UGI Corporation 2004 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 and butane-based
liquefied petroleum gases (collectively, "LPG"); a provider of natural gas and
electric 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, 2004, UGI, through its wholly owned second-tier
subsidiary AmeriGas Propane, Inc. (the "General Partner"), held an approximate
46% effective interest in AmeriGas Partners. 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 wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") (1)
conducts an LPG distribution business in France; (2) conducts an LPG
distribution business in Austria, the Czech Republic and Slovakia ("FLAGA"); and
(3) participates in an LPG joint-venture business in the Nantong region of
China. Our LPG distribution business in France is conducted through Antargaz, an
operating subsidiary of AGZ Holding ("AGZ"), and its operating subsidiaries
(collectively, "Antargaz"). We refer to our foreign operations collectively as
"International 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 electric distribution utility ("Electric Utility") in
northeastern Pennsylvania. Gas Utility and Electric Utility are subject to
regulation by the Pennsylvania Public Utility Commission ("PUC").
Enterprises also 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 electric generation assets. Prior to its transfer to Energy
Services in June 2003, UGID was a wholly owned subsidiary of UGI Utilities.
Through other subsidiaries, Enterprises owns and operates a heating,
ventilation, air-conditioning and refrigeration service business in the Middle
Atlantic states ("HVAC/R").
This Financial Review should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the reportable segment information included in Note 19.
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Fiscal 2004 marked another year of earnings growth as we continued to focus on
our core competencies as a marketer and distributor of energy products and
services.
On March 31, 2004, we purchased the remaining 80.5% ownership interest in
AGZ that we did not already own ("Antargaz Acquisition"). AGZ is the parent
company of Antargaz, a leading distributor of LPG in France. This transaction
was $0.26 per share dilutive in 2004 due to the following factors. First, we
incurred a $9.1 million pre-tax foreign exchange loss ($0.13 per diluted share)
as we fixed the euro-denominated purchase price in dollars. Second, we issued
7.8 million shares of our common stock in March ($0.22 per diluted share) to
finance part of the acquisition. Partially offsetting the first two items were
the additional Antargaz earnings ($0.09 per diluted share) after March 31, 2004
resulting from our increased ownership. The Antargaz Acquisition has also
significantly changed our business. In Fiscal 2005, assuming normal weather, we
expect our domestic and international LPG operations collectively to represent
approximately one-half of our net income and our utility business operations to
represent about one-third.
Winter weather conditions in the United States and Europe are the most
important variables affecting our annual earnings performance. This is because a
substantial portion of the energy products we sell are used in heating
applications.
2004 COMPARED WITH 2003
CONSOLIDATED RESULTS
Effective October 1, 2003, our Energy Services segment includes the operating
results of Energy Services' gas marketing business as well as UGID's electric
generation business. Prior-year amounts have been restated to be consistent with
the current period presentation.
Variance -
Favorable
2004 2003 (Unfavorable)
---- ---- -------------
% OF TOTAL % of total
NET NET Net Net Net
INCOME INCOME Income Income Income % change
------- ---------- ------- ---------- ------- --------
(Millions of dollars)
AmeriGas Propane $ 29.4 26.3% $ 23.2 23.5% $ 6.2 26.7%
International Propane 13.3 11.9% 3.6 3.6% 9.7 N.M.
Gas Utility 37.9 34.0% 48.0 48.5% (10.1) (21.0)%
Electric Utility 11.0 9.9% 10.6 10.7% 0.4 3.8%
Energy Services 18.2 16.3% 11.2 11.3% 7.0 62.5%
Corporate & Other 1.8 1.6% 2.3 2.3% (0.5) (21.7)%
------- ----- ------- ----- ------- -----
Total $ 111.6 100.0% $ 98.9 100.0% $ 12.7 12.8%
------- ----- ------- ----- ------- -----
N.M. - Due to the Antargaz Acquisition, variance is not meaningful.
13
FINANCIAL REVIEW (continued)
The following table presents certain financial and statistical information
for our principal businesses for Fiscal 2004 and Fiscal 2003:
Increase
2004 2003 (Decrease)
-------- -------- ---------------------
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $1,775.9 $1,628.4 $ 147.5 9.1%
Total margin (a) $ 746.7 $ 718.1 $ 28.6 4.0%
Partnership EBITDA (b) $ 255.9 $ 234.4 $ 21.5 9.2%
Operating income $ 176.0 $ 164.5 $ 11.5 7.0%
Retail gallons sold (millions) 1,059.1 1,074.9 (15.8) (1.5)%
Degree days - % (warmer) colder
than normal (c) (4.9)% 0.2% - -
INTERNATIONAL PROPANE:
Revenues $ 333.4 $ 54.5 $ 278.9 N.M.
Total margin (a) $ 195.4 $ 27.1 $ 168.3 N.M.
Operating income $ 20.5 $ 0.7 $ 19.8 N.M.
Income from equity investees $ 10.6 $ 5.9 $ 4.7 N.M.
Income before income taxes $ 13.7 $ 2.5 $ 11.2 N.M.
GAS UTILITY:
Revenues $ 560.4 $ 539.9 $ 20.5 3.8%
Total margin (a) $ 191.5 $ 196.9 $ (5.4) (2.7)%
Operating income $ 80.1 $ 96.1 $ (16.0) (16.6)%
Income before income taxes $ 64.2 $ 80.7 $ (16.5) (20.4)%
System throughput -
billions of cubic feet ("bcf") 82.2 83.8 (1.6) (1.9)%
Degree days - % (warmer) colder
than normal (2.9)% 7.0% - -
ELECTRIC UTILITY:
Revenues $ 89.7 $ 88.8 $ 0.9 1.0%
Total margin (a) $ 41.6 $ 40.3 $ 1.3 3.2%
Operating income $ 20.9 $ 20.3 $ 0.6 3.0%
Income before income taxes $ 18.9 $ 18.0 $ 0.9 5.0%
Distribution sales - millions of
kilowatt hours ("gwh") 983.9 980.0 3.9 0.4%
ENERGY SERVICES:
Revenues $ 967.2 $ 668.0 $ 299.2 44.8%
Total margin (a) $ 55.0 $ 35.6 $ 19.4 54.5%
Operating Income $ 31.1 $ 19.2 $ 11.9 62.0%
Income before income taxes $ 31.1 $ 19.2 $ 11.9 62.0%
N.M. - Due to the Antargaz Acquisition, variance is not meaningful.
(a) Total margin represents total revenues less total cost of sales and, with
respect to Electric Utility, revenue-related taxes, i.e. Electric Utility gross
receipts taxes of $4.8 million in both Fiscal 2004 and Fiscal 2003. For
financial statement purposes, revenue-related taxes are included in "Utility
taxes other than income taxes" on the Consolidated Statements of Income.
(b) Partnership EBITDA (earnings before interest expense, income taxes and
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
reportable segment (see Note 19 to Consolidated Financial Statements).
(c) 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. Based upon heating degree day data, temperatures in Fiscal
2004 were 4.9% warmer than normal compared to temperatures that were essentially
normal in Fiscal 2003. Retail propane volumes sold during Fiscal 2004 decreased
slightly compared to Fiscal 2003 as the effects of warmer than normal winter
weather more than offset volume growth from acquisitions, principally the
October 2003 acquisition of Horizon Propane LLC ("Horizon Propane"). In
addition, Fiscal 2004 retail propane volumes were also negatively affected by
customer conservation driven by record-high propane product costs. Low margin
wholesale volumes increased primarily reflecting greater product cost hedging
activities.
Retail propane revenues increased $104.6 million as a $124.8 million
increase due to higher average selling prices was partially offset by a $20.2
million decrease due to the lower retail volumes sold. Wholesale propane
revenues increased $32.5 million reflecting (1) a $23.3 million increase due to
higher average selling prices and (2) a $9.2 million increase due to the higher
volumes sold relating to product cost hedging activities. In Fiscal 2004, the
propane industry experienced sustained higher propane product costs which
resulted in higher average retail and wholesale selling prices. Total propane
cost of sales increased $115.4 million principally reflecting the effects of
significantly higher propane product costs.
Despite lower retail volumes sold as a result of the warmer weather, total
margin increased $28.6 million due to higher average retail propane margins per
gallon and greater margin from non-propane sales and services. As a result of
significantly higher propane product costs, the Partnership increased average
retail selling prices realizing higher average margins per gallon while
remaining competitive in the marketplace. Average margin per gallon associated
with the Partnership's Prefilled Propane Xchange program ("PPX(R)") decreased in
Fiscal 2004 as selling prices were lowered in response to competition in the
marketplace. The effects of lower average PPX(R) selling prices on PPX(R) margin
per gallon were partially offset by effective cost management initiatives.
Margin from non-propane sales and services increased $6.9 million principally
reflecting higher margin from tank rentals, PPX(R) cylinder sales and hauling
and terminal sales and services.
Partnership EBITDA increased $21.5 million in Fiscal 2004 reflecting (1)
the previously mentioned increase in total margin, (2) the absence of a $3.0
million loss on extinguishment of long-term debt incurred in Fiscal 2003, and
(3) a $2.8 million increase in other income. These increases were partially
offset by a $12.6 million increase in operating and administrative expenses
principally due to higher compensation, distribution, administrative and general
insurance expenses partially offset by the absence of $3.8 million of expenses
associated with initiating the management realignment in Fiscal 2003 and the
continued beneficial effects on Fiscal 2004 operating expenses of the
realignment. Other income in Fiscal 2004 increased principally due to greater
income from finance charges.
Operating income in Fiscal 2004 increased $11.5 million as the previously
mentioned increases in margin and other income were partially offset by (1)
higher depreciation and amortization expense related to recent acquisitions, (2)
higher depreciation associated with PPX(R) and (3) the aforementioned increase
in operating expenses.
14
UGI Corporation 2004 Annual Report
INTERNATIONAL PROPANE. International Propane results of operations in Fiscal
2004 have significantly increased compared to Fiscal 2003 due to the
consolidation of all of Antargaz' operations beginning April 1, 2004 as a result
of the Antargaz Acquisition. Antargaz' revenues, total margin and operating
income from April 1, 2004 to September 30, 2004 were $270.8 million, $164.8
million and $15.1 million, respectively. During the twelve months ended
September 30, 2004, Antargaz sold approximately 336 million gallons of LPG while
experiencing weather that was 5% warmer than normal compared to 342 million
gallons sold and weather that was 11% warmer than normal during the twelve
months ended September 30, 2003. Despite the improved weather in Fiscal 2004
compared to Fiscal 2003, volumes declined due primarily to lower high volume,
low margin sales principally to crop-drying customers. International Propane's
revenues increased significantly during Fiscal 2004 principally due to including
all of Antargaz' results of operations on a consolidated basis beginning April
1, 2004. FLAGA's revenues increased $8.1 million in Fiscal 2004 due to the
effects of an approximately 12% stronger euro on slightly higher base-currency
revenues despite lower volumes sold. International Propane total margin
increased primarily due to the Antargaz Acquisition and a $3.5 million increase
in FLAGA's margin. FLAGA's margin increased in Fiscal 2004 as a result of the
effects of a stronger euro on slightly improved base-currency margin.
The increase in International Propane operating income principally
reflects the previously mentioned increases in margin partially offset by (1)
higher operating expenses resulting from the Antargaz Acquisition and (2) a loss
of $9.1 million resulting from the settlement of contracts for the forward
purchase of euros used to fund a portion of the purchase price of the Antargaz
Acquisition. FLAGA's operating income increased during Fiscal 2004 primarily
reflecting lower operating expenses as a result of cost reduction initiatives
partially offset by the effects of a stronger euro.
International Propane income from equity investees in Fiscal 2004 includes
equity investee income from our 19.5% ownership interest in AGZ through March
31, 2004. The $4.7 million increase over Fiscal 2003 primarily reflects higher
income from AGZ resulting from (1) the effects of colder weather during the
Fiscal 2004 winter heating season and (2) lower base-currency LPG product costs
partially offset by the effect of the stronger euro.
The increase in International Propane income before income taxes reflects
the combined increase in Antargaz' results as an equity investee and on a
consolidated basis and the previously mentioned increase in FLAGA's operating
income partially offset by greater interest expense resulting from the Antargaz
Acquisition.
GAS UTILITY. Weather in Gas Utility's service territory based upon heating
degree days was 2.9% warmer than normal in Fiscal 2004 compared with weather
that was 7.0% colder than normal in Fiscal 2003. Total distribution system
throughput decreased 1.6 bcf or 1.9% as the adverse effects of the warmer
weather on heating-related sales to firm- residential, commercial and industrial
("retail core-market") customers were partially offset by greater volumes
transported for delivery service customers and the volume effects of
year-over-year retail core-market customer growth. The increase in Gas Utility
revenues during Fiscal 2004 includes a $20.1 million increase in revenues from
off-system sales partially offset by lower retail core-market and delivery
service revenues. The decline in retail core-market revenues reflects the
effects of the reduced retail core-market volumes partially offset by higher
average purchased gas cost ("PGC") rates reflecting higher natural gas costs.
Gas Utility's cost of gas was $368.9 million in Fiscal 2004 compared to $343.0
million in Fiscal 2003 reflecting greater cost of gas associated with the higher
off-system sales and the higher average retail core-market PGC rates partially
offset by the effects of the lower retail core-market volumes sold. Increases or
decreases in Gas Utility's cost of gas associated with retail core-market
customers result from changes in retail core-market volumes, the price of the
gas purchased and the level of gas costs collected through the PGC recovery
mechanism. Under this recovery mechanism, Gas Utility records the cost of gas
associated with sales to retail core-market customers equal to the amount
included in rates and defers the difference on the balance sheet as a regulatory
asset or liability representing an amount to be collected from or refunded to
customers in a future period. As a result, increases or decreases in the cost of
gas associated with retail core-market customers have no direct effect on retail
core-market margin.
Gas Utility total margin declined $5.4 million principally reflecting a
$4.0 million decline in retail core-market margin and the effects of lower
margins on delivery-service.
Gas Utility operating income declined $16.0 million in Fiscal 2004
principally reflecting the previously mentioned decline in total margin, lower
other income and higher operating and administrative expenses. Other income
declined $5.4 million due in large part to a decline in non-tariff service
income, costs related to settling a regulatory claim and the absence of pension
income in Fiscal 2004. Operating and administrative expenses increased $3.8
million due primarily to higher compensation and benefits expense, including the
effects of a lump-sum payment made to a participant of UGI Utilities' unfunded
executive retirement plan, partially offset by the absence of costs related to
settling an environmental claim recorded in the prior year and lower Fiscal 2004
distribution system maintenance expenses. The decrease in Gas Utility income
before income taxes reflects the decline in operating income and slightly higher
interest expense in Fiscal 2004 resulting from classifying dividends paid on
preferred shares subject to mandatory redemption as interest expense beginning
July 1, 2003, in accordance with Statement of Financial Accounting Standards
("SFAS") No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity" ("SFAS 150").
ELECTRIC UTILITY. Electric Utility's Fiscal 2004 kilowatt-hour sales were
slightly higher than in Fiscal 2003 due in large part to greater air
conditioning sales partially offset by the adverse effects of slightly warmer
winter weather on heating-related sales.
The increase in Electric Utility revenues in Fiscal 2004 reflects the
higher kilowatt-hour sales and higher rates. Electric Utility's cost of sales
declined $0.4 million in Fiscal 2004 reflecting lower Electric Utility purchased
power costs.
Electric Utility total margin in Fiscal 2004 increased $1.3 million
reflecting the previously mentioned increase in revenues and decrease in
purchased power costs. Operating income was higher in Fiscal 2004 reflecting the
increase in total margin partially offset by slightly higher operating and
administrative expenses
15
FINANCIAL REVIEW (continued)
and lower other income. The increase in income before income taxes reflects the
increase in total operating income and slightly lower interest expense.
ENERGY SERVICES. The increase in Energy Services revenues in Fiscal 2004
resulted primarily from (1) a 30% increase in natural gas volumes sold due in
large part to the full year effect of the March 2003 acquisition of the
northeastern U.S. gas marketing business of TXU Energy Retail Company, L.P., a
subsidiary of TXU Energy (the "TXU Energy Acquisition"), and to a lesser extent
customer growth, (2) the full year effect of UGID's June 2003 purchase of an
additional 4.9% (83 megawatt) interest in the Conemaugh electric generation
station located near Johnstown, Pennsylvania ("Conemaugh"), and (3) higher
natural gas and power prices. Energy Services total margin in Fiscal 2004 grew
$19.3 million over Fiscal 2003. The total margin increase contributed by UGID's
electric generation business was $10.5 million primarily reflecting the
additional interest in Conemaugh and the previously mentioned higher power
prices. The remaining increase in Energy Services total margin in Fiscal 2004,
generated by Energy Services' gas marketing business, reflects the higher
natural gas volumes sold and winter peaking services.
The increase in Energy Services income before income taxes principally
reflects the previously mentioned increase in total margin partially offset by
higher operating expenses resulting from our purchase of the additional interest
in Conemaugh and the TXU Energy Acquisition.
INTEREST EXPENSE AND INCOME TAXES. Interest expense increased to $119.1 million
in Fiscal 2004 from $109.2 million in Fiscal 2003 due to significantly higher
International Propane interest expense as a result of the Antargaz Acquisition
partially offset by lower AmeriGas Propane interest expense. The Company's
effective income tax rate was 36.6% in Fiscal 2004 and 37.8% in Fiscal 2003.
2003 COMPARED WITH 2002
CONSOLIDATED RESULTS
Variance -
Favorable
2003 2002 (Unfavorable)
---- ---- -------------
% of total % of total
Net Net Net Net Net
Income Income Income Income Income % Change
------ ---------- ------ ------ ---------- --------
(Millions of dollars)
AmeriGas Propane $23.2 23.5% $17.4 23.0% $ 5.8 33.3%
Gas Utility 48.0 48.5% 36.4 48.2% 11.6 31.9%
Electric Utility 10.6 10.7% 5.3 7.0% 5.3 100.0%
Energy Services 11.2 11.3% 7.3 9.7% 3.9 53.4%
International Propane 3.6 3.6% 7.5 9.9% (3.9) (52.0)%
Corporate & Other 2.3 2.3% 1.6 2.1% 0.7 43.8%
----- ----- ----- ----- ----- -----
Total $98.9 100.0% $75.5 100.0% $23.4 31.0%
----- ----- ----- ----- ----- -----
Net income was 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 electric 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 AGZ redeemed in July 2002.
The following table presents certain financial and statistical information
by our principal businesses 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 $ 718.1 $ 654.8 $ 63.3 9.7%
Partnership EBITDA $ 234.4 $ 209.6 $ 24.8 11.8%
Operating income $ 164.5 $ 145.0 $ 19.5 13.4%
Retail gallons sold (millions) 1,074.9 987.5 87.4 8.9%
Degree days - % colder (warmer)
than normal 0.2% (10.0)% - -
GAS UTILITY:
Revenues $ 539.9 $ 404.5 $ 135.4 33.5%
Total margin $ 196.9 $ 162.9 $ 34.0 20.9%
Operating income $ 96.1 $ 77.1 $ 19.0 24.6%
Income before income taxes $ 80.7 $ 62.9 $ 17.8 28.3%
System throughput -
billions of cubic feet ("bcf") 83.8 70.5 13.3 18.9%
Degree days - % colder (warmer)
than normal 7.0% (17.4)% - -
ELECTRIC UTILITY:
Revenues $ 88.8 $ 83.5 $ 5.3 6.3%
Total margin (a) $ 40.3 $ 30.2 $ 10.1 33.4%
Operating income $ 20.3 $ 11.7 $ 8.6 73.5%
Income before income taxes $ 18.0 $ 9.3 $ 8.7 93.5%
Distribution sales - millions of
kilowatt hours ("gwh") 980.0 933.6 46.4 5.0%
ENERGY SERVICES:
Revenues $ 668.0 $ 344.8 $ 323.2 93.7%
Total margin $ 35.6 $ 24.1 $ 11.5 47.7%
Operating income $ 19.2 $ 12.6 $ 6.6 52.4%
Income before income taxes $ 19.2 $ 12.6 $ 6.6 52.4%
INTERNATIONAL PROPANE:
Revenues $ 54.5 $ 46.7 $ 7.8 16.7%
Total margin $ 27.1 $ 24.1 $ 3.0 12.4%
Operating income $ 0.7 $ 3.9 $ (3.2) (82.1)%
Income from equity investees $ 5.9 $ 8.3 $ (2.4) (28.9)%
Income before income taxes $ 2.5 $ 8.0 $ (5.5) (68.8)%
(a) Electric Utility total margin represents total revenues less cost of sales
and Electric Utility gross receipts taxes of $4.8 million and $4.6 million in
2003 and 2002, respectively.
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
16
UGI Corporation 2004 Annual Report
notwithstanding the effects of price-induced customer conservation and, with
respect to commercial and industrial customers, continued 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.
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 realignment 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 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 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 over-collections and, beginning July 1, 2003, the classification of
dividends on preferred shares as a component of interest expense.
ELECTRIC UTILITY. Electric Utility's Fiscal 2003 kilowatt-hour distribution
sales increased principally as a result of weather based upon heating degree
days that was 8.4% colder than normal compared to weather that was 14.5% warmer
than normal in the prior year.
The higher Electric Utility revenues reflect the previously mentioned
increase in Electric Utility kilowatt-hour distribution sales. Beginning
September 2002, Electric Utility began purchasing its power needs exclusively
from third-party electricity suppliers under fixed-price energy and capacity
contracts and, to a much lesser extent, on the spot market. Notwithstanding the
increase in Electric Utility revenues, cost of sales decreased $5.0 million in
Fiscal 2003 due to lower Electric Utility per-unit purchased power costs.
The increase in Electric Utility total margin principally reflects lower
Electric Utility per-unit purchased power costs and the increase in Electric
Utility sales. The higher Fiscal 2003 operating income reflects the greater
total margin partially offset by higher operating and administrative expenses
resulting from higher transmission and distribution expenses and a $0.4 million
decrease in other income. The increase in Electric Utility income before income
taxes reflects the increase in operating income and slightly lower interest
expense.
ENERGY SERVICES. The increase in Energy Services' revenues in Fiscal 2003
resulted from higher natural gas prices, and, to a lesser extent, a more than
40% increase in natural gas volumes sold due in large part to the March 2003 TXU
Energy Acquisition and greater sales of electricity produced by UGID's electric
generation assets. Prior to September 2002, UGID sold substantially all of the
electricity it produced to Electric Utility with the associated revenue and
margin eliminated in our consolidated results. Beginning September 2002, UGID
began selling electric power
17
FINANCIAL REVIEW (continued)
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 2003 purchase of an additional 4.9% (83 megawatt)
interest in Conemaugh. The greater Energy Services' Fiscal 2003 total margin
reflects the increase in natural gas volumes sold partially offset by slightly
lower average unit margins and margin from the greater sales of electricity
produced by UGID's electric generation assets. The increase in total margin was
partially offset by higher operating expenses resulting principally from the TXU
Energy Acquisition, growth initiatives and our purchase of the additional
interest in Conemaugh.
INTERNATIONAL PROPANE. FLAGA's revenues increased $7.8 million, notwithstanding
a 5% decline in volumes sold, primarily reflecting the currency translation
effects of a stronger euro and, to a lesser extent, higher average selling
prices. Volumes were lower in Fiscal 2003 principally due to the loss of a
high-volume, low unit margin customer and, to a lesser extent, price-induced
conservation and continued weak economic activity. The increase in Fiscal 2003
total margin reflects the translation effects of the stronger euro. The decline
in FLAGA's 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.
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
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.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Total cash, cash equivalents and short-term investments were $199.6 million at
September 30, 2004 compared with $192.1 million at September 30, 2003. These
amounts include $114.6 million and $116.3 million, respectively, of cash, cash
equivalents and short-term investments readily available to UGI.
The primary sources of UGI's cash and short-term investments are the cash
dividends it receives from its principal subsidiaries AmeriGas, Inc., UGI
Utilities and Enterprises. AmeriGas, Inc.'s ability to pay dividends to UGI is
largely dependent upon distributions it receives from AmeriGas Partners. At
September 30, 2004, our approximately 46% 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 Third
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 2004, 2003 and 2002 was approximately $118 million, $112 million and $109
million, respectively. Based upon the number of Partnership units outstanding on
September 30, 2004, the amount of Available Cash needed annually to pay the MQD
on all units and the general partner interests is approximately $120 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.
Dividends from Enterprises' indirect subsidiary, Antargaz, are subject to
restrictions under its debt agreements. During Fiscal 2004, the Senior
Facilities Agreement was amended to permit AGZ to pay a one-time cumulative
dividend of approximately $54.4 million which was based on 50% of AGZ's
consolidated net income for the two-year period ended March 31, 2004. The amount
of any dividends expected to be received, based on AGZ's consolidated net income
for the period April 1, 2004 through September 30, 2004, is minimal. The
earliest that dividends relating to AGZ's Fiscal 2005 consolidated net income
can be received is during the first quarter of Fiscal 2006.
During Fiscal 2004, 2003 and 2002, AmeriGas, Inc., UGI Utilities and
Enterprises paid cash dividends to UGI as follows:
Year Ended September 30, 2004 2003 2002
- ----------------------- ------- ------- -------
(Millions of dollars)
AmeriGas, Inc. $ 39.0 $ 44.7 $ 49.4
UGI Utilities 45.0 33.9 37.9
Enterprises 69.4(a) 7.1 23.6(b)
------- ------- -------
Total dividends to UGI $ 153.4 $ 85.7 $ 110.9
------- ------- -------
(a) Includes dividend from Antargaz of $54.4 million.
(b) Includes $17.0 of the proceeds related to the redemption of debt
investments in AGZ.
Dividends received by UGI are available to pay dividends on UGI Common
Stock and for investment purposes.
On July 27, 2004, UGI's Board of Directors declared a quarterly dividend
on UGI Common Stock of $0.3125 per share payable on October 1, 2004 to
shareholders of record on August 31, 2004. UGI raised the annual dividend rate
to $1.25 per share, or $0.3125
18
UGI Corporation 2004 Annual Report
per share on a quarterly basis, from $1.14 per share, or $0.2850 per share on a
quarterly basis, effective with this quarterly dividend.
AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30,
2004 totaled $901.4 million. There were no amounts outstanding under AmeriGas
OLP's Credit Agreement at September 30, 2004.
AmeriGas OLP's Credit Agreement expires on October 15, 2008 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, for working capital and general purposes, subject to
restrictions in the AmeriGas Partners Senior Notes indentures. Issued and
outstanding letters of credit under the Revolving Credit Facility, which reduce
the amount available for borrowings, totaled $45.9 million at September 30,
2004. 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 issued debt securities and common units in
underwritten public offerings in each of the last three fiscal years. Most
recently it issued debt securities in April 2004 and common units in May 2004,
both in underwritten public offerings. Proceeds of its public offerings are used
by the Partnership to reduce indebtedness and for general Partnership purposes,
including funding acquisitions. AmeriGas Partners 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) 1.4 million AmeriGas
Partners Common Units and (2) up to $446.2 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, 2004 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 2005.
INTERNATIONAL PROPANE. At September 30, 2004, Antargaz had total debt
outstanding of $474.5 million. There were no amounts outstanding under the
revolver portion of the Senior Facilities Agreement at September 30, 2004.
Antargaz' Senior Facilities Agreement expires June 30, 2008 and consists
of (1) a euro-denominated variable-rate term loan and (2) a E50 million
revolver. At September 30, 2004, there was E193 million ($240.0 million)
outstanding under the term loan. Principal payments of E9 million on the term
loan are due semi-annually on March 31 and September 30 each year with final
payments of E39 million and E100 million due March 31, 2008 and June 30, 2008,
respectively. The Senior Facilities term loan has been collateralized by
substantially all of Antargaz' shares in its subsidiaries, its equity investee
and by substantially all of its accounts receivable.
In July 2002, AGZ issued E165 million of 10% Senior Notes due 2011 (the
"High Yield Bonds"), through one of its subsidiaries, AGZ Finance ("AGZ
Finance"). Interest on the High Yield Bonds is payable semi-annually on January
15 and July 15. AGZ Finance may redeem the bonds in whole or in part at a
premium commencing July 2006. The High Yield Bonds are listed on the Luxembourg
Exchange. Antargaz' management believes that it will be able to meet its
anticipated contractual commitments and projected cash needs during Fiscal 2005
principally with cash generated from operations.
The Senior Facilities Agreement and the Trust Deed, dated July 23, 2002,
among AGZ Finance, as issuer, AGZ, as guarantor, and the Bank of New York, as
trustee, ("Trust Deed") relating to the High Yield Bonds, restrict the ability
of AGZ to, among other things, incur additional indebtedness, make investments,
incur liens, prepay indebtedness, and effect mergers, consolidations and sales
of assets. Under these agreements, AGZ is generally permitted to make restricted
payments, such as dividends, equal to 50% of consolidated net income, as defined
in each respective agreement, for (1) the immediately preceding fiscal year, in
the case of the Senior Facilities Agreement, and (2) on a cumulative basis since
July 2002, in the case of the Trust Deed, if no event of default exists or would
exist upon payment of such restricted payment. Also, see Note 4 to Consolidated
Financial Statements.
FLAGA has a E15 million working capital loan commitment from a European
bank expiring in November 2005. Borrowings under the working capital facility
totaled E13.8 million ($17.2 million) at September 30, 2004. Debt issued under
this agreement, as well as $71.5 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. FLAGA's
management expects to repay long-term debt maturing in Fiscal 2005 of
approximately $11.6 million principally through cash generated from operations
and capital contributions from UGI.
UGI UTILITIES. UGI Utilities' debt outstanding totaled $278.1 million at
September 30, 2004. Included in this amount is $60.9 million under revolving
credit agreements.
UGI Utilities has revolving credit commitments under which it may borrow
up to a total of $110 million. These agreements are currently scheduled to
expire in June 2007. In addition, UGI Utilities has an uncommitted arrangement
with a major bank from which it may borrow up to $20 million. At September 30,
2004, there were no borrowings outstanding under this arrangement. Amounts
outstanding under the revolving credit agreements and the uncommitted
arrangement are classified as bank loans on the Consolidated Balance Sheets. The
revolving credit agreements
19
FINANCIAL REVIEW (continued)
have restrictions on such items as total debt, debt service and payments for
investments. On October 1, 2004, all 200,000 shares of UGI Utilities' $7.75
preferred shares subject to mandatory redemption were redeemed at a price of
$100 per share together with full cumulative dividends. The redemption was
funded with proceeds from the issuance of $20 million of 6.13% Medium-Term Notes
due October 2034. UGI Utilities has a shelf registration statement with the SEC
under which it may issue up to an additional $20 million of Medium-Term Notes or
other debt securities. In order to provide additional short-term liquidity
during the peak-heating season, on November 1, 2004, UGI Utilities borrowed $20
million under the uncommitted arrangement with a major bank which is scheduled
to mature on March 1, 2005. Based upon cash expected to be generated from Gas
Utility and Electric Utility operations, short-term borrowings, including
borrowings available under revolving credit agreements and the availability of
its Medium-Term Notes, UGI Utilities' management believes that it will be able
to meet its anticipated contractual and projected cash commitments during Fiscal
2005. 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 $150 million receivables purchase
facility ("Receivables Facility") with an issuer of receivables-backed
commercial paper expiring in August 2007, although the Receivables Facility may
terminate prior to such date due to the termination of commitments of the
Receivables Facility's 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 $150 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, 2004, the
outstanding balance of ESFC trade receivables was $63.4 million of which no
amount was 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 2005.
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 in April
2005.
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 other
LPG 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/or 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 $257.8 million in
Fiscal 2004, $249.1 million in Fiscal 2003, and $247.5 million in Fiscal 2002.
Cash flow from operating activities before changes in operating working capital
was $330.1 million in Fiscal 2004, $256.3 million in Fiscal 2003, and $233.7
million in Fiscal 2002. Changes in operating working capital used $72.3 million
and $7.2 million of cash in Fiscal 2004 and Fiscal 2003, respectively, and
provided $13.8 million of cash in Fiscal 2002. The increase in cash used for
working capital in Fiscal 2004 reflects the effect of higher natural gas and
propane commodity costs and changes in Gas Utility deferred fuel costs partially
offset by cash provided by Antargaz due in part to net changes in accounts
receivable and accounts payable since March 31, 2004.
INVESTING ACTIVITIES. Cash flow used in investing activities was $412.8 million
in Fiscal 2004, $226.1 million in Fiscal 2003, and $66.4 million in Fiscal 2002.
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 2004, we spent $133.7 million for
property, plant and equipment, an increase of $32.8 million from Fiscal 2003,
principally reflecting Antargaz capital expenditures during the six months ended
September 30, 2004 and increased Partnership capital expenditures. Cash paid for
business acquisitions in Fiscal 2004 principally reflects the Antargaz
Acquisition.
FINANCING ACTIVITIES. Cash flow provided by financing activities was $161.9
million in Fiscal 2004 compared to cash flow used of $75.3 million in Fiscal
2003 and $74.3 million in Fiscal 2002. 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 March 2004, 7.5 million shares of UGI Common Stock were sold in an
underwritten public offering at a public offering price of $32.10 per share.
During April 2004, the underwriters exercised a portion of their overallotment
option for the purchase of an additional 0.3 million shares. The proceeds of
approximately $239 million from this issuance were primarily used to fund the
Antargaz Acquisition.
In May 2004, AmeriGas Partners sold 2.0 million Common Units in an
underwritten public offering at a public offering price of $25.61 per unit. In
June 2004, the underwriters partially exercised their overallotment option in
the amount of 0.1 million Common Units. The net proceeds of the public offering
totaling $51.2 million, and associated capital contributions from the General
Partner totaling $1.0 million, were contributed to AmeriGas OLP and used
20
UGI Corporation 2004 Annual Report
to reduce indebtedness under its bank credit agreement and for general
partnership purposes. Concurrent with this sale of Common Units, the Company
recorded a gain in the amount of $12.2 million, which is reflected in the
Company's balance sheet as an increase in common stockholders' equity and a
corresponding decrease in minority interests in AmeriGas Partners, in accordance
with the guidance in SEC Staff Accounting Bulletin, No. 51, "Accounting for
Sales of Common Stock by a Subsidiary" ("SAB 51"). Deferred income tax
liabilities of $6.6 million associated with this gain were recorded with a
corresponding decrease in stockholders' equity and reflected in the Consolidated
Balance Sheet. The gain had no effect on the Company's net income or cash flow.
The gain resulted because the public offering price of the AmeriGas Partners
Common Units exceeded the associated carrying amount of our investment in the
Partnership on the date of their sale.
In April 2004, AmeriGas OLP repaid $53.8 million face amount of maturing
First Mortgage Notes. In conjunction with this repayment, AmeriGas Partners
issued $28 million face amount of 8.875% Senior Notes due 2011 at an effective
rate of 7.18% and contributed the net proceeds of $30.1 million to AmeriGas OLP.
During Fiscal 2004 we paid cash dividends on UGI Common Stock of $56.3
million and the Partnership paid the MQD on all limited partner units.
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 were determined in accordance with the guidance in
SAB 51. 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. In addition, in June 2003, AmeriGas Partners sold 2,900,000 Common
Units in an underwritten public offering. Concurrent with this sale of Common
Units, the Company recorded a gain in the amount of $22.6 million which is
reflected in the Company's balance sheet as an increase in common stockholders'
equity in accordance with the guidance in SAB 51. Total deferred income tax
liabilities of $70.7 million associated with these gains were recorded with a
corresponding decrease in stockholders' equity and reflected in the restated
Consolidated Balance Sheet at September 30, 2003. The changes to the Company's
balance sheet resulting from the Subordinated Unit conversion and subsequent
sale of AmeriGas Partners Common Units 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. The
fair value of Pension Plan assets was $196.4 million and $183.9 million at
September 30, 2004 and 2003, respectively. At September 30, 2004 and 2003, the
Pension Plan's assets exceeded its accumulated benefit obligations by $9.2
million and $7.3 million, respectively. The Company is in full compliance with
regulations governing defined benefit pension plans, including Employee
Retirement Income Security Act of 1974 ("ERISA") rules and regulations, and does
not anticipate it will be required to make a contribution to the Pension Plan in
Fiscal 2005. Pre-tax pension expense (income) reflected in Fiscal 2004, 2003 and
2002 results was $1.2 million, $(1.1) million and $(4.0) million, respectively.
The decrease in pension income during this period principally reflects the
changes in the market value of Pension Plan assets and decreases in the discount
rate assumption. Pension expense in Fiscal 2005 is expected to be approximately
$3.0 million due in large part to the expiration of the Pension Plan's
transition asset amortization.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures (which exclude
acquisitions) by our businesses for Fiscal 2004, 2003 and 2002. We also provide
amounts we expect to spend in Fiscal 2005. We expect to finance Fiscal 2005
capital expenditures principally from cash generated by operations and
borrowings under our credit facilities.
2005 2004 2003 2002
Year Ended September 30, -------- -------- -------- --------
(Millions of dollars) (estimate)
AmeriGas Propane $ 62.4 $ 61.7 $ 53.4 $ 53.5
International Propane 45.2 27.6 4.5 3.9
Gas Utility 41.4 35.5 37.2 31.0
Electric Utility 9.6 5.3 4.1 4.6
Energy Services 7.1 2.9 1.0 1.2
Other 0.9 0.7 1.2 0.5
-------- -------- -------- --------
Total $ 166.6 $ 133.7 $ 101.4 $ 94.7
-------- -------- -------- --------
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The Company has contractual cash obligations that extend beyond Fiscal 2004
including scheduled repayments of long-term debt, operating lease payments,
unconditional purchase obligations for pipeline capacity, pipeline
transportation and natural gas storage services, commitments to purchase natural
gas, propane and electricity and prior to their redemption on
21
FINANCIAL REVIEW (continued)
October 1, 2004, UGI Utilities preferred shares subject to mandatory redemption.
The following table presents contractual cash obligations under agreements
existing as of September 30, 2004 (in millions).
Payments Due by Period
----------------------------------------------------------------
1 year 2 - 3 4 - 5 After
Total or less years years 5 years
-------- -------- -------- -------- --------
Long-term debt $1,634.5 $ 117.4 $ 348.7 $ 354.2 $ 814.2
UGI Utilities preferred
shares subject to
mandatory redemption 20.0 20.0 - - -
Operating leases 221.8 46.5 73.7 51.4 50.2
AmeriGas Propane
supply contracts 12.8 12.8 - - -
International Propane
supply contracts 271.1 109.4 161.6 - -
Energy Services supply
contracts 510.6 449.4 61.2 - -
Gas Utility and Electric
Utility supply,
storage and
transportation contracts 598.3 188.5 181.3 112.3 116.3
-------- -------- -------- -------- --------
Total $3,269.1 $ 944.0 $ 826.5 $ 517.9 $ 980.7
-------- -------- -------- -------- --------
RELATED PARTY TRANSACTIONS
During Fiscal 2004, 2003 and 2002, the Company did not enter into any related
party transactions that had a material effect on its financial condition,
results of operations or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off balance sheet arrangements that are expected to have a
material effect on the Company's financial condition, change in financial
condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources.
UTILITY REGULATORY MATTERS
Since the 1980s, larger commercial and industrial customers have been able to
purchase gas supplies from entities other than Gas Utility. As a result of
Pennsylvania's Natural Gas Choice and Competition Act (the "Gas Competition
Act") that became effective July 1, 1999, all natural gas consumers in
Pennsylvania, including residential and smaller commercial and industrial
customers ("core-market customers"), have been afforded this opportunity. Under
the Gas Competition Act, natural gas distribution companies ("NGDCs"), like Gas
Utility, continue to serve as the supplier of last resort for all core-market
customers, and such sales of gas, as well as the distribution service provided
by NGDCs, continue to be subject to rate regulation by the PUC. As of September
30, 2004, less than two percent of Gas Utility's core market customers purchase
their gas from alternative suppliers.
As a result of the Electricity Generation Customer Choice and Competition
Act (the "Electric Competition Act") that became effective January 1, 1997, all
of Electric Utility's customers have the ability to acquire their electricity
from entities other than Electric Utility. Electric Utility remains the provider
of last resort ("POLR") for its customers that are not served by an alternate
electric generation provider. The terms and conditions under which Electric
Utility provides POLR service, and rules governing the rates that may be charged
for such service, have been established in a series of PUC-approved settlements,
the latest of which became effective on June 7, 2004 (collectively, the "POLR
Settlement").
Electric Utility's POLR service rules provide 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 are
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. Commercial and industrial 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 will increase beginning January 2005, and Electric Utility is permitted,
but not required, to further increase its POLR rates beginning January 2006.
Electric Utility is also permitted to, and has, entered into multiple-year
fixed-rate POLR service contracts with certain of its customers.
Pursuant to the requirements of the Electric Competition Act, the PUC is
currently developing post-rate-cap POLR regulations that are expected to further
define POLR service obligations and pricing. As of September 30, 2004, fewer
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 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. 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. We believe that SFAS 71 continues to apply to our regulated
operations and that the recovery of our regulatory assets is probable.
22
UGI Corporation 2004 Annual Report
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 private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries. Such 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. 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.
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.
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 and is defending the suit.
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 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.
AGL previously informed UGI Utilities that it was investigating
contamination that appeared to be related to MGP operations at a site owned by
AGL in Savannah, Georgia. A former subsidiary of UGI Utilities' operated the MGP
in the early 1900s. AGL has recently informed UGI Utilities that it has begun
remediation of MGP wastes at the site and believes that the total cost of
remediation could be as high as $55 million. AGL has not filed suit against UGI
Utilities for a share of these costs. UGI Utilities believes that it will have
good defenses to any action that may arise out of this site.
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. By orders issued in November 2003 and March
2004, the court granted UGI Utilities' motion for summary judgment and dismissed
ConEd's complaint. ConEd has appealed.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI
Utilities that KeySpan has spent $2.3 million and expects to spend another $11
million to clean up an MGP site it owns in Sag Harbor, New York. KeySpan
believes that UGI Utilities is responsible for approximately 50% of these costs
as a result of UGI Utilities' alleged direct ownership and operation of the
plant from 1885 to 1902. UGI Utilities is in the process of reviewing the
information provided by KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut
Light and Power Company, subsidiaries of Northeast Utilities, (together, the
"Northeast Companies"), demanded contribution from UGI Utilities for past and
future remediation costs related to MGP operations on thirteen sites owned by
the Northeast Companies in nine cities in the State of Connecticut. The
Northeast Companies allege that UGI Utilities controlled operations of the
plants from 1883 to 1941. According to the letter, investigation and remedial
costs at the sites to date total approximately $10 million and complete
remediation costs for all sites could total $182 million. The Northeast
Companies seek an unspecified fair and equitable allocation of these costs to
UGI Utilities. UGI Utilities is in the process of reviewing the information
provided by Northeast Companies and is investigating this claim.
23
FINANCIAL REVIEW (continued)
MARKET RISK DISCLOSURES
Our primary market risk exposures are (1) market prices for propane and other
LPG, 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 LPG 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 passes on increases in such
costs to customers. The Partnership may not, however, always be able to pass
through product cost increases fully or on a timely basis, 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 sensitive to changes
in LPG supply costs and International Propane generally passes on increases in
such costs to customers. International Propane may not, however, always be able
to pass through product cost increases fully or on a timely basis, particularly
when product costs rise rapidly. In order to reduce the long-term volatility of
Antargaz' LPG market price risk, Antargaz intends to hedge a portion of its
future U.S. dollar denominated LPG product purchases through the use of
derivative instruments, including forward foreign exchange contracts. Antargaz
may also enter into other contracts, similar to those used by the Partnership to
reduce the volatility in the cost of LPG that it purchases. 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 any associated gains,
is included in Gas Utility's PGC recovery mechanism.
Electric Utility purchases its electric power needs from electricity
suppliers under fixed-price energy and capacity contracts and, to a much lesser
extent, on the spot market. Prices for electricity can be volatile especially
during periods of high demand or tight supply. In accordance with POLR
settlements approved by the PUC, Electric Utility may increase its POLR rates up
to certain limits through December 31, 2006. In accordance with these
settlements, effective January 1, 2005 and January 1, 2006, POLR generation
rates for all metered customers may increase up to 4.5% and 7.5%, respectively,
of total rates in effect on December 31, 2004. The approved POLR rate increases
are not expected to have a material effect on our financial condition or results
of operations. Currently, Electric Utility's fixed-price contracts with
electricity suppliers mitigate most risks associated with the POLR service rate
limits in effect through December 31, 2006. However, should any of the suppliers
under these contracts fail to provide electric power under the terms of the
power and capacity contracts, any increases in the cost of replacement power or
capacity would negatively impact Electric Utility results. In order to reduce
this non performance risk, Electric Utility has diversified its purchases across
several suppliers and entered into bilateral collateral arrangements with
certain of them.
In order to manage market price risk relating to substantially all of
Energy Services' forecasted fixed-price sales of natural gas, 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.
UGID has entered into fixed-price sales agreements for a portion of the
electricity expected to be generated by its interests in electric generation
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.
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 Antargaz' and FLAGA's debt. These debt agreements have
interest rates that are generally indexed to short-term market interest rates.
Antargaz has effectively fixed the interest rate on a portion of their
variable-rate debt through June 2005 through the use of
24
UGI Corporation 2004 Annual Report
interest rate swaps. At September 30, 2004 and 2003, combined borrowings
outstanding under these agreements totaled $393.4 million and $119.7 million,
respectively. Excluding the effectively fixed portion of Antargaz' variable-rate
debt, based upon weighted average borrowings outstanding under these agreements
during Fiscal 2004 and Fiscal 2003, an increase in short-term interest rates of
100 basis points (1%) would have increased our interest expense by $2.1 million
and $1.8 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 $61.8 million and $57.1
million at September 30, 2004 and 2003, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $66.6 million and $61.7 million at September 30, 2004 and
2003, 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 a portion of near-term forecasted issuances
of fixed-rate debt, we often 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. 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
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 $37.3 million, which amount would be reflected in other
comprehensive income. In March 2004, the Company entered into a foreign currency
swap agreement to hedge a portion of its net investment in foreign operations.
This foreign currency swap agreement was designated as a net investment hedge in
a foreign subsidiary and qualified for hedge accounting. Therefore, upon
settlement in July 2004, a loss of $1.0 million was recorded in other
comprehensive income. Any realized gains or losses associated with net
investments in foreign operations will remain in other comprehensive income
until such foreign operations have been liquidated. From time to time, the
Company may use derivative instruments to hedge additional portions of its net
investments in foreign subsidiaries.
The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at September 30, 2004 and 2003. Fair
values 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, 2004. The table also includes the changes
in fair value that would result if there were a ten percent adverse change in
(1) the market price of propane; (2) the market price of natural gas; (3) the
market price of electricity; and (4) interest rates on ten-year U.S. treasury
notes.
Change in
Fair Value Fair Value
(Millions of dollars) ---------- ----------
September 30, 2004:
Propane commodity price risk $13.1 $(13.8)
Natural gas commodity price risk 4.8 (3.4)
Electricity commodity price risk 2.0 (1.0)
Interest rate risk (2.8) (6.3)
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)
Gas Utility's exchange traded natural gas call option contracts are
excluded from the table above because any associated net gains 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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with accounting principles generally accepted in the United States of America
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
25
UGI Corporation 2004 Annual Report
FINANCIAL REVIEW (continued)
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 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 and cash flows. As of September 30, 2004, our regulatory assets
totaled $65.0 million. See Note 1 to the Consolidated Financial Statements.
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.
PURCHASE PRICE ALLOCATION. From time to time, the Company enters into material
business combinations. In accordance with SFAS No. 141, "Business Combinations"
("SFAS 141"), the purchase price is allocated to the various assets and
liabilities acquired at their estimated fair value. Fair values of assets and
liabilities are based upon available information and may involve us engaging an
independent third party to perform an appraisal. Estimating fair values can be a
complex and judgmental area and most commonly impacts property, plant and
equipment and intangible assets, including those with indefinite lives.
Generally, we have, if necessary, up to one year from the acquisition date to
finalize the purchase price allocation.
IMPAIRMENT OF GOODWILL. Certain of the Company's business units have goodwill
resulting from purchase business combinations. In accordance with SFAS No. 142,
"Goodwill and Other Intangible Assets" ("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, 2004, our
goodwill totaled $1,245.9 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.
Changes in plan assumptions as well as fluctuations in actual equity or bond
market returns could have a material impact on future pension costs. We believe
the two most critical assumptions are the expected rate of return on plan assets
and the discount rate. An unfavorable change in the expected rate of return on
plan assets of 50 basis points would result in higher pre-tax pension expense of
approximately $1.0 million in Fiscal 2005. An unfavorable change in the discount
rate of 50 basis points would result in higher pre-tax pension expense of $1.5
million in Fiscal 2005.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In December 2003, the Financial
Accounting Standards Board ("FASB") revised Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities" ("FIN 46"), which was originally
issued in January 2003 and clarifies Accounting Research Bulletin No. 51,
"Consolidated Financial Statements." FIN 46 was effective immediately for
variable interest entities created or obtained after January 31, 2003. For
variable interest entities created or acquired before February 1, 2003, FIN 46
was effective beginning with our interim period ended March 31, 2004. If certain
conditions are met, FIN 46 requires the primary beneficiary to consolidate
certain variable interest entities. The adoption of FIN 46, as revised, did not
have a material effect on the Company's financial position, results of
operations or cash flows.
On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Act") was signed into law. Among other things,
the Act provides for a prescription drug benefit to Medicare beneficiaries on a
voluntary
26
UGI Corporation 2004 Annual Report
basis beginning in 2006. To encourage employers to continue to offer retiree
prescription drug benefits, the Act provides for a tax-free subsidy to employers
who offer a prescription drug benefit that is at least actuarially equivalent to
the standard benefit offered under the Act. In May 2004, the FASB issued Staff
Position No. FAS 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003" ("FSP
106-2"). FSP 106-2 is effective for periods beginning after June 15, 2004.
The Company provides postretirement health care benefits to certain of its
retirees and a limited number of active employees meeting certain age and
service requirements. See Note 6 to the Consolidated Financial Statements for
information on our Employee Retirement Plans. These postretirement benefits
include certain retiree prescription drug benefits. The Company has determined
that, as currently designed, its prescription drug benefit for retirees is not
actuarially equivalent to the standard benefit offered under the Act and, as a
result, does not qualify for the tax-free subsidy.
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) cost volatility and availability of
propane and other LPG, oil, electricity, and natural gas and the capacity to
transport product to our market areas; (3) changes in domestic and foreign 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 in excess of insurance coverage 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, propane and LPG; (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 the federal securities laws.
27
UGI Corporation 2004 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. However, this report is not the same as the report of
management on the effectiveness of internal control over financial reporting
that will be included in the Company's annual report on Form 10-K for the fiscal
year ending September 30, 2005.
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 account ants 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 among the
Board of Directors, management, and both the independent accountants and
internal auditors.
The independent accountants, whose appointment is ratified by the
shareholders, perform certain procedures 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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 (the "Company") at September 30, 2004 and
2003, and the results of their operations and their cash flows for each of the
three years in the period ended September 30, 2004 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 the
standards of the Public Company Accounting Oversight Board (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, 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.
In fiscal 2002, the Company adopted Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets."
As discussed in Note 2 to the financial statements, the 2003 consolidated
balance sheet and statement of stockholders' equity have been restated to record
deferred income tax liabilities on the conversion of the Company's subordinated
units in AmeriGas Partners, L.P., which occurred in November 2002, and upon
subsequent sales by the Partnership of units to the public.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
December 6, 2004
28
UGI Corporation 2004 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30,
------------------------
2004 2003 2002
---------- ---------- ----------
REVENUES
AmeriGas Propane $ 1,775.9 $ 1,628.4 $ 1,307.9
Utilities 650.1 628.7 488.0
International Propane 333.4 54.5 46.7
Energy Services and other 1,025.3 714.5 371.1
---------- ---------- ----------
3,784.7 3,026.1 2,213.7
---------- ---------- ----------
COSTS AND EXPENSES
Cost of sales 2,526.9 1,984.3 1,296.6
Operating and administrative expenses 790.5 644.1 576.5
Utility taxes other than income taxes 12.5 12.2 11.9
Depreciation and amortization 132.3 103.0 93.5
Other income, net (8.8) (19.8) (18.1)
---------- ---------- ----------
3,453.4 2,723.8 1,960.4
---------- ---------- ----------
OPERATING INCOME 331.3 302.3 253.3
Income from equity investees 11.3 5.3 8.5
Loss on extinguishments of debt - (3.0) (0.7)
Interest expense (119.1) (109.2) (109.1)
Minority interests, principally in AmeriGas Partners (47.5) (34.6) (28.0)
---------- ---------- ----------
INCOME BEFORE INCOME TAXES AND SUBSIDIARY PREFERRED STOCK DIVIDENDS 176.0 160.8 124.0
Income taxes (64.4) (60.7) (46.9)
Dividends on UGI Utilities preferred shares subject to mandatory
redemption - (1.2) (1.6)
---------- ---------- ----------
NET INCOME $ 111.6 $ 98.9 $ 75.5
---------- ---------- ----------
EARNINGS PER COMMON SHARE:
Basic $ 2.36 $ 2.34 $ 1.83
========== ========== ==========
Diluted $ 2.31 $ 2.29 $ 1.80
========== ========== ==========
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS):
Basic 47.308 42.220 41.325
========== ========== ==========
Diluted 48.341 43.236 41.907
========== ========== ==========
See accompanying notes to consolidated financial statements.
29
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30,
-----------------------
Restated
2004 2003
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 149.6 $ 142.1
Short-term investments (at cost, which approximates fair value) 50.0 50.0
Accounts receivable (less allowances for doubtful accounts of $22.3 and $14.8, respectively) 367.3 213.1
Accrued utility revenues 9.7 7.4
Inventories 198.4 136.6
Deferred income taxes 14.9 23.5
Prepaid expenses and other current assets 46.6 28.6
-------- --------
Total current assets 836.5 601.3
-------- --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 1,121.3 1,076.2
International Propane 525.7 76.4
UGI Utilities 944.3 907.9
Other 83.0 81.5
-------- --------
2,674.3 2,142.0
Accumulated depreciation and amortization (892.4) (805.2)
-------- --------
Net property, plant, and equipment 1,781.9 1,336.8
-------- --------
OTHER ASSETS
Goodwill and excess reorganization value 1,245.9 671.5
Intangible assets (less accumulated amortization of $27.5 and $16.4, respectively) 184.4 34.7
Utility regulatory assets 65.0 60.3
Other assets 121.7 90.6
-------- --------
Total assets $4,235.4 $2,795.2
======== ========
See accompanying notes to consolidated financial statements.
30
UGI Corporation 2004 Annual Report
September 30,
---------------------
Restated
2004 2003
-------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 122.8 $ 65.0
UGI Utilities bank loans 60.9 40.7
Other bank loans 17.2 15.9
UGI Utilities preferred shares subject to mandatory redemption, without par value 20.0 -
Accounts payable 323.9 202.5
Employee compensation and benefits accrued 87.7 41.9
Dividends and interest accrued 43.0 40.1
Income taxes accrued 2.0 8.9
Deposits and advances 98.7 83.0
Other current liabilities 146.6 86.2
-------- --------
Total current liabilities 922.8 584.2
-------- --------
DEBT AND OTHER LIABILITIES
Long-term debt 1,547.3 1,158.5
Deferred income taxes 441.4 293.8
Deferred investment tax credits 7.6 8.0
UGI Utilities preferred shares subject to mandatory redemption, without par value - 20.0
Other noncurrent liabilities 303.8 97.4
-------- --------
Total liabilities 3,222.9 2,161.9
-------- --------
Commitments and contingencies (Note 12)
Minority interests, principally in AmeriGas Partners 178.4 134.6
COMMON STOCKHOLDERS' EQUITY
Common Stock, without par value
(authorized - 150,000,000 shares; issued - 57,576,497 and 49,798,097 shares, respectively) 762.8 511.7
Retained earnings 146.2 90.9
Accumulated other comprehensive income 22.6 4.7
Notes receivable from employees (0.2) (0.4)
-------- --------
931.4 606.9
Treasury stock, at cost (97.3) (108.2)
-------- --------
Total common stockholders' equity 834.1 498.7
-------- --------
Total liabilities and stockholders' equity $4,235.4 $2,795.2
======== ========
31
UGI Corporation 2004 Annual Report
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30,
---------------------------------
2004 2003 2002
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 111.6 $ 98.9 $ 75.5
Reconcile to net cash provided by operating activities:
Depreciation and amortization 132.3 103.0 93.5
Minority interests 47.5 34.6 28.0
Deferred income taxes, net 3.0 (2.8) 11.0
Provision for uncollectible accounts 17.3 18.5 14.2
Net change in settled accumulated other comprehensive income 9.0 (5.2) 13.3
Other, net 9.4 9.3 (1.8)
Net change in:
Accounts receivable and accrued utility revenues 4.9 (56.1) 10.7
Inventories (39.4) (25.3) 19.7
Deferred fuel costs (6.9) 19.0 (7.1)
Accounts payable (49.7) 34.9 (0.4)
Other current assets and liabilities 18.8 20.3 (9.1)
------- ------- -------
Net cash provided by operating activities 257.8 249.1 247.5
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (133.7) (100.9) (94.7)
Acquisitions of businesses, net of cash acquired (308.6) (38.6) (0.7)
Acquisition of additional interest in Conemaugh Station - (51.3) -
Proceeds from redemption of AGZ Bonds - - 17.7
Net proceeds from disposals of assets 11.5 5.9 9.7
Investments in equity investees - (0.4) (0.3)
Increase in short-term investments - (50.0) -
Other, net 18.0 9.2 1.9
------- ------- -------
Net cash used by investing activities (412.8) (226.1) (66.4)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock (56.3) (47.7) (44.8)
Distributions on AmeriGas Partners publicly held Common Units (62.4) (56.4) (53.5)
Issuance of long-term debt 30.1 167.8 81.1
Repayment of long-term debt (77.4) (236.5) (105.0)
AmeriGas Propane bank loans (decrease) increase - (10.0) 10.0
UGI Utilities bank loans increase (decrease) 20.2 3.5 (20.6)
Other bank loans increase (decrease) 0.1 5.4 (2.2)
Issuance of AmeriGas Partners Common Units 51.2 75.0 49.7
Issuance of UGI Common Stock 257.0 23.7 11.0
Repurchases of UGI Common Stock (0.6) (0.1) -
------- ------- -------
Net cash provided (used) by financing activities 161.9 (75.3) (74.3)
------- ------- -------
EFFECT OF EXCHANGE RATE CHANGES ON CASH 0.6 0.1 -
------- ------- -------
Cash and cash equivalents increase (decrease) $ 7.5 $ (52.2) $ 106.8
======= ======= =======
CASH AND CASH EQUIVALENTS:
End of year $ 149.6 $ 142.1 $ 194.3
Beginning of year 142.1 194.3 87.5
------- ------- -------
(Decrease) increase $ 7.5 $ (52.2) $ 106.8
======= ======= =======
See accompanying notes to consolidated financial statements.
32
UGI Corporation 2004 Annual Report
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Millions of dollars, except per share amounts)
Accumulated Notes
Other Receivable
Common Retained Comprehensive from Treasury
Stock Earnings Income (Loss) Employees Stock Total
------ -------- ------------- --------- -------- ---------
BALANCE SEPTEMBER 30, 2001 $395.0 $ 9.0 $ (13.5) $ (4.6) $ (134.9) $ 251.0
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)
Payments on notes receivable from employees 1.1 1.1
------ -------- ------------ --------- -------- ---------
BALANCE SEPTEMBER 30, 2002 396.6 39.7 6.6 (3.5) (125.6) 313.8
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 (loss) 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
Net gain in connection with issuances of units
by AmeriGas Partners (net of tax of $70.7),
as restated 108.9 108.9
Common Stock reacquired (0.1) (0.1)
Payments on notes receivable from employees 3.1 3.1
------ -------- ------------ --------- -------- ---------
BALANCE SEPTEMBER 30, 2003, AS RESTATED 511.7 90.9 4.7 (0.4) (108.2) 498.7
Net income 111.6 111.6
Net gain on derivative instruments
(net of tax of $15.0) 22.6 22.6
Reclassification of net gains on
derivative instruments (net of tax of $6.9) (10.6) (10.6)
Foreign currency translation adjustments
(net of tax of $0.9) 5.9 5.9
-------- ------------ ---------
Comprehensive income 111.6 17.9 129.5
Cash dividends on Common Stock
($1.20 per share) (56.3) (56.3)
Common Stock issued:
Public offering 239.6 239.6
Employee and director plans 4.6 10.3 14.9
Dividend reinvestment plan 1.3 1.2 2.5
Net gain in connection with issuances of units
by AmeriGas Partners (net of tax of $6.6) 5.6 5.6
Common Stock reacquired (0.6) (0.6)
Payments on notes receivable from employees 0.2 0.2
------ -------- ------------ --------- -------- ---------
BALANCE SEPTEMBER 30, 2004 $762.8 $ 146.2 $ 22.6 $ (0.2) $ (97.3) $ 834.1
====== ======== ============ ========= ======== =========
See accompanying notes to consolidated financial statements.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, 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 a joint-venture affiliate, UGI also
distributes liquefied petroleum gases ("LPG") in France, Austria, the Czech
Republic, Slovakia and China. We refer to UGI and its consolidated subsidiaries
collectively as "the Company" or "we."
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, 2004, the General Partner and its wholly
owned subsidiary Petrolane Incorporated ("Petrolane") collectively held a 1%
general partner interest and a 44.6% limited partner interest in AmeriGas
Partners, and effective 46.1% and 46.0% ownership interests in AmeriGas OLP and
Eagle OLP, respectively. Our limited partnership interest in AmeriGas Partners
comprises 24,525,004 Common Units. The remaining 54.4% interest in AmeriGas
Partners comprises 29,948,268 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 and higher relative interest
charges.
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") (1)
conducts a propane and butane-based LPG distribution business in France through
its subsidiary UGI France, Inc. ("UGI France"); (2) conducts an LPG distribution
business in Austria, the Czech Republic and Slovakia ("FLAGA"); and (3)
participates in an LPG joint-venture business in the Nantong region of China. We
refer to our foreign operations collectively as "International Propane." Our LPG
distribution business in France is conducted through Antargaz, an operating
subsidiary of AGZ Holding ("AGZ"), and its operating subsidiaries (collectively,
"Antargaz").
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 electric 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").
In addition, 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 electric generation assets. Prior to its transfer to Energy
Services in June 2003, UGID was a wholly owned subsidiary of UGI Utilities.
Through other subsidiaries, Enterprises owns and operates a heating,
ventilation, air-conditioning and refrigeration service business in the Middle
Atlantic States ("HVAC/R").
UGI is exempt from registration as a holding company and not otherwise
subject to regulation under the Public Utility Holding Company Act of 1935
except for acquisitions under section 9(a)(2) because it files an annual
exemption statement with the U.S. Securities and Exchange Commission ("SEC").
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 and other parties' interests in our
consolidated, but less than 100% owned subsidiaries of Antargaz as minority
interests. Entities in which we own 50% or less and in which we exercise
significant influence over operating and financial policies are accounted for by
the equity method (see Note 17). Effective with our March 31, 2004 acquisition
of the remaining 80.5% ownership interests in AGZ, we began consolidating all of
its operations (see Note 3). Investments in equity investees are included in
other assets in the Consolidated Balance Sheets. Gains resulting from the
issuances and sales of AmeriGas Partners' common units are recorded as an
increase to common stockholders' equity with a corresponding decrease in
minority interests in accordance with SEC Staff Accounting Bulletin No. 51,
"Accounting for Sales of Common Stock by a Subsidiary." In addition, we record
deferred income tax liabilities with a corresponding reduction in stockholders'
equity associated with such gains (see Notes 2 and 16).
RECLASSIFICATIONS. We have reclassified certain prior-year balances to conform
to the current-year presentation.
34
UGI Corporation 2004 Annual Report
USE OF ESTIMATES. We make estimates and assumptions when preparing financial
statements in conformity with accounting principles generally accepted in the
United States of America. These estimates and assumptions affect the reported
amounts of assets and liabilities, revenues and expenses, as well as the
disclosure of contingent assets and liabilities. Actual results could differ
from these estimates.
REGULATED UTILITY OPERATIONS. 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. 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. We believe that
SFAS 71 continues to apply to our regulated utility operations and that the
recovery of our regulatory assets is probable.
Regulatory assets and liabilities associated with Gas Utility and Electric
Utility operations included in our accompanying balance sheets at September 30
comprise the following:
2004 2003
---- ----
Regulatory assets:
Income taxes recoverable $ 62.0 $ 57.6
Other postretirement benefits 1.9 2.2
Other 1.1 0.5
------- -------
Total regulatory assets $ 65.0 $ 60.3
------- -------
Regulatory liabilities:
Other postretirement benefits $ 3.0 $ 3.8
Deferred fuel costs 7.9 14.7
------- -------
Total regulatory liabilities $ 10.9 $ 18.5
------- -------
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.
DERIVATIVE INSTRUMENTS. SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" ("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 lia-
bilities 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. 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 $117.7 in 2004, $109.8 in 2003 and $106.2 in
2002. We paid income taxes totaling $70.2 in 2004, $48.2 in 2003 and $48.0 in
2002.
REVENUE RECOGNITION. We recognize revenues from the sale of propane and other
LPG 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, propane and other
LPG, specific identification for appliances and the first-in, first-out ("FIFO")
method for all other inventories.
EARNINGS PER COMMON SHARE. Basic earnings per share reflect the weighted-average
number of common shares outstanding. Diluted earnings per share include the
effects of dilutive stock options and common stock awards. In the following
table, we present shares used in computing basic and diluted earnings per share
for 2004, 2003 and 2002:
2004 2003 2002
---- ---- ----
Denominator (millions of shares):
Average common shares
outstanding for basic computation 47.308 42.220 41.325
Incremental shares issuable for
stock options and awards 1.033 1.016 0.582
------ ------ ------
Average common shares outstanding for
diluted computation 48.341 43.236 41.907
------ ------ ------
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.
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 1 continued
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 income 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.
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 both 2004 and 2003 and 2.5% in
2002. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 2.8% in 2004 and 3.0% in both 2003 and 2002. We
compute depreciation expense on plant and equipment associated with our LPG
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 12 years for vehicles,
equipment, and office furniture and fixtures. We compute depreciation expense on
plant and equipment associated with our electric generation assets on a
straight-line basis over 25 years. Depreciation expense was $119.9 in 2004,
$97.1 in 2003 and $88.2 in 2002.
Costs to install Partnership-owned tanks, net of amounts billed to
customers, are capitalized and amortized over the estimated period of benefit
not exceeding ten years.
INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2004 2003
---- ----
Not subject to amortization:
Goodwill $ 1,152.6 $ 578.2
Excess reorganization value 93.3 93.3
---------- --------
$ 1,245.9 $ 671.5
---------- --------
Other intangible assets:
Customer relationships, noncompete
agreements and other $ 169.7 $ 51.1
Trademark (not subject to amortization) 42.2 -
---------- --------
Gross carrying amount 211.9 51.1
---------- --------
Accumulated amortization (27.5) (16.4)
---------- --------
Net carrying amount $ 184.4 $ 34.7
---------- --------
The increase in the carrying amount of intangible assets during the year
ended September 30, 2004 is principally the result of the acquisition of the
remaining 80.5% ownership interests in AGZ and other smaller acquisitions. The
increase in goodwill was slightly offset by the settlement of an income tax
benefit held by Petrolane, which related to a period prior to the formation of
the Partnership. The settlement resulted in a reduction to the value of the net
assets contributed to AmeriGas OLP by Petrolane at the Partnership formation
date. The adjustment was recorded by the Partnership during the year ended
September 30, 2004 as a $5.5 reduction in both goodwill and partners' capital.
We amortize customer relationship and noncompete agreement intangibles
over their estimated periods of benefit which do not exceed 15 years.
Amortization expense of intangible assets was $11.1 in 2004, $6.1 in 2003 and
$4.6 in 2002 including amortization expense associated with customer contracts
recorded in cost of sales. Estimated amortization expense of intangible assets
during the next five fiscal years is as follows: Fiscal 2005 - $15.4; Fiscal
2006 - $14.9; Fiscal 2007 - $14.3; Fiscal 2008 - $13.9; Fiscal 2009 - $12.5.
In accordance with the provisions of SFAS No. 142, "Goodwill and Other
Intangible Assets" ("SFAS 142"), we amortize intangible assets over their useful
lives unless we determined their lives 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.
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 2004, 2003
or 2002.
STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for
Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting
Principles Board ("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.
36
UGI Corporation 2004 Annual Report
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 $14.3, $10.4 and $5.7 in 2004, 2003 and 2002,
respectively. If we had determined stock-based compensation expense under the
fair value method prescribed by the provisions of SFAS 123, net income and basic
and diluted earnings per share for 2004, 2003 and 2002 would have been as
follows:
Year Ended September 30,
2004 2003 2002
---- ---- ----
Net income, as reported $ 111.6 $ 98.9 $ 75.5
Add: Stock and unit-based employee
expense included in reported net
income, net of related tax effects 9.3 6.8 3.7
Deduct: Total stock and unit-based
employee compensation expense
determined under the fair value
method for all awards, net of
related tax effects (10.4) (7.6) (4.7)
-------- ------- -------
Pro forma net income $ 110.5 $ 98.1 $ 74.5
-------- ------- -------
Basic earnings per share:
As reported $ 2.36 $ 2.34 $ 1.83
Pro forma $ 2.34 $ 2.32 $ 1.80
Diluted earnings per share:
As reported $ 2.31 $ 2.29 $ 1.80
Pro forma $ 2.29 $ 2.27 $ 1.78
-------- ------- -------
For a description of our stock and unit-based compensation plans and
related disclosures, see Note 9.
DEFERRED DEBT ISSUANCE COSTS. Included in other assets are net deferred debt
issuance costs of $13.9 at September 30, 2004 and $15.5 at September 30, 2003.
We are amortizing these costs over the terms 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 through the date of their redemption on October 1, 2004 (see Note 8),
the Company accounted 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, effective July 1, 2003, 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 periods presented after June 30,
2003. Prior to July 1, 2003, these dividends were reflected as a deduction from
net income on the Consolidated Statements of Income. Because SFAS 150
specifically prohibits the restatement of financial statements prior to its
adoption, prior period amounts have not been reclassified.
ENVIRONMENTAL AND OTHER LEGAL MATTERS. 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. Amounts accrued generally reflect
our best estimate of costs expected to be incurred or the minimum liability
associated with a range of expected environmental response costs. 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 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, 2004, the Company's accrued liability
for environmental investigation and cleanup costs was not material.
Similar to environmental matters, we accrue investigation and other legal costs
when it is probable that a liability exists and the amount or range of amounts
can be reasonably estimated (see Note 12).
FOREIGN CURRENCY TRANSLATION. Balance sheets of international subsidiaries and
our investment in an international propane joint venture 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 an
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 and euros, 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, 2003 and 2004 follow:
Derivative Foreign
Instruments Currency
Gains Translation
(Losses) Adjustments Total
-------- ----------- -----
Balance - September 30, 2003 $ (4.1) $ 8.8 $ 4.7
Balance - September 30, 2004 $ 7.3 $ 15.3 $ 22.6
------- ------- -------
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In December 2003, the Financial
Accounting Standards Board ("FASB") revised Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities" ("FIN 46"), which was originally
issued in January 2003 and clarifies Accounting Research Bulletin No. 51,
"Consolidated Financial Statements." FIN 46 was 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 was
effective beginning with our interim period ended March 31, 2004. If certain
conditions are met, FIN 46 requires the primary beneficiary to consolidate
certain variable interest entities. The adoption of FIN 46, as revised, did not
have a material effect on the Company's financial position, results of
operations or cash flows.
On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Act") was signed into law. Among other things,
the Act provides for a prescription drug benefit to Medicare beneficiaries on a
voluntary basis beginning in 2006. To encourage employers to continue to offer
retiree prescription drug benefits, the Act provides for a tax-free subsidy to
employers who offer a prescription drug benefit that is at least actuarially
equivalent to the standard benefit offered under the Act. In May 2004, the FASB
issued Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003" ("FSP 106-2"). FSP 106-2 is effective for periods beginning after June 15,
2004.
The Company provides postretirement health care benefits principally to
certain of its retirees and a limited number of active employees meeting certain
age and service requirements. See Note 6 for information on our Employee
Retirement Plans. These postretirement benefits include certain retiree
prescription drug benefits. The Company has determined that, as currently
designed, its prescription drug benefit for retirees is not actuarially
equivalent to the standard benefit offered under the Act and, as a result, does
not qualify for the tax-free subsidy.
NOTE 2 - PRIOR YEAR RESTATEMENT
We have restated the fiscal 2003 Consolidated Balance Sheet and Statement of
Stockholders' Equity to record deferred income tax liabilities on the gains
resulting from the conversion of our Subordinated Units in the Partnership (see
Note 16), which occurred in December 2002, and upon subsequent sales by the
Partnership of units to the public. The restatement has no impact on our
Consolidated Statements of Income or Consolidated Statements of Cash Flows.
Under our interpretation of accounting rules at the time of the
conversion, including Staff Accounting Bulletin No. 51, "Accounting for Sales of
Common Stock by a Subsidiary," we accounted for the gains resulting from the
conversion of Subordinated Units in the Partnership, and subsequent sales by the
Partnership of units to the public, as increases in stockholders' equity in
amounts equal to the increase in the value of our investment in the Partnership.
We did not record deferred income tax liabilities relating to the gains because
of our intention to hold our investment in the Partnership indefinitely. While
our intention to hold the Partnership units indefinitely has not changed, we
have reconsidered our previous judgments in the application of SFAS No. 109,
"Accounting for Income Taxes" ("SFAS 109"), and have recorded deferred income
tax liabilities on the gains. The following table summarizes the effect of the
restatement:
As of September 30, 2003
------------------------
As previously
reported As restated
-------- -----------
Deferred income taxes $ 223.1 $ 293.8
Common Stock $ 582.4 $ 511.7
----------- -----------
NOTE 3 - ACQUISITIONS AND INVESTMENTS
On March 31, 2004 (the "Closing Date"), UGI, through its subsidiary, UGI
Bordeaux Holding (as assignee of UGI France), completed its acquisition of the
remaining outstanding 80.5% ownership interests of AGZ, a French corporation and
the parent company of Antargaz, a French corporation and a leading distributor
of LPG in France, pursuant to the terms of (i) a Share Purchase Agreement dated
as of February 17, 2004, by and among UGI France, UGI, PAI partners, a French
corporation, and certain officers, directors and managers of AGZ and Antargaz
and their affiliates, and (ii) that certain Medit Joinder Agreement dated
February 20, 2004, by and among UGI France, UGI, Medit Mediterranea GPL,.,
a company incorporated under the laws of Italy ("Medit"), and PAI partners
(herein referred to as the "Antargaz Acquisition"). The acquisition of the
remaining interests in AGZ is consistent with our growth strategies and core
competencies.
The purchase price on the Closing Date of E261.8 or $319.2 (excluding
transaction fees and expenses) was subject to post-closing working capital and
net debt adjustments. UGI used the cash proceeds from its March 2004 public
offering of 7.5 million shares of its common stock and $89.0 of available cash
to fund the purchase price. In accordance with the Share Purchase Agreement, UGI
paid an additional E5.8 ($7.1) as a result of post-closing adjustments. In
addition, we incurred transaction fees and expenses of $5.4. See Note 9 for
additional information regarding the issuance of UGI Common Stock.
38
UGI Corporation 2004 Annual Report
The Antargaz Acquisition has been accounted for as a step acquisition.
UGI's initial 19.5% equity investment in AGZ has been allocated to 19.5% of
AGZ's assets and liabilities at March 31, 2004. The amount by which the carrying
value of UGI's equity investment exceeded the aforementioned allocation has been
recorded as goodwill. The purchase price of the remaining 80.5% of AGZ,
including transaction fees and expenses, has been allocated to the assets
acquired and liabilities assumed, as follows:
Working capital $ 28.7
Property, plant and equipment 337.0
Goodwill 469.3
Customer relationships (estimated useful life of twelve years) 97.1
Trademark and other intangible assets 38.6
Long-term debt (including current maturities) (392.6)
Deferred income taxes (108.8)
Minority interests (11.1)
Other assets and liabilities (126.5)
------------
Total $ 331.7
------------
None of the goodwill is expected to be deductible for income tax purposes.
The Company has completed its review and determination of the fair value
of the portion of AGZ's assets acquired and liabilities assumed, principally the
fair values of property, plant and equipment and identifiable intangible assets.
The assets and liabilities of AGZ are included in our Consolidated Balance Sheet
as of September 30, 2004. The operating results of AGZ are included in our
consolidated results beginning April 1, 2004. Prior to April 1, 2004, our 19.5%
equity interest in AGZ is reflected in our Consolidated Financial Statements
under the equity method of accounting.
The following table presents unaudited pro forma income statement and
basic and diluted per share data for the years ended September 30, 2004 and 2003
as if the Antargaz Acquisition had occurred as of the beginning of those
periods:
2004 2003
---- ----
(pro forma) (pro forma)
Revenues $ 4,293.0 $ 3,725.0
Net income 168.2 122.9
Earnings per share:
Basic $ 3.31 $ 2.46
Diluted $ 3.24 $ 2.41
----------- -----------
The pro forma results of operations reflect AGZ's historical operating
results after giving effect to adjustments directly attributable to the
transaction that are expected to have a continuing effect. The pro forma amounts
are not necessarily indicative of the operating results that would have occurred
had the acquisition been completed as of the date indicated, nor are they
necessarily indicative of future operating results.
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 December 2003, AmeriGas OLP
paid Horizon Propane a working capital adjustment of $0.1 in accordance with the
Asset Purchase Agreement. During its fiscal year ended June 30, 2003, Horizon
Propane sold over 30 million gallons of propane from ninety locations in twelve
states. In addition, AmeriGas OLP completed several smaller acquisitions of
retail propane businesses, HVAC/R acquired a commercial refrigeration business
and FLAGA acquired a retail propane distribution business in the Czech Republic
during the year ended September 30, 2004. The pro forma effect of these
transactions is not material.
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/R acquired a commercial refrigeration 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.
In November 2004, UGI Asset Management, Inc., a wholly owned subsidiary of
Energy Services, acquired from ConocoPhillips Company and AmerE Holdings, Inc.
(a wholly owned, indirect subsidiary of AmeriGas Propane, L.P.) in separate
transactions 100% of the issued and outstanding common stock of Atlantic Energy,
Inc. for an aggregate purchase price of approximately $24 in cash, subject to
post-closing adjustments. In connection with this acquisition, Atlantic Energy,
Inc. and AmeriGas Propane, L.P. entered into a long-term propane supply
agreement.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 4 - DEBT
Long-term debt comprises the following at September 30:
2004 2003
---- ----
AMERIGAS PROPANE:
AmeriGas Partners Senior Notes:
8.875%, due May 2011 (including unamortized
premium of $8.3 and $6.4, respectively,
effective rate - 8.46%) $ 396.3 $ 366.4
10%, due April 2006 (less unamortized discount
of $0.1 and $0.2, respectively, effective
rate - 10.125%) 59.9 59.8
AmeriGas OLP First Mortgage Notes:
Series A, 9.34% - 11.71%, due April 2005
through April 2009 (including unamortized
premium of $5.2 and $6.6, respectively,
effective rate - 8.91%) 165.2 166.6
Series B, 10.07%, due April 2005 (including
unamortized premium of $0.3 and $1.1,
respectively, effective rate - 8.74%) 40.3 81.1
Series C, 8.83%, due April 2005 through April 2010 82.5 96.3
Series D, 7.11%, due March 2009 (including
unamortized premium of $1.6 and $1.9,
respectively, effective rate - 6.52%) 71.6 71.9
Series E, 8.50%, due July 2010 (including
unamortized premium of $0.1, effective
rate - 8.47%) 80.1 80.1
Other 5.5 5.1
-------- --------
Total AmeriGas Propane 901.4 927.3
-------- --------
INTERNATIONAL PROPANE:
Antargaz Senior Facilities term loan,
due March 2005 through June 2008 240.0 -
Antargaz 10% High Yield Bonds, due July 2011
(including unamortized premium of $20.0,
effective rate - 7.68%) 225.2 -
FLAGA Acquisition Note, due through
September 2006 68.2 68.9
FLAGA euro special purpose facility 3.3 4.2
Other 9.3 -
-------- --------
Total International Propane 546.0 73.1
-------- --------
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
6.62% Notes, due May 2005 20.0 20.0
7.14% Notes, due December 2005 (including
unamortized premium of $0.2 and $0.3,
respectively, effective rate - 6.64%) 30.2 30.3
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 25.0
6.50% Notes, due August 2033 20.0 20.0
-------- --------
Total UGI Utilities 217.2 217.3
-------- --------
Other 5.5 5.8
-------- --------
Total long-term debt 1,670.1 1,223.5
Less current maturities (including net unamortized
premiums of $5.4 and $3.1, respectively) (122.8) (65.0)
-------- --------
Total long-term debt due after one year $1,547.3 $1,158.5
-------- --------
Scheduled principal repayments of long-term debt due in fiscal years 2005
to 2009 follows:
2005 2006 2007 2008 2009
---- ---- ---- ---- ----
AmeriGas Propane $ 57.0 $ 114.9 $ 54.3 $ 54.0 $ 123.9
UGI Utilities 20.0 50.0 20.0 - -
International Propane 39.7 83.8 24.2 173.2 -
Other 0.7 0.7 0.8 3.1 -
------- ------- ------ ------- -------
Total $ 117.4 $ 249.4 $ 99.3 $ 230.3 $ 123.9
------- ------- ------ ------- -------
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. 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,
2008, 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, 2004 and 2003.
40
UGI Corporation 2004 Annual Report
Issued and outstanding letters of credit, which reduce available borrowings
under the Revolving Credit Facility, totaled $45.9 and $33.4 at September 30,
2004 and 2003, 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, for working capital and general
purposes, subject to restrictions in the Senior Notes indentures. The
Acquisition Facility operates as a revolving facility through October 15, 2008,
at which time amounts then outstanding will be immediately due and payable.
There were no amounts outstanding under the Acquisition Facility at September
30, 2004 and 2003.
The Revolving Credit Facility and the Acquisition Facility permit AmeriGas
OLP to borrow at prevailing interest rates, including the base rate, defined as
the higher of the Federal Funds rate plus 0.50% or the agent bank's prime rate
(4.75% at September 30, 2004), 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, 2004, such ratio was 3.14-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, 2004, the Partnership was in compliance with its financial
covenants.
INTERNATIONAL PROPANE
Antargaz' Senior Facilities Agreement consists of (1) a euro-denominated
variable-rate term loan and (2) a E50 revolver. At September 30, 2004, there
was E193 ($240.0) outstanding under the term loan and no borrowings
outstanding under the revolver. Principal payments of E9 on the term loan are
due semi-annually on March 31 and September 30 each year with final payments of
E39 and E100 due March 31, 2008 and June 30, 2008, respectively. The
term loan bears interest at euribor or libor plus margin, as defined by the
Senior Facilities Agreement. Margin (which ranges from 0.85% to 1.75%) is
dependent upon Antargaz' ratio of total net debt to EBITDA, each as defined by
the Senior Facilities Agreement. Antargaz has fixed the interest rate on a
portion of its term loan through the use of interest rate swap agreements (see
Note 13). The Senior Facilities debt has been collateralized by substantially
all of Antargaz' shares in its subsidiaries and its equity investee, and by
substantially all of its accounts receivable.
In July 2002, AGZ issued E165 of 10% Senior Notes due 2011 (the "High
Yield Bonds"), through one of its subsidiaries, AGZ Finance. Interest on the
High Yield Bonds is payable semi-annually on January 15 and July 15. AGZ Finance
may redeem the bonds in whole or in part at a premium commencing July 2006.
At September 30, 2004, FLAGA's multi-currency acquisition note
("Acquisition Note") consisted of $5.4 of U.S. dollar-denominated obligations
and E50.5 of euro-denominated obligations. The U.S. dollar-denominated
obligations under the Acquisition Note bear interest at fixed rates ranging from
5.70% to 5.92% while the euro-denominated 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,
2004 and September 30, 2003 were 3.83% and 4.00%, respectively. FLAGA may prepay
the Acquisition Note, in whole or in part. Prior to March 11, 2005, such
prepayments shall be at a premium
At September 30, 2004, FLAGA has a E15 working capital loan commitment
from a European bank. The working capital facility expires in November 2005, but
may be extended with
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 4 continued
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 3.04% at September 30, 2004 and 3.40% at September 30, 2003. Borrowings
under the working capital facility at September 30, 2004 and 2003 totaled E13.8
($17.2) and E13.6 ($15.9), respectively, and are classified as bank loans.
RESTRICTIVE COVENANTS AND GUARANTEES. The Senior Facilities Agreement and the
Trust Deed, dated July 23, 2002, among AGZ Finance, as issuer, AGZ, as
guarantor, and the Bank of New York, as trustee, ("Trust Deed") relating to the
High Yield Bonds restrict the ability of AGZ and its subsidiaries, including
Antargaz, to, among other things, incur additional indebtedness, make
investments, incur liens, prepay indebtedness, and effect mergers,
consolidations and sales of assets. Under these agreements, AGZ is generally
permitted to make restricted payments, such as dividends, equal to 50% of
consolidated net income, as defined in each respective agreement, for (1) the
immediately preceding fiscal year, in the case of the Senior Facilities
Agreement, and (2) on a cumulative basis since July 2002, in the case of the
Trust Deed, if no event of default exists or would exist upon payment of such
restricted payment.
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.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2004, UGI Utilities had revolving
credit agreements with five banks providing for borrowings of up to $110. These
agreements are currently scheduled to expire in June 2007. 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 $60.9 at
September 30, 2004 and $40.7 at September 30, 2003, which we classify as bank
loans. The weighted-average interest rates on UGI Utilities bank loans were
2.35% at September 30, 2004 and 1.63% at September 30, 2003.
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, 2004,
UGI Utilities was in compliance with these financial covenants.
NOTE 5 - INCOME TAXES
Income (loss) before income taxes comprises the following:
2004 2003 2002
---- ---- ----
Domestic $ 160.7 $ 157.1 $ 117.2
Foreign 15.3 3.7 6.8
---------- -------- --------
Total income before income taxes $ 176.0 $ 160.8 $ 124.0
---------- -------- --------
The provisions for income taxes consist of the following:
2004 2003 2002
---- ---- ----
Current expense:
Federal $ 46.8 $ 48.1 $ 26.5
State 14.4 15.4 9.3
Foreign 0.2 - 0.1
-------- ------- -------
Total current expense 61.4 63.5 35.9
Deferred (benefit) expense:
Federal 4.3 2.3 11.8
State (1.6) (3.6) (0.4)
Foreign 0.7 (1.1) -
Investment tax credit amortization (0.4) (0.4) (0.4)
-------- ------- -------
Total deferred expense (benefit) 3.0 (2.8) 11.0
-------- ------- -------
Total income tax expense $ 64.4 $ 60.7 $ 46.9
-------- ------- -------
A reconciliation from the statutory federal tax rate to our effective tax
rate is as follows:
2004 2003 2002
---- ---- ----
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal 4.8 4.6 5.3
Other, net (3.2) (1.8) (2.5)
---- ---- ----
Effective tax rate 36.6% 37.8% 37.8%
---- ---- ----
42
UGI Corporation 2004 Annual Report
Deferred tax liabilities (assets) comprise the following at September 30:
Restated
2004 2003
---- ----
Excess book basis over tax basis of property,
plant and equipment $ 335.3 $ 224.3
SAB 51 gains 77.3 70.7
Intangibles 58.3 -
Utility regulatory assets 27.6 25.0
Pension plan asset 10.5 11.0
Other 20.0 16.7
---------- --------
Gross deferred tax liabilities 529.0 347.7
---------- --------
Self-insured property and casualty liability (11.6) (9.9)
Employee-related benefits (25.8) (20.6)
Premium on long-term debt (9.7) (3.0)
Tax litigation (8.1) (0.8)
Deferred investment tax credits (3.1) (3.3)
Utility regulatory liabilities (4.0) (7.7)
Operating loss carryforwards (13.3) (17.0)
Allowance for doubtful accounts (4.8) (3.9)
Other (24.8) (12.9)
---------- --------
Gross deferred tax assets (105.2) (79.1)
---------- --------
Deferred tax assets valuation allowance 2.7 1.7
---------- --------
Net deferred tax liabilities $ 426.5 $ 270.3
---------- --------
UGI Utilities had recorded deferred tax liabilities of approximately $39.4
as of September 30, 2004 and $37.0 as of September 30, 2003, 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 $3.1 at September 30, 2004 and $3.3
at September 30, 2003, pertaining to utility deferred investment tax credits.
UGI Utilities had recorded regulatory income tax assets related to these net
deferred taxes of $62.0 as of September 30, 2004 and $57.6 as of September 30,
2003. 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
$44.3 of which $6.7 expires through 2011 and $37.6 of which has no expiration
date. At September 30, 2004, deferred tax assets relating to operating loss
carryforwards include those of FLAGA and $3.1 of deferred tax assets associated
with state net operating loss carryforwards expiring through 2024.
Substantially all of our deferred tax valuation allowances relate to state
operating loss carryforwards.
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. As a result of the Antargaz Acquisition, we assumed underfunded
retirement benefits which are based upon the employee's salary and service and
are primarily to be paid upon retirement ("AGZ benefits"). In addition, Antargaz
employees are covered by a postretirement medical plan. Our disclosures include
the effects of AGZ benefits and other postretirement welfare benefits.
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
2004 2003 2004 2003
---- ---- ---- ----
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations -
beginning of year $ 209.5 $ 190.9 $ 28.8 $ 27.3
Service cost 4.9 4.5 0.2 0.2
Interest cost 13.0 13.0 1.7 1.8
Actuarial loss 2.6 10.5 1.3 1.1
Antargaz Acquisition 11.8 - 3.3 -
Benefits paid (9.5) (9.4) (2.5) (1.6)
-------- -------- -------- --------
Benefit obligations - end of
year $ 232.3 $ 209.5 $ 32.8 $ 28.8
-------- -------- -------- --------
CHANGE IN PLAN ASSETS:
Fair value of plan assets-
beginning of year $ 183.9 $ 166.1 $ 9.0 $ 7.8
Actual return on plan assets 22.0 27.2 0.8 0.2
Employer contributions - - 2.7 2.6
Antargaz Acquisition 3.8 - - -
Benefits paid (9.5) (9.4) (2.5) (1.6)
-------- -------- -------- --------
Fair value of plan assets-
end of year $ 200.2 $ 183.9 $ 10.2 $ 9.0
-------- -------- -------- --------
Funded status of the plans $ (32.1) $ (25.6) $ (22.6) $ (19.8)
Unrecognized net actuarial loss 47.9 51.2 6.1 5.9
Unrecognized prior service cost 1.6 2.4 - -
Unrecognized net transition
(asset) obligation - (1.4) 6.8 7.7
-------- -------- -------- --------
Prepaid (accrued) benefit cost-
end of year $ 17.4 $ 26.6 $ (9.7) $ (6.2)
-------- -------- -------- --------
WEIGHTED-AVERAGE ASSUMPTIONS
AS OF SEPTEMBER 30:
Discount rate 6.1% 6.2% 6.1% 6.2%
Expected return on plan assets 9.0% 9.0% 5.8% 6.0%
Rate of increase in salary levels 4.0% 4.0% 4.0% 4.0%
-------- -------- -------- --------
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 6 continued
Net pension expense (income) is determined using assumptions as of the
beginning of each fiscal year. Funded status is determined using assumptions as
of the end of each fiscal year. The expected rate of return on assets assumption
is based on the rates of return for certain asset classes and the allocation of
plan assets among those asset classes as well as actual historic long-term rates
of return on our plan assets.
Net periodic pension expense (income) and other postretirement benefit
costs include the following components:
Pension Other Postretirement
Benefits Benefits
------------------------ -----------------------
2004 2003 2002 2004 2003 2002
---- ---- ---- ---- ---- ----
Service cost $ 5.0 $ 4.5 $ 3.6 $ 0.2 $ 0.2 $ 0.1
Interest cost 13.0 13.0 12.5 1.8 1.8 1.7
Expected return on assets (17.3) (17.9) (19.1) (0.5) (0.4) (0.3)
Amortization of:
Transition (asset)
obligation (1.4) (1.6) (1.6) 0.9 0.9 0.9
Prior service cost 0.7 0.6 0.6 - - -
Actuarial (gain) loss 1.2 0.3 - 0.3 0.1 (0.1)
Antargaz Aquisition 0.3 - - 0.2 - -
------ ------ ------ ----- ----- ------
Net benefit cost (income) 1.5 (1.1) (4.0) 2.9 2.6 2.3
Change in regulatory
assets and liabilities - - - 0.9 1.0 1.2
------ ------ ------ ----- ----- ------
Net expense (income) $ 1.5 $ (1.1) $ (4.0) $ 3.8 $ 3.6 $ 3.5
------ ------ ------ ----- ----- ------
UGI Utilities Pension Plan assets are held in trust. Although the UGI
Utilities Pension Plan projected benefit obligations exceeded plan assets at
September 30, 2004 and 2003, plan assets exceeded accumulated benefit
obligations by $9.2 and $7.3, respectively. The Company did not make any
contributions in 2004 nor does it believe it will be required to make any
contributions to the UGI Utilities Pension Plan during the year ending September
30, 2005. At September 30, 2004, the accumulated benefit obligation of AGZ
benefits exceeded the plan assets by $6.5. However, the accrual recorded in our
Consolidated Balance Sheet at September 30, 2004 exceeds the minimum pension
liability. Antargaz does not expect to make any contributions to fund AGZ
benefits during the year ending September 30, 2005.
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 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. UGI Utilities
contributed $2.5 million to the VEBA during the year ended September 30, 2004
and expects to contribute approximately $2.5 million during the year ending
September 30, 2005.
Expected payments for pension benefits and for other postretirement
welfare benefits are as follows:
Other
Pension Postretirement
Benefits Benefits
-------- --------
Fiscal 2005 $ 10.6 $ 2.4
Fiscal 2006 10.6 2.5
Fiscal 2007 10.9 2.6
Fiscal 2008 11.0 2.7
Fiscal 2009 11.6 2.7
Fiscal 2010-2014 67.8 13.3
-------- --------
In accordance with our investment strategy to obtain long-term growth, our
target allocations are to maintain a mix of 60% equities and the remainder in
fixed income funds or cash equivalents. The targets and actual allocations for
the UGI Utilities Pension Plan assets and VEBA trust assets at September 30 are
as follows:
Target Pension Plan VEBA
Pension Plan VEBA 2004 2003 2004 2003
Equities 60% 60% 63% 60% 58% 57%
Fixed income funds 40% 30% 37% 40% 27% 29%
Cash equivalents N/A 10% N/A N/A 15% 14%
--- -- --- --- -- --
UGI Common Stock comprised approximately 8% and 7% of UGI Utilities Pension Plan
assets at September 30, 2004 and 2003, respectively.
The assumed health care cost trend rates are 10.0% for fiscal 2005,
decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed
health care cost trend rate would change the 2004 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 $ 1.7 $ (1.5)
------- -------
We also sponsor unfunded and non-qualified supplemental executive
retirement plans. At September 30, 2004 and 2003, the projected benefit
obligations of these plans were $12.4 and $11.9, respectively. We recorded net
benefit costs for these plans of $1.9 in 2004, $1.9 in 2003 and $1.4 in 2002. We
also recorded a settlement loss of $1.5 in 2004 associated with these plans.
DEFINED CONTRIBUTION PLANS. We sponsor 401(k) savings plans for eligible
employees of UGI, UGI Utilities, AmeriGas Propane, HVAC/R 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 $8.2 in 2004, $7.3 in 2003 and
$4.5 in 2002.
NOTE 7 - INVENTORIES
Inventories comprise the following at September 30:
2004 2003
---- ----
Propane and other LPG $ 92.1 $ 53.8
Utility fuel and gases 69.8 54.6
Materials, supplies and other 36.5 28.2
--------- --------
Total inventories $ 198.4 $ 136.6
--------- --------
44
UGI Corporation 2004 Annual Report
NOTE 8 - SERIES PREFERRED STOCK
UGI has 5,000,000 shares of UGI Series Preferred Stock, including both series
subject to and series not subject to mandatory redemption, authorized for
issuance. We had no shares of UGI Series Preferred Stock outstanding at
September 30, 2004 or 2003.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred
Stock, including both series subject to and series not subject to mandatory
redemption, 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, 2004 and 2003, UGI Utilities had outstanding 200,000
shares of $7.75 Series Cumulative Preferred Stock. UGI Utilities' redeemed all
200,000 shares of the $7.75 UGI Utilities Series Cumulative Preferred Stock on
October 1, 2004 at a price of $100 per share together with full cumulative
dividends. The redemption was funded with proceeds from the October 2004
issuance of $20 of 6.13% Medium-Term Notes due October 2034.
NOTE 9 - COMMON STOCK AND INCENTIVE STOCK AWARD PLANS
In March 2004, UGI Corporation sold 7.5 million shares of common stock in an
underwritten public offering at a public offering price of $32.10 per share.
During April 2004, the underwriters exercised a portion of their overallotment
option for the purchase of an additional 0.3 million shares. As mentioned in
Note 3, the proceeds of the public offering of approximately $239 were used
primarily to fund a portion of the purchase price of the remaining ownership
interests in AGZ.
Common Stock share activity for 2002, 2003, and 2004 follows:
Issued Treasury Outstanding
------ -------- -----------
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
Issued:
Public offering 7,778,400 - 7,778,400
Employee and director plans - 653,250 653,250
Dividend reinvestment plan - 80,190 80,190
---------- ---------- ----------
Balance September 30, 2004 57,576,497 (6,365,299) 51,211,198
---------- ---------- ----------
STOCK OPTION AND INCENTIVE PLANS. Under UGI's current equity compensation plans,
we may grant options to acquire shares of Common Stock, or issue stock-based
awards ("Units") to key employees and non-employee directors. The exercise price
for options may not be less than the fair market value on the grant date. Grants
of stock options or Units 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 2004 Omnibus Equity Compensation Plan ("OECP"), awards
representing up to 3,500,000 shares of Common Stock may be granted. The maximum
number of shares that may be issued pursuant to grants other than stock options
or dividend equivalents is 800,000 shares. In addition, the OECP provides that
both option grants and Units may provide for the crediting of Common Stock
dividend equivalents to participants' accounts. Dividend equivalents on employee
awards will be paid in cash, and such payments may, at the participants'
request, be deferred. Dividend equivalents on non-employee director awards are
paid in additional Common Stock Units. Stock-based awards 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
generally dependent upon the achievement of objective performance goals. During
2004, 2003 and 2002, the Company made stock-based awards other than stock
options and dividend equivalents representing 134,300, 81,750, and 254,250
shares, respectively. At September 30, 2004, awards representing 447,100 shares
of Common Stock were outstanding under our equity compensation plans. There are
outstanding stock-based awards and stock options under a number of plans,
however, no further awards will be made under any plan other than the OECP.
Stock option transactions under all of our plans for 2002, 2003, and 2004
follow:
Shares Average Option Price
------ --------------------
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
--------- ------
Granted 747,250 33.637
Exercised (521,026) 15.783
Forfeited (44,250) 25.707
--------- ------
Shares under option - September 30, 2004 2,664,463 23.414
--------- ------
Options exercisable 2002 1,706,889 14.515
Options exercisable 2003 1,428,987 15.454
Options exercisable 2004 1,359,335 18.020
--------- ------
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 9 continued
The following table presents additional information relating to stock
options outstanding and exercisable at September 30, 2004:
Range of exercise prices
--------------------------------------
$13.58-20.40 $20.41-36.45
============ ============
Options outstanding at September 30, 2004:
Number of options 1,274,338 1,390,125
Weighted average remaining
contractual life (in years) 5.85 8.74
Weighted average exercise price $ 16.74 $ 29.53
Options exercisable at September 30, 2004:
Number of options 1,091,585 267,750
Weighted average exercise price $ 16.13 $ 25.70
------------ ------------
At September 30, 2004, 2,508,796 shares of Common Stock were available for
future grants under the OECP, of which up to 547,546 may be issued pursuant to
grants other than stock options or dividend equivalents.
OTHER EQUITY-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 Common Unit
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 51,200, 112,500 and 43,250
Common Units in 2004, 2003 and 2002, respectively. At September 30, 2004 and
2003, awards representing 142,786 and 209,336 Common Units, respectively, were
outstanding.
FAIR VALUE INFORMATION. The per share weighted-average fair value of stock
options granted under our option plans was $3.77 in 2004, $2.60 in 2003 and
$3.27 in 2002. 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 2004, 2003 and 2002 are
as follows:
2004 2003 2002
---- ---- ----
Expected life of option 6 years 6 years 6 years
Expected volatility 18.2% 21.6% 28.8%
Expected dividend yield 4.9% 6.1% 6.7%
Risk free interest rate 3.7% 3.1% 4.7%
----- ----- -----
STOCK OWNERSHIP POLICY. Under the terms of our Stock Ownership Policy,
executives and certain key employees are required to own UGI Common Stock in
amounts ranging from 3,000 to 150,000 shares. 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, 2004 and 2003, loans outstanding totaled $0.2 and
$0.4, 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
46
UGI Corporation 2004 Annual Report
3. 50% or more of our assets or earning power is sold or transferred,
then each holder of a right is entitled to purchase, at the exercise
price of the right, common stock of the acquiring company having a
market value of twice the exercise price of the right.
The rights have no voting or dividend rights and, until exercisable, have
no dilutive effect on our earnings.
NOTE 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 to the
General Partner 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 step-rent provisions. Our
aggregate rental expense for such leases was $50.4 in 2004, $47.4 in 2003 and
$46.5 in 2002.
Minimum future payments under operating leases that have initial or
remaining noncancelable terms in excess of one year are as follows:
After
2005 2006 2007 2008 2009 2009
---- ---- ---- ---- ---- ----
AmeriGas Propane $39.3 $33.2 $28.2 $23.9 $19.6 $45.1
UGI Utilities 3.5 3.1 2.6 1.8 0.9 2.9
International Propane
and other 3.7 3.4 3.2 3.0 2.2 2.2
----- ----- ----- ----- ----- -----
Total $46.5 $39.7 $34.0 $28.7 $22.7 $50.2
----- ----- ----- ----- ----- -----
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 natural gas storage services, 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
fiscal 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.
The following table presents contractual obligations under Gas Utility,
Electric Utility, Energy Services, AmeriGas Propane and International Propane
supply, storage and service contracts existing at September 30, 2004:
After
2005 2006 2007 2008 2009 2009
---- ---- ---- ---- ---- ----
Gas Utility and Electric
Utility supply, storage and
transportation contracts $188.5 $100.6 $ 80.7 $60.6 $51.7 $116.3
Energy Services supply contracts 449.4 59.6 1.6 - - -
AmeriGas Propane supply contracts 12.8 - - - - -
International Propane supply contracts 109.4 109.4 52.2 - - -
------ ------ ------ ----- ----- ------
Total $760.1 $269.6 $134.5 $60.6 $51.7 $116.3
------ ------ ------ ----- ----- ------
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 market prices at date of delivery or fixed prices.
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 $12 at September 30, 2004. The leases expire through 2010
and some of them are currently in default. The
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 12 continued
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. 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, 2004, the potential amount payable under
this indemnity by the Company Parties was approximately $60. 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.
Samuel and Brenda Swiger and their son (the "Swigers") sustained personal
injuries and property damage as a result of a fire that occurred when propane
that leaked from an underground line ignited. In July 1998, the Swigers filed a
class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as
"UGI/AmeriGas, Inc."), in the Circuit Court of Monongalia County, West Virginia,
in which they sought to recover an unspecified amount of compensatory and
punitive damages and attorney's fees, for themselves and on behalf of persons in
West Virginia for whom the defendants had installed propane gas lines, allegedly
resulting from the defendants' failure to install underground propane lines at
depths required by applicable safety standards. The court recently granted the
plaintiffs' motion to include customers acquired from Columbia Propane in August
2001 as additional potential class members and to amend their complaint to name
additional parties consistent with such ruling. In 2003, we settled the
individual personal injury and property damage claims of the Swigers. Class
counsel has indicated that the class is seeking compensatory damages in excess
of $12 plus punitive damages, civil penalties and attorneys' fees. We believe we
have good defenses to the claims of the class members and intend to vigorously
defend against the remaining claims in this lawsuit.
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 private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries. Such 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. 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.
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
48
UGI Corporation 2004 Annual Report
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.
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 and is defending the suit.
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 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.
AGL previously informed UGI Utilities that it was investigating
contamination that appeared to be related to MGP operations at a site owned by
AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP
in the early 1900s. AGL has recently informed UGI Utilities that it has begun
remediation of MGP wastes at the site and believes that the total cost of
remediation could be as high as $55. AGL has not filed suit against UGI
Utilities for a share of these costs. UGI Utilities believes that it will have
good defenses to any action that may arise out of this site.
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. By orders issued in November 2003 and March 2004, the
court granted UGI Utilities' motion for summary judgment and dismissed ConEd's
complaint. ConEd has appealed.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI
Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean
up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI
Utilities is responsible for approximately 50% of these costs as a result of UGI
Utilities' alleged direct ownership and operation of the plant from 1885 to
1902. UGI Utilities is in the process of reviewing the information provided by
KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and
Connecticut Light and Power Company, subsidiaries of Northeast Utilities,
(together, the "Northeast Companies"), demanded contribution from UGI Utilities
for past and future remediation costs related to MGP operations on thirteen
sites owned by the Northeast Companies in nine cities in the State of
Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941. According to the letter,
investigation and remedial costs at the sites to date total approximately $10
and complete remediation costs for all sites could total $182. The Northeast
Companies seek an unspecified fair and equitable allocation of these costs to
UGI Utilities. UGI Utilities is in the process of reviewing the information
provided by Northeast Companies and is investigating this claim.
Antargaz has filed suit against the French tax authorities in connection
with the assessment of business tax related to the tax treatment of Antargaz
owned tanks at customer locations used to store LPG. Antargaz has recorded a
liability for the business tax relating to tanks for the period from January 1,
1997 through September 30, 2004 of approximately E 28.4 ($35.3). Elf Antar
France, now Total France, and Elf Aquitaine, former owners of Antargaz, agreed
to indemnify Antargaz for all payments which would have been due from Antargaz
in respect of the business tax related to its tanks for the period from January
1, 1997 through December 31, 2000. In March 2004, the local court rendered a
decision against Antargaz which resulted in a E 1.7 ($2.1) assessment by the
tax assessor relating to the business tax at certain sites in the pending suit.
Antargaz paid this assessment and was fully reimbursed in April 2004 for this
assessment pursuant to the indemnity agreement. Antargaz is appealing the
assessment. As of September 30, 2004, the indemnity from the former owners
represents approximately E 9.4 ($11.7) of the business tax liability.
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.
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 13 - FINANCIAL INSTRUMENTS
In accordance with its commodity hedging 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 LPG. These contracts may or
may not qualify for hedge accounting under SFAS 133.
In future periods Antargaz may use derivative instruments, including
forward foreign exchange contracts and other instruments similar to those used
by the Partnership, to manage the cost of a portion of its forecasted purchases
of LPG.
Energy Services uses exchange-traded natural gas futures contracts to
manage market risk associated with forecasted purchases of natural gas it sells
under firm commitments. These derivative instruments are designated as cash flow
hedges. The fair values of these futures contracts are affected by changes in
natural gas prices.
In accordance with its commodity hedging policy, Gas Utility may enter
into natural gas call option contracts to reduce volatility in the cost of gas
it purchases for its firm-residential, commercial and industrial ("retail
core-market") customers and the Electric Utility may enter into electric swap
agreements in order to reduce the volatility in the cost of anticipated
electricity requirements. Because the cost of the natural gas option contracts
and any associated gains will be included in Gas Utility's PGC recovery
mechanism, as these contracts are marked to fair value in accordance with SFAS
133, any gains are deferred for future recovery from or refund to Gas Utility's
ratepayers.
UGI Utilities is a party 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 purchase and delivery of natural gas and
electricity, 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.
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.
Antargaz has entered into interest rate swap agreements to fix the
variable interest rates on a portion of the Senior Facilities term loan through
June 2005. Antargaz may enter into additional interest rate swap agreements in
order to fix interest rates over additional periods.
During the year ended September 30, 2004, 2003 and 2002, the net pre-tax
loss recognized in earnings representing cash flow hedge ineffectiveness was
$1.5, $3.1 and $2.1, respectively.
Gains and losses included in accumulated other comprehensive income at
September 30, 2004 relating to cash flow hedges will be reclassified into (1)
cost of sales when the forecasted purchase of propane, natural gas or
electricity 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, 2004 are net after-tax losses of approximately $3.9 from IRPAs associated
with forecasted issuances of debt generally anticipated to occur during the next
two years and settled IRPAs. 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, 2004 are net
after-tax gains of approximately $10.7 principally associated with future
purchases of natural gas and propane generally anticipated to occur during the
next twelve months and net after-tax gains of approximately $1.1 associated with
future electric supply purchases expected to occur in fiscal 2007. 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 primary currency for which the Company has exchange rate risk is the
U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated
assets and liabilities will fluctuate with changes in the associated foreign
currency exchange rates. From time to time, the Company may use derivative
instruments to hedge portions of its net investments in foreign subsidiaries. If
a derivative is designated as a hedge of an investment in a foreign subsidiary
and qualifies for hedge accounting, any realized gains or losses remain in other
comprehensive income until such foreign operations have been liquidated. At
September 30, 2004, a net after-tax loss of $0.6 is included in accumulated
other comprehensive income associated with a settled net investment hedge.
The carrying amounts of financial instruments included in current assets
and current liabilities (excluding unsettled derivative instruments and current
maturities of long-term debt)
50
UGI Corporation 2004 Annual Report
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
------ ----------
2004:
Natural gas futures and options contracts $ 4.8 $ 4.8
Electric supply swap 2.0 2.0
Propane swap and option contracts 13.1 13.1
Interest rate protection agreements (2.8) (2.8)
Long-term debt 1,670.1 1,817.1
UGI Utilities preferred shares subject to
mandatory redemption 20.0 20.0
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
---------- ----------
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. On October 1, 2004 all
200,000 shares of UGI Utilities' $7.75 preferred shares subject to mandatory
redemption were redeemed at a price of $100 per share together with full
cumulative dividends. 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, 2004 and 2003.
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 and several foreign countries. 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 $150 receivables purchase facility ("Receivables
Facility") with an issuer of receivables-backed commercial paper expiring in
August 2007, although the Receivables Facility may terminate prior to such date
due to the termination of the commitments of the Receivables Facility's 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 $150.
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 2004 and 2003, Energy Services sold trade receivables totaling
$949.6 and $651.3, respectively, to ESFC. During 2004 and 2003, ESFC sold an
aggregate $246.0 and $196.0, respectively, of undivided interests in its trade
receivables to the commercial paper conduit. At September 30, 2004, the
outstanding balance of ESFC trade receivables was $63.4 of which no amount was
sold to the commercial paper conduit. At September 30, 2003, there were $38.5 of
ESFC trade receivables outstanding which amount was net of $17 in trade
receivables sold to the commercial paper conduit. Losses on sales of receivables
to the commercial paper conduit that occurred during the years ended September
30, 2004 and 2003, which losses are included in other income, net, were $0.4 and
$0.3, 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 April 2005.
NOTE 15 - OTHER INCOME, NET Other income, net, comprises the following:
2004 2003 2002
---- ---- ----
Interest and interest-related income $ (3.2) $ (6.6) $ (5.3)
Utility non-tariff service income (2.0) (5.7) (5.7)
Gain on sales of fixed assets (0.1) (1.6) (1.6)
Pension income - (1.1) (4.0)
Foreign currency hedge loss 9.1 - -
Finance charges (6.5) (3.9) (2.2)
Other (6.1) (0.9) 0.7
------- ------- -------
Total other income, net $ (8.8) $ (19.8) $ (18.1)
------- ------- -------
51
UGI Corporation 2004 Annual Report
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 16 - 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. 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. Total deferred income tax
liabilities of $70.7 associated with these gains were recorded with a
corresponding decrease in common stockholders' equity and reflected in the
restated Consolidated Balance Sheet at September 30, 2003.
On May 26, 2004, AmeriGas Partners sold 2,000,000 Common Units in an
underwritten public offering at a public offering price of $25.61 per unit. On
June 10, 2004, the underwriters partially exercised their overallotment option
in the amount of 100,000 Common Units. The net proceeds of the public offering
totaling $51.2 and associated capital contributions from the General Partner
totaling $1.0 were contributed to AmeriGas OLP and used to reduce indebtedness
under its bank credit agreement and for general partnership purposes.
Concurrent with this sale of Common Units, the Company recorded a gain in the
amount of $12.2 which is reflected in the Company's balance sheet as an increase
in common stockholders' equity in accordance with the guidance in SAB 51.
Deferred income tax liabilities of $6.6 associated with this gain with a
corresponding decrease in common stockholders' equity were recorded and
reflected in the Consolidated Balance Sheet. The gain had no effect on the
Company's net income or cash flow.
NOTE 17 - INVESTMENTS IN EQUITY INVESTEES
Our principal investments accounted for using the equity method and our
approximate percentage ownership interest in each at September 30, 2004 and 2003
are as follows:
Company 2004 2003
- ------- ---- ----
Atlantic Energy 50.0%(a) 50.0%
AGZ 100.0%(b) 19.5%
China Gas Partners 50.0% 50.0%
Hunlock Creek Energy Ventures 50.0% 50.0%
Geovexin 44.9% N/A
(a) In November 2004, a subsidiary of Energy Services acquired 100% of Atlantic
Energy, (see Note 3).
(b) Prior to the Antargaz Acquisition on March 31, 2004, we accounted for our
19.5% ownership interest in AGZ under the equity method. Effective with our 100%
ownership, we discontinued the equity method and began reflecting all of AGZ's
operations on a consolidated basis beginning April 1, 2004.
Income from our equity investees comprises the following:
2004 2003 2002
---- ---- ----
Equity in income of equity investees $ 11.3 $ 5.3 $ 6.0
Interest income on AGZ Bonds - - 0.9
Currency gain from redemption of
AGZ Bonds - - 1.6
------- ------- -------
Total $ 11.3 $ 5.3 $ 8.5
------- ------- -------
Undistributed net earnings of our equity investees included in
consolidated retained earnings were $0.5 and $3.3 at September 30, 2004 and
2003, respectively.
On March 27, 2001, UGI France, a wholly owned indirect subsidiary of
Enterprises, together with Paribas Affaires Industrielles ("PAI") and Medit
acquired, through AGZ, the stock and certain related
52
UGI Corporation 2004 Annual Report
assets of Antargaz, formerly Elf Antargaz. Under the terms of the Shareholders'
Funding Agreement among UGI France, PAI and Medit, we acquired an approximate
19.5% equity interest in AGZ; PAI an approximate 68.1% interest; Medit an
approximate 9.7% interest; and certain members of management of AGZ 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 E29.8 ($26.6) investment comprising a E9.8 investment in shares of
AGZ and a E20.0 investment in redeemable bonds of AGZ ("AGZ Bonds"). In July
2003, the Company received a dividend of E5.0 ($5.6) from AGZ. In July 2002, the
Company received $19.3 in cash from AGZ in repayment of E18 face value ($17.7)
of AGZ Bonds, representing 90% of such bonds held by the Company, plus accrued
interest. This repayment was funded from the proceeds of the High Yield Bonds.
Concurrent with the repayment, the remaining E2.0 (10%) investment in AGZ Bonds
was redeemed in the form of additional shares of AGZ. After these transactions,
the Company continued 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 in the 2002 Consolidated Statement of Income. Because we believed we
had significant influence over operating and financial policies of AGZ due, in
part, to our membership on its Board of Directors, our investment in AGZ was
accounted for by the equity method prior to our acquisition of the remaining
80.5% ownership interests in AGZ.
Summarized financial information for AGZ, prior to the Antargaz
Acquisition, follows:
2003 2002
---- ----
STATEMENT OF INCOME DATA:
Revenues $ 698.4 $ 534.8
---------- ---------
Operating income $ 96.7 $ 79.4
Interest, net (37.7) (27.9)
---------- ---------
Income before income taxes $ 59.0 $ 51.5
Income taxes $ (24.4) $ (20.7)
Net income $ 32.7 $ 29.9
---------- ---------
BALANCE SHEET DATA (AT SEPTEMBER 30):
Current assets $ 196.8
Property, plant and equipment, net 321.6
Goodwill 443.8
Other assets 106.2
----------
Total assets $ 1,068.4
----------
Current liabilities $ 136.2
Long-term debt 453.9
Other liabilities 354.8
----------
Total liabilities $ 944.9
----------
Equity $ 123.5
----------
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 18 - QUARTERLY DATA (UNAUDITED)
The following unaudited quarterly data includes adjustments (consisting only of
normal recurring adjustments) which we consider necessary for a fair
presentation. Our quarterly results fluctuate because of the seasonal nature of
our businesses.
December 31, March 31, June 30, September 30,
2003 2002 2004 2003 2004 2003 2004 2003
---- ---- ---- ---- ---- ---- ---- ----
Revenues $ 893.7 $ 739.9 $ 1,316.6 $ 1,135.9 $ 823.4 $ 623.1 $ 751.0 $527.2
Operating income $ 108.3 $ 107.4 $ 181.6 $ 184.4 $ 33.9 $ 8.4 $ 7.5 $ 2.1
Income (loss) from equity investees $ 4.2 $ 1.9 $ 8.4 $ 5.0 $ (0.6) $ 0.2 $ (0.7) $ (1.8)
Net income (loss) $ 38.8 $ 36.7 $ 67.1 $ 69.8 $ 8.3 $ (2.0) $ (2.6) $ (5.6)
Earnings (loss) per share:
Basic $ 0.91 $ 0.88 $ 1.51 $ 1.66 $ 0.16 $ (0.05) $ (0.05) $(0.13)
Diluted $ 0.88 $ 0.86 $ 1.48 $ 1.62 $ 0.16 $ (0.05) $ (0.05) $(0.13)
------- ------- --------- --------- ------- ------- ------- ------
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 19 - SEGMENT INFORMATION
We have organized our business units into six reportable segments
generally based upon products sold, geographic location (domestic or
international) or regulatory environment. Our reportable segments are: (1)
AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an
international LPG segment comprising FLAGA and our international propane equity
investment ("Other"); (4) Gas Utility; (5) Electric Utility; and (6) Energy
Services (comprising Energy Services' gas marketing business and UGID's
electricity generation business). We refer to both international segments
collectively as "International Propane."
Effective October 1, 2003, we realigned our business units in order to
expand the energy management services available to our customers and to
strengthen our focus on power marketing. As a result of this realignment, the
operating results of UGID have been combined with those of Energy Services
rather than with Electric Utility as previously reported. We restated our
prior-year segment data to be consistent with the current period presentation.
AmeriGas Propane derives its revenues principally from the sale of propane
and related equipment and supplies to retail customers from locations in 46
states. Our International Propane segments' revenues are derived principally
from the distribution of LPG to retail customers in France, Austria, the Czech
Republic and Slovakia. Gas Utility's revenues are derived principally from the
sale and distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Utility derives its revenues principally from the
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 and LPG to customers located primarily in the
Eastern region of the United States.
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
International Propane, Gas Utility, Electric Utility and Energy Services
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 segments, are derived from sources within the United States, and all of
our reportable segments' long-lived assets, other than those of our
International Propane segments, are located in the United States.
54
UGI Corporation 2004 Annual Report
Financial information by our six reportable business segments follows:
Reportable Segments
-----------------------------------------------------------
International Propane
---------------------
AmeriGas Gas Electric Energy Corporate &
Total Eliminations Propane Utility Utility Services Antargaz Other (b) Other (c)
-------- ------------ -------- ------- ------- -------- -------- --------- -----------
2004
Revenues $3,784.7 $ - $1,775.9 $ 560.4 $ 89.7 $ 967.2 $ 270.8 $ 62.6 $ 58.1
Cost of sales $2,526.9 $ - $1,029.2 $ 368.9 $ 43.3 $ 912.2 $ 106.0 $ 32.0 $ 35.3
Operating income $ 331.3 $ - $ 176.0 $ 80.1 $ 20.9 $ 31.1 $ 15.1 $ 5.4 $ 2.7
Income (loss) from equity investees 11.3 - 0.7 - - - 10.8 (0.2) -
Interest expense (119.1) - (83.1) (15.9) (2.0) - (14.0) (3.6) (0.5)
Minority interests (47.5) - (47.7) - - - 0.1 0.1 -
-------- ------------ -------- ------- ------- -------- -------- --------- --------
Income before income taxes $ 176.0 - $ 45.9 $ 64.2 $ 18.9 $ 31.1 $ 12.0 $ 1.7 $ 2.2
Depreciation and amortization $ 132.3 - $ 80.7 $ 19.5 $ 3.0 $ 4.0 $ 18.5 $ 5.5 $ 1.1
Partnership EBITDA (a) $ 255.9
Total assets $4,235.4 $ (322.1) $1,567.9 $ 766.0 $ 89.8 $ 182.8 $1,344.5 $ 156.2 $ 450.3
Capital expenditures $ 133.7 $ - $ 61.7 $ 35.5 $ 5.3 $ 2.9 $ 23.6 $ 4.0 $ 0.7
Investments in equity investees $ 17.2 $ - $ 3.5 $ - $ - $ 9.6 $ 4.1 $ - $ -
Goodwill and excess reorganization
value $1,245.9 $ - $ 608.2 $ - $ - $ 2.8 $ 561.6 $ 68.2 $ 5.1
======== ============ ======== ======= ======= ======== ======== ========= ========
2003
Revenues $3,026.1 $ (2.4) $1,628.4 $ 539.9 $ 88.8 $ 668.0 $ - $ 54.5 $ 48.9
Cost of sales $1,984.3 $ - $ 910.3 $ 343.0 $ 43.7 $ 632.4 $ - $ 27.4 $ 27.5
Operating income $ 302.3 $ - $ 164.5 $ 96.1 $ 20.3 $ 19.2 $ (0.9) $ 1.6 $ 1.5
Income (loss) from equity investees 5.3 - (0.6) - - - 6.4 (0.5) -
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 $ 18.0 $ 19.2 $ 5.5 $ (3.0) $ 1.2
Depreciation and amortization $ 103.0 $ - $ 74.8 $ 18.1 $ 3.0 $ 2.2 $ - $ 3.9 $ 1.0
Partnership EBITDA (a) $ 234.4
Total assets $2,795.2 $ (39.6) $1,518.5 $ 725.1 $ 84.0 $ 164.2 $ - $ 165.0 $ 178.0
Capital expenditures $ 101.4 $ - $ 53.4(d)$ 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 $ (12.0) $1,307.9 $ 404.5 $ 83.5 $ 344.8 $ - $ 46.7 $ 38.3
Cost of sales $1,296.6 $ (10.0) $ 653.1 $ 241.7 $ 48.7 $ 320.8 $ - $ 22.6 $ 19.7
Operating income $ 253.3 $ - $ 145.0 $ 77.1 $ 11.7 $ 12.6 $ - $ 3.9 $ 3.0
Income (loss) from equity investees 8.5 - 0.3 - - - 9.1(e) (0.8) (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 $ 9.3 $ 12.6 $ 9.1 $ (1.1) $ 2.4
Depreciation and amortization $ 93.5 $ - $ 66.4 $ 19.0 $ 3.0 $ 1.0 $ - $ 3.2 $ 0.9
Partnership EBITDA (a) $ 209.6
Total assets $2,624.5 $ (34.1) $1,505.8 $ 689.1 $ 89.1 $ 77.1 $ - $ 141.1 $ 156.4
Capital expenditures $ 94.7 $ - $ 53.5(d) $ 31.0 $ 4.6 $ 1.2 $ - $ 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
======== ============ ======== ======= ======= ======== ======== ========= ========
(a) The following table provides a reconciliation of Partnership EBITDA to
AmeriGas Propane operating income:
Year ended September 30, 2004 2003 2002
- ------------------------ ---- ---- ----
Partnership EBITDA $255.9 $234.4 $209.6
Depreciation and amortization (i) (80.6) (74.6) (66.1)
Minority interests (ii) 1.4 1.1 1.1
Income (loss) from equity investees (0.7) 0.6 (0.3)
Loss on extinguishments of debt - 3.0 0.7
------ ------ ------
Operating income $176.0 $164.5 $145.0
====== ====== ======
(i) Excludes General Partner depreciation and amortization of $0.1, $0.2, and
$0.3 in 2004, 2003 and 2002, respectively.
(ii) Principally represents the General Partner's 1.01% interest in AmeriGas
OLP
(b) International Other principally comprises FLAGA and our joint-venture
business in China.
(c) Corporate & Other results of operations principally comprise UGI
Enterprises' HVAC/R operations, net expenses of UGI's captive general
liability insurance company and UGI Corporation's unallocated corporate
and general expenses, and interest income. Corporate & Other assets
principally comprise cash and short-term investments and an intercompany
loan. The intercompany interest associated with the intercompany loan is
eliminated in the segment presentation.
(d) Includes capital leases of $0.5 in 2003.
(e) In addition to equity income (loss) of international propane equity
investees, 2002 includes a currency transaction gain of $1.6 from the
redemption of AGZ Bonds and $0.9 of interest income on AGZ Bonds.
55