UGI Corporation 2005 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, 2005, UGI, through its wholly owned second-tier
subsidiary AmeriGas Propane, Inc. (the "General Partner"), held an approximate
44% 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 first- and
second-tier subsidiaries, collectively ("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. In addition, Energy
Services' wholly owned subsidiary UGI Asset Management, Inc., through its
subsidiary Atlantic Energy, Inc. (collectively, "Asset Management") owns a
propane storage terminal located in Chesapeake, Virginia. See Note 2 to
Consolidated Financial Statements. Through other subsidiaries, Enterprises owns
and operates a heating, ventilation, air-conditioning, refrigeration and
electrical contracting services 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 18.
RESULTS OF OPERATIONS
2005 COMPARED WITH 2004
CONSOLIDATED RESULTS
2005 2004 Variance-
--------------- --------------- Favorable
% OF % of (Unfavorable)
TOTAL Total -----------------
NET NET Net Net Net
INCOME INCOME Income Income Income % Change
------ ------ ------ ------ ------ --------
(Millions of dollars)
AmeriGas Propane $ 17.6 9.4% $ 29.4 26.3% $(11.8) (40.1)%
International Propane 99.4 53.0% 13.3 11.9% 86.1 N.M.
Gas Utility 39.3 21.0% 37.9 34.0% 1.4 3.7%
Electric Utility 11.5 6.1% 11.0 9.9% 0.5 4.5%
Energy Services 21.7 11.6% 18.2 16.3% 3.5 19.2%
Corporate & Other (2.0) (1.1)% 1.8 1.6% (3.8) N.M.
------ ----- ------ ----- ------ ----
Total $187.5 100.0% $111.6 100.0% $ 75.9 68.0%
------ ----- ------ ----- ------ ----
N.M. - Variance is not meaningful.
EXECUTIVE OVERVIEW
Fiscal 2005 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. Our net income grew to $187.5 million in Fiscal 2005 from $111.6
million in Fiscal 2004. Our net income for Fiscal 2005 includes 100% of
Antargaz' results for a full fiscal year, including a winter-heating season. The
prior year's results included Antargaz as a 19.5% equity investment for the 2004
winter-heating season and 100% of Antargaz' results beginning April 1, 2004
resulting from our acquisition of the remaining 80.5% ownership interests in AGZ
("Antargaz Acquisition"). AmeriGas Propane's decreased contribution to net
income reflects (1) a $9.4 million after-tax loss on the early extinguishment of
debt associated with a refinancing which will reduce future annual interest
expense and (2) the effects of reduced volumes sold due to customer conservation
and warmer weather. Antargaz' Fiscal 2005 results include the beneficial effects
of unusually high margins per gallon of LPG sold ("unit margins") and a $14.2
million net after-tax gain associated with the resolution of certain non-income
related tax contingencies. Also contributing to the increase in Antargaz' income
is the absence of a $9.1 million pretax foreign exchange loss incurred in Fiscal
2004 associated with fixing a portion of the euro-denominated purchase price in
dollars.
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 commodities we sell is used in heating
applications. Weather in both our domestic and international service territories
was warmer than normal in Fiscal 2005.
Looking ahead to Fiscal 2006, we expect customers to continue to make
efforts to conserve energy due to high energy prices. As part of our business
strategy, we continue to seek new growth opportunities through acquisitions. We
also expect that Antargaz' contribution to net income will decline as its unit
margins return to a level more sustainable over the long-term. Based upon
average historical margins, management estimates the positive effect of
Antargaz' high unit margins coupled with a weak dollar on our net income during
Fiscal 2005 to be approximately $0.25 per diluted share.
13
FINANCIAL REVIEW (continued)
Increase
AMERIGAS PROPANE: 2005 2004 (Decrease)
- ----------------- -------- -------- ----------------
(Millions of dollars)
Revenues $1,963.3 $1,775.9 $187.4 10.6%
Total margin (a) $ 743.3 $ 746.7 $ (3.4) (0.5)%
Partnership EBITDA (b) $ 215.9 $ 255.9 $(40.0) (15.6)%
Operating income $ 168.1 $ 176.0 $ (7.9) (4.5)%
Retail gallons sold (millions) 1,034.9 1,059.1 (24.2) (2.3)%
Degree days - % warmer
than normal (c) 6.9% 4.9% -- --
(a) Total margin represents total revenues less total cost of sales.
(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 18 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.
Weather in AmeriGas Propane's service territories based upon heating degree
days was 6.9% warmer than normal in Fiscal 2005 compared with weather that was
4.9% warmer than normal during Fiscal 2004. Retail propane volumes sold
decreased approximately 2.3% principally due to the warmer than normal winter
weather and the negative effects of customer conservation on volumes sold, which
is primarily attributed to increased propane selling prices. Low-margin
wholesale propane volumes sold decreased during Fiscal 2005 reflecting lower
volumes sold in connection with product cost hedging activities.
Retail propane revenues increased $199.1 million reflecting a $232.9
million increase due to higher average selling prices partially offset by a
$33.8 million decrease due to the lower retail volumes sold. Wholesale propane
revenues decreased $19.1 million reflecting a $54.1 million decrease due to
lower volumes sold partially offset by a $35.0 million increase due to higher
average selling prices. The higher average retail and wholesale selling prices
per gallon reflect significantly higher propane product costs. The average
wholesale cost per gallon of propane during Fiscal 2005 at Mont Belvieu, one of
the major supply points in the United States, was approximately 28% greater than
the average cost per gallon during Fiscal 2004. Total cost of sales increased
$190.8 million reflecting the higher propane product costs.
Total margin decreased $3.4 million principally due to the lower retail
volumes sold partially offset by higher margin from ancillary sales and services
and, to a much lesser extent, slightly higher average retail propane margins per
gallon. Contributing to the decline in total margin during Fiscal 2005 was lower
margin generated by our Prefilled Propane Xchange(R) ("PPX") program due largely
to competitive pricing pressures and the high cost of propane.
Partnership EBITDA during Fiscal 2005 decreased $40.0 million compared to
Fiscal 2004 as a result of (1) a $33.6 million loss on early extinguishment of
debt resulting from the Partnership's refinancing of its Senior Notes in May
2005 (the "Refinancing"), (2) a $17.1 million increase in operating and
administrative expenses and (3) a $3.4 million decrease in total margin all of
which were partially offset by a $14.0 million increase in other income. A $6.3
million increase in vehicle fuel expense and a $3.7 million increase in vehicle
lease costs were the most significant causes of the increase in operating and
administrative expenses. Increases in maintenance and repairs, uncollectible
accounts expense and general insurance expense, among others also contributed to
the higher operating and administrative expenses. The increase in other income
primarily reflects higher gains on fixed asset disposals and higher customer
finance charges.
Operating income decreased $7.9 million reflecting the decrease in margin
and the aforementioned higher operating and administrative expenses which were
partially offset by the higher other income and a $7.4 million decrease in
depreciation expense. The decrease in depreciation expense is largely attributed
to lower capital expenditures related to PPX.
Increase
INTERNATIONAL PROPANE: 2005 2004 (Decrease)
- ---------------------- ------ ------ -------------
(Millions of dollars)
Revenues $943.9 $333.4 $610.5 N.M.
Total margin (a) $499.8 $171.3 $328.5 N.M.
Operating income $193.8 $ 20.5 $173.3 N.M.
Income (loss) from equity investees $ (2.6) $ 10.6 $(13.2) N.M.
Income before income taxes $159.0 $ 13.7 $145.3 N.M.
N.M. - Not meaningful due to Antargaz Acquisition in March 2004.
(a) Total margin represents total revenues less total cost of sales.
International Propane's results of operations in Fiscal 2005 significantly
increased compared to Fiscal 2004 due to the consolidation of all of Antargaz'
operations for a full twelve months, including the winter-heating season,
compared to the consolidation for only six months in Fiscal 2004 which primarily
included the spring and summer months. Antargaz' revenues, total margin and
operating income during Fiscal 2005 were $869.9 million, $468.4 million and
$188.3 million, respectively, compared to $270.8 million, $140.7 million and
$15.1 million, respectively, from April 1, 2004 to September 30, 2004. Weather
in International Propane's service territories based upon heating degree days
was warmer than normal during Fiscal 2005. During Fiscal 2005, Antargaz sold
approximately 338 million retail gallons of LPG while experiencing weather that
was approximately 4% warmer than normal compared to 336 million retail gallons
sold while experiencing weather that was 5% warmer than normal during the twelve
months ended September 30, 2004.
International Propane's revenues increased significantly during Fiscal 2005
due to the absence of revenues in Fiscal 2004 when Antargaz was an equity
investment during the first six months of the fiscal year and, to a lesser
extent, higher LPG selling prices. FLAGA's revenues increased $11.4 million in
Fiscal 2005 due to the effects of (1) higher LPG selling prices, (2) a 7%
increase in volumes sold, largely resulting from the acquisition of the Czech
business of BP PLC in the fourth quarter of Fiscal 2004 and (3) the beneficial
currency translation effects of a stronger euro versus the dollar.
International Propane's increased total margin is attributable to Antargaz'
performance. Antargaz continued to benefit from high
14
UGI Corporation 2005 Annual Report
unit margins primarily reflecting the effects of declining LPG costs during much
of the Fiscal 2005 heating season. Antargaz' LPG purchases are principally
denominated in U.S. dollars. Accordingly, its LPG costs further declined during
the Fiscal 2005 heating season due to the strengthening euro versus the dollar.
Based upon average historical unit margins, management estimates the positive
effect of Antargaz' high unit margins and the effects of a weak dollar on our
net income during Fiscal 2005 to be approximately $0.25 per diluted share. The
euro was translated at a monthly average exchange rate of 1.27 dollars per euro
during Fiscal 2005 compared to 1.22 dollars per euro during Fiscal 2004. FLAGA's
total margin decreased slightly in Fiscal 2005 resulting from lower margins per
gallon of LPG as it was unable to pass on all of the higher average LPG costs to
their customers.
The increase in International Propane operating income principally reflects
the inclusion of Antargaz for twelve months, including $18.8 million resulting
from the reversal of certain non-income tax related reserves (see discussion in
"Antargaz Tax Matters"), the previously mentioned increase in margin and the
absence of $9.1 million loss incurred in the prior year 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 partially offset by higher
operating and administrative expenses and higher depreciation and amortization
resulting from the Antargaz Acquisition. FLAGA's operating income increased
slightly primarily reflecting the favorable effects of a stronger euro versus
the dollar and a decrease in operating and administrative expenses partially
offset by the decrease in its margin.
International Propane income from equity investees in Fiscal 2005 includes
losses related to Antargaz' equity investment in Geovexin compared to Fiscal
2004 which includes equity investee income from our 19.5% ownership interest in
AGZ through March 31, 2004.
The increase in International Propane income before income taxes reflects
the increase in operating income partially offset by the decrease in equity
investee income and greater interest expense resulting from the Antargaz
Acquisition.
GAS UTILITY: 2005 2004 Increase
- ------------ ------ ------ -----------
(Millions of dollars)
Revenues $585.1 $560.4 $24.7 4.4%
Total margin (a) $195.0 $191.5 $ 3.5 1.8%
Operating income $ 81.6 $ 80.1 $ 1.5 1.9%
Income before income taxes $ 65.0 $ 64.2 $ 0.8 1.2%
System throughput -
billions of cubic feet ("bcf") 84.7 82.2 2.5 3.0%
Degree days - % warmer
than normal 1.4% 2.9% -- --
(a) Total margin represents total revenues less total cost of sales.
Weather in Gas Utility's service territory based upon heating degree days
was 1.4% warmer than normal in Fiscal 2005 compared with weather that was 2.9%
warmer than normal in Fiscal 2004. Total distribution system throughput
increased in Fiscal 2005 due primarily to greater interruptible delivery service
volumes. Notwithstanding the volume effects of the slightly colder weather and
an increase in the number of firm- residential, commercial and industrial
("retail core-market") customers, Fiscal 2005 retail core-market throughput was
substantially equal to Fiscal 2004 primarily due to a reduction in customer
usage per degree day. We believe that the lower usage per degree day was
primarily the result of conservation in response to higher natural gas prices.
These higher natural gas prices are passed through to retail core-market
customers through higher purchased gas cost ("PGC") rates.
The increase in Gas Utility revenues during 2005 is principally the result
of a $53.4 million increase in retail core-market revenues reflecting higher
average PGC rates and, to a lesser extent, the increase in throughput and higher
revenues from interruptible customers. These increases were partially offset by
a $37.2 million decrease in revenues from low-margin off-system sales. Increases
or decreases in retail core-market customer revenues and cost of sales results
principally from changes in retail core-market volumes 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 at amounts included in PGC rates. The difference between
actual gas costs and the amount included in rates is deferred on the balance
sheet as a regulatory asset or liability and represents amounts to be collected
from or refunded to customers in a future period. As a result of the PGC
recovery mechanism, 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's cost of gas was $390.1 million in Fiscal 2005 compared to $368.9
million in Fiscal 2004 reflecting the effects of the higher PGC rates partially
offset by lower cost of sales associated with lower off-system sales.
The $3.5 million increase in Gas Utility total margin in Fiscal 2005
principally reflects greater margin generated from higher interruptible delivery
service volumes and higher average interruptible delivery service unit margins.
The increase in average interruptible delivery service unit margins reflects an
increase in the spread between delivered prices for natural gas and alternative
fuels, principally oil. Gross margin from retail core-market customers was
relatively stable as lower usage per degree day was offset by an increase in the
number of customers.
Gas Utility operating income increased $1.5 million in Fiscal 2005 as the
$3.5 million increase in total margin and a $1.9 million increase in other
income were partially offset by higher operating and administrative expenses and
a $1.2 million increase in depreciation and amortization. The increase in other
income is due in large part to the absence of costs recorded in Fiscal 2004
related to a regulatory claim resulting from the discontinuance of natural gas
service to certain customers. Fiscal 2005 operating and administrative expenses
were slightly higher than in Fiscal 2004 as a $1.9 million increase in
uncollectible accounts and customer assistance expenses, the absence of
environmental insurance settlements received in the prior year and higher
professional services expenses were partially offset by lower injuries and
damages and distribution system expenses.
The increase in depreciation expense reflects the normal effects of yearly
capital expenditures. The increase in Gas Utility income before income taxes in
Fiscal 2005 reflects the increase in operating income partially
15
FINANCIAL REVIEW (continued)
offset by higher interest expense resulting from higher average short-term debt
outstanding and higher short-term interest rates.
ELECTRIC UTILITY: 2005 2004 Increase
- ----------------- -------- ------ -----------
(Millions of dollars)
Revenues $ 96.1 $ 89.7 $ 6.4 7.1%
Total margin (a) $ 43.1 $ 41.6 $ 1.5 3.6%
Operating income $ 21.6 $ 20.9 $ 0.7 3.3%
Income before income taxes $ 19.9 $ 18.9 $ 1.0 5.3%
Distribution sales - millions of
kilowatt hours ("gwh") 1,021.8 983.9 37.9 3.9%
(a) Total margin represents total revenues less total cost of sales and
revenue-related taxes, i.e. gross receipts taxes of $5.2 and $4.8 million
in Fiscal 2005 and Fiscal 2004, respectively. For financial statement
purposes, revenue-related taxes are included in "Utility taxes other than
income taxes" on the Consolidated Statements of Income.
Electric Utility's Fiscal 2005 kilowatt-hour sales increased principally
reflecting slightly colder Fiscal 2005 heating-season weather and warmer Fiscal
2005 cooling-season weather which increased sales for air conditioning. The
increase in Electric Utility revenues principally reflects the effects of a 4.5%
increase in its Provider of Last Resort ("POLR") electric generation rates
effective January 1, 2005 and the higher kilowatt-hour sales. Electric Utility's
cost of sales increased $4.5 million as a result of higher per-unit purchased
power costs and the higher sales.
Electric Utility total margin in Fiscal 2005 increased $1.5 million
principally as a result of the previously mentioned increase in POLR rates and
the higher kilowatt-hour sales partially offset by the increase in per-unit
purchased power costs. Operating income and income before income taxes in Fiscal
2005 were higher than the prior year as the increase in total margin was
partially offset by higher operating and administrative costs, principally
higher distribution system maintenance expenses.
ENERGY SERVICES: 2005 2004 Increase
- ---------------- -------- ------ -------------
(Millions of dollars)
Revenues $1,355.0 $967.2 $387.8 40.1%
Total margin (a) $ 73.6 $ 55.0 $ 18.6 33.8%
Operating Income $ 37.5 $ 31.1 $ 6.4 20.6%
Income before income taxes $ 37.5 $ 31.1 $ 6.4 20.6%
(a) Total margin represents total revenues less total cost of sales.
The $387.8 million increase in Energy Services revenues in Fiscal 2005
resulted primarily from (1) increased natural gas prices and to a lesser extent
an approximate 2% growth in natural gas volumes sold, (2) approximately $70
million of revenues generated by Asset Management's propane terminal, which was
acquired by Energy Services in November 2004, and (3) $9.2 million of increased
revenues from UGID's electric generation. The increase in UGID's electric
generation revenues largely reflects the reduced electricity generated in Fiscal
2004 resulting from a scheduled plant maintenance outage. Energy Services total
margin increased $18.6 million resulting from (1) a $10.0 million increase in
margin from Energy Services' gas marketing business principally due to higher
income from winter storage and peaking services, (2) Asset Management's
contribution of $5.6 million of margin and (3) increased margin from UGID.
Atlantic Energy, the owner of a 20 million gallon propane storage terminal
located in Chesapeake, Virginia, was purchased through two separate transactions
with ConocoPhillips Company and AmeriGas Propane. See Note 2 to Consolidated
Financial Statements for additional information regarding the acquisition.
The increase in Energy Services operating income and income before income
taxes principally reflects the previously mentioned increase in total margin
partially offset by $9.3 million higher operating and administrative expenses,
$1.7 million higher depreciation and amortization and $1.3 million lower other
income. The two main drivers of the increased operating and administrative
expenses were operating and administrative expenses associated with the propane
terminal since its acquisition in November 2004 and higher uncollectible
accounts expense. The increase in depreciation and amortization is also largely
attributable to Asset Management's propane terminal since its acquisition.
INTEREST EXPENSE AND INCOME TAXES. Interest expense increased to $130.2 million
in Fiscal 2005 from $119.1 million in Fiscal 2004 principally due to $13.9
million 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 38.9% in Fiscal 2005 and
36.6% in Fiscal 2004.
2004 COMPARED WITH 2003
CONSOLIDATED RESULTS
Variance-
2004 2003 Favorable
------------------- ------------------- (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 2.4% (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.
Highlights from Fiscal 2004:
- - March 2004 Antargaz Acquisition and its contribution to our earnings
- - Issuance of 7.8 million shares of our common stock used to finance a
portion of the Antargaz Acquisition
- - $9.1 million pre-tax loss on the forward purchase of euros used to fix a
portion of the euro-denominated purchase price of AGZ
- - Increased net income contributed by all operating business units with the
exception of our Gas Utility which experienced significantly warmer weather
than in the prior year
16
UGI Corporation 2005 Annual Report
Increase
AMERIGAS PROPANE: 2004 2003 (Decrease)
- ---------------- -------- -------- --------------
(Millions of dollars)
Revenues $1,775.9 $1,628.4 $147.5 9.1%
Total margin $ 746.7 $ 718.1 $ 28.6 4.0%
Partnership EBITDA $ 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 (4.9)% 0.2% -- --
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 significantly higher propane product costs. Low margin wholesale
volumes increased primarily reflecting higher volumes sold in connection with
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 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.
INTERNATIONAL PROPANE: 2004 2003 Increase
- --------------------- ------ ----- -------------
(Millions of dollars)
Revenues $333.4 $54.5 $278.9 N.M.
Total margin $171.3 $27.1 $144.2 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.
N.M. - Due to the Antargaz Acquisition, variance is not meaningful.
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, $140.7 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
17
FINANCIAL REVIEW (continued)
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.
Increase
GAS UTILITY: 2004 2003 (Decrease)
- ------------ ------ ------ --------------
(Millions of dollars)
Revenues $560.4 $539.9 $ 20.5 3.8%
Total margin $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 - bcf 82.2 83.8 (1.6) (1.9)%
Degree days - % (warmer) colder
than normal (2.9)% 7.0% -- --
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 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 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.
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 from delivery-service customers.
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: 2004 2003 Increase
- ----------------- ------ ------ ----------
(Millions of dollars)
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 - gwh 983.9 980.0 3.9 0.4%
(a) Electric Utility total margin represents total revenues less cost of sales
and Electric Utility gross receipts taxes of $4.8 million in both Fiscal
2004 and Fiscal 2003.
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 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 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: 2004 2003 Increase
- ---------------- ------ ------ -------------
(Millions of dollars)
Revenues $967.2 $668.0 $299.2 44.8%
Total margin $ 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%
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 $19.4 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
18
UGI Corporation 2005 Annual Report
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.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Total cash, cash equivalents and short-term investments were $385.0 million at
September 30, 2005 compared with $199.6 million at September 30, 2004. These
amounts include $138.7 million and $114.6 million, respectively, of cash, cash
equivalents and short-term investments readily available to UGI. The primary
sources of UGI's cash are the dividends and other cash payments made to UGI or
its corporate subsidiaries by its principal business segments.
AmeriGas Propane's ability to pay dividends to UGI is largely dependent
upon distributions it receives from AmeriGas Partners. At September 30, 2005,
our approximately 44% 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. In April 2005, the Partnership raised the regular
quarterly distribution from $0.55 to $0.56 per limited partner unit. The amount
of Available Cash needed annually to pay distributions on all units and the
general partner interests ("Units") in Fiscal 2005, 2004 and 2003 was
approximately $122 million, $118 million and $112 million, respectively. Based
upon the number of Partnership units outstanding on September 30, 2005, the
amount of Available Cash needed annually to pay the distributions on all Units
is approximately $129 million. The ability of the Partnership to pay
distributions 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 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 on a French GAAP basis
for the two-year period ended March 31, 2004. The amount of dividends received
in Fiscal 2005, based on AGZ's consolidated net income on a French GAAP basis
for the period April 1, 2004 through September 30, 2004, was $1.3 million.
During Fiscal 2005, 2004 and 2003, AmeriGas Propane, UGI Utilities,
International Propane and Energy Services paid dividends and made cash payments
to UGI and its subsidiaries as follows:
Year Ended September 30, 2005 2004 2003
- ------------------------ ------ ------ -----
(Millions of dollars)
AmeriGas Propane $ 45.4 $ 39.0 $44.7
UGI Utilities 38.5 45.0 33.9
International Propane (a) 22.5 54.4 --
Energy Services 9.0 15.0 7.1
------ ------ -----
Total $115.4 $153.4 $85.7
------ ------ -----
(a) Currently all amounts represent dividends and cash payments from Antargaz.
Dividends and other cash distributions are available to pay dividends on
UGI Common Stock and for investment purposes.
On April 26, 2005, UGI's Board of Directors approved a 2-for-1 split of
UGI's Common Stock. On May 24, 2005, UGI issued one additional common share for
every common share outstanding to shareholders of record on May 17, 2005. Also
on April 26, 2005, UGI's Board of Directors approved an increase in the
quarterly dividend rate on UGI Common Stock to $0.675 per post-split share, or
$1.35 per pre-split share on an annual basis, commencing with the dividend
payable July 1, 2005.
AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30, 2005
totaled $913.5 million. There were no amounts outstanding under AmeriGas OLP's
Credit Agreement at September 30, 2005.
AmeriGas OLP has a Credit Agreement that 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 $56.3 million at September 30, 2005
and was approximately the same amount issued and outstanding during all of
Fiscal 2005. 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. The average daily borrowings
outstanding under the Credit Agreement during Fiscal 2005 and Fiscal 2004 were
$27.9 million and $18.6 million, respectively. Peak borrowings outstanding under
the Credit Agreement in Fiscal 2005 and Fiscal 2004 were $98.0 million and $86.0
million, respectively.
AmeriGas Partners periodically issues debt and equity securities and
expects to continue to do so. It has issued debt securities
19
FINANCIAL REVIEW (continued)
in underwritten public offerings or private offerings and common units in
underwritten public offerings in each of the last three fiscal years. Most
recently it issued debt securities in May 2005 in a private offering and Common
Units in September 2005 in an underwritten public offering. Proceeds from the
private debt offering were used to fund the Refinancing. Proceeds from the
Partnership's securities offerings are generally used by the Partnership to
reduce indebtedness and for general Partnership purposes, including funding
acquisitions. AmeriGas Partners has an effective unallocated debt and equity
shelf registration statement with the U.S. Securities and Exchange Commission
("SEC") under which it may issue up to an additional $370.3 million of debt or
equity.
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, 2005 permit it to borrow up to the maximum amount available. For a
more detailed discussion of the Partnership's credit facilities, see Note 3 to
Consolidated Financial Statements. Based upon existing cash balances, cash
expected to be generated from operations, borrowings available under its Credit
Agreement, and expected refinancings of 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 2006.
INTERNATIONAL PROPANE. At September 30, 2005, Antargaz had total debt
outstanding of $431.1 million. There were no amounts borrowed under the revolver
portion of the Senior Facilities Agreement during the twelve months ended
September 30, 2005.
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, 2005, there was E175 million ($210.4 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. Antargaz' management believes that it will be
able to meet its anticipated contractual commitments and projected cash needs
during Fiscal 2006 principally with cash generated from operations.
At September 30, 2005, Antargaz had E165 million of 10% Senior Notes due
2011 (the "High Yield Bonds") outstanding. The High Yield Bonds are listed on
the Luxembourg Exchange.
On December 7, 2005, Antargaz executed a new five-year, floating rate
Senior Facilities Agreement with a major French bank providing for a E380
million term loan and a E50 million revolving credit facility. AGZ Finance
notified the holders of its High Yield Bonds of its decision to redeem them,
including a premium, pursuant to the Trust Deed. The proceeds of the term loan
will be used 1) to repay immediately the existing E175 million Senior Facilities
term loan, 2) to fund the redemption of the High Yield Bonds in early January
2006 and 3) for general corporate purposes. In addition, AGZ has executed an
interest rate swap agreement with the same bank to fix the rate of interest on
the term loan for the duration of the loan.
The Senior Facilities Agreement restrict the ability of AGZ to, among other
things, incur additional indebtedness and make investments. For a more detailed
discussion of Antargaz' debt, see Note 3 to Consolidated Financial Statements.
FLAGA has working capital loan commitments of E4 million and E11 million
from a European bank expiring in February and November 2006, respectively.
FLAGA's management expects to extend the E4 million portion of its commitments
through November 2006. Borrowings under the working capital commitments totaled
E13.5 million ($16.2 million) at September 30, 2005. Debt issued under these
agreements, as well as $57.9 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 3 to Consolidated Financial Statements. FLAGA's
management plans to obtain an extension of or refinance its outstanding
long-term debt. FLAGA has long-term debt maturing in Fiscal 2006 of
approximately $57.1 million.
UGI UTILITIES. UGI Utilities' debt outstanding totaled $318.2 million at
September 30, 2005. Included in this amount is $81.2 million of bank loans
outstanding.
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 through June 2008. From time to time, UGI Utilities enters into
short-term borrowings under uncommitted arrangements with major banks in order
to meet liquidity needs during the peak heating season. At September 30, 2005,
UGI Utilities had two $35 million borrowings outstanding under these uncommitted
arrangements and $11.2 million outstanding under the revolving credit
facilities. Borrowings under the uncommitted arrangements mature in February and
March 2006. Short-term borrowings, including amounts outstanding under the
revolving credit agreements, are classified as bank loans on the Consolidated
Balance Sheets. The revolving credit agreements have restrictions on such items
as total debt, debt service and payments for investments. In November 2004, UGI
Utilities borrowed $20 million which was repaid on March 1, 2005. During Fiscal
2005 and 2004, peak bank loan borrowings totaled $91.4 million and $90.9
million, respectively. Peak borrowings typically occur during the peak heating
season months of December and January. Average daily bank loan borrowings were
$52.9 million in Fiscal 2005 and $44.5 million in Fiscal 2004.
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 $125 million of Medium-Term Notes or other debt
securities. Medium-Term Notes of $50 million maturing December 2005 are expected
to be refinanced through the issuance of debt under this shelf registration.
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 2006. For a more
20
UGI Corporation 2005 Annual Report
detailed discussion of UGI Utilities' long-term debt and revolving credit
facilities, see Note 3 to Consolidated Financial Statements.
ENERGY SERVICES. UGI Energy Services, Inc. ("ESI") 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. In order to
provide additional short-term liquidity during the peak heating season due to
increased energy product costs, the maximum level of funding available at any
one time from this facility was temporarily increased to $300 million for the
period from November 1, 2005 to April 24, 2006. After April 24, 2006, the
maximum level of funding available at any one time from this facility is $150
million. Under the Receivables Facility, ESI 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 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 ESI 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." ESI continues to service, administer
and collect trade receivables on behalf of the commercial paper issuer and ESFC.
At September 30, 2005, the outstanding balance of ESFC trade receivables was
$77.8 million of which $23.5 million was sold to the commercial paper conduit
and removed from the balance sheet. Based upon cash expected to be generated
from operations and borrowings available under its Receivables Facility,
management believes that Energy Services (including UGID and Asset Management)
will be able to meet its anticipated contractual and projected cash commitments
during Fiscal 2006.
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
2006.
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, LPG, electricity
and other energy products consumed during the peak 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. AmeriGas Propane and UGI Utilities primarily use revolving credit
facilities and, as previously mentioned, have used other borrowings to satisfy
their seasonal operating cash flow needs. Energy Services uses its Receivables
Facility to satisfy its seasonal operating cash flow needs. Antargaz has
historically been successful funding its operating cash flow needs without using
its revolver. Cash flow from operating activities was $437.7 million in Fiscal
2005, $260.7 million in Fiscal 2004 and $257.0 million in Fiscal 2003. The
increase in cash flow from operating activities largely reflects the cash
provided by Antargaz' operations for a full fiscal year. Cash flow from
operating activities before changes in operating working capital was $426.5
million in Fiscal 2005, $333.0 million in Fiscal 2004, and $264.2 million in
Fiscal 2003. Changes in operating working capital provided cash flow of $11.2
million in Fiscal 2005 and used $72.3 million and $7.2 million of cash in Fiscal
2004 and Fiscal 2003, respectively. The increase in cash provided for working
capital in Fiscal 2005 largely reflects changes in accounts payable due in part
to the timing of inventory purchases and payments and an increase in accrued
income taxes partially offset by an increase in accounts receivable. The changes
in operating working capital attributable to Antargaz' operations in Fiscal 2005
reflect the changes over a twelve-month period compared to changes over a
six-month period in Fiscal 2004.
INVESTING ACTIVITIES. Investing activity cash flow is principally affected by
capital expenditures and investments in property, plant and equipment, cash paid
for acquisitions of businesses, changes in short-term investments and proceeds
from sales of assets. Cash flow used in investing activities was $191.4 million
in Fiscal 2005, $412.8 million in Fiscal 2004, and $226.1 million in Fiscal
2003. During Fiscal 2005, we spent $158.4 million for property, plant and
equipment, $133.7 million in Fiscal 2004 and $100.9 million in Fiscal 2003. The
increase largely reflects increased Antargaz capital expenditures, which
includes twelve months of expenditures in Fiscal 2005 and six months of
expenditures in Fiscal 2004. Cash paid for business acquisitions in Fiscal 2005
reflects the cash paid for several retail propane businesses acquired by
AmeriGas OLP and, to a lesser extent, the cash paid for acquisitions made by
FLAGA and HVAC/R.
FINANCING ACTIVITIES. Cash flow used by financing activities was $72.6 million
in Fiscal 2005 compared to cash flow provided by financing activities of $159.0
million in Fiscal 2004 and cash used of $83.2 million in Fiscal 2003. Financing
activity cash flow changes are primarily due to issuances and repayments of
long-term debt, net borrowings under revolving credit facilities and other
short-term borrowings, 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 September 2005, AmeriGas Partners sold 2.3 million Common Units in an
underwritten public offering at a public offering price of $33.00 per unit. The
net proceeds of the public offering totaling $72.7 million and associated
capital contributions from the General Partner totaling $1.5 million were
contributed to AmeriGas OLP and used to reduce indebtedness under its Credit
Agreement and for general partnership purposes. Concurrent with this sale of
Common Units, the Company recorded a gain in the amount of $28.0 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
21
FINANCIAL REVIEW (continued)
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 $16.0 million associated with this gain were also
recorded with a corresponding decrease in common stockholders' equity. 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.
As previously mentioned, the Partnership refinanced $373.4 million of its
outstanding 8.875% Senior Notes due 2011 through the issuance of $415.0 million
of 7.25% Senior Notes due 2015. The Partnership also incurred a $33.6 million
loss on extinguishment of debt in conjunction with its repayment of the 8.875%
Senior Notes. In April 2005, AmeriGas OLP repaid $53.8 million face amount of
maturing First Mortgage Notes with the proceeds from a $35 million term loan
("AmeriGas OLP Term Loan") due October 1, 2006, borrowings under its Credit
Agreement and existing cash balances.
Also, as previously mentioned, in September 2005, UGI Utilities entered
into two $35 million borrowings which are scheduled to mature in February and
March 2006. In May 2005, UGI Utilities refinanced $20 million of its maturing
6.62% Medium-Term Notes through the issuance of 5.16% Medium-Term Notes due in
May 2015. Also during Fiscal 2005, UGI Utilities borrowed and repaid $20 million
associated with a short-term loan that matured on March 1, 2005. On October 1,
2004, UGI Utilities redeemed all 200,000 shares of $7.75 Series Preferred Stock
at a price of $100 per share together with full cumulative dividends. The
redemption of the $7.75 Series Preferred Stock was funded with proceeds from the
October 2004 issuance of $20 million of 6.13% Medium-Term Notes due 2034.
During Fiscal 2005 we paid cash dividends on UGI Common Stock of $67.4
million and the Partnership paid the MQD and, after April 2005, the RQD on all
limited partner units.
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 $211.7 million and $196.4 million at
September 30, 2005 and 2004, respectively. At September 30, 2005 and 2004, the
Pension Plan's assets exceeded its accumulated benefit obligations by $7.4
million and $9.2 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 2006. Pre-tax pension expense (income) reflected in Fiscal 2005, 2004 and
2003 results was $3.0 million, $1.2 million and $(1.1) million, respectively.
The increase in pension expense during this period reflects the changes in the
market value of Pension Plan assets and decreases in the discount rate
assumption. In addition, Fiscal 2005 pension expense reflects the expiration of
the Pension Plan's transition asset amortization. Pension expense in Fiscal 2006
is expected to be approximately $3.1 million.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures (which exclude
acquisitions) by our business segments for Fiscal 2005, 2004 and 2003. We also
provide amounts we expect to spend in Fiscal 2006. We expect to finance Fiscal
2006 capital expenditures principally from cash generated by operations and
borrowings under our credit facilities.
Year Ended September 30, 2006 2005 2004 2003
- ------------------------ ---------- ------ ------ ------
(Millions of dollars) (estimate)
AmeriGas Propane $ 83.4 $ 62.6 $ 61.7 $ 53.4
International Propane 50.8 42.0 27.6 4.5
Gas Utility 47.6 38.8 35.5 37.2
Electric Utility 8.6 7.5 5.3 4.1
Energy Services 10.8 6.2 2.9 1.0
Other 1.4 1.3 0.7 1.2
------ ------ ------ ------
Total $202.6 $158.4 $133.7 $101.4
------ ------ ------ ------
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
The Company has contractual cash obligations that extend beyond Fiscal 2005
including scheduled repayments of long-term debt, interest on long-term fixed
rate debt, operating lease payments, unconditional purchase obligations for
pipeline capacity, pipeline transportation and natural gas storage services and
commitments to purchase natural gas, propane and electricity. The following
table presents contractual cash obligations under agreements existing as of
September 30, 2005 (in millions of dollars).
Payments Due by Period
------------------------------------------------
1 year 2 - 3 4 - 5 After
Total or less years years 5 years
-------- -------- ------ ------ --------
Long-term debt $1,622.2 $ 247.8 $360.3 $219.1 $ 795.0
Interest on long-term
fixed rate debt 580.4 88.0 138.1 108.1 246.2
Operating leases 225.2 48.1 75.5 49.5 52.1
AmeriGas Propane
supply contracts 29.5 29.5 -- -- --
International Propane
supply contracts 123.1 76.9 46.2 -- --
Energy Services
supply contracts 813.8 679.8 134.0 -- --
Gas Utility and Electric
Utility supply, storage
and transportation
contracts 570.2 250.9 149.0 95.4 74.9
-------- -------- ------ ------ --------
Total $3,964.4 $1,421.0 $903.1 $472.1 $1,168.2
-------- -------- ------ ------ --------
RELATED PARTY TRANSACTIONS
During Fiscal 2005, 2004 and 2003, 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.
22
UGI Corporation 2005 Annual Report
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"), since 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, 2005, fewer than
two percent of Gas Utility's core-market customers purchase their gas from
alternate 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 are permitted to acquire their electricity from
entities other than Electric Utility. As of September 30, 2005, fewer than 1% of
Electric Utility's customers have chosen an alternative electricity generation
supplier. 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 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 must remain on POLR service until the next
open shopping period and may, in certain circumstances, be subject to generation
rate surcharges. In October 2005, Electric Utility was notified by the only
alternative electric generation supplier in its service territory that it would
cease providing electric generation service during the first quarter of Fiscal
2006.
In accordance with the POLR Settlement, Electric Utility may increase POLR
rates up to certain limits through December 31, 2006. Consistent with the terms
of the POLR Settlement, Electric Utility's POLR rates increased 4.5% on January
1, 2005, and Electric Utility is permitted to further increase its POLR rates
beginning January 1, 2006 to no more than 7.5% above the total rates in effect
on December 31, 2004. Electric Utility expects to increase POLR rates by 3%
beginning January 1, 2006. Electric Utility is also permitted to and has entered
into multiple-year fixed-rate POLR service contracts with certain of its
customers. The PUC is currently developing post-rate-cap POLR regulations that
are expected to further define POLR service obligations and pricing.
Electric Utility has no agreement currently in place for POLR rates to be
effective after December 31, 2006. The terms of the POLR Settlement require the
POLR Settlement parties to begin discussions on post-2006 POLR rates by April 1,
2006. Although Electric Utility expects it will be able to recover electric
power costs incurred in serving POLR customers after December 31, 2006, it is
unable to forecast the level of margins, if any, from providing POLR service.
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.
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
23
FINANCIAL REVIEW (continued)
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. Citizens alleges that UGI Utilities and its
predecessors owned and operated the plant from 1901 to 1928. Studies conducted
by the City and Citizens suggest that it could cost up to $18 million to clean
up the river. Citizens' third-party claims have been stayed pending a resolution
of the City's suit against Citizens, which was tried in September 2005 and has
not yet been decided. 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. In March 2005, the court granted UGI Utilities' motion
for summary judgment dismissing AGL's complaint. AGL has appealed.
AGL has informed UGI Utilities that it has begun remediation of MGP wastes
at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI
Utilities' operated the MGP in the early 1900s. AGL 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. The trial court granted UGI Utilities' motion
for summary judgment and dismissed ConEd's complaint. The grant of summary
judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a
panel of the Second Circuit Court of Appeals affirmed in part and reversed in
part the decision of the trial court. The appellate panel affirmed the trial
court's decision dismissing claims that UGI Utilities was liable under CERCLA as
an operator of MGPs owned and operated by its former subsidiaries. The appellate
panel reversed the trial court's decision that UGI Utilities was released from
liability at three sites where UGI Utilities operated MGPs under lease.
UGI Utilities filed for reconsideration of the panel's order. UGI Utilities
believes that any liability it may have for a share of the response costs at the
three leased MGP sites will not have a material effect on its financial
condition or results of operations.
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.
ANTARGAZ TAX MATTERS
The French tax authorities levy taxes on legal entities and individuals
regularly operating a business in France which are commonly referred to
collectively as "business tax." The amount of business tax charged annually is
generally dependent upon the value of the entity's tangible fixed assets. Prior
to the Antargaz Acquisition, Antargaz filed suit against French tax authorities
in connection with the assessment of business tax related to the tax treatment
of certain of its owned tanks at customer locations. Elf Antar France and Elf
Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify
Antargaz for all payments that would have been due from Antargaz in respect
24
UGI Corporation 2005 Annual Report
of the tax related to its tanks for the period from January 1, 1997 through
December 31, 2000. During the year ended September 30, 2005, Antargaz was
required to remit payment to French tax authorities with respect to this matter
and Antargaz was fully reimbursed pursuant to the indemnity agreement. The
indemnity from the former owners for tax amounts accrued is reflected in our
balance sheet as an asset and, at September 30, 2005, the remaining amount is
immaterial.
Antargaz has recorded liabilities for business taxes related to various
classes of equipment. On February 4, 2005, Antargaz received a letter from the
French government which eliminated the requirement for Antargaz to pay business
tax associated with tanks at certain customer locations. In addition, during
Fiscal 2005 resolution was reached relating to business taxes relating to a
prior year. Further changes in the French government's interpretation of the tax
laws or in the tax laws themselves could have either an adverse or a favorable
effect on our results of operations. Our 2005 Consolidated Statement of Income
includes a pre-tax gain of $18.8 million and a net after-tax gain of $14.2
million associated with the resolution of certain business tax matters related
principally to prior years.
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. Their profitability is sensitive to changes in LPG supply costs.
Increases in supply costs are generally passed on to customers. International
Propane and 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 LPG market price risk,
the Partnership 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 and Antargaz hedges a
portion of its future U.S. dollar denominated LPG product purchases through the
use of forward foreign exchange contracts. Antargaz may also enter into other
contracts, similar to those used by the Partnership. FLAGA has and may use
derivative commodity instruments to reduce market risk associated with a portion
of its propane purchases. Currently, FLAGA's hedging activities are not material
to the Company's financial position or results of operations. Over-the-counter
derivative commodity instruments utilized 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 periodic adjustments 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, Electric Utility increased its POLR
generation rates for all metered customers 4.5% of total rates in effect on
December 31, 2004 and expects to increase POLR rates by 3% effective January 1,
2006. 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
nonperformance risk, Electric Utility has diversified its purchases across
several suppliers and entered into bilateral collateral arrangements with
certain of them. At September 30, 2005, Electric Utility held $13.5 million in
collateral deposits which are reflected in other current liabilities in the
Consolidated Balance Sheet. From time to time, Electric Utility enters into
electric price swap agreements to reduce the volatility in the cost of a portion
of its anticipated electricity requirements. At September 30, 2005, Electric
Utility had an electric price swap agreement associated with purchases of a
portion of electricity anticipated to occur in 2007.
In order to manage market price risk relating to substantially all of
Energy Services' fixed-price sales contracts for 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. At September 30, 2005,
Energy Services has $2.5 million deposited into such margin accounts. 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.
25
FINANCIAL REVIEW (continued)
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 conjunction with certain of these sales agreements, at September 30,
2005, UGID paid $17.9 million in collateral deposits with its counterparties
which is reflected in other assets on the Consolidated Balance Sheet. In the
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.
Asset Management has and may continue to enter into fixed-price sales
agreements for a portion of its propane sales. In order to manage the market
price risk relating to substantially all of its fixed-price sales contracts for
propane, Asset Management enters into price swap and option contracts.
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, AmeriGas OLP Term Loan, UGI Utilities' short-term borrowings, 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 its
variable-rate debt through June 2006 through the use of interest rate swaps. At
September 30, 2005 and 2004, combined borrowings outstanding under these
agreements totaled $400.6 million and $393.4 million, respectively. Excluding
the effectively fixed portion of Antargaz' variable-rate debt, based upon
weighted average borrowings outstanding under these agreements during Fiscal
2005 and Fiscal 2004, an increase in short-term interest rates of 100 basis
points (1%) would have increased our interest expense by $2.4 million and $2.1
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 $68.0 million and $61.8
million at September 30, 2005 and 2004, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $74.4 million and $66.6 million at September 30, 2005 and
2004, 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.
Our primary exchange rate risk is associated with 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. We use derivative instruments to hedge portions of our net
investment in foreign subsidiaries ("net investment hedges"). Realized gains or
losses associated with net investments in foreign operations remain in other
comprehensive income until such foreign operations are liquidated. At September
30, 2005, the fair value of unsettled net investment hedges was a gain of $1.5
million, which is included in the foreign currency exchange rate risk in the
table below. With respect to our net investments in FLAGA and Antargaz, a 10%
decline in the value of the euro versus the U.S. dollar, excluding the effects
of any net investment hedges, would reduce their aggregate net book value by
approximately $48.1 million, which amount would be reflected in other
comprehensive income.
The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at September 30, 2005 and 2004. 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, 2005. 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; (4) interest rates on ten-year U.S. treasury notes
and the three-month Euribor and; (5) the value of the euro versus the U.S.
dollar.
Change in
Fair Value Fair Value
---------- ----------
(Millions of dollars)
September 30, 2005:
Propane commodity price risk $50.8 $(19.6)
Natural gas commodity price risk (1.5) (7.2)
Electricity commodity price risk 6.1 (1.4)
Interest rate risk (6.2) (3.9)
Foreign currency exchange rate risk 7.5 (16.3)
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)
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.
26
UGI Corporation 2005 Annual Report
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 the Company's Audit Committee. In addition,
management has reviewed the following disclosures regarding the application of
these critical accounting policies with the Audit Committee.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved
in litigation regarding pending claims and legal actions that arise in the
normal course of our businesses. In addition, UGI Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be present. In accordance with accounting
principles generally accepted in the United States of America, the Company
establishes reserves for pending claims and legal actions or environmental
remediation obligations when it is probable that a liability exists and the
amount or range of amounts can be reasonably estimated. Reasonable estimates
involve management judgments based on a broad range of information and prior
experience. These judgments are reviewed quarterly as more information is
received and the amounts reserved are updated as necessary. Such estimated
reserves may differ materially from the actual liability and such reserves may
change materially as more information becomes available and estimated reserves
are adjusted.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility are subject
to regulation by the PUC. In accordance with SFAS 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, 2005, our regulatory assets
totaled $61.3 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. As of September 30, 2005, our net property, plant and equipment
totaled $1,802.7 million and we recorded depreciation expense of $127.8 million
during Fiscal 2005.
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, 2005, our
goodwill totaled $1,231.2 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 an increase in pre-tax pension
expense of approximately $1.0 million in Fiscal 2006. An unfavorable change in
the discount rate of 50 basis points would result in an increase in pre-tax
pension expense of approximately $1.6 million in Fiscal 2006.
27
UGI Corporation 2005 Annual Report
FINANCIAL REVIEW
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Below is a listing of recently issued accounting pronouncements by the Financial
Accounting Standards Board. None of them had or are expected to have a material
effect on our financial position or results of operations. SFAS No. 154 applies
only to changes in accounting and corrections of errors. See Note 1 to the
Consolidated Financial Statements for additional discussion of such
pronouncements.
Title of Pronouncement Month of Issue
- ---------------------- --------------
SFAS No. 154, "Accounting Changes and Error Corrections" May 2005
Interpretation No. 47, "Accounting for Conditional Asset
Retirement Obligations" March 2005
SFAS No. 123 (revised 2004), "Share-Based Payment" December 2004
SFAS No. 153, "Exchanges of Nonmonetary Assets -
An Amendment of APB Opinion No. 29, Accounting for
Nonmonetary Transactions" December 2004
Staff Position 109-1, "Application of FASB Statement No. 109,
Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs
Creation Act of 2004" December 2004
Staff Position 109-2, "Accounting and Disclosure Guidance
for the Foreign Earnings Repatriation Provision Within the
American Jobs Creation Act of 2004" December 2004
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) increased customer
conservation measures due to high energy prices 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, including foreign currency rate
fluctuations, particularly in the euro; (12) reduced access to capital markets
and interest 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.
28
UGI Corporation 2005 Annual Report
REPORT OF MANAGEMENT
FINANCIAL STATEMENTS
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 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 internal control
and for monitoring the independence and performance of the Company's independent
registered public accounting firm and internal auditors. The Committee is also
responsible for maintaining direct channels of communication among the Board of
Directors, management, and both the independent registered public accounting
firm and internal auditors.
PricewaterhouseCoopers LLP, our independent registered public accounting
firm, is engaged to perform audits of our consolidated financial statements.
These audits are performed in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Our independent registered
public accounting firm was given unrestricted access to all financial records
and related data, including minutes of all meetings of the Board of Directors
and committees of the Board. The Company believes that all representations made
to the independent registered public accounting firm during their audits were
valid and appropriate.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal
control over financial reporting for the Company. In order to evaluate the
effectiveness of internal control over financial reporting, as required by
Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an
assessment, including testing, using the criteria in Internal Control -
Integrated Framework, issued by the Committee of Sponsoring Organizations of the
Treadway Commission ("COSO Framework"). The Company's system of internal control
over financial reporting is designed to provide reasonable, but not absolute,
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States. Management also believes the
system of internal control over financial reporting provides reasonable
assurance that assets are safeguarded and that transactions are executed in
accordance with management's authorization and are properly recorded to permit
the preparation of reliable financial information. Because of its inherent
limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate due to
changing conditions, or the degree of compliance with the policies or procedures
may deteriorate.
Based on its assessment, management has concluded that the Company
maintained effective internal control over financial reporting as of September
30, 2005, based on the COSO Framework. Management's assessment of the
effectiveness of the Company's internal control over financial reporting as of
September 30, 2005, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
follows.
/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
29
UGI Corporation 2005 Annual Report
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:
We have completed an integrated audit of UGI Corporation's 2005 consolidated
financial statements and of its internal control over financial reporting as of
September 30, 2005 and audits of its 2004 and 2003 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
CONSOLIDATED FINANCIAL STATEMENTS
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, stockholders' equity and cash flows present
fairly, in all material respects, the financial position of UGI Corporation and
its subsidiaries at September 30, 2005 and 2004, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 2005 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 of financial
statements 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Also, in our opinion, management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that the
Company maintained effective internal control over financial reporting as of
September 30, 2005 based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of
September 30, 2005, based on criteria established in Internal Control -
Integrated Framework issued by the COSO. The Company's management is responsible
for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit. We conducted our audit of internal control over financial
reporting 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 effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
December 13, 2005
30
UGI Corporation 2005 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30,
------------------------------
2005 2004 2003
-------- -------- --------
REVENUES
AmeriGas Propane $1,963.3 $1,775.9 $1,628.4
International Propane 943.9 333.4 54.5
UGI Utilities 681.2 650.1 628.7
Energy Services and other 1,300.3 1,025.3 714.5
-------- -------- --------
4,888.7 3,784.7 3,026.1
-------- -------- --------
COSTS AND EXPENSES
Cost of sales 3,306.0 2,551.0 1,984.3
Operating and administrative expenses 966.6 767.8 644.1
Utility taxes other than income taxes 13.4 12.5 12.2
Depreciation and amortization 146.4 132.3 103.0
Other income, net (46.7) (10.2) (19.8)
-------- -------- --------
4,385.7 3,453.4 2,723.8
-------- -------- --------
OPERATING INCOME 503.0 331.3 302.3
Income (loss) from equity investees (2.6) 11.3 5.3
Loss on extinguishment of debt (33.6) -- (3.0)
Interest expense (130.2) (119.1) (109.2)
-------- -------- --------
INCOME BEFORE INCOME TAXES AND SUBSIDIARY PREFERRED STOCK DIVIDENDS AND
MINORITY INTERESTS 336.6 223.5 195.4
Income taxes (119.2) (64.4) (60.7)
Dividends on UGI Utilities preferred shares subject to mandatory redemption -- -- (1.2)
Minority interests, principally in AmeriGas Partners (29.9) (47.5) (34.6)
-------- -------- --------
NET INCOME $ 187.5 $ 111.6 $ 98.9
======== ======== ========
EARNINGS PER COMMON SHARE:
Basic $ 1.81 $ 1.18 $ 1.17
======== ======== ========
Diluted $ 1.77 $ 1.15 $ 1.14
======== ======== ========
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS):
Basic 103.877 94.616 84.440
======== ======== ========
Diluted 105.723 96.682 86.472
======== ======== ========
See accompanying notes to consolidated financial statements.
31
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30,
-------------------
2005 2004
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 315.0 $ 149.6
Short-term investments (at cost, which approximates fair value) 70.0 50.0
Accounts receivable (less allowances for doubtful accounts of $29.2 and $22.3, respectively) 421.8 367.3
Accrued utility revenues 10.4 9.7
Inventories 239.9 198.4
Deferred income taxes 24.4 22.1
Derivative financial instruments 60.3 22.0
Prepaid expenses and other current assets 30.5 24.6
-------- --------
Total current assets 1,172.3 843.7
-------- --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 1,162.8 1,121.3
International Propane 541.8 525.7
UGI Utilities 985.7 944.3
Other 99.3 83.0
-------- --------
2,789.6 2,674.3
Accumulated depreciation and amortization (986.9) (892.4)
-------- --------
Net property, plant, and equipment 1,802.7 1,781.9
-------- --------
OTHER ASSETS
Goodwill and excess reorganization value 1,231.2 1,245.9
Intangible assets (less accumulated amortization of $45.4 and $27.5, respectively) 172.6 184.4
Utility regulatory assets 61.3 65.0
Other assets 131.4 121.7
-------- --------
Total assets $4,571.5 $4,242.6
======== ========
See accompanying notes to consolidated financial statements.
32
UGI Corporation 2005 Annual Report
September 30,
-------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2005 2004
- ------------------------------------ -------- --------
CURRENT LIABILITIES
Current maturities of long-term debt $ 252.0 $ 122.8
UGI Utilities bank loans 81.2 60.9
Other bank loans 16.2 17.2
UGI Utilities preferred shares subject to mandatory redemption,
without par value -- 20.0
Accounts payable 399.7 323.9
Employee compensation and benefits accrued 78.6 87.5
Dividends and interest accrued 40.8 43.0
Income taxes accrued 40.1 2.0
Deposits and advances 124.1 98.7
Other current liabilities 130.4 141.6
-------- --------
Total current liabilities 1,163.1 917.6
-------- --------
DEBT AND OTHER LIABILITIES
Long-term debt 1,392.5 1,547.3
Deferred income taxes 477.5 448.6
Deferred investment tax credits 7.2 7.6
Other noncurrent liabilities 327.3 309.0
-------- --------
Total liabilities 3,367.6 3,230.1
-------- --------
Commitments and contingencies (Note 11)
Minority interests, principally in AmeriGas Partners 206.3 178.4
COMMON STOCKHOLDERS' EQUITY
Common Stock, without par value
(authorized - 300,000,000 shares; issued - 115,152,994 shares) 793.6 762.8
Retained earnings 266.3 146.2
Accumulated other comprehensive income 16.5 22.6
Notes receivable from employees -- (0.2)
-------- --------
1,076.4 931.4
Treasury stock, at cost (78.8) (97.3)
-------- --------
Total common stockholders' equity 997.6 834.1
-------- --------
Total liabilities and stockholders' equity $4,571.5 $4,242.6
======== ========
33
UGI Corporation 2005 Annual Report
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30,
------------------------
2005 2004 2003
------ ------ ------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $187.5 $111.6 $ 98.9
Reconcile to net cash provided by operating activities:
Depreciation and amortization 146.4 132.3 103.0
Minority interests in AmeriGas Partners 29.9 47.5 34.6
Deferred income taxes, net 12.1 3.0 (2.8)
Provision for uncollectible accounts 25.1 17.3 18.5
Loss on extinguishment of debt 33.6 -- 3.0
Tax benefit on exercise of stock options 10.2 2.9 4.9
Net change in settled accumulated other comprehensive income (3.8) 9.0 (5.2)
Other, net (14.5) 9.4 9.3
Net change in:
Accounts receivable and accrued utility revenues (81.5) 4.9 (56.1)
Inventories (29.4) (39.4) (25.3)
Deferred fuel costs 9.5 (6.9) 19.0
Accounts payable 70.0 (49.7) 34.9
Other current assets and liabilities 42.6 18.8 20.3
------ ------ ------
Net cash provided by operating activities 437.7 260.7 257.0
------ ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (158.4) (133.7) (100.9)
Acquisitions of businesses, net of cash acquired (33.3) (308.6) (38.6)
Acquisition of additional interest in Conemaugh Station -- -- (51.3)
Net proceeds from disposals of assets 16.7 11.5 5.9
Increase in short-term investments (20.0) -- (50.0)
Other, net 3.6 18.0 8.8
------ ------ ------
Net cash used by investing activities (191.4) (412.8) (226.1)
------ ------ ------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock (67.4) (56.3) (47.7)
Distributions on AmeriGas Partners publicly held Common Units (66.6) (62.4) (56.4)
Issuances of debt 576.0 30.1 167.8
Repayments of debt (544.4) (77.4) (239.5)
AmeriGas Propane bank loans decrease -- -- (10.0)
(Decrease) increase in UGI Utilities bank loans with maturities
of three months or less (49.7) 20.2 3.5
Other bank loans (decrease) increase (0.3) 0.1 5.4
Redemption of UGI Utilities preferred shares subject to mandatory
redemption (20.0) -- --
Issuances of AmeriGas Partners Common Units 72.7 51.2 75.0
Issuances of UGI Common Stock 27.1 254.1 18.8
Repurchases of UGI Common Stock -- (0.6) (0.1)
------ ------ ------
Net cash (used) provided by financing activities (72.6) 159.0 (83.2)
------ ------ ------
EFFECT OF EXCHANGE RATE CHANGES ON CASH (8.3) 0.6 0.1
------ ------ ------
Cash and cash equivalents increase (decrease) $165.4 $ 7.5 $(52.2)
====== ====== ======
CASH AND CASH EQUIVALENTS:
End of year $315.0 $149.6 $142.1
Beginning of year 149.6 142.1 194.3
------ ------ ------
Increase (decrease) $165.4 $ 7.5 $(52.2)
====== ====== ======
See accompanying notes to consolidated financial statements.
34
UGI Corporation 2005 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, 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
($0.57 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) 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 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
($0.60 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
Net income 187.5 187.5
Net gain on derivative instruments
(net of tax of $7.9) 12.9 12.9
Reclassification of net gains on
derivative instruments (net of tax of $2.1) (2.7) (2.7)
Foreign currency translation adjustments
(net of tax of $6.5) (16.3) (16.3)
------ ------ ------
Comprehensive income (loss) 187.5 (6.1) 181.4
Cash dividends on Common Stock
($0.65 per share) (67.4) (67.4)
Common Stock issued:
Employee and director plans 17.2 17.7 34.9
Dividend reinvestment plan 1.6 0.8 2.4
Net gain in connection with issuances of units
by AmeriGas Partners (net of tax of $16.0) 12.0 12.0
Payments on notes receivable from employees 0.2 0.2
------ ------ ------ ----- ------- ------
BALANCE SEPTEMBER 30, 2005 $793.6 $266.3 $ 16.5 $ -- $ (78.8) $997.6
====== ====== ====== ===== ======= ======
See accompanying notes to consolidated financial statements.
35
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, 2005, the General Partner and its wholly
owned subsidiary Petrolane Incorporated ("Petrolane") collectively held a 1%
general partner interest and a 42.8% limited partner interest in AmeriGas
Partners, and effective 44.3% and 44.2% ownership interests in AmeriGas OLP and
Eagle OLP, respectively. Our limited partnership interest in AmeriGas Partners
comprises 24,525,004 Common Units. The remaining 56.2% interest in AmeriGas
Partners comprises 32,267,601 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.
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 first and
second-tier subsidiaries (collectively, "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. In addition, Energy
Services' wholly owned subsidiary UGI Asset Management, Inc. through its
subsidiary Atlantic Energy, Inc. (collectively, "Asset Management") owns a
propane storage terminal located in Chesapeake, Virginia. Prior to the sale of
the propane terminal to Asset Management in November 2004, AmeriGas Propane held
a 50% equity ownership interest in it (See Note 2). Through other subsidiaries,
Enterprises owns and operates a heating, ventilation, air-conditioning,
refrigeration and electrical contracting services 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
("PUHCA 1935") except for acquisitions under section 9(a)(2). The Energy Policy
Act of 2005 repealed PUHCA 1935 effective February 8, 2006, and enacted the
Public Utility Holding Company Act of 2005 ("PUHCA 2005") effective February 8,
2006. UGI will be a "holding company" under PUHCA 2005 subject to certain
obligations to maintain books and records, and to disclose those books and
records at the request of the Federal Energy Regulatory Commission ("FERC") and
the PUC. UGI expects that its obligations under PUHCA 2005 will not be
materially different from its current books and records obligations under
federal and state law. 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 16). Effective with our March 2004 acquisition of
the remaining 80.5% ownership interests in AGZ and our
36
UGI Corporation 2005 Annual Report
November 2004 acquisition of the remaining 50% ownership interest in Atlantic
Energy, Inc., we began consolidating all of their operations (see Note 2).
Investments in equity investees are included in other assets in the Consolidated
Balance Sheets. Gains resulting from issuances and sales of AmeriGas Partners'
Common Units are recorded as increases to common stockholders' equity with
corresponding decreases to minority interests in accordance with U.S. Securities
and Exchange Commission ("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 common stockholders'
equity associated with such gains (see Note 15).
RECLASSIFICATIONS. We have reclassified certain prior-year balances to conform
to the current-year presentation.
USE OF ESTIMATES. We make estimates and assumptions when preparing financial
statements in conformity with accounting principles generally accepted in the
United States 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:
2005 2004
----- -----
Regulatory assets:
Income taxes recoverable $58.6 $62.0
Other postretirement benefits 1.7 1.9
Other 1.0 1.1
----- -----
Total regulatory assets $61.3 $65.0
----- -----
Regulatory liabilities:
Other postretirement benefits $ 2.8 $ 3.0
Deferred fuel costs 17.4 7.9
----- -----
Total regulatory liabilities $20.2 $10.9
----- -----
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
liabilities and measured at fair value. The accounting for changes in fair value
depends upon the purpose of the derivative instrument and whether it is
designated and qualifies for hedge accounting. 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 12.
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 $130.6 in 2005, $117.7 in 2004 and $109.8 in
2003. We paid income taxes totaling $54.7 in 2005, $70.2 in 2004 and $48.2 in
2003.
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. On April 26, 2005, UGI's Board of Directors approved
a 2-for-1 common stock split. On May 24, 2005, the Company issued one additional
common share for every common share outstanding to shareholders of record on May
17, 2005. Average shares outstanding, basic and diluted earnings per share and
dividends declared per share for all periods presented are reflected on a
post-split basis. The prior-year amounts have been retroactively restated to
reflect the effects of the common stock split.
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
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and
where indicated otherwise)
Note 1 continued
awards. In the following table, we present shares used in computing basic and
diluted earnings per share for 2005, 2004 and 2003:
2005 2004 2003
------- ------ ------
Denominator (millions of shares):
Average common shares
outstanding for basic computation 103.877 94.616 84.440
Incremental shares issuable for stock
options and awards 1.846 2.066 2.032
------- ------ ------
Average common shares outstanding for
diluted computation 105.723 96.682 86.472
------- ------ ------
INCOME TAXES. AmeriGas Partners and the Operating Partnerships are not directly
subject to federal income taxes. Instead, their taxable income or loss is
allocated to the individual partners. We record income taxes on our share of (1)
the Partnership's current taxable income or loss and (2) the differences between
the book and tax bases of the Partnership's assets and liabilities. The
Operating Partnerships have subsidiaries which operate in corporate form and are
directly subject to federal income taxes.
Gas Utility and Electric Utility record deferred income taxes in the
Consolidated Statements of Income resulting from the use of accelerated
depreciation methods based upon amounts recognized for ratemaking purposes. They
also record a deferred 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 2.4% in 2005 and 2.3% in both 2004 and
2003. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 2.9% in 2005, 2.8% in 2004 and 3.0% in 2003. 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 $127.8 in 2005,
$119.9 in 2004 and $97.1 in 2003.
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:
2005 2004
-------- --------
Not subject to amortization:
Goodwill $1,137.9 $1,152.6
Excess reorganization value 93.3 93.3
-------- --------
$1,231.2 $1,245.9
-------- --------
Other intangible assets:
Customer relationships, noncompete
agreements and other $ 177.2 $ 169.7
Trademark (not subject to amortization) 40.8 42.2
-------- --------
Gross carrying amount 218.0 211.9
-------- --------
Accumulated amortization (45.4) (27.5)
-------- --------
Net carrying amount $ 172.6 $ 184.4
-------- --------
The changes in the carrying amount of intangible assets during the year
ended September 30, 2005 principally reflects business acquisitions and the
effects of foreign currency translation.
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 $16.9 in 2005, $11.1 in 2004 and $6.1 in 2003
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 2006 - $15.8; Fiscal 2007 - $15.2;
Fiscal 2008 -$14.8; Fiscal 2009 - $14.1; Fiscal 2010 - $12.8.
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 2005, 2004
or 2003.
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.
We use the intrinsic value method prescribed by APB 25 for our stock-based
employee compensation plans. We recognized
38
UGI Corporation 2005 Annual Report
total stock and unit-based compensation expense of $15.5, $14.3 and $10.4 in
2005, 2004 and 2003, 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 2005, 2004 and 2003
would have been as follows:
Year Ended September 30,
------------------------
2005 2004 2003
------ ------ ------
Net income, as reported $187.5 $111.6 $98.9
Add: Stock and unit-based employee
expense included in reported net
income, net of related tax effects 10.1 9.3 6.8
Deduct: Total stock and unit-based
employee compensation expense
determined under the fair value method
for all awards, net of related tax effects (11.9) (10.4) (7.6)
------ ------ -----
Pro forma net income $185.7 $110.5 $98.1
------ ------ -----
Basic earnings per share:
As reported $ 1.81 $ 1.18 $1.17
Pro forma $ 1.79 $ 1.17 $1.16
Diluted earnings per share:
As reported $ 1.77 $ 1.15 $1.14
Pro forma $ 1.76 $ 1.14 $1.13
For a description of our stock and unit-based compensation plans and
related disclosures, see Note 8.
DEFERRED DEBT ISSUANCE COSTS. Included in other assets are net deferred debt
issuance costs of $10.1 at September 30, 2005 and $13.9 at September 30, 2004.
We are amortizing these costs over the terms of the related debt.
CUSTOMER DEPOSITS. Included in other noncurrent liabilities are customer paid
deposits on Antargaz owned tanks and cylinders of $200.6 and $209.8 at September
30, 2005 and 2004, respectively. Deposits are refundable to customers when the
tanks or cylinders are returned in accordance with contract terms.
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 fifteen 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 7),
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 "dividends on UGI
Utilities preferred shares subject to mandatory redemption" 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, 2005, neither the Company's
undiscounted amount nor its accrued liability for environmental investigation
and cleanup costs was 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 11).
FOREIGN CURRENCY TRANSLATION. Balance sheets of international subsidiaries and
our investment in an international LPG 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.
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
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 1 continued
accumulated other comprehensive income at September 30, 2004 and 2005 follow:
Derivative Foreign
Instruments Currency
Gains Translation
(Losses) Adjustments Total
----------- ----------- -----
Balance - September 30, 2004 $ 7.3 $15.3 $22.6
Balance - September 30, 2005 $17.7 $(1.2) $16.5
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In May 2005, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 154, "Accounting Changes and Error
Corrections" ("SFAS 154"). SFAS 154 replaces APB No. 20, "Accounting Changes"
and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements"
and establishes retrospective application as the required method for reporting a
change in accounting principle. SFAS 154 provides guidance for determining
whether retrospective application of a change in accounting principle is
impracticable and for reporting a change when retrospective application is
impracticable. SFAS 154 is effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005.
In March 2005, the FASB issued Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations" ("FIN 47"). It requires an entity to
recognize a liability for a conditional asset retirement obligation when
incurred if the liability can be reasonably estimated. FIN 47 clarifies that the
term "Conditional Asset Retirement Obligation" refers to a legal obligation to
perform an asset retirement activity in which the timing and/or method of
settlement are conditional on a future event that may or may not be within the
control of the entity. FIN 47 also clarifies when an entity would have
sufficient information to reasonably estimate the fair value of an asset
retirement obligation. FIN 47 is effective no later than the end of fiscal years
ending after December 15, 2005. The application of FIN 47 will not have a
material effect on our financial position and results of operations.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based
Payment" ("SFAS 123R"). SFAS 123R replaces SFAS 123 and supersedes APB 25. SFAS
123, as originally issued in 1995, established as preferable a fair-value-based
method of accounting for share-based payment transactions with employees.
However, SFAS 123 permitted entities the option of continuing to apply the
guidance in APB 25 as long as the footnotes to financial statements disclosed
what net income would have been had the preferable fair-value-based method been
used. SFAS 123R requires that the compensation cost relating to share-based
payment transactions be recognized in the financial statements. The cost is
required to be measured based on the fair value of the equity or liability
instruments issued. SFAS 123R covers a wide range of share-based compensation
arrangements including share options, restricted share plans, performance-based
awards, share appreciation rights and employee share purchase plans. We adopted
SFAS 123R effective October 1, 2005. Under the modified prospective transition
method, beginning October 1, 2005, unrecognized compensation expense for awards
that are not vested on the adoption date will be recognized in the Company's
statements of income through the end of the requisite service period. Assuming
no significant change in the level of future share-based payment awards, we do
not believe that the adoption of SFAS 123R will have a material impact on our
annual results of operations or financial position. For disclosure regarding pro
forma net income and earnings per share as if we had determined stock-based
compensation under the fair value method prescribed by SFAS 123, see
"Stock-Based Compensation" above.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets - An Amendment of APB Opinion No. 29, Accounting for Nonmonetary
Transactions" ("SFAS 153"). SFAS 153 eliminates the exception from fair value
measurement for nonmonetary exchanges of similar productive assets in paragraph
21(b) of APB Opinion No. 29, "Accounting for Nonmonetary Transactions," and
replaces it with an exception for exchanges that lack commercial substance. SFAS
153 specifies that a nonmonetary exchange has commercial substance if the future
cash flows of the entity are expected to change significantly as a result of the
exchange. SFAS 153 was effective for our interim period beginning July 1, 2005.
The adoption of SFAS 153 did not have a material effect on our financial
position or results of operations.
In December 2004, the FASB issued FASB Staff Position 109-1, "Application
of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs Creation Act of
2004" ("FSP 109-1") and FASB Staff Position 109-2, "Accounting and Disclosure
Guidance for the Foreign Earnings Repatriation Provision Within the American
Jobs Creation Act of 2004" ("FSP 109-2"). The American Jobs Creation Act of 2004
provides deductions for qualified domestic production activities and
repatriation of foreign earnings. FSP 109-1 and FSP 109-2 did not have a
material impact on our financial position or results of operations.
NOTE 2 - ACQUISITIONS AND INVESTMENTS
During 2005, AmeriGas OLP acquired several retail propane distribution
businesses for total cash consideration of approximately $22.7. HVAC/R acquired
a commercial and residential electrical contracting business in September 2005.
The operating results of these businesses have been included in our operating
results from their respective dates of acquisition. The pro forma effects of
these transactions were not material.
In November 2004, UGI Asset Management, Inc. acquired from ConocoPhillips
Company and AmerE Holdings, Inc. (a wholly owned, indirect subsidiary of
AmeriGas OLP) in separate transactions 100% of the issued and outstanding common
stock of Atlantic Energy for an aggregate purchase price of approximately $24 in
cash, including post-closing adjustments (the "AEI Acquisition"). The AEI
Acquisition has been accounted for as a step acquisition in the Consolidated
Financial Statements. In connection with this acquisition, Atlantic Energy and
AmeriGas OLP entered into a long-term propane supply agreement.
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
40
UGI Corporation 2005 Annual Report
GPL, S.r.L., 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 was 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 15 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 8 for
additional information regarding the issuance of UGI Common Stock.
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 completed its review and determination in 2004 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 Sheets as of September 30, 2005 and 2004. The operating
results of AGZ are included in our consolidated results beginning April 1, 2004.
For periods 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 $ 1.66 $ 1.23
Diluted $ 1.62 $ 1.21
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, during the year ended September 30, 2004, 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. 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,
coalfired 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.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 3 - DEBT
Long-term debt comprises the following at September 30:
2005 2004
-------- --------
AMERIGAS PROPANE:
AmeriGas Partners Senior Notes:
8.875%, due May 2011 (including unamortized
premium of $0.3 and $8.3, respectively,
effective rate - 8.46%) $ 14.9 $ 396.3
10%, due April 2006 (less unamortized discount of
$0.1 in 2004, effective rate - 10.125%) 60.0 59.9
7.25%, due May 2015 415.0 --
AmeriGas OLP First Mortgage Notes:
Series A, 9.34% - 11.71%, due April 2006 through
April 2009 (including unamortized premium of
$3.6 and $5.2, respectively, effective rate - 8.91%) 163.6 165.2
Series B, 10.07%, due April 2005 (including
unamortized premium of $0.3 in 2004,
effective rate - 8.74%) -- 40.3
Series C, 8.83%, due April 2006 through April 2010 68.8 82.5
Series D, 7.11%, due March 2009 (including
unamortized premium of $1.3 and $1.6,
respectively, effective rate - 6.52%) 71.3 71.6
Series E, 8.50%, due July 2010 (including
unamortized premium of $0.1, effective
rate - 8.47%) 80.1 80.1
AmeriGas OLP Term Loan, 4.44%, due October 2006 35.0 --
Other 4.8 5.5
-------- --------
Total AmeriGas Propane 913.5 901.4
-------- --------
INTERNATIONAL PROPANE:
Antargaz Senior Facilities term loan,
due March 2006 through June 2008 210.4 240.0
Antargaz 10% High Yield Bonds, due July 2011
(including unamortized premium of $17.0 and
$20.0, respectively, effective rate - 7.68%) 215.4 225.2
FLAGA Acquisition Note, due through
September 2006 55.9 68.2
FLAGA euro special purpose facility 2.0 3.3
Other 5.4 9.3
-------- --------
Total International Propane 489.1 546.0
-------- --------
UGI UTILITIES:
Medium-Term Notes:
6.62% Notes, due May 2005 -- 20.0
7.14% Notes, due December 2005 (including
unamortized premium of $0.2 in 2004,
effective rate - 6.64%) 30.0 30.2
7.14% Notes, due December 2005 20.0 20.0
7.17% Notes, due June 2007 20.0 20.0
5.53% Notes, due September 2012 40.0 40.0
5.37% Notes, due August 2013 25.0 25.0
5.16% Notes, due May 2015 20.0 --
7.37% Notes, due October 2015 22.0 22.0
7.25% Notes, due November 2017 20.0 20.0
6.50% Notes, due August 2033 20.0 20.0
6.13% Notes, due October 2034 20.0 --
-------- --------
Total UGI Utilities 237.0 217.2
-------- --------
Other 4.9 5.5
-------- --------
Total long-term debt 1,644.5 1,670.1
Less current maturities (including net unamortized
premium of $4.2 and $5.4, respectively) (252.0) (122.8)
-------- --------
Total long-term debt due after one year $1,392.5 $1,547.3
-------- --------
Scheduled principal repayments of long-term debt due in fiscal years 2006
to 2010 follows:
2006 2007 2008 2009 2010
------ ------ ------ ------ -----
AmeriGas Propane $116.3 $ 89.8 $ 54.4 $124.1 $94.0
UGI Utilities 50.0 20.0 -- -- --
International Propane 80.8 23.1 167.6 0.6 0.4
Other 0.7 2.3 3.1 -- --
------ ------ ------ ------ -----
Total $247.8 $135.2 $225.1 $124.7 $94.4
------ ------ ------ ------ -----
AMERIGAS PROPANE
AMERIGAS PARTNERS SENIOR NOTES. The 7.25% Senior Notes generally cannot be
redeemed at our option prior to May 20, 2010. 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 refinanced
$373.4 of its 8.875% Senior Notes in May 2005 pursuant to a tender offer with
$415 of 7.25% Senior Notes. AmeriGas Partners redeemed $85 of its 10.125% Senior
Notes in January 2003 with 8.875% Senior Notes. AmeriGas Partners recognized
losses of $33.6 and $3.0 associated with these refinancings which amounts are
reflected in "Loss on extinguishments of debt" in the 2005 and 2003 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 10% and 7.25% 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 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
42
UGI Corporation 2005 Annual Report
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 Agreement at
September 30, 2005 and 2004. Issued and outstanding letters of credit, which
reduce available borrowings under the Revolving Credit Facility, totaled $56.3
and $45.9 at September 30, 2005 and 2004, 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, 2005 and 2004.
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
(6.75% at September 30, 2005), 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.
AMERIGAS OLP TERM LOAN. In April 2005, AmeriGas OLP entered into a $35.0
variable-rate term loan due October 1, 2006 ("AmeriGas OLP Term Loan"), which
bears interest plus margin at the same rates as the Credit Agreement. Proceeds
from the AmeriGas OLP Term Loan were used to repay a portion of the $53.8
maturing AmeriGas OLP First Mortgage Notes.
RESTRICTIVE COVENANTS. The 10% and 7.25% Senior Notes of AmeriGas Partners
restrict the ability of the Partnership and AmeriGas OLP 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 10% and 7.25% Senior Note 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, 2005, such ratio was 2.61-to-1.
The Credit Agreement, AmeriGas OLP Term Loan and 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, AmeriGas OLP Term
Loan 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 AmeriGas OLP Term Loan and 5.25-to-1 with
respect to the First Mortgage Notes. In addition, the Credit Agreement and
AmeriGas OLP Term Loan require 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, 2005, 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, 2005,
there was E175 ($210.4) 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 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 12). 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.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 3 continued
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 at any time or in part commencing July 2006, in
each case at a premium.
On December 7, 2005, Antargaz executed a new five-year, floating rate
Senior Facilities Agreement with a major French bank providing for a E380
million term loan and a E50 million revolving credit facility. AGZ Finance
notified the holders of its High Yield Bonds of its decision to redeem them,
including a premium, pursuant to the Trust Deed. The proceeds of the term loan
will be used 1) to repay immediately the existing E175 million Senior
Facilities term loan, 2) to fund the redemption of the High Yield Bonds in
early January 2006 and 3) for general corporate purposes. In addition, AGZ has
executed an interest rate swap agreement with the same bank to fix the rate of
interest on the term loan for the duration of the loan.
FLAGA has a multi-currency acquisition note ("Acquisition Note"). During
2005, all U.S. dollar-denominated obligations matured and were repaid. At
September 30, 2005, FLAGA had E46.5 ($55.9) of euro-denominated obligations
outstanding. The U.S. dollar-denominated obligations under the Acquisition Note
had fixed rates of interest ranging from 5.70% to 5.92%. 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, 2005 and 2004 were 3.44% and 3.83%,
respectively. FLAGA may prepay the Acquisition Note, in whole or in part,
without incurring any premium.
At September 30, 2005, FLAGA had working capital facility commitments from
a European bank of E4 and E11 which expire in February and November
2006, respectively, but may be extended with the bank's consent. Loans under the
working capital facility, as well as borrowings under FLAGA's special purpose
facility, bear interest at market rates. The weighted-average interest rates on
FLAGA's working capital facility were 3.45% at September 30, 2005 and 3.04% at
September 30, 2004. Borrowings under the working capital facility at September
30, 2005 and 2004 totaled E13.5 ($16.2) and E13.8 ($17.2),
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 on a French GAAP basis, 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 certain financial ratios of UGI, the lending bank may
require UGI to grant additional security or may accelerate repayment of the
debt. At September 30, 2005, UGI was in compliance with these financial
covenants.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2005, 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 through June 2008.
Under these agreements, 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 $11.2 at September 30, 2005 and $60.9 at September
30, 2004, which we classify as bank loans. From time to time, UGI Utilities may
enter into additional short-term borrowings in order to meet liquidity needs
during the peak-heating season. At September 30, 2005, UGI Utilities had two
separate $35 borrowings outstanding under uncommitted arrangements with major
banks. These borrowings are scheduled to mature on February 15, 2006 and on
March 14, 2006 and are also classified as bank loans. The weighted-average
interest rates on UGI Utilities' bank loans were 4.41% at September 30, 2005 and
2.35% at September 30, 2004.
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, 2005,
UGI Utilities was in compliance with these financial covenants.
44
UGI Corporation 2005 Annual Report
NOTE 4 - INCOME TAXES
Income before income taxes comprises the following:
2005 2004 2003
------ ------ ------
Domestic $158.7 $160.7 $157.1
Foreign 148.0 15.3 3.7
------ ------ ------
Total income before income taxes $306.7 $176.0 $160.8
====== ====== ======
The provisions for income taxes consist of the following:
2005 2004 2003
------ ----- -----
Current expense:
Federal $ 49.8 $46.8 $48.1
State 14.6 14.4 15.4
Foreign 42.7 0.2 --
------ ----- -----
Total current expense 107.1 61.4 63.5
Deferred (benefit) expense:
Federal 0.3 4.3 2.3
State 1.6 (1.6) (3.6)
Foreign 10.6 0.7 (1.1)
------ ----- -----
Investment tax credit amortization (0.4) (0.4) (0.4)
------ ----- -----
Total deferred expense (benefit) 12.1 3.0 (2.8)
------ ----- -----
Total income tax expense $119.2 $64.4 $60.7
------ ----- -----
Federal income taxes for 2005 are net of foreign tax credits of $25.4. The
tax benefits associated with nonqualified stock options reduced taxes currently
payable by $10.2, $2.9 and $4.9 for 2005, 2004 and 2003, respectively.
A reconciliation from the statutory federal tax rate to our effective tax
rate is as follows:
2005 2004 2003
---- ---- ----
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal 2.6 4.8 4.6
Planned repatriation of foreign
earnings net of foreign tax credits 2.2 -- --
Other, net (0.9) (3.2) (1.8)
---- ---- ----
Effective tax rate 38.9% 36.6% 37.8%
---- ---- ----
Deferred tax liabilities (assets) comprise the following at September 30:
2005 2004
------ ------
Excess book basis over tax basis of property, plant
and equipment $330.2 $335.3
SAB 51 gains 94.1 77.3
Intangibles 53.7 58.3
Utility regulatory assets 25.4 27.6
Pension plan asset 9.3 10.5
Unrepatriated foreign earnings 9.4 --
Accumulated other comprehensive income 10.3 11.0
Other 8.5 9.3
------ ------
Gross deferred tax liabilities 540.9 529.3
------ ------
Self-insured property and casualty liability (12.2) (11.6)
Employee-related benefits (23.5) (25.8)
Premium on long-term debt (6.7) (9.7)
Tax litigation (4.4) (8.1)
Deferred investment tax credits (3.0) (3.1)
Utility regulatory liabilities (7.4) (4.0)
Operating loss carryforwards (12.6) (13.3)
Allowance for doubtful accounts (6.8) (4.8)
Foreign tax credit carryforwards (31.7) --
Other (17.1) (25.1)
------ ------
Gross deferred tax assets (125.4) (105.5)
------ ------
Deferred tax assets valuation allowance 37.6 2.7
------ ------
Net deferred tax liabilities $453.1 $426.5
------ ------
UGI Utilities had recorded deferred tax liabilities of approximately $37.3
as of September 30, 2005 and $39.4 as of September 30, 2004, 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 $3.0 at September 30, 2005 and $3.1
at September 30, 2004, pertaining to utility deferred investment tax credits.
UGI Utilities had recorded regulatory income tax assets related to these net
deferred taxes of $58.6 as of September 30, 2005 and $62.0 as of
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 4 continued
September 30, 2004. 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
$39.5 of which $6.4 expires through 2011 and $33.1 of which has no expiration
date. At September 30, 2005, deferred tax assets relating to operating loss
carryforwards include those of FLAGA and $4.4 of deferred tax assets associated
with state net operating loss carryforwards expiring through 2025. A valuation
allowance of $5.9 has been provided for all deferred tax assets related to state
net operating loss carryforwards and other state deferred tax assets of certain
subsidiaries because, on a state reportable basis, it is more likely than not
that these assets will be unusable.
We have foreign tax credit carryforwards of approximately $31.7 expiring
through 2010, resulting from the planned repatriation of AGZ's accumulated
earnings and profits included in U.S. taxable income since its acquisition.
Since we expect that these credits will expire unused, a valuation allowance has
been provided for the entire foreign tax credit carryforward amount.
NOTE 5 - EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS. We sponsor a defined
benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI
Utilities, and certain of UGI's other wholly owned subsidiaries. In addition, we
provide postretirement health care benefits to certain retirees and
postretirement life insurance benefits to nearly all domestic active and retired
employees. As a result of the Antargaz Acquisition, we assumed retirement
obligations 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 Antargaz' 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
----------------- --------------------
2005 2004 2005 2004
-------- ------ ------- ----------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations -
beginning of year $232.3 $209.5 $ 32.8 $ 28.8
Service cost 5.6 4.9 0.4 0.2
Interest cost 14.0 13.0 1.7 1.7
Actuarial loss 6.9 2.6 (1.7) 1.3
Antargaz Acquisition(a) -- 11.8 -- 3.3
Plan amendments -- -- (7.6) --
Foreign currency gain (0.2) -- (0.1) --
Benefits paid (10.7) (9.5) (2.1) (2.5)
------ ------ ------ ------
Benefit obligations - end of year $247.9 $232.3 $ 23.4 $ 32.8
------ ------ ------ ------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -
beginning of year $200.2 $183.9 $ 10.2 $ 9.0
Actual return on plan assets 25.5 22.0 0.8 0.9
Foreign currency gain (0.1) -- -- --
Employer contributions 0.4 -- 2.3 2.8
Antargaz Acquisition(a) -- 3.8 -- --
Benefits paid (10.7) (9.5) (2.1) (2.5)
------ ------ ------ ------
Fair value of plan assets -
end of year $215.3 $200.2 $ 11.2 $ 10.2
------ ------ ------ ------
Funded status of the plans $(32.6) $(32.1) $(12.2) $(22.6)
Unrecognized net actuarial loss 46.2 47.9 3.7 6.1
Unrecognized prior service cost 1.1 1.6 (2.5) --
Unrecognized net transition (asset)
obligation -- -- 0.8 6.8
------ ------ ------ ------
Prepaid (accrued) benefit cost -
end of year $ 14.7 $ 17.4 $(10.2) $ (9.7)
------ ------ ------ ------
WEIGHTED-AVERAGE ASSUMPTIONS
AS OF SEPTEMBER 30(b):
Discount rate 5.7% 6.1% 5.7% 6.1%
Expected return on plan assets 9.0% 9.0% 5.8% 5.8%
Rate of increase in salary levels 4.0% 4.0% 4.0% 4.0%
------ ------ ------ ------
(a) In 2004, amounts related to AGZ benefits and Antargaz' other postretirement
welfare benefits are reflected in the above table as "Antargaz
Acquisition." In 2005, such amounts are not segregated and are included in
the appropriate components.
(b) Represents domestic plan assumptions. Assumptions for the foreign plans are
consistent with market conditions in France.
46
UGI Corporation 2005 Annual Report
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
--------------------- ---------------------
2005 2004 2003 2005 2004 2003
----- ----- ----- ----- ----- -----
Service cost $ 5.6 $ 5.0 $ 4.5 $ 0.4 $ 0.2 $ 0.2
Interest cost 14.0 13.0 13.0 1.7 1.8 1.8
Expected return on assets (18.0) (17.3) (17.9) (0.5) (0.5) (0.4)
Amortization of:
Transition (asset)
obligation -- (1.4) (1.6) 0.8 0.9 0.9
Prior service cost 0.7 0.7 0.6 (0.1) -- --
Actuarial (gain) loss 1.5 1.2 0.3 0.2 0.3 0.1
Antargaz Acquisition(a) -- 0.3 -- -- 0.2 --
----- ----- ----- ----- ----- -----
Net benefit cost (income) 3.8 1.5 (1.1) 2.5 2.9 2.6
Change in regulatory
assets and liabilities -- -- -- 1.6 0.9 1.0
----- ----- ----- ----- ----- -----
Net expense (income) $ 3.8 $ 1.5 $(1.1) $ 4.1 $ 3.8 $ 3.6
----- ----- ----- ----- ----- -----
(a) In 2004, amounts related to AGZ benefits and Antargaz' other postretirement
welfare benefits are reflected in the above table as "Antargaz
Acquisition." In 2005, such amounts are not segregated and are included in
the appropriate components.
(b) Represents domestic plan assumptions. Assumptions for the foreign plans are
consistent with market conditions in France.
UGI Utilities Pension Plan assets are held in trust. Although the UGI
Utilities Pension Plan projected benefit obligations exceeded plan assets at
September 30, 2005 and 2004, plan assets exceeded accumulated benefit
obligations by $7.4 and $9.2, respectively. The Company did not make any
contributions in 2005 nor does it believe it will be required to make any
contributions to the UGI Utilities Pension Plan during the year ending September
30, 2006 for ERISA funding purposes. At September 30, 2005, the accumulated
benefit obligation of AGZ benefits exceeded the plan assets by $5.2. However,
the accrual recorded in our Consolidated Balance Sheet at September 30, 2005
exceeds the minimum pension liability. Antargaz does not expect to make any
contributions to fund AGZ benefits during the year ending September 30, 2006.
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. Effective July 1,
2005, substantially all retirees and their beneficiaries participating in the
UGI Utilities' postretirement benefit program were enrolled in insured Medicare
Advantage plans. As a result, the projected benefit obligation of our
postretirement benefits program was lower at September 30, 2005 as compared to
such obligations at September 30, 2004. Additionally, the UGI Utilities'
required contribution to the VEBA during the year ending September 30, 2006 is
expected to be significantly less than in 2005.
Expected payments for pension benefits and for other postretirement welfare
benefits are as follows:
Pension Other Postretirement
Benefits Benefits
-------- --------------------
Fiscal 2006 $10.7 $1.6
Fiscal 2007 10.9 1.7
Fiscal 2008 11.4 1.7
Fiscal 2009 12.0 1.7
Fiscal 2010 12.8 1.8
Fiscal 2011-2015 75.3 8.6
In accordance with our investment strategy to obtain long-term growth, our
target asset 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 2005 2004 2005 2004
------------ ---- ---- ---- ---- ----
Equities 60% 60% 60% 63% 62% 58%
Fixed income funds 40% 30% 40% 37% 31% 27%
Cash equivalents N/A 10% N/A N/A 7% 15%
UGI Common Stock comprised approximately 11% and 8% of UGI Utilities
Pension Plan assets at September 30, 2005 and 2004, respectively.
The assumed domestic health care cost trend rates are 10% for fiscal 2006,
decreasing to 5.5% in fiscal 2011. A one percentage point change in the assumed
health care cost trend rate would change the 2005 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 $0.7 $(0.6)
We also sponsor unfunded and non-qualified supplemental executive
retirement plans. At September 30, 2005 and 2004, the projected benefit
obligations of these plans were $14.8 and $12.4, respectively. We recorded net
benefit costs for these plans of $2.0 in 2005, $1.9 in 2004, and $1.9 in 2003.
We also recorded a settlement loss of $1.5 in 2004 associated with these plans.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 5 continued
DEFINED CONTRIBUTION PLANS. We sponsor 401(k) savings plans for eligible
employees of UGI and certain of UGI's 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 $8.3 in 2005, $8.2 in 2004, and $7.3 in 2003.
NOTE 6 - INVENTORIES
Inventories comprise the following at September 30:
2005 2004
------ ------
LPG and natural gas $134.6 $ 99.2
Utility natural gas and LPG 69.2 62.7
Materials, supplies and other 36.1 36.5
------ ------
Total inventories $239.9 $198.4
------ ------
NOTE 7 - SERIES PREFERRED STOCK
UGI has 10,000,000 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, 2005 or 2004.
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. At September 30, 2005, there were no UGI Utilities
Series Preferred Stock outstanding. Any holders of shares of UGI Utilities
Series Preferred Stock would have the right to elect a majority of UGI
Utilities' Board of Directors (without cumulative voting) if dividend payments
on any series were in arrears in an amount equal to four quarterly dividends.
This election right would continue until the arrearage was cured. We paid cash
dividends at the specified annual rates on all outstanding UGI Utilities Series
Preferred Stock.
At September 30, 2004, UGI Utilities had outstanding 200,000 shares of
$7.75 Series Preferred Stock. UGI Utilities redeemed all 200,000 shares of the
$7.75 UGI Utilities Series 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 8 - COMMON STOCK AND INCENTIVE STOCK AWARD PLANS
As stated in Note 1, on May 24, 2005, UGI issued one additional common share for
every common share outstanding to shareholders of record on May 17, 2005. All
UGI Common Stock activity and stock-based award disclosures reflect the effects
of the 2-for-1 common stock split and prior-year amounts have been retroactively
restated as appropriate. In March 2004, UGI Corporation sold 15.6 million shares
(including shares sold to the underwriters upon exercise of their overallotment
option in April 2004) of UGI Common Stock in an underwritten public offering at
a public offering price of $16.05 per share. As stated in Note 2, 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.
UGI Common Stock share activity for 2003, 2004, and 2005 follows:
Issued Treasury Outstanding
----------- ----------- -----------
Balance September 30, 2002 99,596,194 (16,491,004) 83,105,190
Issued:
Employee and director plans -- 2,101,842 2,101,842
Dividend reinvestment plan -- 195,330 195,330
Reacquired -- (3,646) (3,646)
----------- ----------- -----------
Balance September 30, 2003 99,596,194 (14,197,478) 85,398,716
Issued:
Public offering 15,556,800 -- 15,556,800
Employee and director plans -- 1,306,500 1,306,500
Dividend reinvestment plan -- 160,380 160,380
Reacquired -- -- --
----------- ----------- -----------
Balance September 30, 2004 115,152,994 (12,730,598) 102,422,396
Issued:
Employee and director plans -- 2,320,478 2,320,478
Dividend reinvestment plan -- 106,584 106,584
----------- ----------- -----------
Balance September 30, 2005 115,152,994 (10,303,536) 104,849,458
----------- ----------- -----------
STOCK OPTION AND INCENTIVE PLANS. Under UGI's 2004 Omnibus Equity Compensation
Plan ("OECP"), 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.
48
UGI Corporation 2005 Annual Report
Under the OECP, awards representing up to 7,000,000 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 1,600,000 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. 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 2005, 2004 and 2003, the
Company made stock-based awards other than stock options and dividend
equivalents representing 261,300, 268,600, and 163,500 shares, respectively. At
September 30, 2005, awards representing 677,600 shares of Common Stock were
outstanding under our equity compensation plans. There are outstanding
stock-based awards and stock options outstanding under other predecessor plans,
however, since January 2004 no awards have been made under any plan other than
the OECP.
Stock option transactions under all of our plans for 2003, 2004 and 2005
follow:
Average
Option
Shares Price
---------- -------
Shares under option - September 30, 2002 5,659,530 7.929
---------- ------
Granted 1,389,000 12.590
Exercised (1,995,052) 7.341
Forfeited (88,500) 11.363
---------- ------
Shares under option - September 30, 2003 4,964,978 9.409
---------- ------
Granted 1,494,500 16.819
Exercised (1,042,052) 7.892
Forfeited (88,500) 12.854
---------- ------
Shares under option - September 30, 2004 5,328,926 11.707
---------- ------
Granted 1,596,100 21.127
Exercised (1,913,168) 8.407
Forfeited (58,340) 21.908
---------- ------
Shares under option - September 30, 2005 4,953,518 15.709
---------- ------
Options exercisable 2003 2,857,974 7.727
Options exercisable 2004 2,718,670 9.010
Options exercisable 2005 2,093,821 12.380
---------- ------
The following table presents additional information relating to stock
options outstanding and exercisable at September 30, 2005:
Range of exercise prices
----------------------------------
$6.88 - $12.57 - $18.23 -
$10.63 $17.01 $27.90
-------- ---------- ----------
Options outstanding at September 30, 2005:
Number of options 952,350 2,392,568 1,608,100
Weighted average remaining
contractual life (in years) 5.47 7.58 9.25
Weighted average exercise price $ 9.67 $ 15.00 $ 21.07
Options exercisable at September 30, 2005:
Number of options 952,350 1,068,638 72,833
Weighted average exercise price $ 9.67 $ 14.33 $ 19.29
At September 30, 2005, 3,192,226 shares of Common Stock were available for
future grants under the OECP, of which up to 815,440 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 authorizes the crediting of Partnership Common Unit distribution
equivalents to participants' accounts. Any distribution equivalents will be paid
in cash. 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 41,100, 51,200, and 112,500
Common Units in 2005, 2004 and 2003, respectively. At September 30, 2005 and
2004, awards representing 116,000 and 142,786 Common Units, respectively, were
outstanding. At September 30, 2005, 371,103 and 151,500 Common Units were
available for future grants under the 2000 Propane Plan and the nonexecutive
plan, respectively.
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 8 continued
FAIR VALUE INFORMATION. The per share weighted-average fair value of stock
options granted under our option plans was $2.81 in 2005, $1.89 in 2004 and
$1.30 in 2003. 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 2005, 2004 and 2003 are as
follows:
2005 2004 2003
------- ------- -------
Expected life of option 6 years 6 years 6 years
Expected volatility 17.7% 18.2% 21.6%
Expected dividend yield 4.1% 4.9% 6.1%
Risk free interest rate 4.0% 3.7% 3.1%
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 6,000 to 300,000 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. The
Company is no longer offering loans under this program. At September 30, 2005,
there were no loans outstanding under this program. At September 30, 2004, loans
outstanding totaled $0.2.
NOTE 9 - PREFERENCE STOCK PURCHASE RIGHTS
Holders of our Common Stock own one-sixth of one right (as described below) for
each outstanding share of Common Stock. The rights expire in April 2006. Each
right entitles the holder to purchase one one-hundredth of a share of First
Series Preference Stock, without par value, at an exercise price of $120 per one
one-hundredth of a share or, under the circumstances summarized below, to
purchase the Common Stock described in the following paragraph. The rights are
exercisable only if a person or group, other than certain underwriters:
1. acquires 20% or more of our Common Stock ("Acquiring Person") or
2. announces or commences a tender offer for 30% or more of our Common
Stock.
We are entitled to redeem the rights at five cents per right at any time
before the earlier of:
1. the expiration of the rights in April 2006 or
2. ten days after a person or group has acquired 20% of our Common Stock
if a majority of continuing Directors concur and, in certain
circumstances, thereafter.
Each holder of a right, other than an Acquiring Person, is entitled to
purchase, at the exercise price of the right, Common Stock having a market value
of twice the exercise price of the right if:
1. an Acquiring Person merges with UGI or engages in certain other
transactions with us or
2. a person acquires 40% or more of our Common Stock.
In addition, if, after UGI (or an Acquiring Person) publicly announces that
an Acquiring Person has become such, UGI engages in a merger or other business
combination transaction in which:
1. we are not the surviving corporation, or
2. we are the surviving corporation, but our Common Stock is changed or
exchanged, or
3. 50% or more of our assets or earning power is sold or transferred,
then each holder of a right is entitled to purchase, at the exercise
price of the right, common stock of the acquiring company having a
market value of twice the exercise price of the right.
The rights have no voting or dividend rights and, until exercisable, have
no dilutive effect on our earnings.
NOTE 10 - PARTNERSHIP DISTRIBUTIONS
The Partnership makes distributions to its partners approximately 45 days after
the end of each fiscal quarter in a total amount equal to its Available Cash for
such quarter. Available Cash generally means:
1. all cash on hand at the end of such quarter,
2. plus all additional cash on hand as of the date of determination
resulting from borrowings after the end of such quarter,
3. less the amount of cash reserves established by the General Partner in
its reasonable discretion.
The General Partner may establish reserves for the proper conduct of the
Partnership's business and for distributions during the next four quarters. In
addition, certain of the Partnership's debt agreements require reserves be
established for the payment of debt principal and interest.
Distributions of Available Cash 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 and the First Target Distribution of $0.055 per unit on all units.
50
NOTE 11 - 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 $55.1 in 2005, $50.4 in 2004, and $47.4 in 2003.
Minimum future payments under operating leases that have initial or
remaining noncancelable terms in excess of one year are as follows:
After
2006 2007 2008 2009 2010 2010
---- ---- ---- ---- ---- -----
AmeriGas Propane 42.0 35.4 30.8 25.8 20.7 49.4
UGI Utilities 3.9 3.4 2.4 1.4 1.0 2.7
International Propane
and other 2.2 1.9 1.6 0.5 0.1 --
---- ---- ---- ---- ---- ----
Total 48.1 40.7 34.8 27.7 21.8 52.1
==== ==== ==== ==== ==== ====
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 and, from time to time,
variable-priced contracts to purchase a portion of its supply requirements.
These contracts generally have terms of less than one year.
International Propane, particularly Antargaz, enters into variable-priced
contracts to purchase a portion of its supply requirements. Generally, these
contracts have terms that do not exceed three years.
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, 2005:
After
2006 2007 2008 2009 2010 2010
-------- ------ ----- ----- ----- -----
Gas Utility and Electric
Utility supply, storage
and transportation
contracts $ 250.9 $ 85.5 $63.5 $53.7 $41.7 $74.9
Energy Services
supply contracts 679.8 131.5 2.5 -- -- --
AmeriGas Propane
supply contracts 29.5 -- -- -- -- --
International Propane
supply contracts 76.9 46.2 -- -- -- --
-------- ------ ----- ----- ----- -----
Total $1,037.1 $263.2 $66.0 $53.7 $41.7 $74.9
======== ====== ===== ===== ===== =====
The Partnership and International Propane also enter into contracts to
purchase LPG 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 $10 at September 30, 2005. The leases expire through 2010
and some of them are currently in default. The Partnership has succeeded to the
indemnity agreement of Petrolane by which Texas Eastern Corporation ("Texas
Eastern"), a prior owner of Petrolane, agreed to indemnify Petrolane against any
liabilities arising out of the conduct of businesses that do not relate to, and
are not a part of, the propane business, including lease guarantees. In December
1999, Texas Eastern filed for dissolution under the Delaware General Corporation
Law. 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.
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
Note 11 continued
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, 2005, the potential amount payable under
this indemnity by the Company Parties was approximately $58. 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. In 2003, AmeriGas OLP settled
the individual personal injury and property damage claims of the Swigers. In
2004, the court granted the plaintiffs' motion to include customers acquired
from Columbia Propane in August 2001 as additional potential class members and
the plaintiffs amended their complaint to name additional parties pursuant to
such ruling. Subsequently, in March 2005, AmeriGas OLP filed a cross-claim
against CEG, former owner of Columbia Propane, seeking indemnification for
conduct undertaken by Columbia Propane prior to AmeriGas OLP's acquisition.
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 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.
52
UGI Corporation 2005 Annual Report
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. Citizens alleges that UGI Utilities and its
predecessors owned and operated the plant from 1901 to 1928. Studies conducted
by the City and Citizens suggest that it could cost up to $18 to clean up the
river. Citizens' third-party claims have been stayed pending a resolution of the
City's suit against Citizens, which was tried in September 2005 and has not yet
been decided. 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. In March 2005, the court granted UGI Utilities motion for summary
judgment dismissing AGL's complaint. AGL has appealed.
AGL has informed UGI Utilities that it has begun remediation of MGP wastes
at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI
Utilities operated the MGP in the early 1900s. AGL 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. The trial court granted UGI Utilities' motion for
summary judgment and dismissed ConEd's complaint. The grant of summary judgment
was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of
the Second Circuit Court of Appeals affirmed in part and reversed in part the
decision of the trial court. The appellate panel affirmed the trial court's
decision dismissing claims that UGI Utilities was liable under CERCLA as an
operator of MGPs owned and operated by its former subsidiaries. The appellate
panel reversed the trial court's decision that UGI Utilities was released from
liability at three sites where UGI Utilities operated MGPs under lease.
UGI Utilities has filed for reconsideration of the panel's order. UGI Utilities
believes that any liability it may have for a share of the response costs at the
three leased MGP sites will not have a material effect on its financial
condition or results of operations.
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 remediation
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.
The French tax authorities levy taxes on legal entities and individuals
regularly operating a business in France which are commonly referred to
collectively as "business tax." The amount of business tax charged annually is
generally dependent upon the rental value of the entity's tangible fixed assets
and the rate of tax is affected by an entity's earnings. Prior to the Antargaz
Acquisition, Antargaz filed suit against French tax authorities in connection
with the assessment of business tax related to certain of its owned tanks at
customer locations. Elf Antar France and Elf Aquitaine, now Total France, former
owners of Antargaz, agreed to indemnify Antargaz for all payments which would
have been due from Antargaz in respect of the tax related to its tanks for the
period from January 1, 1997 through December 31, 2000. During the year ended
September 30, 2005, Antargaz was required to remit payment to the French tax
authorities with respect to this matter and Antargaz was fully reimbursed
pursuant to the indemnity agreement. The indemnity from the former owners is
reflected in our balance sheet as both an asset and a liability. At September
30, 2005, the remaining amount subject to the indemnification is immaterial.
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and
where indicated otherwise)
Note 11 continued
Antargaz accrues for business tax on a monthly basis. It has recorded
liabilities for business taxes related to various classes of fixed assets. On
February 4, 2005, Antargaz received a letter from the French government which
eliminated the requirement for Antargaz to pay business tax associated with
tanks at certain customer locations. In addition, during 2005 resolution was
reached relating to business taxes relating to a prior year. Further changes in
the French government or tax authorities' interpretation of the tax laws or in
the tax laws themselves, could have either an adverse or a favorable effect on
our results of operations. Our 2005 Statement of Income includes a pre-tax gain
of $18.8 and net after-tax gain of $14.2 associated with the resolution of
business tax matters related principally to prior years.
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 and
result in losses in excess of recorded amounts. We are unable to estimate any
possible losses in excess of recorded amounts. Although we currently believe,
after consultation with counsel, that damages or settlements, if any, recovered
by the plaintiffs in such claims or actions will not have a material adverse
effect on our financial position, damages or settlements could be material to
our operating results or cash flows in future periods depending on the nature
and timing of future developments with respect to these matters and the amounts
of future operating results and cash flows.
NOTE 12 - 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.
Antargaz uses forward foreign exchange contracts and may use other
derivative 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. In addition, Energy Services uses price swap and option
contracts to manage market risk associated with forecasted purchases of propane
it sells under firm commitments. These derivative instruments are designated as
cash flow hedges. The fair values of these futures and swap and option contracts
are affected by changes in natural gas and propane 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 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.
We are 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
2006. Antargaz may enter into additional interest rate swap agreements in order
to fix interest rates over additional periods.
54
UGI Corporation 2005 Annual Report
During the year ended September 30, 2005, 2004 and 2003, the net pre-tax
loss recognized in earnings representing cash flow hedge ineffectiveness was
$1.7, $1.5 and $3.1, respectively.
Gains and losses included in accumulated other comprehensive income at
September 30, 2005 relating to cash flow hedges will be reclassified into (1)
cost of sales when the forecasted purchase of LPG, 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, 2005
are net after-tax losses of approximately $4.9 from IRPAs associated with
forecasted issuances of debt generally anticipated to occur during the next two
years and with settled IRPAs. The amount of this net loss that 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, 2005 are net
after-tax gains of approximately $14.1 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 $3.6 associated with
future electric supply purchases expected to occur in 2007. Amounts included in
accumulated other comprehensive income at September 30, 2005 are gains of $3.9
associated with forecasted U.S. dollar-denominated purchases of LPG generally
anticipated to occur during the next three years. The amount of the gain that is
expected to be reclassified into net income during the next twelve months is not
material. 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
euro. The U.S. dollar value of our foreign-denominated assets and liabilities
will fluctuate with changes in the associated foreign currency exchange rates.
We use derivative instruments to hedge portions of our 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, 2005, a net after-tax loss of $0.6 is
included in accumulated other comprehensive income associated with settled net
investment hedges.
The carrying amounts of financial instruments included in current assets
and current liabilities (excluding unsettled derivative instruments and current
maturities of long-term debt) approximate their fair values because of their
short-term nature. The carrying amounts and estimated fair values of our
remaining financial instruments (including unsettled derivative instruments) at
September 30 are as follows:
Carrying Estimated
Amount Fair Value
-------- ----------
2005:
Natural gas futures and options contracts $ (1.5) $ (1.5)
Electric supply swap 6.1 6.1
Propane swap and option contracts 50.8 50.8
Interest rate protection agreements (6.2) (6.2)
Foreign currency swaps 7.5 7.5
Long-term debt 1,644.5 1,730.7
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
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. 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, 2005 and
2004.
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 the credit risk associated with our derivative financial
instruments through the application of credit policies.
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 13 - ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY
UGI Energy Services, Inc. ("ESI") 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. In order to provide additional short-term
liquidity during the peak-heating season due to increased product costs, the
maximum level of funding available at any one point in time from this facility
was temporarily increased to $300 for the period from November 1, 2005 to April
24, 2006. After April 24, 2006, the maximum level of funding available at any
one time from this facility is $150. Under the Receivables Facility, ESI
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 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 ESI 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." ESI continues to service, administer and collect trade
receivables on behalf of the commercial paper issuer and ESFC.
During 2005 and 2004, ESI sold trade receivables totaling $1,253.6 and
$949.6, respectively, to ESFC. During 2005 and 2004, ESFC sold an aggregate
$475.5 and $246.0, respectively, of undivided interests in its trade receivables
to the commercial paper conduit. At September 30, 2005, the outstanding balance
of ESFC trade receivables was $77.8 of which $23.5 was sold to the commercial
paper conduit and removed from the balance sheets. At September 30, 2004, there
were $63.4 of ESFC trade receivables outstanding of which no amount was sold to
the commercial paper conduit. Losses on sales of receivables to the commercial
paper conduit that occurred during the years ended September 30, 2005 and 2004,
which are included in other income, net, were $0.9 and $0.4, 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 2006.
NOTE 14 - OTHER INCOME, NET
Other income (loss), net, comprises the following:
2005 2004 2003
----- ----- -----
Interest and interest-related income $ 6.3 $ 3.2 $ 6.6
Utility non-tariff service income 1.3 2.0 5.7
Gain on sales of fixed assets 3.4 0.1 1.6
Pension income -- -- 1.1
Foreign currency hedge loss -- (9.1) --
Finance charges 7.6 6.5 3.9
Business tax reversal 19.9 -- --
Other 8.2 7.5 0.9
----- ----- -----
Total other income, net $46.7 $10.2 $19.8
----- ----- -----
NOTE 15 - CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS AND COMMON UNIT
ISSUANCES
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 contribution.
56
UGI Corporation 2005 Annual Report
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 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 at September 30, 2004. The gain had no effect on the Company's net
income or cash flow.
In September 2005, AmeriGas Partners sold 2,300,000 Common Units in an
underwritten public offering at a public offering price of $33.00 per unit. The
net proceeds of the public offering totaling $72.7 and the 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. Concurrent with this sale of Common Units,
the Company recorded a gain in the amount of $28.0 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 SAB 51. The gain had no effect on the Company's net income
or cash flow. Total deferred income tax liabilities of $16.0 associated with
this gain with a corresponding decrease to stockholders' equity were recorded
and reflected in the Consolidated Balance Sheet at September 30, 2005.
NOTE 16 - INVESTMENTS IN EQUITY INVESTEES
Our principal investments accounted for using the equity method and our
approximate percentage ownership interest in each at September 30, 2005 and 2004
are as follows:
Company 2005 2004
- ------- ----- ----
Atlantic Energy (a) 100.0% 50.0%
China Gas Partners 50.0% 50.0%
Hunlock Creek Energy Ventures 50.0% 50.0%
Geovexin 44.9% 44.9%
(a) In November 2004, a subsidiary of Energy Services acquired 100% of Atlantic
Energy, (see Note 2).
Prior to the Antargaz Acquisition on March 31, 2004, we accounted for our
19.5% ownership interest in AGZ under the equity method. As a result of the
Antargaz Acquisition, beginning April 1, 2004 we discontinued the equity method
and began reflecting all of AGZ's operations on a consolidated basis.
(Loss) income from our equity investees was $(2.6) in 2005, $11.3 in 2004
and $5.3 in 2003. Undistributed net earnings of our equity investees included in
consolidated retained earnings was not material at September 30, 2005, 2004 or
2003.
Summarized financial information for AGZ, prior to the Antargaz
Acquisition, follows:
2003
------
STATEMENT OF INCOME DATA:
Revenues $698.4
Operating income $ 96.7
Interest, net (37.7)
Income before income taxes $ 59.0
Income taxes $(24.4)
Net income $ 32.7
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.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars and euros, except per share amounts and where indicated
otherwise)
NOTE 17 - QUARTERLY DATA (UNAUDITED)
The following unaudited quarterly data includes adjustments (consisting only of
normal recurring adjustments) which we consider necessary for a fair
presentation unless otherwise indicated. Our quarterly results fluctuate because
of the seasonal nature of our businesses. Results include Antargaz as an equity
investee through March 31, 2004 and include all of the results of Antargaz'
operations beginning April 1, 2004.
December 31, March 31, June 30, September 30,
----------------- ------------------- ---------------- -----------------
2004(A) 2003 2005 2004(b) 2005(C) 2004 2005 2004
-------- ------ -------- -------- ------- ------ ------ ------
Revenues $1,362.4 $893.7 $1,787.7 $1,316.6 $932.5 $823.4 $806.1(D) $751.0
Operating income $ 175.0 $108.3 $ 287.7 $ 181.6 $ 37.6 $ 33.9 $ 2.7 $ 7.5
Income (loss) from equity investees $ (0.7) $ 4.2 $ (0.6) $ 8.4 $ (0.7) $ (0.6) $ (0.6) $ (0.7)
Net income (loss) $ 78.2 $ 38.8 $ 117.3 $ 67.1 $ 0.7 $ 8.3 $ (8.7) $ (2.6)
Earnings (loss) per share (e):
Basic $ 0.76 $ 0.45 $ 1.13 $ 0.76 $ 0.01 $ 0.08 $(0.08) $(0.03)
Diluted $ 0.74 $ 0.44 $ 1.12 $ 0.74 $ 0.01 $ 0.08 $(0.08) $(0.03)
(a) Includes the effects of the resolution of certain Antargaz business tax
related contingencies which increased operating income by $19.9 and net
income by $14.9 or $0.14 per diluted share.
(b) Includes a foreign exchange loss associated with the March 31, 2004
Antargaz Acquisition which decreased operating income by $9.1 and net
income by $5.9 or $0.07 per diluted share.
(c) Includes a loss on early extinguishment of AmeriGas Propane's debt which
increased net loss by $9.4 or $0.09 per diluted share.
(d) Revenues reflect the elimination of fiscal year 2005 intercompany
transactions of approximately $124.
(e) Earnings (loss) per share for all periods reflect the effects of the
Company's 2-for-1 common stock split distributed May 24, 2005 to
shareholders of record on May 17, 2005.
NOTE 18 - 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. We
refer to both international segments collectively as "International Propane."
AmeriGas Propane derives its revenues principally from the sale of propane
and related equipment and supplies to retail customers from locations in 46
states. 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, LPG, electricity and fuel oil 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 EBIT-DA 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. 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.
58
UGI Corporation 2005 Annual Report
Financial information by reportable business segment follows:
Reportable Segments
---------------------------------------------------------------
International Propane
-------------------------
AmeriGas Gas Electric Energy International Corporate &
Total Eliminations Propane Utility Utility Services Antargaz Other (b) Other (c)
-------- ------------ -------- ------- -------- -------- -------- ------------- -----------
2005
Revenues $4,888.7 $(124.1)(d) $1,963.3 $585.1 $96.1 $1,355.0 $ 869.9 $ 74.0 $ 69.4
Cost of sales $3,306.0 $(120.0)(d) $1,220.0 $390.1 $47.8 $1,281.4 $ 401.5 $ 42.6 $ 42.6
Operating income $ 503.0 $ -- $ 168.1 $ 81.6 $21.6 $ 37.5 $ 188.3(e) $ 5.5 $ 0.4
Income (loss) from equity
investees (2.6) -- -- -- -- -- (2.5) (0.1) --
Loss on extinguishments of debt (33.6) -- (33.6) -- -- -- -- -- --
Interest expense (130.2) -- (79.8) (16.6) (1.7) -- (28.6) (2.9) (0.6)
Minority interests (29.9) 3.9 (33.1) -- -- -- (0.7) -- --
Income before income taxes $ 306.7 $ 3.9 $ 21.6 $ 65.0 $19.9 $ 37.5 $ 156.5(e) $ 2.5 $ (0.2)
Depreciation and amortization $ 146.4 $ -- $ 73.7 $ 20.7 $ 3.1 $ 5.7 $ 37.6 $ 4.9 $ 0.7
Partnership EBITDA (a) $ 215.9
Total assets $4,571.5 $(348.1) $1,672.9 $803.6 $99.8 $ 296.1 $1,404.8 $152.4 $490.0
Capital expenditures $ 158.4 $ -- $ 62.6 $ 38.8 $ 7.5 $ 6.2 $ 38.5 $ 3.5 $ 1.3
Investments in equity investees $ 12.8 $ -- $ -- $ -- $ -- $ 8.5 $ 1.6 $ 2.7 $ --
Goodwill and excess
reorganization value $1,231.2 $ (4.0) $ 618.2 $ -- $ -- $ 11.8 $ 531.4 $ 67.5 $ 6.3
2004
Revenues $3,784.7 $ -- $1,775.9 $560.4 $89.7 $ 967.2 $ 270.8 $ 62.6 $ 58.1
Cost of sales $2,551.0 $ -- $1,029.2 $368.9 $43.3 $ 912.2 $ 130.1 $ 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 $4,242.6 $(322.1) $1,567.9 $765.5 $89.7 $ 182.8 $1,352.3 $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 $ 20.0 $ -- $ 3.5 $ -- $ -- $ 9.6 $ 4.1 $ 2.8 $ --
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 (loss) $ 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 (loss) 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 $ 23.8 $141.2 $178.0
Capital expenditures $ 101.4 $ -- $ 53.4(f) $ 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 $ 23.8 $ 3.0 $ --
Goodwill and excess
reorganization value $ 671.5 $ -- $ 601.6 $ -- $ -- $ 2.8 $ -- $ 62.8 $ 4.3
(a) The following table provides a reconciliation of Partnership EBITDA to
AmeriGas Propane operating income:
Year ended September 30, 2005 2004 2003
- ------------------------ ------ ------ ------
Partnership EBITDA (i) $215.9 $255.9 $234.4
Depreciation and amortization (ii) (73.6) (80.6) (74.6)
Minority interests (iii) 1.5 1.4 1.1
Income (loss) from equity investees -- (0.7) 0.6
Intercompany gain on sale of Atlantic Energy (9.1) -- --
Loss on extinguishments of debt 33.6 -- 3.0
------ ------ ------
Operating income $168.1 $176.0 $164.5
------ ------ ------
(i) Includes $9.1 gain on the sale of Atlantic Energy to Energy Services
during Fiscal 2005. See Note 2.
(ii) Excludes General Partner depreciation and amortization of $0.1 in both
2005 and 2004 and $0.2 in 2003.
(iii) 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) Represents the elimination of intersegment transactions primarily
associated with Energy Services' net energy commodity sales to Gas Utility
and AmeriGas Propane totaling $89.2 and $25.9, respectively.
(e) International Propane-Antargaz' operating income and income before income
taxes for Fiscal 2005 include $18.8 associated with the resolution of
certain business tax contingencies (see Note 11).
(f) Includes capital leases of $0.5 in 2003.
59