Annual Report — [x] Reg. S-K Item 405 — Form 10-K
Filing Table of Contents
Document/Exhibit Description Pages Size
1: 10-K405 Form 10-K Fiscal Year Ended September 30, 2001 52 208K
2: EX-10.34(A) Amendments Dated 10/11/01-9/99 Guarantee Agmts. 12 29K
3: EX-13 Pages 13-47 of the 2001 Annual Report 71± 312K
4: EX-21 Subsiadiaries of the Registrant 2± 10K
5: EX-23 Consent of Arthur Andersen LLP 1 6K
UGI Corporation 2001 Annual Report
FINANCIAL REVIEW
BUSINESS OVERVIEW
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").
We refer to AmeriGas Partners and its subsidiaries as "the Partnership." At
September 30, 2001, UGI, through its wholly owned second-tier subsidiary
AmeriGas Propane, Inc. (the "General Partner"), held an effective approximate
53% interest in the Partnership.
Our utility business is conducted through UGI Utilities, Inc.
("UGI Utilities"). UGI Utilities owns and operates a natural gas distribution
utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an
electricity distribution and electricity generation business (collectively
referred to as "Electric Utility") in northeastern Pennsylvania.
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises")
conducts an energy marketing business primarily in the Middle Atlantic region of
the United States through its wholly owned subsidiary, UGI Energy Services, Inc.
("Energy Services"). Through other subsidiaries, Enterprises (1) owns and
operates a propane distribution business in Austria, the Czech Republic and
Slovakia ("FLAGA"); (2) owns and operates a heating, ventilation and
air-conditioning service business in the Middle Atlantic states ("HVAC"); and
(3) participates in propane joint-venture businesses in France ("Antargaz") and
in the Nantong region of China.
This Financial Review should be read in conjunction with our
Consolidated Financial Statements and Notes to Consolidated Financial Statements
including the business segment information included in Note 19.
RESULTS OF OPERATIONS
2001 COMPARED WITH 2000
CONSOLIDATED RESULTS
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Variance -
Favorable
2001 2000 (Unfavorable)
---- ---- -------------
DILUTED Diluted Diluted
NET EARNINGS Net Earnings Net Earnings
INCOME (LOSS) Income (Loss) Income (Loss)
(LOSS) PER SHARE (Loss) Per Share (Loss) Per Share
------ --------- ------ --------- ------ ---------
(Millions of dollars, except per share)
AmeriGas Propane $ 13.5 $ 0.49 $ -- $ -- $ 13.5 $ 0.49
UGI Utilities 46.6 1.70 48.9 1.79 (2.3) (0.09)
Energy Services 4.0 0.15 1.6 0.06 2.4 0.09
International Propane (4.4) (0.16) (5.6) (0.20) 1.2 0.04
Other Enterprises (a) (9.3) (0.34) (3.8) (0.14) (5.5) (0.20)
Corporate & Other 1.6 0.06 3.6 0.13 (2.0) (0.07)
Changes in accounting (b) 4.5 0.16 -- -- 4.5 0.16
------- ------- ------- ------- ------- -------
Total $ 56.5 $ 2.06 $ 44.7 $ 1.64 $ 11.8 $ 0.42
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(a) Comprised principally of Hearth USA(TM), HVAC, and Enterprises corporate and
general expenses. Net loss in 2001 includes after-tax shut-down costs of $5.5
million or $0.20 per share associated with closing the Company's two Hearth
USA(TM) retail stores (see Note 15 to Consolidated Financial Statements).
(b) Includes cumulative effect of accounting changes associated with (1) the
Partnership's changes in accounting for tank fee revenue and tank installation
costs and (2) the Company's adoption of SFAS 133 (see "Changes in Accounting"
below).
The higher Fiscal 2001 net income and earnings per share reflect a
significant increase in the Partnership's and Energy Services' results.
Excluding the cumulative effect of accounting changes and one-time costs to
close the Hearth USA(TM) retail stores, diluted earnings per share increased 28%
to $2.10 in Fiscal 2001.
The following table presents certain financial and statistical
information by business segment for 2001 and 2000:
[Download Table]
Increase
2001 2000 (Decrease)
---- ---- ----------
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $1,418.4 $1,120.1 $ 298.3 26.6%
Total margin $ 582.4 $ 491.8 $ 90.6 18.4%
EBITDA (a) $ 209.3 $ 158.6 $ 50.7 32.0%
Operating income $ 133.8 $ 90.2 $ 43.6 48.3%
Retail gallons sold (millions) 820.8 771.2 49.6 6.4%
Degree days - % colder (warmer)
than normal (b) 2.6% (13.7)% -- --
GAS UTILITY:
Revenues $ 500.8 $ 359.0 $ 141.8 39.5%
Total margin $ 177.9 $ 170.8 $ 7.1 4.2%
EBITDA (a) $ 108.0 $ 105.3 $ 2.7 2.6%
Operating income $ 87.8 $ 86.2 $ 1.6 1.9%
System throughput -
billions of cubic feet ("bcf") 77.3 79.7 (2.4) (3.0)%
Degree days - % colder (warmer)
than normal 2.0% (9.9)% -- --
ELECTRIC UTILITY:
Revenues $ 83.9 $ 77.9 $ 6.0 7.7%
Total margin $ 28.6 $ 40.5 $ (11.9) (29.4)%
EBITDA (a) $ 14.3 $ 19.6 $ (5.3) (27.0)%
Operating income $ 10.7 $ 15.1 $ (4.4) (29.1)%
Distribution sales - millions of
kilowatt hours ("gwh") 945.5 907.2 38.3 4.2%
ENERGY SERVICES:
Revenues $ 370.7 $ 146.9 $ 223.8 152.3%
Total margin $ 13.4 $ 6.2 $ 7.2 116.1%
EBITDA (a) $ 7.6 $ 3.0 $ 4.6 153.3%
Operating income $ 7.3 $ 2.8 $ 4.5 160.7%
INTERNATIONAL PROPANE:
Revenues $ 50.9 $ 50.5 $ 0.4 0.8%
Total margin $ 22.5 $ 20.8 $ 1.7 8.2%
EBITDA (a) $ 3.6 $ 1.9 $ 1.7 89.5%
Operating loss $ (0.7) $ (2.7) $ (2.0) (74.1)%
-------- -------- -------- -----
(a) EBITDA (earnings before interest expense, income taxes, depreciation and
amortization) should not be considered as an alternative to net income (as an
indicator of operating performance) or as an alternative to cash flow (as a
measure of liquidity or ability to service debt obligations) and is not a
measure of performance under accounting principles generally accepted in the
United States.
(b) Deviation from average heating degree days during the 30-year period from
1961 to 1990, based upon national weather statistics provided by the National
Oceanic and Atmospheric Administration ("NOAA") for 335 airports in the
continental U.S.
13
FINANCIAL REVIEW (continued)
AMERIGAS PROPANE. Retail propane gallons sold increased 49.6 million gallons
(6.4%) primarily due to the effects of colder weather and the impact of
acquisitions, including the acquisition of Columbia Propane Corporation on
August 21, 2001 (see "Acquisition of Columbia Propane" below). Temperatures
based upon heating degree days were 2.6% colder than normal in Fiscal 2001
compared to temperatures that were 13.7% warmer than normal in Fiscal 2000. The
greater acquisition and weather-related sales were reduced by customer
conservation resulting from higher product costs and a slowing U.S. economy. The
wholesale price of propane at Mont Belvieu, Texas, a major U.S. supply point,
reached a high of 95 cents per gallon in Fiscal 2001 compared to a high of 74
cents per gallon during Fiscal 2000.
Total revenues from retail propane sales increased $238.1 million
reflecting (1) a $182.1 million increase as a result of higher average selling
prices and (2) a $56.0 million increase as a result of the higher retail volumes
sold. Wholesale propane revenues increased $61.9 million principally reflecting
higher average prices and greater sales associated with product cost management
activities. Cost of sales increased $207.7 million as a result of higher per
unit propane product costs and the greater retail and wholesale volumes sold.
Total margin increased $90.6 million due to the impact of
higher-than-normal average retail unit margins and, to a lesser extent, the
greater retail propane volumes sold. Retail propane unit margins in Fiscal 2001
benefited from gains on derivative hedge instruments and favorably priced supply
arrangements.
The significant increase in EBITDA in Fiscal 2001 resulted from the
increase in margin partially offset by a $37.3 million increase in Partnership
operating and administrative expenses. Operating and administrative expenses of
the Partnership were $380.0 million in Fiscal 2001 compared to $342.7 million in
Fiscal 2000. Adjusting prior-year expenses for the impact of the Partnership's
change in accounting for tank installation costs (see "Changes in Accounting"
below), operating and administrative expenses of the Partnership increased $44.3
million. The higher Fiscal 2001 expenses reflect (1) higher employee-related
costs, including greater overtime and incentive compensation costs; (2)
growth-related expenses, including the impact of Columbia Propane and other
acquisitions, and expenses associated with our PPX(R) grill cylinder exchange
business; and (3) higher distribution costs, including vehicle fuel and lease
expense. Depreciation and amortization expense of the Partnership increased $7.4
million reflecting greater depreciation associated with acquisitions and $4.4
million of depreciation expense resulting from the change in accounting for tank
installation costs.
GAS UTILITY. Although temperatures based upon heating degree days were colder in
Fiscal 2001, total system throughput declined 3.0% as the impact of the colder
weather was more than offset by lower interruptible and firm delivery service
volumes, the impact of price-induced customer conservation, and the effects of a
slowing economy. Natural gas prices were significantly higher in Fiscal 2001
than in the prior year. The higher prices resulted in fuel switching by many of
our interruptible customers, who have the ability to switch to alternate fuels,
and encouraged price-induced conservation by many of our firm customers.
Throughput to our firm - residential, commercial and industrial ("core market")
customers increased 3.3 bcf (10.6%) reflecting the impact of the colder Fiscal
2001 weather.
The significant increase in Gas Utility revenues is primarily a result
of higher core-market revenues reflecting greater purchased gas cost ("PGC")
rates and higher off-system sales revenues. Gas Utility's tariffs permit it to
pass through prudently incurred gas costs to its core market customers through
higher PGC rates.
Gas Utility cost of gas totaled $322.9 million in Fiscal 2001 compared
with $184.2 million in Fiscal 2000 principally reflecting the higher average PGC
rates and, to a lesser extent, higher core market and off-system sales.
Gas Utility total margin increased $7.1 million reflecting a $12.1
million increase in core-market margin partially offset by lower total margin
from interruptible customers. The decline in interruptible margin reflects lower
average interruptible unit margins due to a decline in the spread between oil
and natural gas prices and the lower interruptible throughput.
Gas Utility EBITDA increased $2.7 million as the previously mentioned
increase in total margin and higher pension income resulting primarily from the
impact of investment gains in prior years was partially offset by higher
operating and administrative expenses. The increase in operating and
administrative expenses includes, among other things, greater allowances for
uncollectible accounts reflecting significantly higher Fiscal 2001 customer
bills and lower income from environmental insurance litigation settlements. Such
settlements totaled $0.9 million in Fiscal 2001 compared with $4.5 million in
Fiscal 2000. Depreciation expense increased $1.1 million reflecting greater
depreciation associated with distribution system capital expenditures.
ELECTRIC UTILITY. Distribution system sales in Fiscal 2001 increased 4.2% on
favorable weather. Revenues increased as a result of the higher distribution
system sales as well as off-system sales of electricity generated by Energy
Ventures, our joint-venture electricity generation business (see "Regulatory
Matters" below). Cost of sales totaled $51.9 million in Fiscal 2001 compared to
$33.9 million in the prior year. The increase reflects higher per-unit purchased
power costs, the impact on cost of sales resulting from the formation of Energy
Ventures, and the higher Fiscal 2001 sales.
Electric Utility total margin decreased $11.9 million as a result of
the higher purchased power costs. Because the generation component of Electric
Utility's rates are currently subject to rate caps, increases in the cost of
electricity purchased by Electric Utility negatively impacts earnings. EBITDA
declined less than the decline in total margin principally reflecting lower
power production expenses subsequent to the formation of Energy Ventures and
lower utility realty taxes. Depreciation expense decreased $0.9 million
reflecting the impact of the formation of Energy Ventures.
ENERGY SERVICES. Revenues from Energy Services increased significantly
reflecting higher natural gas prices and acquisition-related volume growth.
During Fiscal 2001, Energy Services acquired the energy marketing businesses of
PG Energy Services, Inc. and Conectiv. Total margin, EBITDA and operating income
were also
14
UGI Corporation 2001 Annual Report
substantially higher in Fiscal 2001 reflecting the greater acquisition-driven
sales volumes and higher average unit margins.
INTERNATIONAL PROPANE. FLAGA's results in Fiscal 2001 were adversely impacted by
weather that was approximately 12% warmer than normal. Propane volumes sold were
8.5% lower than in Fiscal 2000 reflecting the impact of the warm weather and
price-induced conservation. The increase in total margin, notwithstanding the
decline in sales volumes, reflects higher average unit margins partially offset
by the impact of a weaker EURO in Fiscal 2001. International Propane EBITDA and
operating loss in Fiscal 2001 also includes (1) a loss of $1.1 million from the
write-off of our propane joint-venture investment in Romania and (2) $0.5
million of income associated with our investment in Antargaz (see "Investment in
Antargaz" below).
CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate & Other operating income in
Fiscal 2001 declined $1.9 million principally reflecting lower interest and
investment income and greater incentive compensation costs. The increase in
Other Enterprises' revenues is principally a result of HVAC, which was acquired
in late Fiscal 2000. Other Enterprises' operating loss in Fiscal 2001 includes
$8.5 million of shut-down costs associated with Hearth USA(TM), our pilot retail
hearth, spa and grill products business. In September 2001, after evaluating the
prospects for Hearth USA(TM) in light of the weak retail environment and the
capital required to expand beyond its two-store pilot phase, we committed to
close both stores and cease operations in October 2001. Other Enterprises'
operating loss in Fiscal 2001 also includes a $2.0 million loss resulting from
the write-down of an investment in a business-to-business e-commerce company.
INTEREST EXPENSE AND INCOME TAXES. Interest expense increased $6.3 million in
Fiscal 2001 primarily as a result of greater amounts of Partnership long-term
debt outstanding. The effective income tax rate was 45.9% in Fiscal 2001,
compared to a 46.4% rate in Fiscal 2000.
2000 COMPARED WITH 1999
CONSOLIDATED RESULTS
[Enlarge/Download Table]
Variance -
Favorable
2000 1999 (Unfavorable)
---- ---- -------------
Diluted Diluted Diluted
Net Earnings Net Earnings Net Earnings
Income (Loss) Income (Loss) Income (Loss)
(Loss) Per Share (Loss) Per Share (Loss) Per Share
------ --------- ------ --------- ------ ---------
(Millions of dollars, except per share)
AmeriGas Propane $ -- $ -- $ 4.5 $ 0.14 $ (4.5) $ (0.14)
UGI Utilities 48.9 1.79 37.4 1.17 11.5 0.62
Energy Services 1.6 0.06 1.5 0.05 0.1 0.01
International Propane (5.6) (0.20) (0.1) -- (5.5) (0.20)
Other Enterprises (3.8) (0.14) (3.6) (0.11) (0.2) (0.03)
Corporate & Other 3.6 0.13 3.1 0.09 0.5 0.04
Merger termination
fee, net (a) -- -- 12.9 0.40 (12.9) (0.40)
------- ------- ------- ------- ------- -------
Total $ 44.7 $ 1.64 $ 55.7 $ 1.74 $ (11.0) $ (0.10)
------- ------- ------- ------- ------- -------
(a) Represents after-tax merger termination fee income, net of related expenses,
associated with the Company's terminated merger agreement with Unisource
Worldwide, Inc. See Note 17 to Consolidated Financial Statements.
Our Fiscal 2000 results reflect improved earnings from UGI Utilities
partially offset by a decline in net income from AmeriGas Propane and
International Propane losses. Excluding the effect of merger termination fee
income in Fiscal 1999, earnings per share increased 22% in Fiscal 2000
reflecting a 15% decline in average shares outstanding and higher net income.
The following table presents certain financial and statistical
information by business segment for Fiscal 2000 and Fiscal 1999:
[Download Table]
Increase
2000 1999 (Decrease)
---- ---- ----------
(Millions of dollars)
AMERIGAS PROPANE:
Revenues $1,120.1 $ 872.5 $ 247.6 28.4%
Total margin $ 491.8 $ 481.7 $ 10.1 2.1%
EBITDA $ 158.6 $ 158.8 $ (0.2) (0.1)%
Operating income $ 90.2 $ 92.5 $ (2.3) (2.5)%
Retail gallons sold (millions) 771.2 783.2 (12.0) (1.5)%
Degree days - % (warmer)
than normal (13.7)% (9.9)% -- --
GAS UTILITY:
Revenues $ 359.0 $ 345.6 $ 13.4 3.9%
Total margin $ 170.8 $ 160.6 $ 10.2 6.4%
EBITDA $ 105.3 $ 87.0 $ 18.3 21.0%
Operating income $ 86.2 $ 68.0 $ 18.2 26.8%
System throughput -
billions of cubic feet ("bcf") 79.7 76.1 3.6 4.7%
Degree days - % (warmer)
than normal (9.9)% (12.8)% -- --
ELECTRIC UTILITY:
Revenues $ 77.9 $ 75.0 $ 2.9 3.9%
Total margin $ 40.5 $ 38.6 $ 1.9 4.9%
EBITDA $ 19.6 $ 16.7 $ 2.9 17.4%
Operating income $ 15.1 $ 12.7 $ 2.4 18.9%
Distribution sales - millions of
kilowatt hours ("gwh") 907.2 900.4 6.8 0.8%
ENERGY SERVICES:
Revenues $ 146.9 $ 90.4 $ 56.5 62.5%
Total margin $ 6.2 $ 6.0 $ 0.2 3.3%
EBITDA $ 3.0 $ 2.7 $ 0.3 11.1%
Operating income $ 2.8 $ 2.6 $ 0.2 7.7%
INTERNATIONAL PROPANE:
Revenues $ 50.5 $ -- $ 50.5 N.M.
Total margin $ 20.8 $ -- $ 20.8 N.M.
EBITDA $ 1.9 $ (0.1) $ 2.0 N.M.
Operating loss $ (2.7) $ (0.1) $ 2.6 N.M.
-------- -------- -------- --------
N.M. - Not Meaningful.
15
FINANCIAL REVIEW (continued)
AMERIGAS PROPANE. Based upon national heating degree day information,
temperatures in Fiscal 2000 were 13.7% warmer than normal and 3.8% warmer than
in Fiscal 1999. Retail volumes of propane sold were 12 million gallons lower,
primarily a result of the warmer weather's effect on residential heating gallons
and a decline in agricultural gallons as a result of a poor crop drying season.
Partially offsetting these decreases were higher motor fuel sales, reflecting
the continuing effects of our expanding National Accounts program, the volume
impact of PPX(R), and acquisition-related volume increases.
Total revenues from retail propane sales increased $160.5 million in
Fiscal 2000 due to higher average selling prices. The higher average selling
prices resulted from significantly higher propane product costs. Wholesale
propane revenues increased $77.4 million reflecting (1) a $50.7 million increase
as a result of higher average wholesale prices and (2) a $26.7 million increase
as a result of higher wholesale volumes sold. Nonpropane revenues increased $9.7
million in Fiscal 2000 reflecting higher customer fees, hauling, and PPX(R)
cylinder sales revenue. Cost of sales increased $237.5 million primarily as a
result of the higher propane product costs and greater wholesale volumes sold.
Total margin increased $10.1 million in Fiscal 2000 due to (1) greater
volumes sold to higher margin PPX(R) customers; (2) slightly higher average
retail unit margins; and (3) an increase in total margin from customer fees, and
ancillary sales and services.
EBITDA in Fiscal 2000 was comparable to Fiscal 1999 as the increases in
total margin and higher other income were offset by higher operating expenses.
Other income increased $3.1 million due to, among other things, higher income
from sales of assets and higher finance charge income. Operating expenses of the
Partnership were $342.7 million in Fiscal 2000 compared with $329.6 million in
Fiscal 1999 reflecting incremental expenses from growth and operational
initiatives and higher vehicle fuel costs. Our growth and operational
initiatives in Fiscal 2000 included significantly expanding PPX(R), acquiring
retail propane businesses, and developing and implementing more efficient
methods of operating the business. Although EBITDA in Fiscal 2000 was about
equal to Fiscal 1999, operating income declined $2.3 million reflecting higher
PPX(R) and acquisition-related charges for depreciation and amortization.
GAS UTILITY. Weather in Gas Utility's service territory was 9.9% warmer than
normal in Fiscal 2000 but 3.8% colder than in Fiscal 1999. The increase in
system throughput during Fiscal 2000 resulted from higher interruptible delivery
service volumes and higher sales to our core-market customers.
The increase in Gas Utility's revenues during Fiscal 2000 principally
resulted from (1) a $13.1 million increase in core-market revenues reflecting
higher sales and higher average PGC rates partially offset by the impact of the
elimination of gross receipts tax revenue effective January 1, 2000 pursuant to
Pennsylvania's Gas Competition Act and (2) a $5.9 million increase in revenues
from interruptible customers. These increases in revenue were partially offset
by lower off-system sales and firm delivery service revenues. Gas Utility cost
of gas was $184.2 million in Fiscal 2000 compared with $172.0 million in Fiscal
1999. The increase reflects higher average PGC rates and higher core-market
sales partially offset by lower costs associated with the decline in off-system
sales.
Gas Utility total margin increased $10.2 million reflecting (1) a $4.2
million increase in total interruptible retail and interruptible delivery
service margin; (2) a $4.9 million increase in core-market margin; and (3)
slightly higher firm delivery service total margin.
Gas Utility EBITDA and operating income increased $18.3 million and
$18.2 million, respectively, as a result of (1) the higher total margin; (2) a
$5.0 million increase in other income; and (3) a decrease in net operating
expenses. Other income in Fiscal 2000 includes, among other things, (1) income
from the refund of revenue-related tax overpayments made in prior years
(including associated interest); (2) interest income from PGC undercollections;
and (3) higher income from a construction project and other activities. Gas
Utility's net operating expenses declined $3.1 million, despite an increase in
distribution system maintenance expenses, principally reflecting (1) $4.5
million in income from insurance litigation settlements and (2) $0.9 million
from adjustments to incentive compensation accruals.
ELECTRIC UTILITY. Electric sales for Fiscal 2000 increased 0.8% on weather that
was slightly colder than in the prior year. Revenues increased as a result of
the higher sales as well as an increase in transmission revenues from wholesale
transmission services which have been unbundled as a result of electric customer
choice. Cost of sales increased to $33.9 million in Fiscal 2000 from $33.2
million in Fiscal 1999 reflecting the higher sales and higher costs associated
with wholesale transmission services.
Electric Utility total margin increased $1.9 million principally
reflecting the impact of lower average power costs and higher sales. EBITDA and
operating income also increased reflecting higher total margin and a $2.5
million increase in other income principally from the sale of pollution credits.
These increases were partially offset by higher utility realty taxes and greater
power production maintenance expenses.
ENERGY SERVICES. Revenues increased $56.5 million during Fiscal 2000 primarily
as a result of higher natural gas prices and to a lesser extent higher volumes
sold. Total margin, EBITDA and operating income in Fiscal 2000 were slightly
higher than in Fiscal 1999 due to the impact of the higher sales on total
margin.
INTERNATIONAL PROPANE. International Propane results include equity in our joint
venture projects in Romania and China and, in Fiscal 2000, the results of FLAGA.
The results of FLAGA during Fiscal 2000 were adversely affected by weather that
was 9.6% warmer than normal and by higher propane supply costs. The higher
propane supply costs resulted in lower than normal unit margins and
price-induced conservation. Equity income in Fiscal 2000 from our China propane
joint venture partnership was also negatively impacted by higher propane product
costs and customer conservation.
16
UGI Corporation 2001 Annual Report
CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate & Other operating income in
Fiscal 2000 was $5.1 million, a decrease of $0.8 million from Fiscal 1999,
primarily reflecting lower interest income on cash investments. Other
Enterprises' results in Fiscal 2000 primarily reflect start-up costs and initial
operating losses of Hearth USA(TM). Results in Fiscal 1999 include due diligence
expenses associated with Enterprises' domestic and international new business
activities and start-up expenses associated with Hearth USA(TM).
INTEREST EXPENSE AND INCOME TAXES. The higher interest expense in Fiscal 2000 is
a result of an increase in the Partnership's long-term debt, higher interest
under the Partnership's and UGI Utilities' bank credit agreements, and interest
on FLAGA debt in Fiscal 2000. The effective income tax rate was 46.4% in Fiscal
2000 compared to 43.0% in Fiscal 1999 which rate reflected a lower tax rate on
merger termination fee income.
FINANCIAL CONDITION AND LIQUIDITY
ACQUISITION OF COLUMBIA PROPANE
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the
propane distribution businesses of Columbia Energy Group ("Columbia Propane
Businesses") in a series of equity and asset purchases pursuant to the terms of
the Purchase Agreement dated January 30, 2001 and Amended and Restated August 7,
2001 ("Columbia Purchase Agreement") by and among Columbia Energy Group ("CEG"),
Columbia Propane Corporation ("Columbia Propane"), Columbia Propane, L.P.
("CPLP"), CP Holdings, Inc., AmeriGas Partners, AmeriGas OLP, and the General
Partner. The acquired businesses comprised the seventh largest retail marketer
of propane in the United States with annual sales of over 300 million gallons
from locations in 29 states. The acquired businesses were principally conducted
through Columbia Propane and its approximate 99% owned subsidiary, CPLP
(referred to after the acquisition as "Eagle OLP"). AmeriGas OLP acquired
substantially all of the assets of Columbia Propane, including an indirect 1%
general partner interest and an approximate 99% limited partnership interest in
Eagle OLP.
The purchase price of the Columbia Propane Businesses consisted of
$201.8 million in cash. In addition, AmeriGas OLP agreed to pay CEG for the
amount of working capital, as defined, in excess of $23 million. The Columbia
Purchase Agreement also provided for the purchase by CEG of limited partnership
interests in AmeriGas OLP valued at $50 million for $50 million in cash, which
interests were exchanged for 2,356,953 Common Units of AmeriGas Partners having
an estimated fair value of $54.4 million. Concurrently with the acquisition,
AmeriGas Partners issued $200 million of 8 7/8% Senior Notes due 2011, the net
proceeds of which were contributed to AmeriGas OLP to finance the acquisition of
the Columbia Propane Businesses, to fund related fees and expenses, and to repay
debt outstanding under AmeriGas OLP's Bank Credit Agreement.
The operating results of the Columbia Propane Businesses are included
in our consolidated results subsequent to August 21, 2001. For further
information on the acquisition of the Columbia Propane Businesses, see Note 2 to
Consolidated Financial Statements.
INVESTMENT IN ANTARGAZ
On March 27, 2001, UGI France, Inc. ("UGI France"), a wholly owned indirect
subsidiary of Enterprises, together with Paribas Affaires Industrielles ("PAI")
and Medit Mediterranea GPL, S.r.L. ("Medit"), acquired, through AGZ Holdings
("AGZ"), the stock and certain related assets of Elf Antargaz, S.A., one of the
largest distributors of liquefied petroleum gas in France (referred to after the
transaction and herein as "Antargaz"). Prior to the transaction, Antargaz was a
subsidiary of Total Fina Elf S.A., a French petroleum and chemical company.
Under the terms of the Shareholders' Funding Agreement among UGI, PAI and Medit,
the Company acquired an approximate 19.5% equity interest in Antargaz; PAI an
approximate 68.1% interest; Medit an approximate 9.7% interest; and certain
members of management of Antargaz an approximate 2.7% interest. PAI is a leading
private equity fund manager in Europe and an affiliate of BNP Paribas, one of
Europe's largest commercial and investment banks. Medit is a supplier of
logistics services to the liquefied petroleum gas industry in Europe, primarily
Italy.
Pursuant to the Shareholders' Funding Agreement, UGI France made a 29.8
million EURO ($26.6 million U.S. dollar equivalent) investment comprising a 9.8
million EURO investment in shares of AGZ and a 20.0 million EURO investment in
redeemable bonds of AGZ. The bonds are redeemable in the form of additional
shares of AGZ on December 31, 2013. Under certain circumstances, the bonds may
be redeemed earlier in the form of additional shares or in cash. Because we
believe we have significant influence over operating and financial policies of
Antargaz due, in part, to our membership on its Board of Directors, our
investment in AGZ shares is accounted for by the equity method. Our investment
in AGZ did not materially impact our Fiscal 2001 results of operations.
CAPITALIZATION AND LIQUIDITY
Our cash and short-term investments totaled $91.1 million at September 30, 2001
compared with $101.7 million at September 30, 2000. Included in these amounts
are $31.9 million and $56.3 million, respectively, of cash and short-term
investments held by UGI.
The primary sources of UGI's cash and short-term investments are the
cash dividends it receives from its principal operating subsidiaries, AmeriGas,
Inc. and UGI Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is
dependent upon the receipt of distributions on the Common and Subordinated units
of AmeriGas Partners that we own. During Fiscal 2001, 2000 and 1999, AmeriGas,
Inc. and UGI Utilities paid cash dividends to UGI as follows:
[Download Table]
Year Ended September 30, 2001 2000 1999
------------------------ ---- ---- ----
(Millions of dollars)
AmeriGas $ 41.0 $ 51.6 $ 47.6
UGI Utilities 35.3 44.0 29.0
------- ------- -------
Total dividends to UGI $ 76.3 $ 95.6 $ 76.6
------- ------- -------
17
FINANCIAL REVIEW (continued)
AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30, 2001
totaled $1,005.9 million. Included in this amount is $20 million of debt
outstanding under AmeriGas OLP's Acquisition Facility.
In October 2000, AmeriGas Partners issued 2,300,000 Common Units in a
public offering. The net proceeds from the Common Unit offering and related
capital contributions from the General Partner of $40.2 million were used to
reduce AmeriGas OLP Bank Credit Agreement indebtedness and for working capital
purposes. On October 5, 2001, subsequent to year end, AmeriGas Partners sold
350,000 Common Units to the General Partner. On December 11, 2001, AmeriGas
Partners sold 1,843,047 Common Units in an underwritten public offering. The
proceeds of these sales and related capital contributions from the General
Partner of approximately $45.3 million were contributed to AmeriGas OLP and used
to reduce Bank Credit Agreement borrowings and for working capital purposes. In
November 2001, AmeriGas Partners redeemed $15 million of its 10.125% Senior
Notes at a redemption price of 103.375%.
On April 4, 2001, AmeriGas Partners issued $60 million face value of
10% Senior Notes due April 2006. The proceeds of these notes were contributed to
AmeriGas OLP and used to (1) repay revolving loans under AmeriGas OLP's Bank
Credit Agreement and (2) fund a portion of AmeriGas OLP's scheduled April 2001
$58 million principal repayment of its First Mortgage Notes. In August 2001,
AmeriGas Partners issued $200 million of 8 7/8% Senior Notes due 2011 to finance
the acquisition of Columbia Propane and related fees and expenses, and to repay
debt outstanding under AmeriGas OLP's Bank Credit Agreement.
AmeriGas OLP's Bank Credit Agreement consists of (1) a $100 million
Revolving Credit Facility and (2) a $75 million Acquisition Facility. The
Revolving Credit Facility may be used for working capital and general purposes
of AmeriGas OLP. There were no borrowings outstanding under this facility at
September 30, 2001. AmeriGas OLP's borrowing needs are seasonal, and are
typically greatest during the fall and early winter months due to higher working
capital needs entering the winter heating season. AmeriGas OLP may borrow under
its Acquisition Facility to finance the purchase of propane businesses or
propane business assets. In addition, up to $30 million of the Acquisition
Facility may be used for working capital purposes. The Acquisition Facility
operates like a revolving facility. Loans outstanding under the Acquisition
Facility at September 30, 2001 were $20 million. The Acquisition Facility and
the Revolving Credit Facility expire September 15, 2002. The Partnership intends
to renew these facilities prior to their expiration.
AmeriGas OLP also has a credit agreement with the General Partner to
borrow up to $20 million on an unsecured, subordinated basis, for working
capital and general purposes. UGI has agreed to contribute up to $20 million to
the General Partner to fund such borrowings.
The Partnership must maintain certain financial ratios in order to
borrow under the Bank Credit Agreement including a minimum interest coverage
ratio and a maximum debt to EBITDA ratio. The Partnership's ratios calculated as
of September 30, 2001 permit it to borrow up to the maximum amount available.
For a more detailed discussion of the Partnership's credit facilities, see Note
5 to Consolidated Financial Statements.
The Partnership's management believes that cash flow from operations
and Bank Credit Agreement borrowings will be sufficient to satisfy its liquidity
needs in Fiscal 2002.
UGI UTILITIES. UGI Utilities debt outstanding totaled $266.2 million at
September 30, 2001. Included in this amount is $57.8 million under revolving
credit agreements.
UGI Utilities may borrow up to a total of $97 million under its
revolving credit agreements. The revolving credit agreements contain financial
covenants including interest coverage ratios, minimum working capital, and
minimum tangible net worth. In November 2001, UGI Utilities filed a shelf
registration statement with the U.S. Securities and Exchange Commission covering
a total of $123 million of debt securities. The registration statement was
declared effective on November 6, 2001.
Management believes that UGI Utilities' cash flow from operations and
borrowings under its bank credit agreements will satisfy UGI Utilities' cash
needs in Fiscal 2002. For a more detailed discussion of UGI Utilities' debt and
credit facilities, see Note 5 to Consolidated Financial Statements.
ENERGY SERVICES. On November 30, 2001, Energy Services entered into an accounts
receivable securitization facility with a major bank and its commercial paper
conduit. In conjunction with this facility, on December 4, 2001, Energy Services
initially received $6 million in cash in exchange for the sale and contribution
of $14.7 million of its trade accounts receivable to its wholly owned, special
purpose subsidiary, Energy Services Funding Corporation. Energy Services Funding
Corporation then sold, and will from time to time thereafter sell, an undivided
percentage ownership interest in its receivables to this bank's commercial paper
conduit. During the term of this facility Energy Services will sell or
contribute its receivables to Energy Services Funding Corporation. The level of
funding available under this three-year facility is limited to $50 million.
Energy Services intends to use the proceeds of this facility principally for
working capital purposes. Prior to the transaction, working capital was funded
primarily through an intercompany loan agreement with UGI. The securitization
transaction will be reflected in the Company's consolidated financial statements
as a sale of accounts receivable and an investment in an unconsolidated
subsidiary.
FLAGA. FLAGA has a 15 million EURO working capital loan commitment and a 15
million EURO special purpose facility from a foreign bank. Borrowings under the
working capital facility totaled 11 million EURO ($10 million U.S. dollar
equivalent) at September 30, 2001. Borrowings under the special purpose facility
totaled 11.8 million EURO ($10.7 million U.S. dollar equivalent) at September
30, 2001. Management believes that cash flow from operations, as well as
borrowings under these loan commitments, will satisfy FLAGA's cash needs in
Fiscal 2002. Debt issued under these agreements, as well as $62.7 million of
additional U.S. dollar equivalent debt of FLAGA, is subject to guarantees of
UGI. For a more detailed discussion, see Note 5 to Consolidated Financial
Statements.
18
UGI Corporation 2001 Annual Report
CASH FLOWS
OPERATING ACTIVITIES. Cash flow from operating activities was $203.5 million in
Fiscal 2001 compared to $132.7 million in Fiscal 2000 reflecting increased cash
flow from changes in working capital and the improved Fiscal 2001 results. In
Fiscal 2001, changes in operating working capital provided $23.7 million of
operating cash flow. In Fiscal 2000, changes in operating working capital
required $34.8 million primarily reflecting changes in inventories and accounts
receivable partially offset by changes in accounts payable. Cash flow before
changes in operating working capital increased to $179.8 million in Fiscal 2001
from $167.5 million in Fiscal 2000 reflecting the improved operating performance
partially offset principally by settlement payments associated with Energy
Services' exchange-traded natural gas futures contracts.
INVESTING ACTIVITIES. Cash spent for property, plant and equipment totaled $78.0
million in Fiscal 2001 compared with $71.0 million in Fiscal 2000. The increase
reflects greater Partnership capital expenditures including expenditures
relating to tank installation costs resulting from the Partnership's change in
accounting. During Fiscal 2001, the Company made a $26.6 million investment in
Antargaz and contributed $6.0 million to Energy Ventures in conjunction with its
formation. In Fiscal 2001, we spent $209.1 million in conjunction with
acquisitions, principally the Partnership's acquisition of Columbia Propane,
compared to $65.3 million in Fiscal 2000.
FINANCING ACTIVITIES. In Fiscal 2001 and 2000, we paid cash dividends on our
Common Stock of $53.2 million and $41.2 million, respectively, and the
Partnership paid the full minimum quarterly distribution of $0.55 ("MQD") to its
public unitholders (as well as on the Common and Subordinated units we own). The
increase in dividends paid on Common Stock in Fiscal 2001 reflects the one-time
impact of funding the quarterly dividend on the last day of the quarter rather
than on the first day of the quarter. During 2001, the Partnership received
$39.8 million in cash from the sale of 2,300,000 Common Units in October 2000
and $50.0 million from the sale of limited partner interests in AmeriGas OLP to
CEG. These interests were then exchanged for 2,356,953 AmeriGas Partners Common
Units in accordance with the Columbia Purchase Agreement. Concurrently with the
acquisition, AmeriGas Partners issued $200 million of 8 7/8% Senior Notes due
2011, the net proceeds of which were used to fund the acquisition of Columbia
Propane and related costs and expenses, and to repay debt under AmeriGas OLP's
Bank Credit Agreement. During Fiscal 2001, the Partnership and UGI Utilities
issued $60 million and $50 million face value of long-term debt, respectively,
and made long-term debt repayments of $110.8 million and $15 million,
respectively.
DIVIDENDS AND DISTRIBUTIONS
In April 2001, our board of directors increased the annual dividend rate on UGI
Common Stock to $1.60 a share from $1.55. Dividends declared on our Common Stock
in 2001 totaled $42.6 million.
At September 30, 2001, our approximate 53% effective ownership interest
in the Partnership consisted of (1) 14.3 million Common Units; (2) 9.9 million
Subordinated Units; and (3) a 2% general partner interest. The remaining
approximate 47% effective interest consists of 22.5 million publicly held Common
Units. Approximately 45 days after the end of each fiscal quarter, the
Partnership distributes all of its Available Cash (as defined in the Amended and
Restated Agreement of Limited Partnership of AmeriGas Partners, the "Partnership
Agreement") relating to such fiscal quarter. Common Unitholders receive the MQD,
plus any arrearages, before a distribution of Available Cash can be made on the
Subordinated Units.
Since its formation in 1995, the Partnership has paid the MQD on all
limited partner units outstanding. The amount of Available Cash needed annually
to pay the MQD on all units and the general partner interests in Fiscal 2001,
2000 and 1999 was approximately $99 million, $94 million and $94 million,
respectively. Based upon the number of Common and Subordinated units outstanding
on September 30, 2001 as adjusted for the 350,000 Common Units issued to the
General Partner on October 5, 2001 and the 1,843,047 Common Units sold to the
public on December 11, 2001, the amount of Available Cash needed annually to pay
the MQD on all units and the general partner interests is approximately $110
million. A reasonable proxy for the amount of cash available for distribution
that is generated by the Partnership can be calculated by subtracting from the
Partnership's EBITDA (1) cash interest expense and (2) capital expenditures
needed to maintain operating capacity. Partnership distributable cash flow as
calculated for Fiscal 2001, 2000 and 1999 is as follows:
[Download Table]
Year Ended September 30, 2001 2000 1999
------------------------ ---- ---- ----
(Millions of dollars)
EBITDA $ 208.6 $ 157.6 $ 157.5
Cash interest expense(a) (82.0) (76.7) (68.3)
Maintenance capital expenditures (17.8) (11.6) (11.1)
------- ------- -------
Distributable cash flow $ 108.8 $ 69.3 $ 78.1
------- ------- -------
(a) Interest expense adjusted for noncash items.
Although distributable cash flow is a reasonable estimate of the amount
of cash generated by the Partnership, it does not reflect the impact of changes
in working capital, which can significantly affect cash available for
distribution, and is not a measure of performance or financial condition under
accounting principles generally accepted in the United States but provides
additional information for evaluating the Partnership's ability to declare and
pay the MQD. Although the levels of distributable cash flow in Fiscal 2000 and
1999 were less than the full MQD, cash from borrowings in each of these years
was more than sufficient to permit the Partnership to pay the full MQD. The
ability of the Partnership to pay the MQD on all units depends upon a number of
factors. These factors include (1) the level of Partnership earnings; (2) the
cash needs of the Partnership's operations (including cash needed for
maintaining and increasing operating capacity); (3) changes in operating working
capital; and (4) the Partnership's ability to borrow under its Bank Credit
Agreement, to refinance maturing debt and to increase its long-term debt. Some
of these factors are affected by conditions beyond our control including
weather, competition in markets we serve, and the cost of propane.
19
FINANCIAL REVIEW (continued)
The Partnership's ability to attain the cash-based performance and
distribution requirements necessary to convert to Common Units the remaining
9,891,072 Subordinated Units held by the General Partner depends upon a number
of factors, including highly seasonal operating results, changes in working
capital, asset sales and debt refinancings. Due to the historical quarterly
requirements of the conversion test, the possibility is remote that the
Partnership will satisfy the cash-based performance requirements for conversion
any earlier than in respect of the quarter ending September 30, 2002.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures (which include
expenditures for capital leases but exclude acquisitions) by business segment
for Fiscal 2001, 2000 and 1999. We also provide amounts we expect to spend in
Fiscal 2002. We expect to finance Fiscal 2002 capital expenditures principally
from cash generated by operations and borrowings under our credit facilities.
[Download Table]
Year Ended September 30, 2002 2001 2000 1999
------------------------ ---- ---- ---- ----
(Millions of dollars) (estimate)
AmeriGas Propane $ 52.9 $ 39.2 $ 30.4 $ 34.6
UGI Utilities 42.2 36.8 36.4 36.4
International Propane 2.7 2.7 1.8 --
Other 1.6 0.6 2.4 2.7
--------- ------- ------- -------
Total $ 99.4 $ 79.3 $ 71.0 $ 73.7
--------- ------- ------- -------
CHANGES IN ACCOUNTING
Effective October 1, 2000 (1) the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivatives and Hedging
Activities" ("SFAS 133"); (2) the Partnership applied the guidance of SEC Staff
Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101") with
respect to its nonrefundable tank fees; and (3) the Partnership changed its
method of accounting for costs to install Partnership-owned tanks at customer
locations. The net effect of these accounting changes on prior periods resulted
in a $4.5 million after-tax cumulative effect increase in 2001 net income (equal
to $0.16 per diluted share) which is reflected on the 2001 Consolidated
Statement of Income as "Cumulative effect of accounting changes, net."
The adoption of SFAS 133 resulted in a cumulative effect decrease to
net income of $0.3 million and a cumulative effect increase to accumulated other
comprehensive income of $7.1 million. The increase to accumulated other
comprehensive income represents the fair value of derivative instruments
qualifying and designated as cash flow hedges on October 1, 2000.
The application of SAB 101 resulted in a cumulative effect decrease to
net income of $2.1 million representing the impact on prior periods resulting
from the change in the Partnership's method of recognizing revenue associated
with nonrefundable fees for installed Partnership-owned tanks. Prior to the
change in accounting method, such fees, which are generally billed annually,
were recorded as revenue when billed. The Partnership now records such
nonrefundable fees as revenue on a straight-line basis over one year.
In order to better match the costs of installing Partnership-owned
tanks at customer locations with their period of benefit, the Partnership
changed its method of accounting for tank installation costs. Previously, costs
to install Partnership-owned tanks were expensed as incurred. Under the new
method of accounting, such costs are capitalized and amortized over the
estimated period of benefit not exceeding ten years. The change in accounting
for tank installation costs resulted in a cumulative effect increase to net
income of $6.9 million representing the impact on prior periods resulting from
the accounting change. Although this change in accounting resulted in a $5.1
million increase in Partnership EBITDA because costs to install such tanks are
now capitalized and amortized, it did not have a material impact on operating
income in Fiscal 2001. For a detailed discussion of these changes in accounting,
see Note 3 to Consolidated Financial Statements.
UTILITY REGULATORY MATTERS
GAS RESTRUCTURING ORDER. On June 29, 2000, the Pennsylvania Public Utility
Commission ("PUC") issued its order ("Gas Restructuring Order") approving Gas
Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act (see Note 4 to Consolidated Financial
Statements). Among other things, the implementation of the Gas Restructuring
Order resulted in an increase in Gas Utility's core-market base rates effective
October 1, 2000. This base rate increase was designed to generate approximately
$16.7 million in additional net annual revenues. The Gas Restructuring Order
also provided that effective October 1, 2000, Gas Utility must reduce its PGC
rates by an annualized amount of $16.7 million for the first 14 months following
the base rate increase.
Beginning December 1, 2001, Gas Utility is required to reduce its PGC
rates by an amount equal to the margin it receives from customers served under
interruptible rates to the extent they use capacity contracted by Gas Utility
for core-market customers. As a result, Gas Utility expects that beginning in
Fiscal 2002 operating results will be less sensitive to the market prices of
alternative fuels and more sensitive to the effects of heating-season weather.
TRANSFERS OF ASSETS. On September 30, 2001, pursuant to PUC authorization, Gas
Utility transferred certain of its liquefied natural gas ("LNG") and propane air
facilities to Energy Services. The reduction in Gas Utility's base rates
resulting from the transfer, adjusted for the transfer's impact on net operating
expenses, is not expected to have a material effect on Gas Utility's future
results.
On December 8, 2000, UGI Utilities' wholly owned subsidiary, UGI
Development Company, contributed its coal-fired Hunlock Creek generating station
("Hunlock") and certain related assets having a net book value of approximately
$4.2 million, and $6 million in cash, to Hunlock Creek Energy Ventures ("Energy
Ventures"), a general partnership jointly owned by the Company and a subsidiary
of Allegheny Energy, Inc. ("Allegheny"). Also on December 8, 2000, Allegheny
contributed a newly constructed, gas-fired combustion turbine generator to be
operated at the Hunlock site. Under the terms of our arrangement with Allegheny,
each partner is entitled to
20
UGI Corporation 2001 Annual Report
purchase 50% of the output of the joint venture at cost. Prior to the formation
of Energy Ventures, Hunlock produced a significant portion of Electric Utility's
electricity requirements. The contribution of Hunlock to Energy Ventures results
in lower Electric Utility power production and depreciation expenses but higher
cost of sales because Electric Utility must purchase a greater percentage of its
electricity needs from others, including Energy Ventures.
MANUFACTURED GAS PLANTS
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities does not expect its costs for investigation and
remediation of hazardous substances at Pennsylvania MGP sites to be material to
its results of operations because Gas Utility is currently permitted to include
in rates, through future base rate proceedings, prudently incurred remediation
costs associated with such sites. UGI Utilities has been notified of several
sites outside Pennsylvania on which (1) MGPs were formerly operated by it or
owned or operated by its former subsidiaries and (2) either environmental
agencies or private parties are investigating the extent of environmental
contamination or performing environmental remediation. UGI Utilities is
currently litigating two claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not
be liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by manufactured gas plants outside Pennsylvania
that UGI Utilities directly operated, or that were owned or operated by former
subsidiaries of UGI Utilities if a court were to conclude that the subsidiary's
separate corporate form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance
companies alleging that the defendants breached contracts of insurance by
failing to indemnify UGI Utilities for certain environmental costs. The suit
seeks to recover more than $11 million in such costs. During 2001 and 2000, UGI
Utilities entered into settlement agreements with several of the insurers and
recorded pre-tax income of $0.9 million and $4.5 million, respectively, which
amounts are included in operating and administrative expenses in the
Consolidated Statements of Income.
MARKET RISK DISCLOSURES
Our primary market risk exposures are (1) market prices for propane, natural gas
and electricity; (2) changes in interest rates; and (3) foreign currency
exchange rates.
Price risk associated with fluctuations in the prices the Partnership
and FLAGA pay for propane, and Energy Services pays for natural gas, are
principally a result of market forces reflecting changes in supply and demand.
The Partnership's profitability is sensitive to changes in propane supply costs,
and the Partnership generally attempts to pass on increases in such costs to
customers. The Partnership may not, however, always be able to pass through
product cost increases fully, particularly when product costs rise rapidly. In
order to manage a portion of the Partnership's propane market price risk, it
uses contracts for the forward purchase or sale of propane, propane fixed-price
supply agreements, and over-the-counter derivative commodity instruments
including price swap and option contracts. FLAGA's profitability is also
sensitive to changes in propane supply costs. FLAGA on occasion also uses
derivative commodity instruments to reduce market risk associated with purchases
of propane. In order to manage market price risk relating to substantially all
of Energy Services' forecasted sales of natural gas, we purchase exchange-traded
natural gas futures contracts. In addition, in the past we have, on occasion,
utilized a managed program of derivative instruments, including natural gas and
oil futures contracts, to preserve gross margin associated with certain of our
natural gas customers. 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.
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 settlement in
margin accounts with brokers. Over-the-counter derivative commodity instruments
utilized by the Partnership and FLAGA to hedge forecasted purchases of propane
are generally settled at expiration of the contract. In order to minimize credit
risk associated with these contracts, we carefully monitor established credit
limits with the contract counterparties.
Although Gas Utility is also subject to changes in the price of natural
gas, the current regulatory framework allows Gas Utility to recover prudently
incurred gas costs from its customers. Because of this ratemaking mechanism,
there is limited commodity price risk associated with our Gas Utility
operations.
Electric Utility's electricity distribution business purchases most of
its electric power needs under power supply arrangements of various lengths and
on the spot market. Prices for electricity can be volatile especially during
periods of high demand or tight supply. Because the generation component of
Electric Utility's rates are subject to rate caps as a result of the Electricity
Restructuring Order that are expected to extend through September 2002 in the
case of its commercial and industrial customers and May 2003 in the case of its
residential customers, any increase in the cost of electricity purchased by
Electric Utility will
21
FINANCIAL REVIEW (continued)
negatively impact Electric Utility's results. Electric Utility has mitigated
this electricity cost exposure by entering into power and capacity contracts for
a substantial portion of these periods.
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 Bank
Credit Agreement, borrowings under UGI Utilities' revolving credit agreements,
and most of FLAGA's debt. These debt agreements have interest rates that are
generally indexed to short-term market interest rates. At September 30, 2001 and
2000, combined borrowings outstanding under these agreements totaled $162.3
million and $282.1 million, respectively. Based upon weighted average borrowings
outstanding under these agreements during Fiscal 2001 and Fiscal 2000, an
increase in short-term interest rates of 100 basis points (1%) would have
increased our interest expense by $2.4 million and $2.5 million, respectively.
The remainder of our debt outstanding is subject to fixed rates of
interest. A 100 basis point increase in market interest rates would result in
decreases in the fair value of this fixed-rate debt of $57.9 million and $42.2
million at September 30, 2001 and 2000, respectively. A 100 basis point decrease
in market interest rates would result in increases in the fair value of this
fixed-rate debt of $58.8 million and $45.4 million at September 30, 2001 and
2000, 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 forecasted issuances of fixed-rate debt, we
generally enter into interest rate protection agreements.
The primary currency for which the Company has exchange rate risk is
the U.S. dollar versus the EURO. We do not currently use derivative instruments
to hedge foreign currency exposure associated with our international propane
operations and investments, principally FLAGA and Antargaz. As a result, the
U.S. dollar value of our foreign denominated assets and liabilities will
fluctuate with changes in the associated foreign currency exchange rates,
principally the EURO. With respect to FLAGA, our exposure to changes in foreign
currency exchange rates has been significantly limited because the purchase of
FLAGA was financed with EURO denominated debt, and FLAGA's U.S. dollar
denominated financial instrument assets and liabilities are substantially equal
in amount. With respect to our debt and equity investments in Antargaz, a 10%
decline in the value of the EURO would reduce the book value of these
investments by approximately $2.5 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, 2001 and 2000. It also
includes the changes in fair value that would result if there were an adverse
change in (1) the market price of propane of 10 cents a gallon; (2) the market
price of natural gas of 50 cents a dekatherm; and (3) interest rates on ten-year
U.S. treasury notes of 100 basis points.
[Download Table]
Change in
Fair Value Fair Value
---------- ----------
(Millions of dollars)
September 30, 2001:
Propane commodity price risk $ (10.5) $ (19.3)
Natural gas commodity price risk (1.5) (2.2)
Interest rate risk (3.0) (2.1)
September 30, 2000:
Propane commodity price risk $ 6.5 $ (10.5)
Natural gas commodity price risk 4.2 (3.5)
Interest rate risk 2.5 (3.9)
--------- ---------
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 underlying
transactions.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 141,
"Business Combinations" ("SFAS 141"); SFAS No. 142, "Goodwill and Other
Intangible Assets" ("SFAS 142"); SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"); and SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144").
SFAS 141 addresses financial accounting and reporting for business
combinations. Under SFAS 141, all business combinations initiated after June 30,
2001 are required to be accounted for using the purchase method of accounting.
Among other provisions, SFAS 141 establishes specific criteria for the
recognition of intangible assets separate from goodwill acquired in a purchase
business combination. Although SFAS 141 supersedes Accounting Principles Board
("APB") Opinion No. 16, "Business Combinations," and SFAS No. 38, "Accounting
for Preacquisition Contingencies of Purchased Enterprises," it does not change
many of their provisions relating to the application of the purchase method. The
Company has historically accounted for business combinations using the purchase
method and, therefore, SFAS No. 141 is not expected to have a material impact on
the Company.
SFAS 142 addresses the financial accounting and reporting for acquired
goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." SFAS 142 addresses the financial accounting and reporting
for intangible assets acquired individually or with a group of other assets
(excluding those acquired in a business combination) at acquisition and also
addresses the financial accounting and reporting for goodwill and other
intangible assets subsequent to their acquisition. Under SFAS 142, an intangible
asset will be amortized over its useful life unless that life is determined to
be indefinite. Goodwill and other intangible assets with indefinite lives will
be tested for impairment at least annually.
22
UGI Corporation 2001 Annual Report
The Company adopted SFAS 142 effective October 1, 2001. Although there is no
effect on the Company's cash flows, the Company's amortization expense in Fiscal
2001 would have been approximately $25.2 million lower, and its net income
approximately $14.0 million higher (after adjusting for the minority interests
in AmeriGas Partners), if SFAS 142 had been effective October 1, 2000.
SFAS 142 requires the Company to test goodwill for impairment within six
months of adoption. Based upon the fair value of AmeriGas Partners, we do not
believe the Partnership's goodwill is impaired. We have not yet completed the
evaluation of the impact, if any, of the goodwill impairment provisions of SFAS
142 on our other reporting units.
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using a
systematic and rational method over the related asset's useful life and adjust
the fair value of the liability resulting from the passage of time through
charges to interest expense. The Company is required to adopt SFAS 143 effective
October 1, 2002. The Company is currently in the process of evaluating the
impact SFAS 143 will have on its financial condition and results of operations.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions," as
it relates to the disposal of a segment of a business. SFAS 144 establishes a
single accounting model for long-lived assets to be disposed of based upon the
framework of SFAS 121, and resolves significant implementation issues of SFAS
121. SFAS 144 is effective for the Company October 1, 2002. The Company believes
that the adoption of SFAS 144 will not have a material impact on its financial
position or results of operations.
FORWARD-LOOKING STATEMENTS
Information contained in this Financial Review and elsewhere in this Annual
Report may contain forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Such statements use forward-looking words such as "believe," "plan,"
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss plans, strategies, events or developments that
we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or
bases underlying the forward-looking statement. We believe that we have chosen
these assumptions or bases in good faith and that they are reasonable. However,
we caution you that actual results almost always vary from assumed facts or
bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking
statements, you should keep in mind the following important factors which could
affect our future results and could cause those results to differ materially
from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) price volatility and availability of
propane, oil, electricity, and natural gas and the capacity to transport to
market areas; (3) changes in laws and regulations, including safety, tax and
accounting matters; (4) competitive pressures from the same and alternative
energy sources; (5) liability for environmental claims; (6) customer
conservation measures and improvements in energy efficiency and technology
resulting in reduced demand; (7) adverse labor relations; (8) large customer
defaults; (9) liability for personal injury and property damage arising from
explosions and other catastrophic events resulting from operating hazards and
risks incidental to generating and distributing electricity and transporting,
storing and distributing natural gas and propane including liability in excess
of insurance coverage; (10) political, regulatory and economic conditions in the
United States and in foreign countries; (11) interest rate fluctuations and
other capital market conditions, including foreign currency rate fluctuations;
(12) reduced distributions from subsidiaries; and (13) 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.
23
UGI Corporation 2001 Annual Report
REPORT OF MANAGEMENT
The Company's consolidated financial statements and other financial information
contained in this Annual Report are prepared by management, which is responsible
for their fairness, integrity and objectivity. The consolidated financial
statements and related information were prepared in accordance with accounting
principles generally accepted in the United States and include amounts that are
based on management's best judgments and estimates.
The Company maintains a system of internal controls. Management believes the
system provides reasonable assurance that assets are safeguarded and that
transactions are executed in accordance with management's authorization and are
properly recorded to permit the preparation of reliable financial information.
There are limits in all systems of internal control, based on the recognition
that the cost of the system should not exceed the benefits to be derived. We
believe that the Company's internal control system is cost effective and
provides reasonable assurance that material errors or irregularities will be
prevented or detected within a timely period. The internal control system and
compliance therewith are monitored by the Company's internal audit staff.
The Audit Committee of the Board of Directors is composed of three members,
none of whom is an employee of the Company. This Committee is responsible for
overseeing the financial reporting process and the adequacy of controls, and for
monitoring the independence of the Company's independent public accountants and
the performance of the independent accountants and internal audit staff. The
Committee recommends to the Board of Directors the engagement of the independent
public accountants to conduct the annual audit of the Company's consolidated
financial statements. The Committee is also responsible for maintaining direct
channels of communication between the Board of Directors and both the
independent public accountants and internal auditors.
The independent public accountants, who are appointed by the Board of
Directors and ratified by the shareholders, perform certain procedures,
including an evaluation of internal controls to the extent required by auditing
standards generally accepted in the United States, in order to express an
opinion on the consolidated financial statements and to obtain reasonable
assurance that such financial statements are free of material misstatement.
/s/ Lon R. Greenberg
-----------------------------
Lon R. Greenberg
Chief Executive Officer
/s/ Anthony J. Mendicino
-----------------------------
Anthony J. Mendicino
Chief Financial Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION:
We have audited the accompanying consolidated balance sheets of UGI Corporation
and subsidiaries as of September 30, 2001 and 2000, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended September 30, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
UGI Corporation and subsidiaries as of September 30, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Notes 1 and 3 to the financial statements, effective October
1, 2000, the Partnership changed its methods of accounting for tank installation
costs and nonrefundable tank fees and the Company adopted the provisions of SFAS
No. 133.
/s/ Arthur Andersen LLP
--------------------------------
Philadelphia, Pennsylvania
November 16, 2001
24
UGI Corporation 2001 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
[Enlarge/Download Table]
Year Ended September 30,
------------------------------------------
2001 2000 1999
------------------------------------------
REVENUES
AmeriGas Propane $ 1,418.4 $ 1,120.1 $ 872.5
UGI Utilities 584.7 436.9 420.6
International Propane 50.9 50.5 --
Energy Services and other 414.1 154.2 90.5
---------- ---------- ----------
2,468.1 1,761.7 1,383.6
---------- ---------- ----------
COSTS AND EXPENSES
AmeriGas Propane cost of sales 836.0 628.3 390.8
UGI Utilities - gas, fuel and purchased power 374.8 218.1 205.2
International Propane cost of sales 28.4 29.7 --
Energy Services and other cost of sales 382.2 145.5 84.4
Operating and administrative expenses 517.8 461.2 429.2
Utility taxes other than income taxes 9.2 17.1 25.2
Depreciation and amortization 105.2 97.5 89.7
Provision for exit costs - Hearth USA(TM) 8.5 -- --
Other income, net (21.4) (26.9) (16.8)
---------- ---------- ----------
2,240.7 1,570.5 1,207.7
---------- ---------- ----------
OPERATING INCOME 227.4 191.2 175.9
Merger fee income and expenses, net -- -- 19.9
Interest expense (104.8) (98.5) (84.6)
Minority interests in AmeriGas Partners (23.6) (6.3) (10.7)
---------- ---------- ----------
INCOME BEFORE INCOME TAXES, SUBSIDIARY PREFERRED STOCK DIVIDENDS
AND ACCOUNTING CHANGES 99.0 86.4 100.5
Income taxes (45.4) (40.1) (43.2)
Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (1.6)
---------- ---------- ----------
Income before accounting changes 52.0 44.7 55.7
Cumulative effect of accounting changes, net 4.5 -- --
---------- ---------- ----------
NET INCOME $ 56.5 $ 44.7 $ 55.7
========== ========== ==========
EARNINGS PER COMMON SHARE
Basic:
Income before accounting changes $ 1.91 $ 1.64 $ 1.74
Cumulative effect of accounting changes, net 0.17 -- --
---------- ---------- ----------
Net income $ 2.08 $ 1.64 $ 1.74
========== ========== ==========
Diluted:
Income before accounting changes $ 1.90 $ 1.64 $ 1.74
Cumulative effect of accounting changes, net 0.16 -- --
---------- ---------- ----------
Net income $ 2.06 $ 1.64 $ 1.74
========== ========== ==========
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS)
Basic 27.163 27.219 31.954
========== ========== ==========
Diluted 27.373 27.255 32.016
========== ========== ==========
See accompanying notes to consolidated financial statements.
25
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
[Enlarge/Download Table]
September 30,
-----------------------
ASSETS 2001 2000
-----------------------
CURRENT ASSETS
Cash and cash equivalents $ 87.5 $ 93.9
Short-term investments, at cost which approximates market value 3.6 7.8
Accounts receivable (less allowances for doubtful accounts of $15.6 and $9.3,
respectively) 180.8 165.7
Accrued utility revenues 11.1 10.5
Inventories 128.6 117.4
Deferred income taxes 25.2 8.8
Utility regulatory assets -- 7.2
Prepaid expenses and other current assets 22.1 19.0
-------- --------
Total current assets 458.9 430.3
-------- --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 984.0 722.1
UGI Utilities 855.2 857.8
Other 74.3 72.2
-------- --------
1,913.5 1,652.1
Accumulated depreciation and amortization (645.5) (578.9)
-------- --------
Net property, plant and equipment 1,268.0 1,073.2
-------- --------
OTHER ASSETS
Intangible assets (less accumulated amortization of $217.9 and $190.2,
respectively) 672.4 675.5
Utility regulatory assets 56.2 55.1
Investments and other assets 94.7 41.7
-------- --------
Total assets $2,550.2 $2,275.8
======== ========
See accompanying notes to consolidated financial statements.
26
UGI Corporation 2001 Annual Report
[Enlarge/Download Table]
September 30,
------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2001 2000
------------------------
CURRENT LIABILITIES
Current maturities of long-term debt $ 98.3 $ 85.9
AmeriGas Propane bank loans -- 30.0
UGI Utilities bank loans 57.8 100.4
Other bank loans 10.0 4.3
Accounts payable 167.0 156.7
Employee compensation and benefits accrued 39.4 26.5
Dividends and interest accrued 38.4 47.3
Income taxes accrued 11.6 10.3
Deposits and refunds 55.6 39.0
Other current liabilities 89.4 39.0
-------- --------
Total current liabilities 567.5 539.4
-------- --------
DEBT AND OTHER LIABILITIES
Long-term debt 1,196.9 1,029.7
Deferred income taxes 182.4 169.9
Deferred investment tax credits 8.8 9.2
Other noncurrent liabilities 72.8 83.3
Commitments and contingencies (note 13)
MINORITY INTERESTS
Minority interests in AmeriGas Partners 246.2 177.1
PREFERRED AND PREFERENCE STOCK
UGI Utilities Series Preferred Stock Subject to Mandatory
Redemption, without par value 20.0 20.0
Preference Stock, without par value (authorized - 5,000,000 shares) -- --
COMMON STOCKHOLDERS' EQUITY
Common Stock, without par value
(authorized - 100,000,000 shares; issued - 33,198,731 shares) 395.0 394.5
Retained earnings (accumulated deficit) 9.0 (4.9)
Accumulated other comprehensive loss (13.5) --
Unearned compensation - restricted stock -- (0.7)
-------- --------
390.5 388.9
Treasury stock, at cost (134.9) (141.7)
-------- --------
Total common stockholders' equity 255.6 247.2
-------- --------
Total liabilities and stockholders' equity $2,550.2 $2,275.8
======== ========
27
UGI Corporation 2001 Annual Report
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
[Enlarge/Download Table]
Year Ended September 30,
-------------------------------
2001 2000 1999
-------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 56.5 $ 44.7 $ 55.7
Reconcile to net cash provided by operating activities:
Depreciation and amortization 105.2 97.5 89.7
Cumulative effect of accounting changes, net (4.5) -- --
Minority interests in AmeriGas Partners 23.6 6.3 10.7
Deferred income taxes, net (5.5) 3.2 7.7
Hearth USA(TM) shut-down costs 8.5 -- --
Other, net (4.0) 15.8 6.5
------ ------ ------
179.8 167.5 170.3
Net change in:
Accounts receivable and accrued utility revenues (13.6) (63.4) (25.1)
Inventories and prepaid propane purchases (4.2) (26.1) (5.0)
Deferred fuel costs 9.9 (3.8) (5.1)
Accounts payable 5.8 52.0 17.4
Other current assets and liabilities 25.8 6.5 (10.6)
------ ------ ------
Net cash provided by operating activities 203.5 132.7 141.9
------ ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (78.0) (71.0) (70.2)
Acquisitions of businesses, net of cash acquired (209.1) (65.3) (77.6)
Short-term investments decrease 4.2 7.3 66.7
Net proceeds from disposals of assets 4.2 8.4 4.9
Investments in joint venture entities (32.6) -- (4.9)
Other, net (2.0) (0.9) (5.4)
------ ------ ------
Net cash used by investing activities (313.3) (121.5) (86.5)
------ ------ ------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock (53.2) (41.2) (47.9)
Distributions on Partnership public Common Units (44.3) (39.1) (39.0)
Issuance of long-term debt 308.2 209.7 173.7
Repayment of long-term debt (137.0) (95.4) (70.9)
AmeriGas Propane bank loans increase (decrease) (30.0) 8.0 12.0
UGI Utilities bank loans increase (decrease) (42.6) 13.0 19.0
Other bank loans increase (decrease) 6.2 (6.8) --
Issuance of AmeriGas Partners Common Units 39.8 -- --
Proceeds from sale of AmeriGas OLP interest 50.0 -- --
Issuance of UGI Common Stock 7.6 3.8 4.7
Repurchases of UGI Common Stock (1.0) (9.6) (133.1)
------ ------ ------
Net cash provided (used) by financing activities 103.7 42.4 (81.5)
------ ------ ------
EFFECT OF EXCHANGE RATE CHANGES ON CASH (0.3) (0.2) --
------ ------ ------
Cash and cash equivalents increase (decrease) $ (6.4) $ 53.4 $(26.1)
====== ====== ======
CASH AND CASH EQUIVALENTS:
End of year $ 87.5 $ 93.9 $ 40.5
Beginning of year 93.9 40.5 66.6
------ ------ ------
Increase (decrease) $ (6.4) $ 53.4 $(26.1)
====== ====== ======
See accompanying notes to consolidated financial statements.
28
UGI Corporation 2001 Annual Report
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Millions of dollars, except per share amounts)
[Enlarge/Download Table]
Retained Accumulated Unearned
Earnings Other Compensation-
Common (Accumulated Comprehensive Restricted Treasury
Stock Deficit) Income Stock Stock Total
------ ------------ ------------- ------------ -------- ------
BALANCE SEPTEMBER 30, 1998 $394.3 $(17.7) $ -- $ -- $ (9.5) $367.1
Net income 55.7 55.7
Net unrealized gains on available for sale
securities (net of tax of $.03) 0.5 0.5
------ ------ -------
Comprehensive income 55.7 0.5 56.2
Cash dividends on Common Stock
($1.47 per share) (45.8) (45.8)
Common Stock issued:
Employee and director plans 0.4 (0.1) 3.4 3.7
Dividend reinvestment plan 0.1 (0.3) 3.0 2.8
Common Stock repurchased (133.1) (133.1)
Issuance of restricted stock awards (2.1) (2.1)
Amortization of unearned compensation-
restricted stock awards 0.4 0.4
------ ----- ------ ---- ------- ------
BALANCE SEPTEMBER 30, 1999 394.8 (8.2) 0.5 (1.7) (136.2) 249.2
Net income 44.7 44.7
Reclassification of unrealized gains
on available for sale securities
(net of tax of $.03) (0.5) (0.5)
----- ----- ------
Comprehensive income 44.7 (0.5) 44.2
Cash dividends on Common Stock
($1.525 per share) (41.4) (41.4)
Common Stock issued:
Employee and director plans (0.1) 1.5 1.4
Dividend reinvestment plan (0.2) 2.6 2.4
Common Stock repurchased (9.6) (9.6)
Amortization of unearned compensation-
restricted stock awards 1.0 1.0
------ ----- ------ ---- ------- ------
BALANCE SEPTEMBER 30, 2000 394.5 (4.9) -- (0.7) (141.7) 247.2
Net income 56.5 56.5
Cumulative effect of change in accounting
principle - SFAS No. 133 (net of tax of $4.8) 7.1 7.1
Net loss on derivative instruments
(net of tax of $7.9) (10.5) (10.5)
Reclassification of net gains on
derivative instruments (net of tax of $6.5) (10.3) (10.3)
Foreign currency translation adjustments
(net of tax of $0.1) 0.2 0.2
----- ------ ------
Comprehensive income 56.5 (13.5) 43.0
Cash dividends on Common Stock
($1.575 per share) (42.6) (42.6)
Common Stock issued:
Employee and director plans 0.3 5.5 5.8
Dividend reinvestment plan 0.2 2.3 2.5
Common Stock repurchased (1.0) (1.0)
Amortization of unearned compensation-
restricted stock awards 0.7 0.7
------ ----- ------ ---- ------- ------
BALANCE SEPTEMBER 30, 2001 $395.0 $ 9.0 $(13.5) $ -- $(134.9) $255.6
====== ===== ======= ==== ======== ======
See accompanying notes to consolidated financial statements.
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. UGI Corporation ("UGI") is a holding company that owns and
operates natural gas and electric utility, propane distribution, energy
marketing and related businesses in the United States. Through foreign
subsidiaries and joint-venture affiliates, UGI also distributes propane in
Austria, the Czech Republic, Slovakia, France and China.
Our utility business is conducted through our wholly owned subsidiary, UGI
Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates a natural gas
distribution utility ("Gas Utility") in parts of eastern and southeastern
Pennsylvania and an electricity distribution and electricity generation business
(collectively referred to as "Electric Utility") in northeastern Pennsylvania.
We refer to Gas Utility and Electric Utility together as "Utilities."
We conduct a national propane distribution business through AmeriGas Partners,
L.P. ("AmeriGas Partners") and its principal operating subsidiaries AmeriGas
Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle OLP").
AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships.
UGI's wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the "General
Partner") serves as the general partner of AmeriGas Partners and AmeriGas OLP.
AmeriGas OLP and Eagle OLP (collectively referred to as "the Operating
Partnerships") comprise the largest retail propane distribution business in the
United States serving residential, commercial, industrial, motor fuel and
agricultural customers from locations in 46 states. We refer to AmeriGas
Partners and its subsidiaries together as "the Partnership" and the General
Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane."
At September 30, 2001, the General Partner and its wholly owned subsidiary
Petrolane Incorporated ("Petrolane," a predecessor company of AmeriGas OLP)
collectively held a 1% general partner interest and a 51.3% limited partner
interest in AmeriGas Partners, and effective 52.8% and 52.7% ownership interests
in AmeriGas OLP and Eagle OLP, respectively. Our limited partnership interest in
AmeriGas Partners comprises 14,283,932 Common Units and 9,891,072 Subordinated
Units. The remaining 47.7% interest in AmeriGas Partners comprises 22,477,307
publicly held Common Units representing limited partner interests. On October 5,
2001, subsequent to year end, AmeriGas Partners sold 350,000 Common Units to the
General Partner. On December 11, 2001, AmeriGas Partners sold an additional
1,843,047 Common Units in an underwritten public offering. After these
transactions, we held effective 51.2% and 51.1% ownership interests in AmeriGas
OLP and Eagle OLP, respectively.
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 for direct and indirect
expenses incurred 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 (1) the
Partnership's significant minority interest; (2) higher relative interest
charges; and (3) a higher effective income tax rate associated with the
Partnership's pre-tax income.
Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") conducts an
energy marketing business primarily in the Middle Atlantic region of the United
States through its wholly owned subsidiary, UGI Energy Services, Inc. ("Energy
Services"). Through other subsidiaries, Enterprises (1) owns and operates a
propane distribution business in Austria, the Czech Republic and Slovakia
("FLAGA"); (2) owns and operates a heating, ventilation and air-conditioning
service business in the Middle Atlantic states ("HVAC"); and (3) participates in
propane joint-venture businesses in France and China.
UGI is exempt from registration as a holding company and is not otherwise
subject to regulation under the Public Utility Holding Company Act of 1935
except for acquisitions under Section 9(a)(2). UGI is not subject to regulation
by the Pennsylvania Public Utility Commission ("PUC").
CONSOLIDATION PRINCIPLES. The consolidated financial statements include the
accounts of UGI and its majority-owned subsidiaries. We eliminate all
significant intercompany accounts and transactions when we consolidate. We
report the public's limited partner interests in the Partnership as minority
interests. Investments in entities in which we own 50 percent or less and in
which we exercise significant influence over operating and financial policies
are accounted for by the equity method.
RECLASSIFICATIONS. We have reclassified certain prior-period balances to
conform with the current period presentation.
USE OF ESTIMATES. We make estimates and assumptions when preparing financial
statements in conformity with accounting principles generally accepted in the
United States. These estimates and assumptions affect the reported amounts of
assets and liabilities, revenues and expenses, as well as the disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates.
REGULATED UTILITY OPERATIONS. Gas Utility and Electric Utility's electricity
distribution business are subject to regulation by the PUC. We account for all
of our regulated Gas Utility and Electric Utility operations in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the
Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us to
record the effects of rate regulation in the financial statements. If a
separable portion of Gas Utility or Electric Utility no longer meets the
provisions of SFAS 71, we are required to eliminate the financial statement
effects of regulation for that portion of our operations.
On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in
Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
provisions of the Gas Restructuring Order and the Gas Competition Act, we
believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS
71. For further information on the impact of the Gas Competition Act and
Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see
Note 4.
30
UGI Corporation 2001 Annual Report
DERIVATIVE INSTRUMENTS. Effective October 1, 2000, we adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. It requires that all
derivative instruments be recognized as either assets or liabilities and
measured at fair value. The accounting for changes in fair value depends upon
the purpose of the derivative instrument and whether it is designated and
qualifies for hedge accounting. To the extent a derivative instrument qualifies
and is designated as a hedge of the variability of cash flows associated with a
forecasted transaction ("cash flow hedge"), the effective portion of the gain or
loss on such derivative instrument is generally reported in other comprehensive
income and the ineffective portion, if any, is reported in net income. Such
amounts reported in other comprehensive income are reclassified into net income
when the forecasted transaction affects earnings. If a cash flow hedge is
discontinued because it is probable that the forecasted transaction will not
occur, the net gain or loss is immediately reclassified into net income. To the
extent derivative instruments qualify and are designated as hedges of changes in
the fair value of an existing asset, liability or firm commitment ("fair value
hedge"), the gain or loss on the hedging instrument is recognized in earnings
along with changes in the fair value of the hedged asset, liability or firm
commitment attributable to the hedged risk.
The adoption of SFAS 133 resulted in an after-tax cumulative effect charge
to net income of $0.3 million and an after-tax cumulative effect increase to
accumulated other comprehensive income of $7.1 million. The increase in
accumulated other comprehensive income is attributable to net gains on
derivative instruments designated and qualifying as cash flow hedges on
October 1, 2000.
Prior to the adoption of SFAS 133, gains or losses on derivative
instruments associated with forecasted transactions generally were recorded in
net income when the forecasted transactions affected earnings. If it became
probable that the original forecasted transactions would not occur, we
immediately recognized in net income any gains or losses on the derivative
instruments.
For a detailed description of the derivative instruments we use, our
objectives for using them, and related supplemental information required by SFAS
133, see Note 14.
CONSOLIDATED STATEMENTS OF CASH FLOWS. We define cash equivalents as all highly
liquid investments with maturities of three months or less when purchased. We
record cash equivalents at cost plus accrued interest, which approximates market
value. We paid interest totaling $103.9 million in 2001, $96.9 million in 2000,
and $84.6 million in 1999. We paid income taxes totaling $43.0 million in 2001,
$26.6 million in 2000, and $36.2 million in 1999.
REVENUE RECOGNITION. We recognize revenues from the sale of propane and related
equipment and supplies principally when shipped or delivered to customers. 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 Utilities' rate increases or decreases in revenues
from effective dates permitted by the PUC. Energy Services records revenues when
product is delivered to customers.
Effective October 1, 2000, the Partnership applied the provisions of the
Securities and Exchange Commission Staff Accounting Bulletin No. 101 entitled
"Revenue Recognition" ("SAB 101") with respect to its annually billed
nonrefundable tank fees. Under the new accounting method, revenues from such
fees are recorded on a straight-line basis over one year. Prior to the change in
accounting, such revenues were recorded when billed. For a more detailed
description of this change in accounting and its impact on our results, see
Note 3.
INVENTORIES AND PREPAID PROPANE PURCHASES. Our inventories are stated at the
lower of cost or market. We determine cost principally on an average or
first-in, first-out ("FIFO") method except for appliances for which we use the
specific identification method.
From time to time the Partnership enters into contracts with certain
suppliers requiring it to prepay all or a portion of the purchase price of a
fixed volume of propane for future delivery. These prepayments are included in
prepaid expenses and other current assets in the Consolidated Balance Sheets.
EARNINGS PER COMMON SHARE. Basic earnings per share are based on the
weighted-average number of common shares outstanding. Diluted earnings per share
include the effects of dilutive stock options and awards. In the following
table, we present the shares used in computing basic and diluted earnings per
share for 2001, 2000 and 1999:
[Download Table]
2001 2000 1999
-----------------------------
Denominator (millions of shares):
Average common shares
outstanding for basic computation 27.163 27.219 31.954
Incremental shares issuable for stock
options and awards 0.210 0.036 0.062
------ ------ ------
Average common shares outstanding for
diluted computation 27.373 27.255 32.016
------ ------ ------
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 difference between
the book and tax basis 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.
UGI Utilities' regulated operations 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. UGI
Utilities also records a deferred tax liability for tax benefits that are flowed
through to ratepayers when temporary differences originate and establishes 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.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION. The amounts we assign to
property, plant and equipment of businesses we acquire are based upon estimated
fair value at date of acquisition. When we retire Utilities' plant, we charge
its original cost and the net cost of its removal to accumulated depreciation
for financial accounting purposes. When we retire or dispose of other plant and
equipment, we remove from the accounts the cost and accumulated depreciation and
include in income any gains or losses.
We record depreciation expense for Utilities' plant 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 2.6% in 2001 and 2000, and 2.7% in
1999. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 3.0% in 2001, 3.5% in 2000, and 3.2% in 1999. We
compute depreciation expense on plant and equipment associated with our propane
operations using the straight-line method over estimated service lives generally
ranging from 15 to 40 years for buildings and improvements; 7 to 30 years for
storage and customer tanks and cylinders; and 5 to 10 years for vehicles,
equipment, and office furniture and fixtures. Depreciation expense was $75.7
million in 2001, $69.3 million in 2000, and $63.6 million in 1999.
Effective October 1, 2000, the Partnership changed its method of accounting
for costs to install Partnership-owned tanks at customer locations. Under the
new accounting method, all costs to install such tanks, net of amounts billed to
customers, are capitalized and amortized over the estimated period of benefit
not exceeding ten years. For a detailed description of this change in accounting
and its impact on our results, see Note 3.
INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
[Download Table]
2001 2000
--------------------
Goodwill (less accumulated amortization of $143.9
million and $126.6 million, respectively) $547.8 $566.8
Excess reorganization value (less accumulated amortization
of $68.2 million and $60.2 million, respectively) 93.3 101.3
Other (less accumulated amortization of $5.8
million and $3.4 million, respectively) 31.3 7.4
------- -------
Total intangible assets $672.4 $675.5
------- -------
Substantially all of our goodwill is a result of propane purchase business
combinations. This goodwill is amortized on a straight-line basis over 40 years.
We amortize excess reorganization value (resulting from Petrolane's July 15,
1993 reorganization under Chapter 11 of the U.S. Bankruptcy Code) on a
straight-line basis over 20 years. We amortize other intangible assets,
principally customer relationships and covenants not to compete, over the
estimated periods of benefit, which do not exceed fifteen years. Amortization
expense of intangible assets was $27.7 million in 2001, $26.5 million in 2000,
and $24.3 million in 1999.
We evaluate the impairment of long-lived assets, including intangibles,
whenever events or changes in circumstances indicate that the carrying amount of
such assets may not be recoverable. We evaluate recoverability based upon
undiscounted future cash flows expected to be generated by such assets.
STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for
Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting
Principles Board Opinion ("APB") 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.
OTHER ASSETS. Included in other assets are net deferred debt issuance costs of
$15.9 million at September 30, 2001 and $10.8 million at September 30, 2000. We
are amortizing these costs over the term of the related debt.
COMPUTER SOFTWARE COSTS. We include in property, plant and equipment costs
associated with computer software we develop or obtain for use in our
businesses. We amortize computer software costs on a straight-line basis over
expected periods of benefit not exceeding ten years once the installed software
is ready for its intended use.
DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery
of certain purchased gas costs ("PGCs"). The clauses provide for periodic
adjustments for the difference between the total amount collected from customers
under each clause and the recoverable costs incurred. We defer the difference
between amounts recognized in revenues and the applicable gas costs incurred
until they are subsequently billed or refunded to customers.
ENVIRONMENTAL LIABILITIES. We accrue environmental investigation and cleanup
costs when it is probable that a liability exists and the amount or range of
amounts can be reasonably estimated. Our estimated liability for environmental
contamination is reduced to reflect anticipated participation of other
responsible parties but is not reduced for possible recovery from insurance
carriers. We do not discount to present value the costs of future expenditures
for environmental liabilities. We intend to pursue recovery of any incurred
costs through all appropriate means, including regulatory relief. Gas Utility is
permitted to amortize as removal costs site-specific environmental investigation
and remediation costs, net of related third-party payments, associated with
Pennsylvania sites. Gas Utility is currently permitted to include in rates,
through future base rate proceedings, a five-year average of such prudently
incurred removal costs.
FOREIGN CURRENCY TRANSLATION. Balance sheets of international subsidiaries and
investments in international propane joint ventures are translated into U.S.
dollars using the exchange rate at the balance sheet date. Income statements and
equity method results are translated into U.S. dollars using a weighted-average
exchange rate for each reporting period. Where the local currency is the
functional currency, translation adjustments are recorded in other comprehensive
income. Where the local currency is not the functional currency, translation
adjustments are recorded in net income.
COMPREHENSIVE INCOME. Comprehensive income comprises net income and other
comprehensive income (loss). Other comprehensive income (loss) principally
results from gains and losses on derivative instruments qualifying as cash flow
hedges, unrealized gains and losses on available for sale securities, and
foreign currency translation adjustments. The components of accumulated other
comprehensive income (loss) at September 30, 1999, 2000 and 2001 follows:
32
[Download Table]
Derivative Foreign
Unrealized Instruments Currency
Gains on Gains Translation
Securities (Losses) Adjustments Total
---------------------------------------------------------------------------------
Balance - September 30, 1999 $ 0.5 $ -- $ -- $ 0.5
Balance - September 30, 2000 $ -- $ -- $ -- $ --
Balance - September 30, 2001 $ -- $(13.7) $ 0.2 $ (13.5)
---------------------------------------------------------------------------------
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. The Financial Accounting
Standards Board ("FASB") recently issued SFAS No. 141, "Business
Combinations" ("SFAS 141"); SFAS No. 142, "Goodwill and Other Intangible
Assets" ("SFAS 142"); SFASNo. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"); and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS 144").
SFAS 141 addresses financial accounting and reporting for business
combinations. Under SFAS 141, all business combinations initiated after June 30,
2001 are required to be accounted for using the purchase method of accounting.
Among other provisions, SFAS 141 establishes specific criteria for the
recognition of intangible assets separate from goodwill acquired in a purchase
business combination. Although SFAS 141 supersedes APB Opinion No. 16, "Business
Combinations," and SFAS No. 38, "Accounting for Preacquisition Contingencies of
Purchased Enterprises," it does not change many of their provisions relating to
the application of the purchase method. The Company has historically accounted
for business combinations using the purchase method and, therefore, SFAS 141 is
not expected to have a material impact on the Company.
SFAS 142 addresses the financial accounting and reporting for acquired
goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." SFAS 142 addresses the financial accounting and reporting
for intangible assets acquired individually or with a group of other assets
(excluding those acquired in a business combination) at acquisition and also
addresses the financial accounting and reporting for goodwill and other
intangible assets subsequent to their acquisition. Under SFAS 142, an intangible
asset will be amortized over its useful life unless that life is determined to
be indefinite. Goodwill and other intangible assets with indefinite lives will
be tested for impairment at least annually.
The Company adopted SFAS 142 effective October 1, 2001. Although there is no
effect on the Company's cash flows, the Company's amortization expense in 2001
would have been approximately $25.2 million lower, and its net income
approximately $14.0 million higher (after adjusting for the minority interests
in AmeriGas Partners), if SFAS 142 had been effective October 1, 2000.
SFAS 142 requires the Company to test goodwill for impairment within six
months of adoption. Based upon the fair value of the Partnership, we do not
believe the Partnership's goodwill is impaired. We have not yet completed the
evaluation of the impact, if any, of the goodwill impairment provisions of SFAS
142 on our other reporting units.
SFAS 143 addresses financial accounting and reporting for legal obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 requires that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it is
incurred with a corresponding increase in the carrying value of the related
asset. Entities shall subsequently charge the retirement cost to expense using a
systematic and rational method over the related asset's useful life and adjust
the fair value of the liability resulting from the passage of time through
charges to interest expense. The Company is required to adopt SFAS 143 effective
October 1, 2002. The Company is currently in the process of evaluating the
impact SFAS 143 will have on its financial condition and results of operations.
SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the
accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," as it relates to the disposal of a segment of a business. SFAS
144 establishes a single accounting model for long-lived assets to be disposed
of based upon the framework of SFAS 121, and resolves significant implementation
issues of SFAS 121. SFAS 144 is effective for the Company October 1, 2002. The
Company believes that the adoption of SFAS 144 will not have a material impact
on its financial position or results of operations.
NOTE 2 - ACQUISITIONS AND INVESTMENTS
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the
propane distribution businesses of Columbia Energy Group ("Columbia Propane
Businesses") in a series of equity and asset purchases pursuant to the terms of
the Purchase Agreement dated January 30, 2001 and Amended and Restated August 7,
2001 ("Columbia Purchase Agreement") by and among Columbia Energy Group ("CEG"),
Columbia Propane Corporation ("Columbia Propane"), Columbia Propane, L.P.
("CPLP"), CP Holdings, Inc. ("CPH"), AmeriGas Partners, AmeriGas OLP, and the
General Partner. The acquired businesses comprised the seventh largest retail
marketer of propane in the United States with annual sales of over 300 million
gallons from locations in 29 states. The acquired businesses were principally
conducted through Columbia Propane and its approximate 99% owned subsidiary,
CPLP (referred to after the acquisition as "Eagle OLP"). AmeriGas OLP acquired
substantially all of the assets of Columbia Propane, including an indirect 1%
general partner interest and an approximate 99% limited partnership interest in
Eagle OLP.
The purchase price of the Columbia Propane Businesses consisted of $201.8
million in cash. In addition, AmeriGas OLP agreed to pay CEG for the amount of
working capital, as defined, in excess of $23 million. The Columbia Purchase
Agreement also provided for the purchase by CEG of limited partnership interests
in AmeriGas OLP valued at $50 million for $50 million in cash, which interests
were exchanged for 2,356,953 Common Units of AmeriGas Partners having an
estimated fair value of $54.4 million. Concurrently with the acquisition,
AmeriGas Partners issued $200 million of 8.875% Senior Notes due 2011, the net
proceeds of which were contributed to AmeriGas OLP to finance the acquisition of
the Columbia Propane Businesses, to fund related fees and expenses, and to repay
debt outstanding under AmeriGas OLP's Bank Credit Agreement.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
The purchase price of the Columbia Propane Businesses has been
preliminarily allocated to the assets and liabilities acquired as follows:
[Download Table]
Working capital $ 23.2
Property, plant and equipment 181.4
Customer relationships and noncompete agreements
(estimated useful life of 15 and 5 years, respectively) 21.0
Other assets and liabilities (1.0)
------
Total $224.6
------
The Partnership is currently in the process of completing the review
and determination of the fair value of the Columbia Propane Businesses' assets
acquired and liabilities assumed, principally the fair values of property, plant
and equipment and identifiable intangible assets. Accordingly, the allocation of
the purchase price is subject to revision. The operating results of the Columbia
Propane Businesses are included in our consolidated results from August 21,
2001.
The following table presents unaudited pro forma income statement and
diluted per share data for 2001 and 2000 as if the acquisition of the Columbia
Propane Businesses had occurred as of the beginning of those years:
[Download Table]
2001 2000
---- ----
Revenues $ 2,838.3 $ 2,069.8
Income before accounting changes 50.8 39.5
Net income 55.3 39.5
Diluted earnings per share:
Income before accounting changes 1.86 1.45
Net income 2.02 1.45
--------- ---------
The pro forma results of operations reflect the Columbia Propane
Businesses' historical operating results after giving effect to adjustments
directly attributable to the transaction that are expected to have a continuing
impact. They are not adjusted for, among other things, the impact of normal
weather conditions, operating synergies and anticipated cost savings. In our
opinion, the unaudited pro forma results are not indicative of the actual
results that would have occurred had the acquisition of the Columbia Propane
Businesses occurred as of the beginning of the years presented or of future
operating results under our management.
On March 27, 2001, UGI France, Inc. ("UGI France"), a wholly owned
indirect subsidiary of Enterprises, together with Paribas Affaires Industrielles
("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), acquired, through AGZ
Holdings ("AGZ"), the stock and certain related assets of Elf Antargaz, S.A.,
one of the largest distributors of liquefied petroleum gas in France (referred
to after the transaction and herein as "Antargaz"). Prior to the transaction,
Antargaz was a subsidiary of Total Fina Elf S.A., a French petroleum and
chemical company. Under the terms of the Shareholders' Funding Agreement among
UGI France, PAI and Medit, we acquired an approximate 19.5% equity interest in
Antargaz; PAI an approximate 68.1% interest; Medit an approximate 9.7% interest;
and certain members of management of Antargaz an approximate 2.7% interest. PAI
is a leading private equity fund manager in Europe and an affiliate of BNP
Paribas, one of Europe's largest commercial and investment banks. Medit is a
supplier of logistics services to the liquefied petroleum gas industry in
Europe, primarily Italy.
Pursuant to the Shareholders' Funding Agreement, UGI France made a 29.8
million EURO ($26.6 million U.S. dollar equivalent) investment comprising a 9.8
million EURO investment in shares of AGZ and a 20.0 million EURO investment in
redeemable bonds of AGZ. The bonds are redeemable in the form of additional
shares of AGZ on December 31, 2013. Under certain circumstances, the bonds may
be redeemed earlier in the form of additional shares or in cash. Because we
believe we have significant influence over operating and financial policies of
Antargaz due, in part, to our membership on its Board of Directors, our
investment in AGZ shares is being accounted for by the equity method.
During 2001, Energy Services acquired two energy marketing businesses
and the Partnership acquired several small propane distribution businesses for
total cash consideration of $5.4 million. During 2000, the Partnership acquired
several propane distribution businesses, and Enterprises acquired an HVAC
business, for net cash consideration of $65.3 million. The excess of the
purchase price over the amount allocated to the net assets acquired for the 2000
acquisitions was approximately $42 million. During 1999, the Partnership
acquired several retail propane distribution businesses for net cash
consideration of $3.9 million. These acquisitions were recorded using the
purchase method of accounting. The operating results of these businesses have
been included in the consolidated results from their respective dates of
acquisition. The pro forma effect of these transactions was not material to our
2001, 2000 and 1999 results of operations. In addition to these acquisitions,
during 1999 we paid $4.9 million for a 25% equity interest in a propane
distribution business in Nantong, China, which is being accounted for by the
equity method.
On September 21, 1999, Enterprises, through subsidiaries, acquired all
of the outstanding stock of FLAGA for net cash consideration of $73.7 million
and the assumption of approximately $18 million of debt. The cash purchase price
was financed through the issuance of EURO denominated debt. The acquisition of
FLAGA has been accounted for using the purchase method of accounting. The excess
of the purchase price over the amount allocated to the net assets acquired
totaled approximately $58 million. For accounting convenience only, September
30, 1999 was deemed to be the acquisition date. As a result, the acquisition of
FLAGA did not impact our 1999 results of operations.
NOTE 3 - CHANGES IN ACCOUNTING
TANK FEE REVENUE RECOGNITION. In order to comply with the provisions of SAB 101,
effective October 1, 2000, the Partnership changed its method of accounting for
annually billed nonrefundable tank fees. Historically, nonrefundable tank fees
for installed Partnership-owned tanks were recorded as revenue when billed.
Under the new accounting method, revenues from such fees are being recorded on a
straight-line basis over one year. As a result of the new accounting method, on
October 1, 2000, we recorded an after-tax charge of $2.1 million representing
the cumulative effect of the change in accounting method on prior years. The
change in accounting method for nonrefundable tank fees did not have a material
impact on reported revenues in 2001 and would not have materially impacted
revenues in 2000 or 1999.
34
UGI Corporation 2001 Annual Report
At September 30, 2001, the deferred revenue balance relating to nonrefundable
tank fees was $6.2 million.
ACCOUNTING FOR TANK INSTALLATION COSTS. Effective October 1, 2000, the
Partnership changed its method of accounting for tank installation costs which
are not billed to customers. Prior to the change in accounting method, all such
costs to install Partnership-owned tanks at a customer location were expensed as
incurred. Under the new accounting method, all such costs, net of amounts billed
to customers, are capitalized and amortized over the estimated period of benefit
not exceeding ten years. The Partnership believes that the new accounting method
better matches the costs of installing Partnership-owned tanks with the periods
benefited. As a result of this change in accounting, we recorded after-tax
income of $6.9 million representing the cumulative effect of the change in
accounting method on prior years. The effect on net income from the change in
accounting for tank installation costs during the year ended September 30, 2001
was not material.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND PRO FORMA DISCLOSURE. The cumulative
effect reflected on the 2001 Consolidated Statement of Income and related
diluted per share amounts resulting from the above changes in accounting
principles, as well as the cumulative effect from the adoption of SFAS 133 (see
Note 1), comprise the following:
[Download Table]
Income Diluted
Pre-Tax Tax After-Tax Earnings
Income (Expense) Income (Loss)
(Loss) Benefit (Loss) Per Share
------ ------- ------ ---------
Tank fees $ (3.5) $ 1.4 $ (2.1) $ (0.08)
Tank installation costs 11.3 (4.4) 6.9 0.25
SFAS 133 (0.4) 0.1 (0.3) (0.01)
-------- -------- -------- --------
Total $ 7.4 $ (2.9) $ 4.5 $ 0.16
-------- -------- -------- --------
The following table reflects unaudited pro forma net income and net
income per share after applying retroactively the changes in accounting for tank
installation costs and nonrefundable tank fees:
[Download Table]
As Reported As Adjusted
----------- -----------
Year Ended September 30, 2000:
Net income $44.7 $44.6
Net income per share - basic $1.64 $1.64
Net income per share - diluted $1.64 $1.64
Year Ended September 30, 1999:
Net income $55.7 $55.9
Net income per share - basic $1.74 $1.75
Net income per share - diluted $1.74 $1.75
----- -----
NOTE 4 - UTILITY REGULATORY MATTERS
GAS UTILITY
GAS COMPETITION ACT. On June 22, 1999, the Gas Competition Act was signed into
law. The purpose of the Gas Competition Act is to provide all natural gas
consumers in Pennsylvania with the ability to purchase their gas supplies from
the supplier of their choice. Under the Gas Competition Act, local gas
distribution companies ("LDCs") may continue to sell gas to customers, and such
sales of gas, as well as distribution services provided by LDCs, continue to be
subject to price regulation by the PUC. As of January 1, 2000, the Gas
Competition Act, in conjunction with a companion bill, eliminated the gross
receipts tax on sales of gas.
Generally, LDCs will serve as the supplier of last resort for all
residential and small commercial and industrial customers unless the PUC
approves another supplier of last resort. The Gas Competition Act requires
energy marketers seeking to serve customers of LDCs to accept assignment of a
portion of the LDC's pipeline capacity and storage contracts at contract rates,
thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas
supplier may petition the PUC to avoid such contract release or assignment.
However, such petition may be granted only if the LDC fully recovers the cost of
contracts.
On June 29, 2000, the PUC issued the Gas Restructuring Order approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas
Competition Act. Among other things, the implementation of the Gas Restructuring
Order resulted in an increase in Gas Utility's core-market base rates effective
October 1, 2000. This base rate increase was designed to generate approximately
$16.7 million in additional net annual revenues. The Gas Restructuring Order
also provided that effective October 1, 2000, Gas Utility must reduce its PGC
rates by an annualized amount of $16.7 million for the first 14 months following
the base rate increase.
Beginning December 1, 2001, Gas Utility is required to reduce its PGC
rates by an amount equal to the margin it receives from customers served under
interruptible rates to the extent they use capacity contracted by Gas Utility
for core-market customers. As a result, Gas Utility expects that beginning in
Fiscal 2002 operating results will be less sensitive to the market prices of
alternative fuels and more sensitive to the effects of heating-season weather.
TRANSFER OF ASSETS. On May 24, 2001, the PUC approved Gas Utility's application
for approval to transfer its liquefied natural gas ("LNG") and propane air
("LP") facilities, along with related assets, to Energy Services. The associated
reduction in Gas Utility's base rates, adjusted for the impact of the transfer
on net operating expenses, is not expected to have a material effect on Gas
Utility's or the Company's results of operations. Gas Utility transferred the
LNG and LP assets, which are not material to its total assets, on September 30,
2001.
ELECTRIC UTILITY
ELECTRIC UTILITY RESTRUCTURING ORDER. On June 19, 1998, the PUC entered its
Opinion and Order ("Electricity Restructuring Order") in Electric Utility's
restructuring proceeding pursuant to the Electricity Choice Act. Under the terms
of the Electricity Restructuring Order, commencing January 1, 1999, Electric
Utility is authorized to recover $32.5 million in stranded costs (on a full
revenue requirements basis which includes all income and gross receipts taxes)
over a four-year period through a Competitive Transition Charge ("CTC")
(together with carrying charges on unrecovered balances of 7.94%) and to charge
unbundled rates for
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
generation, transmission and distribution services. Stranded costs are electric
generation-related costs that traditionally would be recoverable in a regulated
environment but may not be recoverable in a competitive electric generation
market. The recoverable stranded costs include $8.7 million for the buy-out of a
1993 power purchase agreement with an independent power producer.
Under the terms of the Electricity Restructuring Order and in
accordance with the Electricity Choice Act, Electric Utility generally may not
increase the generation component of prices as long as stranded costs are being
recovered through the CTC. This generation rate cap is expected to extend
through September 2002 in the case of Electric Utility's commercial and
industrial customers and May 2003 in the case of Electric Utility's residential
customers. Since January 1, 1999, all of Electric Utility's customers have been
permitted to select an alternative generation supplier. Customers choosing an
alternative supplier receive a "shopping credit." As permitted by the
Electricity Restructuring Order, on October 1, 1999, Electric Utility
transferred its electric generation assets to its wholly owned nonregulated
subsidiary, UGI Development Company ("UGIDC").
FORMATION OF HUNLOCK CREEK ENERGY VENTURES. On December 8, 2000, UGIDC
contributed its coal-fired Hunlock Creek generating station ("Hunlock") and
certain related assets having a net book value of approximately $4.2 million,
and $6 million in cash, to Hunlock Creek Energy Ventures ("Energy Ventures"), a
general partnership jointly owned by us and a subsidiary of Allegheny Energy,
Inc. ("Allegheny"). The contribution was recorded at carrying value and no gain
was recognized by the Company. Also on December 8, 2000, Allegheny contributed a
newly constructed, gas-fired combustion turbine generator to be operated at the
Hunlock site. Under the terms of our arrangement with Allegheny, each partner is
entitled to purchase 50% of the output of the joint venture at cost. Total
purchases from Energy Ventures in 2001 were $8.0 million.
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
[Download Table]
2001 2000
---- ----
Regulatory assets:
Income taxes recoverable $ 51.8 $ 47.7
Power agreement buy-out 1.3 3.5
Other postretirement benefits 2.6 2.9
Deferred fuel costs -- 7.2
Other 0.5 1.0
------- -------
Total regulatory assets $ 56.2 $ 62.3
------- -------
Regulatory liabilities:
Other postretirement benefits $ 4.3 $ 4.0
Deferred fuel costs 2.8 --
------- -------
Total regulatory liabilities $ 7.1 $ 4.0
------- -------
NOTE 5 - DEBT
Long-term debt comprises the following at September 30:
[Download Table]
2001 2000
---- ----
AMERIGAS PROPANE:
AmeriGas Partners Senior Notes:
8.875%, due May 2011 $ 200.0 $ --
10%, due April 2006 (less unamortized
discount of $0.3, effective rate - 10.125%) 59.7 --
10.125%, due April 2007 100.0 100.0
AmeriGas OLP First Mortgage Notes:
Series A, 9.34% - 11.71%, due April 2001 through
April 2009 (including unamortized premium of
$9.2 and $10.6, respectively, effective rate - 8.91%) 189.2 208.6
Series B, 10.07%, due April 2001 through April 2005
(including unamortized premium of $3.9 and $5.9,
respectively, effective rate - 8.74%) 163.9 205.9
Series C, 8.83%, due April 2003 through April 2010 110.0 110.0
Series D, 7.11%, due March 2009 (including
unamortized premium of $2.4 and $2.7,
respectively, effective rate - 6.52%) 72.4 72.7
Series E, 8.50%, due July 2010 (including unamortized
premium of $0.2, effective rate - 8.47%) 80.2 80.2
AmeriGas OLP Acquisition Facility 20.0 70.0
Other 10.5 9.8
-------- --------
Total AmeriGas Propane 1,005.9 857.2
-------- --------
UGI UTILITIES:
Medium-Term Notes:
7.25% Notes, due November 2017 20.0 20.0
7.17% Notes, due June 2007 20.0 20.0
6.17% Notes, due March 2001 -- 15.0
7.37% Notes, due October 2015 22.0 22.0
6.73% Notes, due October 2002 26.0 26.0
6.62% Notes, due May 2005 20.0 20.0
7.14% Notes, due December 2005 (including
unamortized premium of $0.5, effective rate - 6.64%) 30.5 --
7.14% Notes, due December 2005 20.0 --
6.50% Senior Notes, due August 2003
(less unamortized discount of $0.1) 49.9 49.9
-------- --------
Total UGI Utilities 208.4 172.9
-------- --------
OTHER:
FLAGA EURO Note, due September 2001 through
September 2006 62.7 65.5
FLAGA EURO special purpose facility 10.7 11.9
Other 7.5 8.1
-------- --------
Total long-term debt 1,295.2 1,115.6
Less current maturities (98.3) (85.9)
-------- --------
Total long-term debt due after one year $1,196.9 $1,029.7
-------- --------
36
UGI Corporation 2001 Annual Report
Long-term debt due in fiscal years 2002 to 2006 follows:
[Download Table]
2002 2003 2004 2005 2006
---- ---- ---- ---- ----
AmeriGas Propane $87.2 $60.7 $57.5 $57.0 $174.8
UGI Utilities - 76.0 - 20.0 50.0
Other 11.1 16.7 9.9 15.7 0.8
----- ----- ----- ----- ------
Total $98.3 $153.4 $67.4 $92.7 $225.6
----- ----- ----- ----- ------
AMERIGAS PROPANE
AMERIGAS PARTNERS SENIOR NOTES. The 10% Senior Notes generally cannot be
redeemed at our option prior to their maturity. The 8.875% Senior Notes
generally cannot be redeemed prior to May 20, 2006. A redemption premium applies
thereafter through May 19, 2009. However, prior to May 20, 2004, AmeriGas
Partners may use the proceeds of a public offering of Common Units to redeem up
to 33% of the 8.875% Senior Notes at 108.875% plus accrued and unpaid interest.
The 10.125% Senior Notes are redeemable prior to their maturity date. A
redemption premium applies until April 15, 2004. AmeriGas Partners may, under
certain circumstances following the disposition of assets or a change of
control, be required to offer to prepay the Senior Notes.
AMERIGAS OLP FIRST MORTGAGE NOTES. AmeriGas OLP's First Mortgage Notes are
collateralized by substantially all of its assets. The General Partner and
Petrolane are co-obligors of the Series A, B, and C First Mortgage Notes, and
the General Partner is co-obligor of the Series D and E First Mortgage Notes.
AmeriGas OLP may prepay the First Mortgage Notes, in whole or in part. These
prepayments include a make whole premium. Following the disposition of assets or
a change of control, AmeriGas OLP may be required to offer to prepay the First
Mortgage Notes, in whole or in part.
AMERIGAS OLP BANK CREDIT AGREEMENT. AmeriGas OLP's Bank Credit Agreement
consists of (1) a Revolving Credit Facility and (2) an Acquisition Facility.
AmeriGas OLP's obligations under the Bank Credit Agreement are collateralized by
substantially all of its assets. The General Partner and Petrolane are
co-obligors of amounts outstanding under the Bank Credit Agreement.
Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $100
million (including a $35 million sublimit for letters of credit) subject to
restrictions in the AmeriGas Partners Senior Notes indenture (see "Restrictive
Covenants" below). The Revolving Credit Facility may be used for working capital
and general purposes of AmeriGas OLP. The Revolving Credit Facility expires
September 15, 2002, but may be extended for additional one-year periods with the
consent of the participating banks representing at least 80% of the commitments
thereunder. The Revolving Credit Facility permits AmeriGas OLP to borrow at
various prevailing interest rates, including the Base Rate, defined as the
higher of the Federal Funds Rate plus 0.50% or the agent bank's reference rate
(6.00% at September 30, 2001), or at two-week, one-, two-, three-, or six-month
offshore interbank offering rates ("IBOR"), plus a margin. The margin on IBOR
borrowings (which ranges from 0.50% to 1.75%) and the Revolving Credit Facility
commitment fee rate are dependent upon AmeriGas OLP's ratio of funded debt to
earnings before interest expense, income taxes, depreciation and amortization
("EBITDA"), each as defined in the Bank Credit Agreement. There were no
borrowings outstanding under the Revolving Credit Facility at September 30,
2001. AmeriGas OLP had borrowings under the Revolving Credit Facility totaling
$30 million at September 30, 2000, which we classify as bank loans. The
weighted-average interest rates on the bank loans outstanding as of September
30, 2000 was 8.11%. Issued outstanding letters of credit under the Revolving
Credit Facility totaled $9.5 million and $1.5 million at September 30, 2001 and
2000, respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to
borrow up to $75 million to finance the purchase of propane businesses or
propane business assets. In addition, up to $30 million of the Acquisition
Facility may be used for working capital purposes. The Acquisition Facility
operates as a revolving facility through September 15, 2002, at which time
amounts then outstanding will be immediately due and payable. The Acquisition
Facility permits AmeriGas OLP to borrow at the base rate or at two-week, one-,
two-, three-, or six-month IBOR, plus a margin. The margin on IBOR borrowings
and the Acquisition Facility commitment fee rate are dependent upon AmeriGas
OLP's ratio of funded debt to EBITDA, as defined. The weighted-average interest
rates on Acquisition Facility loans outstanding were 4.08% and 8.12% as of
September 30, 2001 and 2000, respectively.
GENERAL PARTNER FACILITY. AmeriGas OLP also has a revolving credit agreement
with the General Partner under which it may borrow up to $20 million for working
capital and general purposes. This agreement is coterminous with, and generally
comparable to, AmeriGas OLP's Revolving Credit Facility except that borrowings
under the General Partner Facility are unsecured and subordinated to all senior
debt of AmeriGas OLP. Interest rates on borrowings are based upon one-month
IBOR. Commitment fees are determined in the same manner as fees under the
Revolving Credit Facility. UGI has agreed to contribute up to $20 million to the
General Partner to fund such borrowings.
RESTRICTIVE COVENANTS. The Senior Notes of AmeriGas Partners restrict the
ability of the Partnership to, among other things, incur additional
indebtedness, make investments, incur liens, issue preferred interests, prepay
subordinated indebtedness, and effect mergers, consolidations and sales of
assets. Under the Senior Notes Indentures, AmeriGas Partners is generally
permitted to make cash distributions equal to available cash, as defined, as of
the end of the immediately preceding quarter, if certain conditions are met.
These conditions include:
1. no event of default exists or would exist upon making such
distributions and
2. the Partnership's consolidated fixed charge coverage ratio, as
defined, is greater than 1.75-to-1.
If the ratio in item 2 above is less than or equal to 1.75-to-1, the
Partnership may make cash distributions in a total amount not to exceed $24
million less the total amount of distributions made during the immediately
preceding 16 fiscal quarters. At September 30, 2001, such ratio was 2.57-to-1.
The Bank Credit Agreement and the First Mortgage Notes restrict the
incurrence of additional indebtedness and also restrict
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
certain liens, guarantees, investments, loans and advances, payments, mergers,
consolidations, asset transfers, transactions with affiliates, sales of assets,
acquisitions and other transactions. They also 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 5.25-to-1. In addition, the Bank Credit Agreement requires that
AmeriGas OLP maintain a ratio of EBITDA to interest expense, as defined, of at
least 2.25-to-1 on a rolling four-quarter basis. Generally, as long as no
default exists or would result, AmeriGas OLP is permitted to make cash
distributions not more frequently than quarterly in an amount not to exceed
available cash, as defined, for the immediately preceding calendar quarter. At
September 30, 2001, the Partnership was in compliance with its financial
covenants.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2001, UGI Utilities had revolving
credit agreements with four banks providing for borrowings of up to $97 million.
These agreements expire at various dates through June 2004. UGI Utilities may
borrow at various prevailing interest rates, including LIBOR. UGI Utilities pays
quarterly commitment fees on these credit lines. UGI Utilities had borrowings
under these agreements totaling $57.8 million at September 30, 2001 and $100.4
million at September 30, 2000, which we classify as bank loans. The
weighted-average interest rates on UGI Utilities bank loans were 5.69% at
September 30, 2001 and 7.12% at September 30, 2000.
RESTRICTIVE COVENANTS. UGI Utilities' credit agreements have restrictions on
such items as total debt, working capital, debt service, and payments for
investments. They also require consolidated tangible net worth of at least $125
million. At September 30, 2001, UGI Utilities had not satisfied the minimum
working capital requirement under its revolving credit agreements. This default
was cured within the thirty day period allowed under such agreements.
OTHER
FLAGA's EURO note bears interest at a rate of 1.25% over one- to twelve-month
EURIBOR rates (as chosen by FLAGA from time to time). The effective interest
rates on the EURO note at September 30, 2001 and September 30, 2000 were 5.42%
and 5.71%, respectively. On or after September 10, 2003, FLAGA may prepay the
EURO note, in whole or in part. Prior to March 11, 2005, such prepayments shall
be at a premium. In October 2001, an 18.5 million EURO portion of the EURO note
was converted to a $16.7 million U.S. dollar denominated obligation.
At September 30, 2001, FLAGA has EURO loan commitments from a foreign
bank in the form of (1) a 15 million EURO special purpose facility and (2) a 15
million EURO working capital facility. Borrowings under the FLAGA special
purpose facility can be used to repay certain debt obligations of FLAGA existing
at the acquisition date and for general business purposes. The working capital
facility expires in September 2002, but may be extended with the bank's consent.
Loans under the special purpose facility and the working capital facility bear
interest at market rates. The weighted-average interest rates on FLAGA's working
capital facility and special purpose facility at September 30, 2001 were 4.75%
and 4.79%, respectively. Borrowings under the EURO working capital facility at
September 30, 2001 and 2000 totaled $10.0 million and $4.3 million,
respectively, and are classified as bank loans.
The FLAGA EURO note, special purpose facility and the working capital
facility are subject to guarantees of UGI. In addition, under certain conditions
regarding changes in the credit rating of UGI Utilities' long-term debt, the
lending bank may require UGI to grant additional security or may accelerate
repayment of the debt prior to its scheduled maturity.
NOTE 6 - INCOME TAXES
Income before income taxes comprises the following:
[Download Table]
2001 2000 1999
------- ------- -------
Domestic $ 103.0 $ 93.4 $ 100.5
Foreign (4.0) (7.0) --
------- ------- -------
Total income before income taxes $ 99.0 $ 86.4 $ 100.5
======= ======= =======
The provisions for income taxes consist of the following:
[Download Table]
2001 2000 1999
---- ---- ----
Current expense:
Federal $ 39.2 $ 28.6 $ 29.2
State 11.7 8.3 6.3
------- ------- -------
Total current expense 50.9 36.9 35.5
Deferred (benefit) expense:
Federal (2.9) 5.7 6.8
State (1.2) (0.2) 1.3
Foreign (1.0) (1.9) --
Investment tax credit amortization (0.4) (0.4) (0.4)
------- ------- -------
Total deferred (benefit) expense (5.5) 3.2 7.7
------- ------- -------
Total income tax expense $ 45.4 $ 40.1 $ 43.2
------- ------- -------
A reconciliation from the statutory federal tax rate to our effective
tax rate is as follows:
[Download Table]
2001 2000 1999
---- ---- ----
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal 7.3 7.5 5.2
Goodwill amortization 4.4 5.8 4.6
Other, net (0.8) (1.9) (1.8)
------- ------- -------
Effective tax rate 45.9% 46.4% 43.0%
------- ------- -------
38
UGI Corporation 2001 Annual Report
Deferred tax liabilities (assets) comprise the following at September 30:
[Download Table]
2001 2000
---- ----
Excess book basis over tax basis of property, plant
and equipment $ 180.3 $ 172.5
Regulatory assets 23.3 25.6
Other 15.5 13.7
------- -------
Gross deferred tax liabilities 219.1 211.8
------- -------
Self-insured property and casualty liability (8.0) (8.2)
Employee-related benefits (15.7) (12.0)
Premium on long-term debt (3.2) (4.4)
Deferred investment tax credits (3.6) (3.8)
Hearth USA(TM) shut-down costs (3.0) --
Accumulated comprehensive loss (3.7) --
Operating loss carryforwards (7.8) (6.6)
Allowance for doubtful accounts (2.9) (2.6)
Other (14.2) (13.3)
------- -------
Gross deferred tax assets (62.1) (50.9)
------- -------
Deferred tax assets valuation allowance 0.2 0.2
------- -------
Net deferred tax liabilities $ 157.2 $ 161.1
------- -------
UGI Utilities had recorded deferred tax liabilities of approximately $33.9
million as of September 30, 2001 and $31.7 million as of September 30, 2000
pertaining to utility temporary differences, principally a result of accelerated
tax depreciation, the tax benefits of which previously were or will be flowed
through to ratepayers. These deferred tax liabilities have been reduced by
deferred tax assets of $3.6 million at September 30, 2001 and $3.8 million at
September 30, 2000, pertaining to utility deferred investment tax credits. UGI
Utilities had recorded regulatory income tax assets related to these net
deferred taxes of $51.8 million as of September 30, 2001 and $47.7 million as of
September 30, 2000. 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
$26.2 million at September 30, 2001. These operating losses have no expiration
date.
NOTE 7 - EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS. We sponsor a defined
benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI
Utilities, and certain of UGI's wholly owned subsidiaries. In addition, we
provide postretirement health care benefits to certain retirees and a limited
number of active employees meeting certain age and service requirements, and
postretirement life insurance benefits to nearly all domestic active and retired
employees.
The following provides a reconciliation of benefit obligations, plan
assets, and funded status of these plans as of September 30:
[Enlarge/Download Table]
Pension Other Postretirement
Benefits Benefits
---------------------- -----------------------
2001 2000 2001 2000
---- ---- ---- ----
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 150.9 $ 149.5 $ 19.7 $ 16.8
Service cost 3.1 3.2 0.1 0.1
Interest cost 12.1 11.8 1.6 1.4
Actuarial (gain) loss 7.9 (4.4) 1.8 3.0
Benefits paid (8.8) (9.2) (1.9) (1.6)
------- ------- ------- -------
Benefit obligations - end of year $ 165.2 $ 150.9 $ 21.3 $ 19.7
------- ------- ------- -------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -
beginning of year $ 223.5 $ 202.1 $ 6.4 $ 4.9
Actual return on plan assets (31.0) 30.6 0.2 0.3
Employer contributions -- -- 2.2 2.2
Benefits paid (8.8) (9.2) (1.8) (1.0)
------- ------- ------- -------
Fair value of plan assets - end of year $ 183.7 $ 223.5 $ 7.0 $ 6.4
------- ------- ------- -------
Funded status of the plans $ 18.5 $ 72.6 $ (14.3) $ (13.3)
Unrecognized net actuarial (gain) loss 4.2 (54.8) (1.4) (3.0)
Unrecognized prior service cost 3.3 4.0 -- --
Unrecognized net transition (asset) obligation (4.6) (6.3) 9.5 10.5
------- ------- ------- -------
Prepaid (accrued) benefit cost - end of year $ 21.4 $ 15.5 $ (6.2) $ (5.8)
------- ------- ------- -------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 7.7% 8.2% 7.7% 8.2%
Expected return on plan assets 9.5% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5%
------- ------- ------- -------
Net periodic pension income and other postretirement benefit costs
include the following components:
[Enlarge/Download Table]
Pension Other Postretirement
Benefits Benefits
---------------------------------- -----------------------------------
2001 2000 1999 2001 2000 1999
------- ------- ------- ------- ------- -------
Service cost $ 3.1 $ 3.2 $ 3.8 $ 0.1 $ 0.1 $ 0.1
Interest cost 12.1 11.8 11.2 1.6 1.4 1.2
Expected return on assets (18.9) (17.0) (16.3) (0.3) (0.3) (0.2)
Amortization of:
Transition (asset)
obligation (1.6) (1.6) (1.6) 0.9 0.9 0.9
Prior service cost 0.6 0.6 0.6 -- -- --
Actuarial gain (1.2) -- -- (0.1) (0.2) (0.2)
------- ------- ------- ------- ------- -------
Net benefit cost (income) (5.9) (3.0) (2.3) 2.2 1.9 1.8
Change in regulatory
assets and liabilities -- -- -- 1.4 1.4 1.7
------- ------- ------- ------- ------- -------
Net expense (income) $ (5.9) $ (3.0) $ (2.3) $ 3.6 $ 3.3 $ 3.5
------- ------- ------- ------- ------- -------
Pension plan assets are held in trust and consist principally of equity and
fixed income mutual funds and investment grade corporate and U.S. government
obligations. UGI Common Stock comprised less than 5% of trust assets at
September 30, 2001 and 2000.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Pursuant to orders issued by the PUC, UGI Utilities has established a
Voluntary Employee Benefit Trust ("VEBA") to pay retiree health care and life
insurance benefits and to fund the UGI Utilities' postretirement benefit
liability. UGI Utilities is required to fund its postretirement benefit
obligations by depositing into the VEBA the annual amount of postretirement
benefits costs determined under SFAS 106, "Employers Accounting for
Postretirement Benefits Other than Pensions." The difference between such
amounts and amounts included in UGI Utilities' rates is deferred for future
recovery from, or refund to, ratepayers. VEBA investments consist principally of
money market funds.
The assumed health care cost trend rates are 9% for fiscal 2002,
decreasing to 5.5% in fiscal 2005. A one percentage point change in the assumed
health care cost trend rate would change the 2001 postretirement benefit cost
and obligation as follows:
[Download Table]
1% Increase 1% Decrease
----------- -----------
Effect on total service and interest costs $0.1 $(0.1)
Effect on postretirement benefit obligation $1.0 $(0.9)
---- -----
We also sponsor unfunded retirement benefit plans for certain key
employees. At September 30, 2001 and 2000, the projected benefit obligations of
these plans were not material. We recorded expense for these plans of $1.2
million in 2001, $0.9 million in 2000, and $1.6 million in 1999.
DEFINED CONTRIBUTION PLANS. We sponsor 401(k) savings plans for eligible
employees of UGI, UGI Utilities, AmeriGas Propane, HVAC and certain of UGI's
other wholly owned domestic subsidiaries. Generally, participants in these plans
may contribute a portion of their compensation on either a before-tax basis, or
on both a before-tax and after-tax basis. These plans also provide for either
mandatory or discretionary employer matching contributions, at various rates.
The cost of benefits under the savings plans totaled $6.2 million in 2001, $5.9
million in 2000, and $4.8 million in 1999.
NOTE 8 - INVENTORIES
Inventories comprise the following at September 30:
[Download Table]
2001 2000
---- ----
Propane gas $ 54.8 $ 47.3
Utility fuel and gases 45.6 33.6
Materials, supplies and other 28.2 36.5
------- -------
Total inventories $ 128.6 $ 117.4
------- -------
NOTE 9 - SERIES PREFERRED STOCK
The UGI Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 5,000,000 shares authorized for issuance.
We had no shares of UGI Series Preferred Stock outstanding at September 30, 2001
or 2000.
UGI Utilities Series Preferred Stock, including both series subject to
and series not subject to mandatory redemption, has 2,000,000 shares authorized
for issuance. The holders of shares of UGI Utilities Series Preferred Stock have
the right to elect a majority of UGI Utilities' Board of Directors (without
cumulative voting) if dividend payments on any series are in arrears in an
amount equal to four quarterly dividends. This election right continues until
the arrearage has been cured. We have paid cash dividends at the specified
annual rates on all outstanding UGI Utilities Series Preferred Stock.
At September 30, 2001 and 2000, UGI Utilities had outstanding 200,000
shares of $7.75 Series cumulative preferred stock. UGI Utilities is required to
establish a sinking fund to redeem on October 1 in each year, commencing October
1, 2004, 10,000 shares of its $7.75 Series at a price of $100 per share. The
$7.75 Series is redeemable, in whole or in part, at the option of UGI Utilities
on or after October 1, 2004, at a price of $100 per share. All outstanding
shares of $7.75 Series Preferred Stock are subject to mandatory redemption on
October 1, 2009, at a price of $100 per share.
NOTE 10 - COMMON STOCK AND INCENTIVE STOCK AWARD PLANS
Common Stock share activity for 1999, 2000 and 2001 follows:
[Download Table]
Issued Treasury Outstanding
------ -------- -----------
Balance September 30, 1998 33,198,731 (375,469) (32,823,262)
Issued:
Employee and director plans -- 175,040 175,040
Dividend reinvestment plan -- 136,587 136,587
Reacquired (a) -- (5,864,496) (5,864,496)
---------- ---------- -----------
Balance at September 30, 1999 33,198,731 (5,928,338) (27,270,393)
Issued:
Employee and director plans -- 62,525 62,525
Dividend reinvestment plan -- 114,430 114,430
Reacquired -- (453,639) (453,639)
---------- ---------- -----------
Balance September 30, 2000 33,198,731 (6,205,022) 26,993,709
Issued:
Employee and director plans -- 241,039 241,039
Dividend reinvestment plan -- 98,812 98,812
Reacquired -- (37,163) (37,163)
---------- ---------- -----------
Balance September 30, 2001 33,198,731 (5,902,334) 27,296,397
---------- ---------- -----------
(a) On September 7, 1999, pursuant to strategic and financial initiatives
announced on July 28, 1999, we repurchased 4,500,000 shares of Common Stock
through a "Dutch Auction" tender offer for $109.1 million, or $24.25 per share.
The repurchased shares are held in treasury. In addition, during 1999, in
conjunction with our proposed merger with Unisource (see Note 17), we purchased
1,364,496 shares of Common Stock for $23.2 million.
STOCK OPTION AND INCENTIVE PLANS. Under UGI's current employee stock option and
incentive plans, we may grant options to acquire shares of Common Stock, or
issue shares of restricted stock, to key employees. The exercise price for
options granted under these plans may not be less than the fair market value on
the grant date. Grants of stock options or restricted stock under these plans
may vest immediately or ratably over a period of years, and stock options
generally can be exercised no later than ten years from the grant date.
Under the 2000 Stock Incentive Plan ("2000 Incentive Plan"), up to
1,100,000 shares of Common Stock may be issued in connection with stock options
and grants of restricted stock. However, no more than 500,000 shares of
restricted stock may be granted. In addition,
40
UGI Corporation 2001 Annual Report
the 2000 Incentive Plan provides that both option grants and restricted stock
grants may provide for the crediting of Common Stock dividend equivalents to
participants' accounts. Dividend equivalents will be paid in cash, and such
payments may, at the participants' request, be deferred. Grants of restricted
stock will be contingent upon the achievement of objective performance goals.
During 2001, the Company made restricted stock awards representing 110,675
shares of UGI Common Stock under the 2000 Incentive Plan.
Under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP
Plan"), we may grant options to acquire a total of 1,500,000 shares of Common
Stock. Certain option grants under the 1997 SODEP Plan provided for the
crediting of dividend equivalents subject to UGI's total shareholder return
relative to a peer group of companies during the three-year period ended
December 31, 1999. Based upon such performance, no dividend equivalent payments
were made.
Under the 1992 Non-Qualified Stock Option Plan, we may grant options to
acquire a total of 500,000 shares of Common Stock to key employees who do not
participate in the 2000 Incentive Plan or the 1997 SODEP Plan.
In addition to these employee incentive plans, UGI may grant options to
acquire up to a total of 200,000 shares of Common Stock to each of UGI's
nonemployee Directors. No Director may be granted options to acquire more than
10,000 shares of Common Stock in any calendar year, and the exercise price may
not be less than the fair market value of the Common Stock on the grant date.
Generally, all options will be fully vested on the grant date and exercisable
only while the recipient is a Director.
Stock option transactions under all of our plans for 1999, 2000 and
2001 follow:
[Download Table]
Average
Shares Option Price
------ ------------
Shares under option - September 30, 1998 1,029,755 $21.905
--------- -------
Granted 231,806 20.406
Exercised (27,250) 21.978
Forfeited (18,750) 21.152
--------- -------
Shares under option - September 30, 1999 1,215,561 21.632
--------- -------
Granted 794,750 20.683
Exercised (30,000) 22.625
Forfeited (96,667) 22.302
--------- -------
Shares under option - September 30, 2000 1,883,644 21.181
--------- -------
Granted 33,600 25.875
Exercised (202,673) 20.807
--------- -------
Shares under option - September 30, 2001 1,714,571 21.318
--------- -------
Options exercisable 1999 984,061 21.725
Options exercisable 2000 947,144 21.696
Options exercisable 2001 1,100,904 21.799
--------- -------
For options outstanding as of September 30, 2001, the exercise prices
range from $18.625 to $26.250. The weighted-average remaining contractual life
of these options is 8.5 years. At September 30, 2001, 1,205,828 shares of Common
Stock were available for future option or restricted stock grants under all of
our stock option and incentive plans.
OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS. Under the AmeriGas
Propane, Inc. 2000 Long-Term Incentive Plan ("2000 Propane Plan"), the General
Partner may grant to key employees the right to receive a total of 500,000
AmeriGas Partners Common Units, or cash equivalent to the fair market value of
such Common Units, upon the achievement of performance goals. In addition, the
2000 Propane Plan may provide for the crediting of Partnership distribution
equivalents to participants' accounts. Distribution equivalents will be paid in
cash and such payments may, at the participants' request, be deferred.
Generally, each grant, unless paid, will terminate when the participant ceases
to be employed by the General Partner. During 2001, the General Partner made
awards under the 2000 Propane Plan representing 41,325 Common Units.
Under the 1997 AmeriGas Propane, Inc. Long-Term Incentive Plan ("1997
Propane Plan"), the General Partner granted to key employees the right to
receive AmeriGas Partners Common Units, or cash generally equivalent to their
fair market value, on the payment date. The 1997 Propane Plan also provided for
the crediting of dividend equivalents to participants' accounts. The actual
number of Common Units (or their cash equivalent) awarded, and the amount of the
distribution equivalent, depended upon the date when the cash generation-based
requirements for early conversion of AmeriGas Partners Subordinated Units were
met. Because such requirements were achieved at March 31, 1999, 81,226 Common
Units were issued, and $1.1 million in cash payments were made, in May 1999.
Under the 1997 UGI Corporation Directors' Equity Compensation Plan
("1997 Directors' Plan"), we make annual awards to our nonemployee Directors of
(1) "Units," each representing an interest equivalent to one share of Common
Stock, and (2) Common Stock for a portion of their annual retainer. Directors
may also elect to receive the cash portion of their retainer fee and all or a
portion of their meeting fees in the form of Units. The 1997 Directors' Plan
also provides for the crediting of dividend equivalents in the form of
additional Units. Units and dividend equivalents are fully vested when credited
to a Director's account and will be converted to shares of Common Stock and paid
upon retirement or termination of service. Units issued relating to annual
awards and deferred compensation totaled 11,556, 12,017, and 9,137 in 2001, 2000
and 1999, respectively. At September 30, 2001 and 2000, there were 53,736 and
53,294 Units, respectively, outstanding.
In June 1999, we awarded 103,000 shares of restricted stock to key
executives. These awards vested in June 2001. During the restriction period,
recipients had the right to vote the shares and to receive dividends.
FAIR VALUE INFORMATION. The per share weighted-average fair value of stock
options granted under our option plans was $4.35 in 2001, $3.76 in 2000, and
$2.58 in 1999. 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
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
the expected life of the option. The assumptions we used for option grants
during 2001, 2000 and 1999 are as follows:
[Download Table]
2001 2000 1999
---- ---- ----
Expected life of option 6 YEARS 6 years 6 years
Expected volatility 29.1% 26.5% 19.3%
Expected dividend yield 6.6% 6.2% 6.2%
Risk free interest rate 5.0% 6.6% 5.9%
------- ------- -------
We use the intrinsic value method prescribed by APB 25 for our
stock-based employee compensation plans. We recognized total stock-based
compensation expense (income) of $2.7 million in 2001, $(0.8) million in 2000,
and $1.9 million in 1999. Stock-based compensation income in 2000 reflects the
reversal of $2.1 million of accrued dividend equivalent payments relating to the
1997 SODEP Plan. If we had determined compensation expense under the fair value
method prescribed by SFAS 123, net income and diluted earnings per share for
2001, 2000 and 1999 would have been as follows:
[Download Table]
2001 2000 1999
---- ---- ----
Net earnings:
As reported $56.5 $44.7 $55.7
Pro forma 55.7 44.2 55.3
Diluted earnings per share:
As reported $2.06 $1.64 $1.74
Pro forma 2.03 1.62 1.73
----- ----- -----
STOCK OWNERSHIP POLICY. Under the terms of our Stock Ownership Policy,
executives and certain key employees are required to own UGI Common Stock having
a fair value equal to approximately 40% to 450% of their base salaries. We offer
full recourse, interest-bearing loans to employees in order to assist them in
meeting the ownership requirements. Each loan may not exceed ten years and is
collateralized by the Common Stock purchased. At September 30, 2001 and 2000,
loans outstanding totaled $4.6 million and $5.2 million, respectively.
NOTE 11 - PREFERENCE STOCK PURCHASE RIGHTS
Holders of our Common Stock own one-half of one right (as described below) for
each outstanding share of Common Stock. 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 12 - PARTNERSHIP DISTRIBUTIONS
The Partnership makes distributions to its partners approximately 45 days after
the end of each fiscal quarter in a total amount equal to its Available Cash for
such quarter. Available Cash generally means:
1. all cash on hand at the end of such quarter,
2. plus all additional cash on hand as of the date of
determination resulting from borrowings after the end of such
quarter,
3. less the amount of cash reserves established by the General
Partner in its reasonable discretion.
The General Partner may establish reserves for the proper conduct of
the Partnership's business and for distributions during the next four quarters.
In addition, certain of the Partnership's debt agreements require reserves be
established for the payment of debt principal and interest.
Distributions of Available Cash will generally be made 98% to the
Common and Subordinated unitholders and 2% to the General Partner. The
Partnership may pay an incentive distribution if Available Cash exceeds the
Minimum Quarterly Distribution of $0.55 ("MQD") on all units. If there is
sufficient Available Cash, the holders of Common Units have the right to receive
the MQD, plus any arrearages, before the distribution of Available Cash to
holders of Subordinated Units. Common Units will not accrue arrearages for any
quarter after the Subordination Period (as defined below), and Subordinated
Units will not accrue arrearages for any quarter.
42
UGI Corporation 2001 Annual Report
Pursuant to the Agreement of Limited Partnership of AmeriGas Partners
("Partnership Agreement"), because required cash generation-based objectives
were achieved as of March 31, 1999, a total of 9,891,074 Subordinated Units held
by the General Partner and Petrolane, were converted into Common Units on May
18, 1999. The remaining outstanding 9,891,072 Subordinated Units, all of which
are held by the General Partner, are eligible to convert to Common Units on the
first day after the record date for any quarter ending on or after March 31,
2000 in respect of which:
1. distributions of Available Cash from Operating Surplus (as
defined in the Partnership Agreement) equal or exceed the MQD
on each of the outstanding Common and Subordinated units for
each of the four consecutive nonoverlapping four-quarter
periods immediately preceding such date,
2. the Adjusted Operating Surplus (as defined in the Partnership
Agreement) generated during both (i) each of the two
immediately preceding nonoverlapping four-quarter periods and
(ii) the immediately preceding sixteen-quarter period, equals
or exceeds the MQD on each of the Common and Subordinated
units outstanding during those periods, and
3. there are no arrearages on the Common Units.
The ability of the Partnership to attain the cash-based performance and
distribution requirements will depend upon a number of factors including highly
seasonal operating results, changes in working capital, asset sales and debt
refinancings. Due to the historical quarterly requirements of the conversion
test, the possibility is remote that the Partnership will satisfy the cash-based
performance requirements for conversion any earlier than in respect of the
quarter ending September 30, 2002.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer, and office equipment
under operating leases. Certain of our leases contain renewal and purchase
options and also contain escalation clauses. Our aggregate rental expense for
such leases was $38.4 million in 2001, $34.1 million in 2000, and $35.3 million
in 1999.
Minimum future payments under operating leases that have initial or
remaining noncancelable terms in excess of one year are as follows:
[Enlarge/Download Table]
After
2002 2003 2004 2005 2006 2006
---- ---- ---- ---- ---- ----
AmeriGas Propane $ 34.0 $ 27.4 $ 22.9 $ 19.3 $ 15.5 $ 35.1
UGI Utilities 3.6 3.0 2.6 1.2 0.5 0.4
International Propane
and other 1.2 0.9 0.5 0.3 0.2 0.3
--------- --------- --------- --------- --------- ---------
Total $ 38.8 $ 31.3 $ 26.0 $ 20.8 $ 16.2 $ 35.8
--------- --------- --------- --------- --------- ---------
Gas Utility has gas supply agreements with producers and marketers with
terms of less than one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity, which Gas Utility may terminate at various
dates through 2015. Gas Utility's costs associated with transportation and
storage capacity agreements are included in its annual PGC filing with the PUC
and are recoverable through PGCrates. 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's distribution operations purchase their capacity
requirements and electric energy needs under contracts with power producers,
including UGIDC, a partner in Energy Ventures, and on the spot market. Contracts
with producers for capacity and energy needs expire at various dates through
December 2002. In high usage months, Electric Utility meets its additional
electric power needs through monthly market-based contracts and through spot
purchases at market prices as delivered.
The Partnership enters into contracts to purchase propane and Energy
Services enters into contracts to purchase natural gas to meet a portion of
their supply requirements. Generally, such contracts have terms of less than one
year and call for payment based on either fixed prices or market prices at date
of delivery.
The Partnership has succeeded to certain lease guarantee obligations of
Petrolane relating to Petrolane's divestiture of non-propane operations before
its 1989 acquisition by QFB Partners. Future lease payments under these leases
total approximately $25.0 million at September 30, 2001. The leases expire
through 2010, and some of them are currently in default. The Partnership has
succeeded to the indemnity agreement of Petrolane by which Texas Eastern
Corporation ("Texas Eastern"), a prior owner of Petrolane, agreed to indemnify
Petrolane against any liabilities arising out of the conduct of businesses that
do not relate to, and are not a part of, the propane business, including lease
guarantees. In December 1999, Texas Eastern filed for dissolution under the
Delaware General Corporation Law. In May 2001, Petrolane filed a declaratory
judgment action in the Delaware Chancery Court seeking confirmation of Texas
Eastern's indemnification obligations and judicial supervision of Texas
Eastern's dissolution to ensure that its indemnification obligations to
Petrolane are paid or adequately provided for in accordance with law. Those
proceedings are pending. Notwithstanding the dissolution proceeding, and based
on Texas Eastern previously having satisfied directly defaulted lease
obligations without the Partnership's having to honor its guarantee, we believe
that the probability that the Partnership will be required to directly satisfy
the lease obligations subject to the indemnification agreement is remote.
Columbia Propane, CPLP, and CPH (collectively, the "Company Parties")
agreed to indemnify the former general partners of National Propane Partners,
L.P. and certain of their affiliates (collectively, "National General Partners")
against certain income tax and other losses that the National General Partners
may sustain as a result of the 1999 acquisition by CPLP of the National Propane
business (the "1999 Acquisition") or its operation of the business after the
1999 Acquisition.
CEG has agreed to indemnify AmeriGas Partners, AmeriGas OLP, the
General Partner (collectively, the "Buyer Parties") and the Company Parties
against any losses that they sustain under the 1999 Acquisition Agreement and
related agreements ("Losses"), including claims asserted by the National General
Partners
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
("National Claims"), to the extent such claims are based on acts or omissions of
CEG or the Company Parties prior to the acquisition of the Columbia Propane
Businesses by AmeriGas OLP on August 21, 2001 (the "2001 Acquisition"). The
Buyer Parties have agreed to indemnify CEG against Losses, including National
Claims, to the extent such claims are based on acts or omissions of the Buyer
Parties or the Company Parties after the 2001 Acquisition. The Seller and Buyer
Parties have agreed to apportion certain losses resulting from a National Claim
to the extent such losses result from the 2001 Acquisition itself.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities does not expect its costs for investigation and
remediation of hazardous substances at Pennsylvania MGP sites to be material to
its results of operations because Gas Utility is currently permitted to include
in rates, through future base rate proceedings, prudently incurred remediation
costs associated with such sites. UGI Utilities has been notified of several
sites outside Pennsylvania on which (1) MGPs were formerly operated by it or
owned or operated by its former subsidiaries and (2) either environmental
agencies or private parties are investigating the extent of environmental
contamination or performing environmental remediation. UGI Utilities is
currently litigating two claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not
be liable in those instances in which a former subsidiary operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that the subsidiary's separate corporate
form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance
companies alleging that the defendants breached contracts of insurance by
failing to indemnify UGI Utilities for certain environmental costs. The suit
seeks to recover more than $11 million in such costs. During 2001 and 2000, UGI
Utilities entered into settlement agreements with several of the insurers and
recorded pre-tax income of $0.9 million and $4.5 million, respectively, which
amounts are included in operating and administrative expenses in the
Consolidated Statements of Income.
In addition to these matters, there are other pending claims and legal
actions arising in the normal course of our businesses. We cannot predict with
certainty the final results of environmental and other matters. However, it is
reasonably possible that some of them could be resolved unfavorably to us. We
believe, after consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a material
adverse effect on our financial position but could be material to our operating
results or cash flows in future periods depending on the nature and timing of
future developments with respect to these matters and the amounts of future
operating results and cash flows.
NOTE 14 - FINANCIAL INSTRUMENTS
In accordance with its propane price risk management policy, the Partnership
uses derivative instruments, including price swap and option contracts and
contracts for the forward sale of propane, to manage the cost of a portion of
its forecasted purchases of propane and to manage market risk associated with
propane storage inventories. These derivative instruments are generally
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 on occasion also
uses derivative instruments, principally price swap contracts, to reduce market
risk associated with purchases of propane. These contracts may or may not
qualify for hedge accounting under SFAS 133.
Energy Services uses exchange-traded natural gas futures contracts to
manage market risk associated with forecasted purchases of natural gas it sells
under firm commitments. These derivative instruments are designated as cash flow
hedges. The fair values of these futures contracts are affected by changes in
natural gas prices.
In addition, in the past we have, on occasion, used a managed program
of derivative instruments including natural gas and oil futures contracts, to
preserve gross margin associated with certain of our natural gas customers.
These contracts are generally designated as cash flow hedges.
Gas Utility and Electric Utility are parties to a number of contracts
that have elements of a derivative instrument. These contracts include, among
others, binding purchase orders, contracts which provide for the delivery of
natural gas, and service contracts that require the counterparty to provide
commodity storage, transportation or capacity service to meet our normal sales
commitments. Although many of these contracts have the requisite elements of a
derivative instrument, these contracts are not subject to the accounting
requirements of SFAS 133 because they provide for the delivery of products or
services in quantities that are expected to be used in the normal course of
operating our business or the value of the contract is directly associated with
the price or value of a service. The adoption of SFAS 133 did not materially
impact Gas Utility's and Electric Utility's results of operations or financial
position during the year ended September 30, 2001.
We use fixed-rate long-term debt as a source of capital. When these long-term
debt issues mature, we often refinance them with fixed-rate debt bearing
then-existing market interest rates. On occasion, we enter into interest rate
protection agreements
44
UGI Corporation 2001 Annual Report
("IRPAs") to reduce market interest rate risk associated with these forecasted
debt issuances. We designate these IRPAs as cash flow hedges. Gains or losses on
IRPAs are included in other comprehensive income and are reclassified to
interest expense as the interest expense on the associated debt issue affects
earnings.
During the year ended September 30, 2001, the net gain or loss
recognized in earnings representing cash flow hedge ineffectiveness was not
material. The amount of cash flow hedge gains reclassified to net income because
it became probable that the original forecasted transactions would not occur was
$1.0 million which amount is included in other income.
Gains and losses included in accumulated other comprehensive income at
September 30, 2001 relating to cash flow hedges will be reclassified into (1)
cost of sales when the forecasted purchase of propane or natural gas subject to
the hedges impacts net income and (2) interest expense when interest on
anticipated issuances of fixed-rate long-term debt is reflected in net income.
Included in accumulated other comprehensive loss at September 30, 2001 are net
losses of approximately $0.7 million from IRPAs associated with forecasted
issuances of ten-year debt. The amount of this net loss which is expected to be
reclassified into net income during the next twelve months is not material. The
remaining net loss on derivative instruments included in accumulated other
comprehensive loss at September 30, 2001 of $13.0 million is principally
associated with future purchases of natural gas or propane generally anticipated
to occur during the next twelve months. The actual amount of gains or losses on
unsettled derivative instruments that ultimately is reclassified into net income
will depend upon the value of such derivative contracts when settled. The fair
value of derivative instruments is included in other current assets, other
current liabilities and other noncurrent liabilities in the September 30, 2001
Consolidated Balance Sheet.
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:
[Download Table]
Carrying Estimated
Amount Fair Value
------ ----------
2001:
Natural gas futures contracts $ (1.5) $ (1.5)
Propane swap, option and forward sales contracts (10.5) (10.5)
Interest rate protection agreements (3.0) (3.0)
Available for sale securities 18.3 18.3
Long-term debt 1,295.2 1,386.5
UGI Utilities Series Preferred Stock 20.0 21.4
2000:
Natural gas futures contracts $ -- $ 4.2
Propane swap, option and forward sales contracts 1.0 6.5
Interest rate protection agreements -- 2.5
Long-term debt 1,115.6 1,135.9
UGI Utilities Series Preferred Stock 20.0 21.0
-------- --------
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. The estimated fair value of UGI Utilities Series Preferred Stock is
based on the fair value of redeemable preferred stock with similar credit
ratings and redemption features. Fair values of derivative instruments reflect
the estimated amounts that we would receive or pay to terminate the contracts at
the reporting date based upon quoted market prices of comparable contracts at
September 30, 2001 and 2000.
We have financial instruments such as short-term investments and trade
accounts receivable, which could expose us to concentrations of credit risk. We
limit our credit risk from short-term investments by investing only in
investment-grade commercial paper and in U.S. Government securities. The credit
risk from trade accounts receivable is limited because we have a large customer
base, which extends across many different U.S. markets. We attempt to minimize
our credit risk associated with our derivative financial instruments through the
application of credit policies.
NOTE 15 - PROVISION FOR EXIT COSTS - HEARTH USA(TM)
In September 2001, after evaluating the prospects for Hearth USA(TM) in light of
the weak retail environment and the capital required to expand beyond its
two-store pilot phase, we committed to close both of its stores and cease all
operations by the end of October 2001. Hearth USA(TM) sold, installed and
serviced hearth, grill and spa products and sold related accessories from two
superstores located in Rockville, Maryland and Springfield, Virginia. As a
result of this action, in September 2001 we recorded a pre-tax charge of $8.5
million which is included in the 2001 Consolidated Statement of Income as
"Provision for exit costs - Hearth USA(TM)." The pre-tax charge includes $3.7
million associated with fixed asset write-downs, estimated lease commitment
obligations of $3.2 million, and other incremental costs totaling $1.6 million.
The charge decreased 2001 net income by $5.5 million or $0.20 per basic and
diluted share.
NOTE 16 - OTHER INCOME, NET
Other income, net, comprises the following:
[Download Table]
2001 2000 1999
---- ---- ----
Interest and interest-related income $ (6.7) $ (9.3) $ (8.5)
Gain on sales of investments -- (1.8) --
Equity investment loss 2.1 0.9 0.3
Gain on sales of fixed assets (2.4) (3.6) (2.2)
Pension income (5.9) (3.0) (2.3)
Other (8.5) (10.1) (4.1)
------- ------- -------
Total other income, net $ (21.4) $ (26.9) $ (16.8)
------- ------- -------
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 17 - TERMINATED MERGER - UNISOURCE WORLDWIDE, INC.
On May 25, 1999, we announced that Unisource Worldwide, Inc. ("Unisource") had
entered into a merger agreement with Georgia-Pacific Corp. ("GP") and that it
would allow Unisource to terminate the previously announced Agreement and Plan
of Merger (the "Merger Agreement") among Unisource, UGI and Vulcan Acquisition
Corp. (a wholly owned subsidiary of UGI) which would have provided for the
merger of UGI and Unisource. Because the board of directors of Unisource decided
to enter into a merger agreement with GP, Unisource was required to pay us a $25
million merger termination fee pursuant to the terms of the Merger Agreement. We
received the termination fee on May 28, 1999. The fee, net of related merger
expenses, is classified as merger fee income and expenses, net, in the 1999
Consolidated Statement of Income.
NOTE 18 - QUARTERLY DATA (UNAUDITED)
[Enlarge/Download Table]
December 31, March 31, June 30, September 30,
2000 1999 2001 2000(a) 2001 2000 2001(b) 2000(c)
---- ---- ---- ------- ---- ---- ------- -------
Revenues $ 737.1 $ 466.6 $ 943.8 $ 610.4 $ 411.9 $ 335.9 $ 375.3 $ 348.8
Operating income (loss) $ 92.0 $ 70.7 $ 142.6 $ 117.9 $ 8.4 $ 8.7 $ (15.6) $ (6.1)
Income (loss) before changes in accounting $ 27.1 $ 21.1 $ 45.5 $ 38.8 $ (4.3) $ (4.7) $ (16.3) $ (10.5)
Cumulative effect of accounting changes, net (d) 4.5 -- -- -- -- -- -- --
------- ------- ------- -------- ------- ------- ------- -------
Net income (loss) $ 31.6 $ 21.1 $ 45.5 $ 38.8 $ (4.3) $ (4.7) $ (16.3) $ (10.5)
------- ------- ------- -------- ------- ------- ------- -------
Earnings per share:
Basic:
Income (loss) before accounting changes $ 1.00 $ 0.77 $ 1.68 $ 1.42 $ (0.16) $ (0.17) $ (0.60) $ (0.39)
Cumulative effect of accounting changes, net (d) 0.17 -- -- -- -- -- -- --
------- ------- ------- -------- ------- ------- ------- -------
Net income (loss) $ 1.17 $ 0.77 $ 1.68 $ 1.42 $ (0.16) $ (0.17) $ (0.60) $ (0.39)
------- ------- ------- -------- ------- ------- ------- -------
Diluted:
Income (loss) before accounting changes $ 1.00 $ 0.77 $ 1.67 $ 1.42 $ (0.16) $ (0.17) $ (0.60) $ (0.39)
Cumulative effect of accounting changes, net (d) 0.16 -- -- -- -- -- -- --
------- ------- ------- -------- ------- ------- ------- -------
Net income (loss) $ 1.16 $ 0.77 $ 1.67 $ 1.42 $ (0.16) $ (0.17) $ (0.60) $ (0.39)
------- ------- ------- -------- ------- ------- ------- -------
The quarterly data above includes all adjustments (consisting only of normal
recurring adjustments with the exception of those indicated below) that we
consider necessary for a fair presentation. Our quarterly results fluctuate
because of the seasonal nature of our business.
(a) Includes income from a litigation settlement which increased operating
income by $2.4 million and net income by $1.4 million or $0.05 per share.
(b) Includes shut-down costs associated with Hearth USA(TM) which increased
operating loss by $8.5 million and net loss by $5.5 million or $0.20 per share.
(c) Includes income from a litigation settlement which decreased operating loss
by $2.1 million and net loss by $1.2 million or $0.04 per share.
(d) Includes the impact of changes in accounting associated with (1) the
Partnership's changes in accounting for tank fee revenue and tank installation
costs, and (2) the Company's adoption of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities."
46
UGI Corporation 2001 Annual Report
NOTE 19 - SEGMENT INFORMATION
We have organized our business units into five reportable segments generally
based upon products sold, geographic location (domestic or international) or
regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2)
Gas Utility; (3) Electric Utility (including our nonutility electricity
generation business); (4) Energy Services; and (5) an international propane
segment comprising FLAGA and our international propane equity investments
("International Propane").
AmeriGas Propane derives its revenues principally from the sale of
propane and related equipment and supplies to retail customers from locations in
46 states. Gas Utility's revenues are derived principally from the sale and
distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Utility derives its revenues principally from the sale
and distribution of electricity in two northeastern Pennsylvania counties.
Energy Services revenues are derived from the sale of natural gas and, to a
lesser extent, electricity and fuel oil to customers located primarily in the
Middle Atlantic region. Our International Propane segment's revenues are derived
principally from the distribution of propane to retail customers in Austria, the
Czech Republic and Slovakia.
The accounting policies of our reportable segments are the same as
those described in Note 1. We evaluate our AmeriGas Propane and International
Propane segments' performance principally based upon earnings before interest
expense, income taxes, depreciation and amortization ("EBITDA"). We evaluate the
performance of our Gas Utility, Electric Utility and Energy Services segments
principally based upon their earnings before income taxes.
No single customer represents more than ten percent of our consolidated
revenues and there are no significant intersegment transactions. In addition,
all of our reportable segments' revenues, other than those of our International
Propane segment, are derived from sources within the U.S., and all of our
reportable segments' long-lived assets, other than those of our International
Propane segment, are located in the U.S.
Financial information by business segment follows:
[Enlarge/Download Table]
Inter- Other Corp-
Elimi- AmeriGas Gas Electric Energy national Enter- orate &
Total nations Propane Utility Utility Services Propane prises Other
----- ------- ------- ------- ------- -------- ------- ------ -----
2001
Revenues $2,468.1 $ (2.8) $1,418.4 $ 500.8 $ 83.9 $ 370.7 $ 50.9 $ 43.4 $ 2.8
EBITDA $ 332.6 $ (1.1) $ 209.3 $ 108.0 $ 14.3 $ 7.6 $ 3.6 $ (12.5)(a) $ 3.4
Depreciation and amortization (105.2) -- (75.5) (20.2) (3.6) (0.3) (4.3) (1.1) (0.2)
-------- ------- -------- ------- ------- ------- ------- ------- -------
Operating income (loss) 227.4 (1.1) 133.8 87.8 10.7 7.3 (0.7) (13.6) 3.2
Interest expense (104.8) 1.1 (80.3) (16.3) (2.7) (0.4) (4.9) (0.7) (0.6)
Minority interest (23.6) -- (23.6) -- -- -- -- -- --
-------- ------- -------- ------- ------- ------- ------- ------- -------
Income (loss) before income taxes $ 99.0 $ -- $ 29.9 $ 71.5 $ 8.0 $ 6.9 $ (5.6) $ (14.3) $ 2.6
Total assets $2,550.2 $ (43.3) $1,522.3 $ 678.9 $ 105.5 $ 44.7 $ 141.2 $ 23.7 $ 77.2
Capital expenditures $ 79.3 $ -- $ 39.2(b) $ 31.8 $ 5.0 $ 0.2 $ 2.7 $ 0.4 $ --
Investments in equity investees $ 41.6 $ -- $ -- $ -- $ 10.8 $ -- $ 30.8 $ -- $ --
======== ======= ======== ======= ======= ======= ======= ======= =======
2000
Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9 $ 50.5 $ 7.3 $ 3.1
EBITDA $ 288.7 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0 $ 1.9 $ (5.0) $ 5.3
Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2) (4.6) (0.5) (0.2)
-------- ------- -------- ------- ------- ------- ------- ------- -------
Operating income (loss) 191.2 -- 90.2 86.2 15.1 2.8 (2.7) (5.5) 5.1
Interest expense (98.5) -- (74.7) (16.2) (2.2) -- (4.8) -- (0.6)
Minority interest (6.3) -- (6.3) -- -- -- -- -- --
-------- ------- -------- ------- ------- ------- ------- ------- -------
Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8 $ (7.5) $ (5.5) $ 4.5
Total assets $2,275.8 $ (19.0) $1,281.7 $ 653.7 $ 97.4 $ 36.2 $ 113.7 $ 28.2 $ 83.9
Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1 $ 1.8 $ 2.3 $ --
Investments in equity investees $ 5.5 $ -- $ -- $ -- $ -- $ -- $ 5.5 $ -- $ --
======== ======= ======== ======= ======= ======= ======= ======= =======
1999
Revenues $1,383.6 $ (2.3) $ 872.5 $ 345.6 $ 75.0 $ 90.4 $ -- $ 0.1 $ 2.3
EBITDA $ 265.6 $ -- $ 158.8 $ 87.0 $ 16.7 $ 2.7 $ (0.1) $ (5.7) $ 6.2
Depreciation and amortization (89.7) -- (66.3) (19.0) (4.0) (0.1) -- -- (0.3)
-------- ------- -------- ------- ------- ------- ------- ------- -------
Operating income (loss) 175.9 -- 92.5 68.0 12.7 2.6 (0.1) (5.7) 5.9
Merger fee income, net 19.9 -- -- -- -- -- -- -- 19.9
Interest expense (84.6) -- (66.5) (15.2) (2.3) -- -- -- (0.6)
Minority interest (10.7) -- (10.7) -- -- -- -- -- --
-------- ------- -------- ------- ------- ------- ------- ------- -------
Income (loss) before income taxes $ 100.5 $ -- $ 15.3 $ 52.8 $ 10.4 $ 2.6 $ (0.1) $ (5.7) $ 25.2
Total assets $2,140.5 $ (15.6) $1,221.9 $ 620.4 $ 95.3 $ 17.4 $ 143.2 $ 3.7 $ 54.2
Capital expenditures $ 73.7 $ -- $ 34.6(b) $ 31.9 $ 4.5 $ 0.2 $ -- $ 2.5 $ --
Investments in equity investees $ 6.3 $ -- $ -- $ -- $ -- $ -- $ 6.3 $ -- $ --
======== ======= ======== ======= ======= ======= ======= ======= =======
(a)Includes Hearth USA(TM) shut-down costs of $8.5 million.
(b)Includes capital leases of $1.3 million and $3.5 million in 2001 and 1999,
respectively.
47
Dates Referenced Herein and Documents Incorporated by Reference
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