferred on the balance sheet
and recognized in income as the related 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.
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 ("Gas Competition Act").
Based upon the provisions of the Gas Restructuring Order and the Gas Competition
Act, we believe Gas Utility's regulatory assets continue to satisfy the criteria
of SFAS 71. For further information on the impact of the Gas Competition Act and
Pennsylvania's Electricity Customer Choice and Competition Act ("Electricity
Choice Act"), see Note 3.
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.
The adoption of SFAS 133 on October 1, 2000 resulted in an after-tax
cumulative effect charge to 2001 net income of $0.3 and an after-tax cumulative
effect increase to accumulated other comprehensive income of $7.1. The after-tax
cumulative effect 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.
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 13.
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 $109.8 in 2003, $106.2 in 2002 and $103.9 in
2001. We paid income taxes totaling $48.2 in 2003, $48.0 in 2002 and $43.0 in
2001.
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.
INVENTORIES. Our inventories are stated at the lower of cost or market. We
determine cost using an average cost method for natural gas and propane,
specific identification for appliances and the first-in, first-out ("FIFO")
method for all other inventories.
EARNINGS PER COMMON SHARE. 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, 2003. Average shares outstanding, earnings per share
and dividends declared per share for all years presented are reflected on a
post-split basis.
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 2003, 2002 and
2001:
2003 2002 2001
------ ------ ------
Denominator (millions of shares):
Average common shares
outstanding for basic computation 42.220 41.325 40.745
Incremental shares issuable for stock
options and awards 1.016 0.582 0.315
------ ------ ------
Average common shares outstanding for
diluted computation 43.236 41.907 41.060
------ ------ ------
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.
35
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 Gas Utility and Electric Utility retire
depreciable utility plant and equipment, we charge the original cost, net of
removal costs and salvage value, to accumulated depreciation for financial
accounting purposes. When our unregulated businesses retire or otherwise dispose
of plant and equipment, we remove the cost and accumulated depreciation from the
appropriate accounts and any resulting gain or loss is recognized in "other
income, net" in the Consolidated Statements of Income. 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 2.3% in 2003, 2.5% in 2002 and 2.6% in
2001. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 3.0% in each of 2003 and 2002 and 3.3% in 2001.
The declines in the Gas Utility and Electric Utility percentages for 2003 and
2002 are the result of changes, effective April 1, 2002, in the estimated
remaining useful lives of Gas Utility's and Electric Utility's distribution
assets. 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. We compute depreciation
expense on plant and equipment associated with our electricity generation assets
on a straight-line basis over 25 years. Depreciation expense was $97.1 in 2003,
$88.2 in 2002 and $75.7 in 2001.
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 15.
INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2003 2002
------ ------
Subject to amortization:
Customer relationships, noncompete
agreements and other (a) $ 51.1 $ 36.1
Accumulated amortization (16.4) (10.3)
------ ------
$ 34.7 $ 25.8
------ ------
Not subject to amortization:
Goodwill (a) $578.2 $551.6
Excess reorganization value 93.3 93.3
------ ------
$671.5 $644.9
------ ------
(a) The increase in the carrying amount of intangible assets during the year
ended September 30, 2003 is principally the result of business acquisitions and,
with respect to goodwill, foreign currency translation effects.
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 on a straight-line basis 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 $6.1 in 2003 and $4.6 in 2002 including
amortization expense associated with customer contracts recorded in cost of
sales. Amortization expense of intangible assets in 2001, which includes
amortization of goodwill and excess reorganization value prior to the adoption
of SFAS 142, was $27.7. Estimated amortization expense of intangible assets
during the next five fiscal years is as follows: Fiscal 2004 - $5.4; Fiscal 2005
- - $4.6; Fiscal 2006 - $4.1; Fiscal 2007 - $3.5; Fiscal 2008 - $3.1.
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.
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,
2003 2002 2001
------ ------ ------
NET INCOME:
Reported income before accounting changes $ 98.9 $ 75.5 $ 52.0
Add back goodwill and excess
reorganization value amortization - - 25.2
Adjust minority interests in AmeriGas Partners - - (10.5)
Adjust income tax expense - - (0.7)
------ ------ ------
Adjusted income before accounting changes 98.9 75.5 66.0
Cumulative effect of accounting changes - - 4.5
------ ------ ------
Adjusted net income $ 98.9 $ 75.5 $ 70.5
------ ------ ------
DILUTED EARNINGS PER SHARE:
Reported income before accounting changes $ 2.29 $ 1.80 $ 1.27
Add back goodwill and excess
reorganization value amortization - - 0.61
Adjust minority interests in AmeriGas Partners - - (0.25)
Adjust income tax expense - - (0.02)
------ ------ ------
Adjusted income per share before accounting
changes 2.29 1.80 1.61
Cumulative effect of accounting changes - - 0.11
------ ------ ------
Adjusted net income per share $ 2.29 $ 1.80 $ 1.72
------ ------ ------
36
UGI Corporation 2003 Annual Report
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 provisions for goodwill impairments were recorded during 2003 or
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.
We use the intrinsic value method prescribed by APB 25 for our
stock-based employee compensation plans. We recognized total stock and
unit-based compensation expense of $10.4, $5.7 and $2.7 in 2003, 2002 and 2001,
respectively. If we had determined stock-based compensation expense under the
fair value method prescribed by SFAS 123, net income and basic and diluted
earnings per share for 2003, 2002 and 2001 would have been as follows:
Year Ended September 30,
2003 2002 2001
------ ------ ------
Net income, as reported $ 98.9 $ 75.5 $ 56.5
Add: Stock and unit-based employee
compensation expense included in
reported net income, net of related
tax effects 6.8 3.7 1.8
Deduct: Total stock and unit-based
employee compensation expense
determined under the fair value method
for all awards, net of related tax effects (7.6) (4.7) (2.6)
------ ------ ------
Pro forma net income $ 98.1 $ 74.5 $ 55.7
------ ------ ------
Basic earnings per share:
As reported $ 2.34 $ 1.83 $ 1.39
Pro forma $ 2.32 $ 1.80 $ 1.37
Diluted earnings per share:
As reported $ 2.29 $ 1.80 $ 1.38
Pro forma $ 2.27 $ 1.78 $ 1.36
------ ------ ------
For a description of our stock-based compensation plans and related disclosures,
see Note 9.
DEFERRED DEBT ISSUANCE COSTS. Included in other assets are net deferred debt
issuance costs of $15.5 at September 30, 2003 and $14.8 at September 30, 2002.
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.
UGI UTILITIES PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION. Beginning July
1, 2003, the Company accounts for UGI Utilities preferred shares subject to
mandatory redemption in accordance with SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity"
("SFAS 150"). SFAS 150 establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The adoption of SFAS 150 results 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 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.
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. In those instances for which the amount and timing of cash payments
associated with environmental investigation and cleanup are reliably
determinable, we discount such liabilities to reflect the time value of money.
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. At
September 30, 2003, the Company's liability for environmental investigation and
cleanup costs was not material.
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.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 1 continued
COMPREHENSIVE INCOME. Comprehensive income comprises net income and other
comprehensive (loss) income. Other comprehensive (loss) income 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 at September 30, 2002 and 2003 follows:
Derivative Foreign
Instruments Currency
Gains Translation
(Losses) Adjustments Total
-------- ----------- -----
Balance - September 30, 2002 $ 3.1 $3.5 $ 6.6
Balance - September 30, 2003 $(4.1) $8.8 $ 4.7
----- ---- -----
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In December 2002, the Financial
Accounting Standards Board ("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 APB 25, 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 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 is not expected to materially change the methods the
Company uses to account for and report its derivatives and hedging activities.
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.
NOTE 2 - ACQUISITIONS AND INVESTMENTS
In June 2003, pursuant to an asset purchase agreement between and among
Allegheny Energy Supply Company, LLC, Allegheny Energy Supply Conemaugh, LLC
("Allegheny Conemaugh"), UGID, and UGI, UGID acquired an additional 83 megawatt
ownership interest in the Conemaugh electricity generation station ("Conemaugh")
from Allegheny Conemaugh, a unit of Allegheny Energy, Inc. ("Allegheny"), for
$51.3 in cash, subject to a $3.0 credit. Conemaugh is a 1,711-megawatt,
coal-fired electricity generation station located near Johnstown, Pennsylvania
and is owned by a consortium of energy companies and operated by a unit of
Reliant Resources, Inc. under contract. The purchase increased UGID's ownership
interest in Conemaugh to 102 megawatts (6.0%) from 19 megawatts (1.1%)
previously. Substantially all of the purchase price for the additional interest
in Conemaugh is included in property, plant and equipment in the Consolidated
Balance Sheet.
In March 2003, Energy Services acquired the northeastern U.S. gas
marketing business of TXU Energy Retail Company, L.P., a subsidiary of TXU Corp.
(the "TXU Energy Acquisition") for approximately $10.0 in cash. As a result of
the TXU Energy Acquisition, Energy Services assumed the existing sales and
supply agreements for approximately one thousand commercial and industrial
customers located primarily in New York, Pennsylvania, Ohio and New Jersey.
During 2003, AmeriGas OLP acquired several retail propane distribution
businesses and HVAC acquired a heating, ventilation and air conditioning
business for total cash consideration of $28.6. In conjunction with these
acquisitions, liabilities of $1.5 were incurred. The operating results of these
businesses have been included in our results of operations from their respective
dates of acquisition.
The total purchase price of the TXU Energy Acquisition and the AmeriGas
OLP and HVAC acquisitions has been allocated to the assets and liabilities
acquired as follows:
Net current assets $ 2.5
Property, plant and equipment 6.4
Customer relationships and noncompete agreements
(estimated useful life of 10 and 5 years, respectively) 17.8
Goodwill (tax deductible) 13.5
Other assets and liabilities (0.1)
-----
Total $40.1
-----
The pro forma effect of these acquisitions was not material to our
results of operations.
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")
38
UGI Corporation 2003 Annual Report
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 in cash. In addition, AmeriGas OLP agreed to pay CEG for the amount of
working capital, as defined, in excess of $23. 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. The Columbia Purchase Agreement also provided
for the purchase by CEG of limited partnership interests in AmeriGas OLP valued
at $50 for $50 in cash, which interests were exchanged for 2,356,953 Common
Units of AmeriGas Partners having an estimated fair value of $54.4. Concurrently
with the acquisition, AmeriGas Partners issued $200 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 of
the Columbia Propane Businesses:
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
------
The purchase price of the Columbia Propane Businesses was 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 as if the acquisition of the Columbia Propane
Businesses had occurred as of the beginning of that year:
2001
--------
Revenues $2,838.3
Income before accounting changes 50.8
Net income 55.3
Diluted earnings per share:
Income before accounting changes 1.24
Net income 1.35
--------
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 year presented or of
future operating results under our management.
During 2001, in addition to the acquisitions of the Columbia Propane
Businesses, Energy Services acquired two energy marketing businesses and the
Partnership acquired several small propane distribution businesses for total
cash consideration of $5.4. The operating results of these businesses have been
included in the consolidated results from their respective dates of acquisition.
These transactions did not have a material effect on our results of operations.
On October 1, 2003, AmeriGas OLP acquired substantially all of the
retail propane distribution assets and business of Horizon Propane LLC ("Horizon
Propane") for total cash consideration of $31.0. In addition, AmeriGas OLP
agreed to pay Horizon for the amount of working capital, as defined in the Asset
Purchase Agreement, in excess of $2.6. During its 2003 fiscal year, Horizon
Propane sold over 30 million gallons of propane from ninety locations in twelve
states.
NOTE 3 - UTILITY REGULATORY MATTERS
GAS UTILITY
GAS RESTRUCTURING ORDER. 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. The purpose of the Gas Competition Act, which was
signed into law on June 22, 1999, 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 customers.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 3 continued
Among other things, the implementation of the Gas Restructuring Order
resulted in an increase in Gas Utility's firm-residential, commercial and
industrial ("retail core-market") base rates effective October 1, 2000. This
base rate increase was designed to generate approximately $16.7 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 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.
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 in stranded costs 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. 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.
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 generation rate caps as of August 1, 2002 for C&I
customers and as of November 1, 2002 for residential customers. 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.
FORMATION OF HUNLOCK CREEK ENERGY VENTURES. On December 8, 2000, UGID
contributed its coal-fired Hunlock Creek generating station ("Hunlock") and
certain related assets having a net book value of approximately $4.2, and $6 in
cash, to 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 Energy Ventures 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 2003, 2002 and 2001 were $9.9, $9.8 and $8.0,
respectively.
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
2003 2002
------ -----
Regulatory assets:
Income taxes recoverable $ 57.6 $54.7
Other postretirement benefits 2.2 2.4
Deferred fuel costs - 4.3
Other 0.5 0.6
------ -----
Total regulatory assets $ 60.3 $62.0
------ -----
Regulatory liabilities:
Other postretirement benefits $ 3.8 $ 4.3
Deferred fuel costs 14.7 -
------ -----
Total regulatory liabilities $ 18.5 $ 4.3
------ -----
Utilities' regulatory liabilities relating to other postretirement
benefits and deferred fuel costs are included in "other noncurrent liabilities"
and "other current liabilities," respectively, on the Consolidated Balance
Sheets. Utilities does not recover a rate of return on its regulatory assets.
40
UGI Corporation 2003 Annual Report
NOTE 4 - DEBT
Long-term debt comprises the following at September 30:
2003 2002
-------- --------
AMERIGAS PROPANE:
AmeriGas Partners Senior Notes:
8.875%, due May 2011 (including unamortized
premium of $6.4 and $1.6, respectively,
effective rate - 8.56%) $ 366.4 $ 241.6
10%, due April 2006 (less unamortized discount
of $0.2, effective rate - 10.125%) 59.8 59.8
10.125%, due April 2007 - 85.0
AmeriGas OLP First Mortgage Notes:
Series A, 9.34% - 11.71%, due April 2002 through
April 2009 (including unamortized premium of
$6.6 and $7.9, respectively, effective rate - 8.91%) 166.6 167.9
Series B, 10.07%, due April 2002 through April 2005
(including unamortized premium of $1.1 and $2.3,
respectively, effective rate - 8.74%) 81.1 122.3
Series C, 8.83%, due April 2003 through April 2010 96.3 110.0
Series D, 7.11%, due March 2009 (including
unamortized premium of $1.9 and $2.2,
respectively, effective rate - 6.52%) 71.9 72.2
Series E, 8.50%, due July 2010 (including
unamortized premium of $0.1, effective
rate - 8.47%) 80.1 80.1
Other 5.1 6.9
-------- --------
Total AmeriGas Propane 927.3 945.8
-------- --------
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
6.62% Notes, due May 2005 20.0 20.0
7.14% Notes, due December 2005 (including
unamortized premium of $0.3 and $0.4,
respectively, effective rate - 6.64%) 30.3 30.4
7.14% Notes, due December 2005 20.0 20.0
5.53% Notes, due September 2012 40.0 40.0
5.37% Notes, due August 2013 25.0 -
6.50% Notes, due August 2033 20.0 -
6.50% Senior Notes, due August 2003 - 50.0
-------- --------
Total UGI Utilities 217.3 248.4
-------- --------
OTHER:
FLAGA Acquisition Note, due through
September 2006 68.9 64.3
FLAGA euro special purpose facility 4.2 10.8
Other 5.8 6.4
-------- --------
Total long-term debt 1,223.5 1,275.7
Less current maturities (including net unamortized
premiums of $3.1 and $2.9, respectively) (65.0) (148.7)
-------- --------
Total long-term debt due after one year $1,158.5 $1,127.0
-------- --------
Scheduled principal repayments of long-term debt due in fiscal years 2004 to
2008 follows:
2004 2005 2006 2007 2008
----- ----- ------ ----- -----
AmeriGas Propane $55.6 $55.5 $114.4 $54.1 $54.1
UGI Utilities - 20.0 50.0 20.0 -
Other 6.3 11.9 56.1 1.5 3.1
----- ----- ------ ----- -----
Total $61.9 $87.4 $220.5 $75.6 $57.2
----- ----- ------ ----- -----
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. AmeriGas Partners prepaid $15 of its 10.125% Senior Notes in November
2001 at a redemption price of 103.375% and the remaining $85 of its 10.125%
Senior Notes in January 2003 at a redemption price of 102.25%, in each instance,
including accrued interest. AmeriGas Partners recognized losses of $3.0 and $0.7
associated with these prepayments which amounts are reflected in "Loss on
extinguishments of debt" in the 2003 and 2002 Consolidated Statements of Income,
respectively. AmeriGas Partners may, under certain circumstances following the
disposition of assets or a change of control, be required to offer to prepay its
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 CREDIT AGREEMENT. AmeriGas OLP's Credit Agreement ("Credit
Agreement") consists of (1) a Revolving Credit Facility and (2) an Acquisition
Facility. AmeriGas OLP's obligations under the Credit Agreement are
collateralized by substantially all of its assets. The General Partner and
Petrolane are guarantors of amounts outstanding under the Credit Agreement.
Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $100
(including a $100 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 on October 15,
2006, but may be extended for additional one-year periods with the consent of
the participating banks representing at least 80% of the commitments thereunder.
There were no borrowings outstanding under AmeriGas OLP's Revolving Credit
Facility at September 30, 2003. AmeriGas OLP had borrowings under the Revolving
Credit Facility totaling $10
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 4 Continued
at September 30, 2002, which we classify as bank loans. Issued and outstanding
letters of credit, which reduce available borrowings under the Revolving Credit
Facility, totaled $33.4 and $19.8 at September 30, 2003 and 2002, respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to
borrow up to $75 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. The Acquisition Facility operates as a revolving
facility through October 15, 2006, at which time amounts then outstanding will
be immediately due and payable. There were no amounts outstanding under the
Acquisition Facility at September 30, 2003 and 2002.
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 (4.00% at September 30, 2003), or at a two-week, one-, two-, three-,
or six-month Eurodollar Rate, as defined in the Credit Agreement, plus a margin.
The margin on Eurodollar Rate borrowings (which ranges from 1.00% to 2.25%), and
the Credit Agreement facility 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 Credit Agreement.
GENERAL PARTNER FACILITY. AmeriGas OLP also has a revolving credit agreement
with the General Partner under which it may borrow up to $20 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. Facility fees are determined in the same
manner as fees under the Revolving Credit Facility. UGI has agreed to contribute
up to $20 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 less
the total amount of distributions made during the immediately preceding 16
fiscal quarters. At September 30, 2003, such ratio was 2.79-to-1.
The 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 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 Credit Agreement and 5.25-to-1
with respect to the First Mortgage Notes. In addition, the 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, 2003, the Partnership was in compliance with its financial
covenants.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2003, UGI Utilities had revolving
credit agreements with five banks providing for borrowings of up to $107. These
agreements are currently scheduled to expire in June 2005 and 2006. UGI
Utilities may borrow at various prevailing interest rates, including LIBOR and
the banks' prime rate. UGI Utilities pays quarterly commitment fees on these
credit lines. UGI Utilities had revolving credit agreement borrowings totaling
$40.7 at September 30, 2003 and $37.2 at September 30, 2002, which we classify
as bank loans. The weighted-average interest rates on UGI Utilities bank loans
were 1.63% at September 30, 2003 and 2.35% at September 30, 2002.
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. At September 30, 2003,
UGI Utilities was in compliance with these financial covenants.
OTHER
At September 30, 2003, FLAGA's multi-currency acquisition note ("Acquisition
Note") consisted of $9.9 of U.S. dollar denominated obligations and 50.6 million
of euro-denominated obligations. The U.S. dollar denominated obligations under
the Acquisition Note bear interest at fixed rates ranging from 5.14% to 5.92%
while the eurodollar obligations bear 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, 2003 and September 30,
2002 were 4.00% and 4.86%, respectively. FLAGA may prepay the Acquisition Note,
in whole or in part. Prior to March 11, 2005, such prepayments shall be at a
premium.
42
UGI Corporation 2003 Annual Report
At September 30, 2003, FLAGA has a 15 million euro working capital
loan commitment from a European bank. The working capital facility expires in
November 2004, 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 rates on
FLAGA's working capital facility were 3.40% at September 30, 2003 and 4.40% at
September 30, 2002. Borrowings under the working capital facility at September
30, 2003 and 2002 totaled 13.6 million euro ($15.9 U.S. dollar equivalent) and
8.7 million euro ($8.6 U.S. dollar equivalent), respectively, and are classified
as bank loans.
The FLAGA Acquisition Note, special purpose facility and 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 5 - INCOME TAXES
Income (loss) before income taxes comprises the following:
2003 2002 2001
- ---------------------------------------------------------------------
Domestic $157.1 $117.2 $103.0
Foreign 3.7 6.8 (4.0)
- ---------------------------------------------------------------------
Total income before income taxes $160.8 $124.0 $ 99.0
- ---------------------------------------------------------------------
The provisions for income taxes consist of the following:
2003 2002 2001
- ---------------------------------------------------------------------
Current expense:
Federal $ 48.1 $ 26.5 $ 39.2
State 15.4 9.3 11.7
Foreign - 0.1 -
- ---------------------------------------------------------------------
Total current expense 63.5 35.9 50.9
Deferred (benefit) expense:
Federal 2.3 11.8 (2.9)
State (3.6) (0.4) (1.2)
Foreign (1.1) - (1.0)
Investment tax credit amortization (0.4) (0.4) (0.4)
- ---------------------------------------------------------------------
Total deferred (benefit) expense (2.8) 11.0 (5.5)
- ---------------------------------------------------------------------
Total income tax expense $ 60.7 $ 46.9 $ 45.4
- ---------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective
tax rate is as follows:
2003 2002 2001
- ---------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal 4.6 5.3 7.3
Goodwill amortization - - 4.4
Other, net (1.8) (2.5) (0.8)
- ---------------------------------------------------------------------
Effective tax rate 37.8% 37.8% 45.9%
- ---------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September
30:
2003 2002
- ----------------------------------------------------------------------
Excess book basis over tax basis of property, plant
and equipment $224.3 $199.2
Utility regulatory assets 25.0 25.7
Pension plan asset 11.0 10.5
Other 16.7 15.0
- ----------------------------------------------------------------------
Gross deferred tax liabilities 277.0 250.4
- ----------------------------------------------------------------------
Self-insured property and casualty liability (9.9) (9.0)
Employee-related benefits (20.6) (16.2)
Premium on long-term debt (3.0) (2.5)
Deferred investment tax credits (3.3) (3.5)
Utility regulatory liabilities (7.7) (1.8)
Operating loss carryforwards (17.0) (13.3)
Allowance for doubtful accounts (3.9) (2.4)
Other (13.7) (13.8)
- ----------------------------------------------------------------------
Gross deferred tax assets (79.1) (62.5)
- ----------------------------------------------------------------------
Deferred tax assets valuation allowance 1.7 1.9
- ----------------------------------------------------------------------
Net deferred tax liabilities $199.6 $189.8
- ----------------------------------------------------------------------
Deferred income taxes of approximately $4.4 have not been provided on
the excess of book basis over tax basis of our equity investment in AGZ
Holdings, the parent company of Antargaz, because the Company's intent is to
reinvest all equity earnings.
UGI Utilities had recorded deferred tax liabilities of approximately
$37.0 as of September 30, 2003 and $35.5 as of September 30, 2002, pertaining to
utility temporary differences, principally a result of accelerated tax
depreciation for state income tax purposes, 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 $3.3 at September 30, 2003 and $3.5
at September 30, 2002, pertaining to utility deferred investment tax credits.
UGI Utilities had recorded regulatory income tax assets related to these net
deferred taxes of $57.6 as of September 30, 2003 and $54.7 as of September 30,
2002. 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
$44.5 of which $7.9 expires through 2010 and $36.6 of which has no expiration
date. At September 30, 2003, deferred tax assets relating to operating loss
carryforwards include those of FLAGA and $2.1 of deferred tax assets associated
with state net operating loss carryforwards expiring through 2023. Substantially
all of our deferred tax valuation allowances relate to state operating loss
carryforwards.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 6 - EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS. We sponsor a defined
benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI
Utilities, and certain of UGI's other wholly owned subsidiaries. In addition, we
provide postretirement health care benefits to certain retirees and a limited
number of active employees meeting certain age and service requirements, and
postretirement life insurance benefits to nearly all domestic active and
retired employees.
The following provides a reconciliation of projected benefit
obligations, plan assets, and funded status of these plans as of September 30:
Pension Other Postretirement
Benefits Benefits
----------------- --------------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations -
beginning of year $190.9 $165.2 $ 27.3 $ 21.3
Service cost 4.5 3.6 0.2 0.1
Interest cost 13.0 12.5 1.8 1.7
Plan amendments - 0.4 - -
Actuarial loss 10.5 18.6 1.1 5.8
Benefits paid (9.4) (9.4) (1.6) (1.6)
- ----------------------------------------------------------------------------------
Benefit obligations - end of year $209.5 $190.9 $ 28.8 $ 27.3
- ----------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -
beginning of year $166.1 $183.7 $ 7.8 $ 7.0
Actual return on plan assets 27.2 (8.3) 0.2 0.1
Employer contributions - - 2.6 2.3
Benefits paid (9.4) (9.3) (1.6) (1.6)
- ----------------------------------------------------------------------------------
Fair value of plan assets -
end of year $183.9 $166.1 $ 9.0 $ 7.8
- ----------------------------------------------------------------------------------
Funded status of the plans $(25.6) $(24.8) $(19.8) $(19.5)
Unrecognized net actuarial loss 51.2 50.2 5.9 4.7
Unrecognized prior service cost 2.4 3.0 - -
Unrecognized net transition (asset)
obligation (1.4) (3.0) 7.7 8.7
- ----------------------------------------------------------------------------------
Prepaid (accrued) benefit cost -
end of year $ 26.6 $ 25.4 $ (6.2) $ (6.1)
- ----------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.2% 6.8% 6.2% 6.8%
Expected return on plan assets 9.0% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.0% 4.5% 4.0% 4.5%
- ----------------------------------------------------------------------------------
Net pension income is determined using assumptions as of the beginning
of each year. Funded status is determined using assumptions as of the end of
each year.
Net periodic pension income and other postretirement benefit costs
include the following components:
Pension Other Postretirement
Benefits Benefits
-------------------------- --------------------------
2003 2002 2001 2003 2002 2001
- -----------------------------------------------------------------------------------------
Service cost $ 4.5 $ 3.6 $ 3.1 $ 0.2 $ 0.1 $ 0.1
Interest cost 13.0 12.5 12.1 1.8 1.7 1.6
Expected return on assets (17.9) (19.1) (18.9) (0.4) (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) loss 0.3 - (1.2) 0.1 (0.1) (0.1)
- -----------------------------------------------------------------------------------------
Net benefit cost (income) (1.1) (4.0) (5.9) 2.6 2.3 2.2
Change in regulatory
assets and liabilities - - - 1.0 1.2 1.4
- -----------------------------------------------------------------------------------------
Net expense (income) $ (1.1) $ (4.0) $ (5.9) $ 3.6 $ 3.5 $ 3.6
- -----------------------------------------------------------------------------------------
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 7% of trust assets at September 30,
2003. Although the UGI Utilities Pension Plan projected benefit obligations
exceeded plan assets at September 30, 2003 and 2002, plan assets exceeded
accumulated benefit obligations by $7.3 and $7.2, respectively.
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 equity and fixed income mutual funds.
The assumed health care cost trend rates are 11.0% for fiscal 2004,
decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed
health care cost trend rate would change the 2003 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 $ 1.6 $ (1.4)
- -------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key
employees. At September 30, 2003 and 2002, the projected benefit obligations
of these plans were $11.9 and $7.9, respectively. We recorded expense for these
plans of $1.9 in 2003, $1.4 in 2002 and $1.2 in 2001.
44
UGI Corporation 2003 Annual Report
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 $7.3 in 2003, $4.5
in 2002 and $6.2 in 2001.
NOTE 7 - INVENTORIES
Inventories comprise the following at September 30:
2003 2002
- --------------------------------------------------------------
Propane gas $ 53.8 $ 40.4
Utility fuel and gases 54.6 36.6
Materials, supplies and other 28.2 32.2
- --------------------------------------------------------------
Total inventories $136.6 $109.2
- --------------------------------------------------------------
NOTE 8 - SERIES PREFERRED STOCK
The UGI Series Preferred Stock, including both series subject to and
series not subject to mandatory redemption, has 5,000,000 shares authorized for
issuance. We had no shares of UGI Series Preferred Stock outstanding at
September 30, 2003 or 2002.
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, 2003 and 2002, 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 9 - COMMON STOCK AND INCENTIVE STOCK
AWARD PLANS
Common Stock share activity for 2001, 2002 and 2003 follows:
Issued Treasury Outstanding
- -----------------------------------------------------------------------------
Balance September 30, 2000 49,798,097 (9,307,533) 40,490,564
Issued:
Employee and director plans - 361,559 361,559
Dividend reinvestment plan - 148,218 148,218
Reacquired - (55,745) (55,745)
- -----------------------------------------------------------------------------
Balance September 30, 2001 49,798,097 (8,853,501) 40,944,596
Issued:
Employee and director plans - 482,794 482,794
Dividend reinvestment plan - 130,593 130,593
Reacquired - (5,388) (5,388)
- -----------------------------------------------------------------------------
Balance September 30, 2002 49,798,097 (8,245,502) 41,552,595
Issued:
Employee and director plans - 1,050,921 1,050,921
Dividend reinvestment plan - 97,665 97,665
Reacquired - (1,823) (1,823)
- -----------------------------------------------------------------------------
Balance September 30, 2003 49,798,097 (7,098,739) 42,699,358
- -----------------------------------------------------------------------------
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 1,650,000 shares of Common Stock may be granted in connection
with stock options and awards of restricted stock. However, awards representing
no more than 750,000 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 2003, 2002 and 2001, the Company made restricted stock awards
representing 81,750, 254,250, and 166,013 shares, respectively. At September 30,
2003, awards representing 458,813 shares of restricted stock were outstanding.
In addition to the 2000 Incentive Plan, at September 30, 2003, there remained
available for grant options to acquire 17,791 shares of Common Stock
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 9 continued
under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP Plan"). 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 300,000 shares of Common Stock to each of UGI's
nonemployee Directors. No Director may be granted options to acquire more than
15,000 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 2001, 2002, and
2003 follow:
Shares Average Option Price
- -----------------------------------------------------------------------------
Shares under option - September 30, 2000 2,825,466 $ 14.121
- -----------------------------------------------------------------------------
Granted 50,400 17.250
Exercised (304,009) 13.871
Forfeited (18,500) 13.885
- -----------------------------------------------------------------------------
Shares under option - September 30, 2001 2,553,357 14.214
- -----------------------------------------------------------------------------
Granted 714,375 20.470
Exercised (437,967) 14.019
- -----------------------------------------------------------------------------
Shares under option - September 30, 2002 2,829,765 15.857
- -----------------------------------------------------------------------------
Granted 694,500 25.179
Exercised (997,526) 14.681
Forfeited (44,250) 22.725
- -----------------------------------------------------------------------------
Shares under option - September 30, 2003 2,482,489 18.818
- -----------------------------------------------------------------------------
Options exercisable 2001 1,651,356 14.533
Options exercisable 2002 1,706,889 14.515
Options exercisable 2003 1,428,987 15.454
- -----------------------------------------------------------------------------
The following table presents additional information relating to stock
options outstanding and exercisable at September 30, 2003:
Range of exercise prices
------------------------
$ 13.58 - $20.41 -
$ 20.40 $ 25.61
- ------------------------------------------------------------------------
Options outstanding at September 30, 2003:
Number of options 1,754,114 728,375
Weighted average remaining
contractual life (in years) 6.67 9.21
Weighted average exercise price $ 16.24 $ 24.88
Options exercisable at September 30, 2003:
Number of options 1,370,612 58,375
Weighted average exercise price $ 15.08 $ 24.27
- ------------------------------------------------------------------------
At September 30, 2003, 1,043,951 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 112,500, 43,250 and 66,075 Common
Units in 2003, 2002 and 2001, respectively. At September 30, 2003 and 2002,
awards representing 209,336 and 105,825 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 could have elected 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 7,218, 14,174
and 17,334 in 2003, 2002 and 2001, respectively. At September 30, 2003 and 2002,
there were 106,069 and 94,778 Units, respectively, outstanding.
FAIR VALUE INFORMATION. The per share weighted-average fair value of stock
options granted under our option plans was $2.60 in 2003, $3.27 in 2002 and
$2.90 in 2001. 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 2003, 2002 and 2001
are as follows:
2003 2002 2001
- ----------------------------------------------------------
Expected life of option 6 years 6 years 6 years
Expected volatility 21.6% 28.8% 29.1%
Expected dividend yield 6.1% 6.7% 6.6%
Risk free interest rate 3.1% 4.7% 5.0%
- ----------------------------------------------------------
46
UGI Corporation 2003 Annual Report
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, 2003 and 2002, loans out-
standing totaled $0.4 and $3.5, respectively. The Company is not currently
offering loans under this program.
NOTE 10 - PREFERENCE STOCK PURCHASE RIGHTS
Holders of our Common Stock own one-third 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 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 pur-
chase, 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 11 - 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 are made 98% to limited partners 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.
NOTE 12 - COMMITMENTS AND CONTINGENCIES
We lease various buildings and other facilities 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 $47.4 in 2003, $46.5 in 2002 and $38.4 in
2001.
Minimum future payments under operating leases that have initial or
remaining noncancelable terms in excess of one year are as follows:
After
2004 2005 2006 2007 2008 2008
- ---------------------------------------------------------------------------
AmeriGas Propane $ 35.7 $ 30.7 $ 25.7 $ 21.3 $ 17.9 $ 39.6
UGI Utilities 2.9 2.4 2.1 1.8 1.0 3.2
International Propane
and other 1.5 1.2 0.9 0.7 0.6 0.1
- ---------------------------------------------------------------------------
Total $ 40.1 $ 34.3 $ 28.7 $ 23.8 $ 19.5 $ 42.9
- ---------------------------------------------------------------------------
Gas Utility has gas supply agreements with producers and marketers with
terms not exceeding one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity, which Gas Utility may terminate at various
dates through 2016. 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 2008.
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 Partnership enters into fixed price contracts to purchase a portion
of its supply requirements. These contracts generally have terms of less than
one year.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 12 continued
The following table presents contractual obligations under Gas Utility,
Electric Utility, Energy Services and AmeriGas Propane supply, storage and
service contracts existing at September 30, 2003:
After
2004 2005 2006 2007 2008 2008
- ------------------------------------------------------------------------------------
Gas Utility and Electric
Utility supply, storage
and service contracts $157.1 $ 87.9 $ 48.1 $ 25.1 $ 14.7 $ 74.0
Energy Services
supply contracts 435.3 65.6 8.1 1.4 - -
AmeriGas Propane
supply contracts 16.7 - - - - -
- ------------------------------------------------------------------------------------
Total $609.1 $153.5 $ 56.2 $ 26.5 $ 14.7 $ 74.0
- ------------------------------------------------------------------------------------
The Partnership also enters into contracts to purchase propane to meet
additional supply requirements. Generally, these contracts are one- to
three-year agreements subject to annual review 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 $15 at September 30, 2003. 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. Pursuant to a Liquidation and Winding Up Agreement dated September 17,
2002, PanEnergy Corporation ("PanEnergy"), Texas Eastern's sole stockholder,
assumed 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 was estimated to exceed $94), 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.
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired
the propane distribution businesses of Columbia Energy Group (the "2001
Acquisition") pursuant to the terms of a purchase agreement (the "2001
Acquisition Agreement") by and among Columbia Energy Group ("CEG"), Columbia
Propane Corporation ("Columbia Propane"), Columbia Propane, L.P. ("CPLP"), CP
Holdings, Inc. ("CPH," and together with Columbia Propane and CPLP, the "Company
Parties"), AmeriGas Partners, AmeriGas OLP and the General Partner (together
with AmeriGas Partners and AmeriGas OLP, the "Buyer Parties"). As a result of
the 2001 Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane
and CPH and substantially all of the partnership interests of CPLP. Under the
terms of an earlier acquisition agreement (the "1999 Acquisition Agreement"),
the Company Parties agreed to indemnify the former general partners of
National Propane Partners, L.P. (a predecessor company of the Columbia Propane
businesses) and an affiliate (collectively, "National General Partners")
against certain income tax and other losses that they may sustain as a result of
the 1999 acquisition by CPLP of National Propane Partners, L.P. (the "1999
Acquisition") or the operation of the business after the 1999 Acquisition
("National Claims"). At September 30, 2003, the potential amount payable under
this indemnity by the Company Parties was approximately $65. These indemnity
obligations will expire on the date that CPH acquires the remaining outstanding
partnership interest of CPLP, which is expected to occur on or after July 19,
2009.
Under the terms of the 2001 Acquisition Agreement, CEG agreed to
indemnify the Buyer Parties and the Company Parties against any losses that they
sustain under the 1999 Acquisition Agreement and related agreements ("Losses"),
including National Claims, to the extent such claims are based on acts or
omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer
Parties 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. CEG and the Buyer Parties have
agreed to apportion certain losses resulting from National Claims 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
48
UGI Corporation 2003 Annual Report
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 (1) the
subsidiary's separate corporate form should be disregarded or (2) UGI Utilities
should be considered to have 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 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 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. 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.
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.
Although we currently 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, damages or
settlements could be material to our operating results or cash flows in future
periods depending on the nature and timing of future developments with respect
to these matters and the amounts of future operating results and cash flows.
NOTE 13 - 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.
During 2003 and 2002, Gas Utility entered into natural gas call option
contracts to reduce volatility in the cost of gas it purchases for retail
core-market customers. Because net gains or losses associated with these
contracts will be included in Gas Utility's PGC recovery mechanism, as these
contracts are marked to market in accordance with SFAS 133, any gains or
losses are deferred for future recovery from or refund to Gas Utility
ratepayers.
During 2001, we 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 were
designated as cash flow hedges.
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Note 13 continued
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") designed to manage interest rate risk associated with planned
issuances of fixed-rate long-term debt. 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, 2003 and 2002, the net pre-tax loss
recognized in earnings representing cash flow hedge ineffectiveness was $3.1 and
$2.1, respectively. During the year ended September 30, 2001, such amount 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 in 2001.
Gains and losses included in accumulated other comprehensive income at
September 30, 2003 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, 2003 are net
after-tax losses of approximately $2.9 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, 2003 are net after-tax losses of
approximately $1.2 principally associated with future purchases of natural gas
and 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 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
- ------------------------------------------------------------------------
2003:
Natural gas futures and options contracts $ 1.1 $ 1.1
Propane swap and option contracts (0.6) (0.6)
Interest rate protection agreements 0.2 0.2
Long-term debt 1,223.5 1,337.7
UGI Utilities preferred shares subject to
mandatory redemption 20.0 20.9
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 preferred shares subject to
mandatory redemption 20.0 20.4
- ------------------------------------------------------------------------
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 preferred shares subject to
mandatory redemption 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, 2003 and 2002.
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, money market mutual funds and securities
guaranteed by the U.S. Government or its agencies. 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 14 - ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY
Energy Services has a $100 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
50
UGI Corporation 2003 Annual Report
funding available at any one time from this facility is $100. 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.
During 2003 and 2002, Energy Services sold trade receivables totaling
$651.3 and $302.4, respectively, to ESFC. During 2003 and 2002, ESFC sold an
aggregate $196.0 and $34.0, respectively, of undivided interests in its trade
receivables to the commercial paper conduit. At September 30, 2003, the out-
standing balance of ESFC trade receivables was $38.5 which amount is net of $17
in trade receivables sold to the commercial paper conduit. At September 30,
2002, there were $22.9 of ESFC trade receivables outstanding and 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 years ended September 30, 2003 and 2002, which losses are
included in other income, net, were $0.3 and $0.1, respectively.
In addition, a major bank has committed to issue up to $50 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.
NOTE 15 - CHANGES IN ACCOUNTING
TANK FEE REVENUE RECOGNITION. In order to apply the guidance of SEC Staff
Accounting Bulletin No. 101 entitled "Revenue Recognition," 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 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 2003, 2002 and 2001.
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 customer locations 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 this 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
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. 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) $ (0.05)
Tank installation costs 11.3 (4.4) 6.9 0.17
SFAS 133 (0.4) 0.1 (0.3) (0.01)
- ---------------------------------------------------------------------------
Total $ 7.4 $ (2.9) $ 4.5 $ 0.11
- ---------------------------------------------------------------------------
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.
The pre-tax charge reflects $3.7 associated with the impairment of leasehold
improvements; $3.2 for estimated costs associated with lease guaranty
arrangements and the restoration of the leased facilities; $1.1 associated with
the write-down of inventory to net realizable value; and $0.5 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)." At September 30, 2002, all amounts had been settled.
NOTE 17 - OTHER INCOME, NET
Other income, net, comprises the following:
2003 2002 2001
- -------------------------------------------------------------------------
Interest and interest-related income $ (6.6) $ (5.3) $ (6.7)
Utility non-tariff service income (5.7) (5.7) (5.4)
Gain on sales of fixed assets (1.6) (1.6) (2.4)
Pension income (1.1) (4.0) (5.9)
Other (4.8) (1.5) (2.6)
- ------------------------------------------------------------------------
Total other income, net $(19.8) $(18.1) $(23.0)
- ------------------------------------------------------------------------
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 18 - CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS AND COMMON UNIT
ISSUANCE
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 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 were determined in
accordance with the guidance in SEC Staff Accounting Bulletin No. 51,
"Accounting for Sales of Common Stock by a Subsidiary" ("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.
On June 17, 2003, AmeriGas Partners sold 2,900,000 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 and associated capital
contributions from the General Partner totaling $1.5, 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 which is reflected in the Company's
balance sheet as an increase in common stockholders' equity in accordance with
the guidance in SAB 51. The gain had no effect on the Company's net income or
cash flow.
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, 2003 and 2002 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:
2003 2002 2001
- ----------------------------------------------------------------------
Equity in income (loss) of equity investees $ 5.3 $ 6.0 $ (2.1)
Interest income on AGZ Bonds - 0.9 0.5
Currency gain from redemption of AGZ Bonds - 1.6 -
- ----------------------------------------------------------------------
Total $ 5.3 $ 8.5 $ (1.6)
- ----------------------------------------------------------------------
Undistributed net earnings (loss) of our equity investees included in
consolidated retained earnings were $3.3 and $3.6 at September 30, 2003 and
2002, 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
52
UGI Corporation 2003 Annual Report
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 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 2003, the
Company received a dividend of 5.0 million euro ($5.6 U.S. dollar equivalent)
from AGZ. In July 2002, the Company received $19.3 in cash from AGZ in repayment
of 18 million euro face value ($17.7 U.S. dollar equivalent) of AGZ Bonds,
representing 90% of such 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 which is included in income
from equity investees on the 2002 Consolidated Statement of Income. 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:
2003 2002 2001(a)
- ------------------------------------------------------------------------
STATEMENT OF INCOME DATA:
Revenues $ 698.4 $ 534.8 $ 243.8
- ------------------------------------------------------------------------
Operating income $ 96.7 $ 79.4 $ 22.5
Interest, net (37.7) (27.9) (13.9)
- ------------------------------------------------------------------------
Income before income taxes $ 59.0 $ 51.5 $ 8.6
Income taxes $ (24.4) $ (20.7) $ (5.1)
Net income $ 32.7 $ 29.9 $ 2.9
- ------------------------------------------------------------------------
BALANCE SHEET DATA (AT SEPTEMBER 30):
Current assets $ 196.8 $ 171.5
Property, plant and equipment, net 321.6 259.5
Goodwill 443.8 378.8
Other assets 106.2 116.7
- ------------------------------------------------------------
Total assets $1,068.4 $ 926.5
- ------------------------------------------------------------
Current liabilities $ 136.2 $ 106.1
Long-term debt 453.9 436.2
Other liabilities 354.8 292.0
- ------------------------------------------------------------
Total liabilities $ 944.9 $ 834.3
- ------------------------------------------------------------
Equity $ 123.5 $ 92.2
- ------------------------------------------------------------
(a) Statement of income data is for the period March 27, 2001 to September 30,
2001.
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.
NOTE 20 - QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30,
2002 2001 2003 2002 2003 2002 2003 2002(a)
- -----------------------------------------------------------------------------------------------------------------
Revenues $739.9 $619.4 $1,135.9 $764.0 $623.1 $446.3 $ 527.2 $ 384.0
Operating income (loss) $107.4 $ 73.8 $ 184.4 $150.5 $ 8.4 $ 29.0 $ 2.1 $ (0.7)
Income (loss) from equity investees $ 1.9 $ 3.8 $ 5.0 $ 3.7 $ 0.2 $ 0.7 $ (1.8) $ 0.3
Net income (loss) $ 36.7 $ 24.1 $ 69.8 $ 54.0 $ (2.0) $ 4.0 $ (5.6) $ (6.6)
Earnings (loss) per share:
Basic $ 0.88 $ 0.59 $ 1.66 $ 1.31 $(0.05) $ 0.10 $ (0.13) $ (0.16)
Diluted $ 0.86 $ 0.58 $ 1.62 $ 1.28 $(0.05) $ 0.09 $ (0.13) $ (0.16)
- -----------------------------------------------------------------------------------------------------------------
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 and decreased net
loss by $1.1 or $0.03 per share.
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
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 UGlD's
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
Eastern region of the United States. 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 AmeriGas Propane's performance
principally based upon the Partnership's earnings before interest expense,
income taxes, depreciation and amortization ("Partnership EBITDA"). Although we
use Partnership EBITDA to evaluate AmeriGas Propane's profitability, it 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. The Company's definition of Partnership EBITDA may be
different from that used by other companies. We evaluate the performance of our
Gas Utility, Electric Operations, Energy Services and International Propane
segments principally based upon their income (loss) 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.
54
UGI Corporation 2003 Annual Report
Financial information by reportable business segment follows:
Reportable Segments
-----------------------------------------------------------
AmeriGas Gas Electric Energy International Corporate &
Total Eliminations Propane Utility Operations Services Propane Other
- ---------------------------------------------------------------------------------------------------------------------------------
2003
Revenues $ 3,026.1 $ (2.4) $1,628.4 $ 539.9 $ 108.1(a) $ 648.7 $ 54.5 $ 48.9
Cost of sales $ 1,984.3 $ - $ 910.3 $ 343.0 $ 55.9 $ 620.2 $ 27.4 $ 27.5
Operating income $ 302.3 $ - $ 164.5 $ 96.1 $ 25.9 $ 13.6 $ 0.7 $ 1.5
Income (loss) from
equity investees 5.3 - (0.6) - - - 5.9 -
Loss on
extinguishments
of debt (3.0) - (3.0) - - - - -
Interest expense (109.2) - (87.1) (15.4) (2.3) - (4.1) (0.3)
Minority interests (34.6) - (34.6) - - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
Income before
income taxes $ 160.8 $ - $ 39.2 $ 80.7 $ 23.6 $ 13.6 $ 2.5 $ 1.2
Depreciation and
amortization $ 103.0 $ - $ 74.8 $ 18.1 $ 3.7 $ 1.5 $ 3.9 $ 1.0
Partnership
EBITDA (b) $ 234.4
Total assets $ 2,781.7 $ (39.6) $1,504.6 $ 725.1 $ 160.1 $ 88.1 $ 165.0 $ 178.4
Capital expenditures $ 101.4 $ - $ 53.4(c) $ 37.2 $ 4.1 $ 1.0 $ 4.5 $ 1.2
Acquisition of
additional interest
in Conemaugh Station $ 51.3 $ - $ - $ - $ 51.3 $ - $ - $ -
Investments in equity
investees $ 39.9 $ - $ 2.8 $ - $ 10.3 $ - $ 26.8 $ -
Goodwill and excess
reorganization value $ 671.5 $ - $ 601.6 $ - $ - $ 2.8 $ 62.8 $ 4.3
=================================================================================================================================
2002
Revenues $ 2,213.7 $ (2.0) $1,307.9 $ 404.5 $ 86.0(a) $ 332.3 $ 46.7 $ 38.3
Cost of sales $ 1,296.6 $ - $ 653.1 $ 241.7 $ 48.6 $ 310.9 $ 22.6 $ 19.7
Operating income $ 253.3 $ - $ 145.0 $ 77.1 $ 13.2 $ 11.1 $ 3.9 $ 3.0
Income (loss) from
equity investees 8.5 - 0.3 - - - 8.3(d) (0.1)
Loss on extinguishments
of debt (0.7) - (0.7) - - - - -
Interest expense (109.1) - (87.8) (14.2) (2.4) - (4.2) (0.5)
Minority interests (28.0) - (28.0) - - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
Income before
income taxes $ 124.0 $ - $ 28.8 $ 62.9 $ 10.8 $ 11.1 $ 8.0 $ 2.4
Depreciation and
amortization $ 93.5 $ - $ 66.4 $ 19.0 $ 3.2 $ 0.8 $ 3.2 $ 0.9
Partnership EBITDA (b) $ 209.6
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
Cost of sales $ 1,632.4 $ - $ 847.0 $ 322.9 $ 51.9 $ 357.3 $ 28.4 $ 24.9
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)(d) (0.1)
Interest expense (104.8) 0.4 (80.3) (16.3) (2.7) (0.4) (4.9) (0.6)
Minority interests (23.6) - (23.6) - - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
Income (loss)
before income taxes $ 99.0 $ - $ 29.9 $ 71.5 $ 8.0 $ 6.9 $ (5.6) $ (11.7)
Depreciation and
amortization $ 105.2 $ - $ 75.5 $ 20.2 $ 3.6 $ 0.3 $ 4.3 $ 1.3
Partnership EBITDA (b) $ 220.3
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(e) $ -
Goodwill and excess
reorganization value $ 641.1 $ - $ 589.0 $ - $ - $ - $ 48.6 $ 3.5
=================================================================================================================================
(a) Electric Operations' 2003 and 2002 revenues include UGID's unregulated
electricity generation revenues totaling $19.3 and $2.6, respectively.
(b) The following table provides a reconciliation of Partnership EBITDA to
AmeriGas Propane operating income:
Year ended September 30, 2003 2002 2001
- --------------------------------------------------------------------
Partnership EBITDA $234.4 $209.6 $220.3
Depreciation and amortization (i) (74.6) (66.1) (74.7)
Minority interests (ii) 1.1 1.1 0.7
Income (loss) from equity investees 0.6 (0.3) -
Loss on extinguishments of debt 3.0 0.7 -
Cumulative effect of accounting changes - - (12.5)
- --------------------------------------------------------------------
Operating income $164.5 $145.0 $133.8
- --------------------------------------------------------------------
(i) Excludes General Partner depreciation and amortization of $0.2, $0.3, and
$0.8 in 2003, 2002, and 2001, respectively.
(ii) Principally represents the General Partner's 1.01% interest in AmeriGas
OLP.
(c) Includes capital leases of $0.5 and $1.3 in 2003 and 2001,
respectively.
(d) In addition to equity income (loss) of international propane equity
investees, (1) 2002 amount includes a currency transaction gain of $1.6
from the redemption of AGZ Bonds and $0.9 of interest income on AGZ
Bonds and (2) 2001 amount includes $0.5 of interest income on AGZ
Bonds.
(e) Includes investment in AGZ Bonds of $18.2.
55