1
Exhibit 13
UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
FINANCIAL REVIEW
BUSINESS OVERVIEW
Our domestic propane business is conducted through AmeriGas Partners, L.P.
("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the
"Operating Partnership"). We refer to AmeriGas Partners and the Operating
Partnership together as "the Partnership." At September 30, 2000, we held an
effective 58.4% interest in the Operating Partnership.
UGI Utilities, Inc. ("UGI Utilities") operates a natural gas distribution
utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an
electric distribution utility and electricity generation business ("Electric
Utility") in northeastern Pennsylvania. Gas Utility and Electric Utility are
together referred to as "Utilities."
UGI Enterprises, Inc. ("Enterprises"), our "new business" arm, conducts an
energy marketing business ("Energy Services") and through other subsidiaries (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 ("HVAC") and a retail hearth, spa and grill
products business in the Middle Atlantic states ("Hearth USA(TM)"); and (3)
participates in international propane joint-venture projects.
This Financial Review should be read in conjunction with our Consolidated
Financial Statements and Notes to Consolidated Financial Statements including
the business segment information in Note 17.
RESULTS OF OPERATIONS
2000 COMPARED WITH 1999
CONSOLIDATED RESULTS. Our 2000 results reflect improved earnings from 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 1999, earnings per share increased 22% in 2000 reflecting a 15%
decline in average shares outstanding and higher net income.
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)
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 (a) (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 (b) -- -- 12.9 0.40 (12.9) (0.40)
- --------------------------------------------------------------------------------------------------------------------------
Total $ 44.7 $ 1.64 $ 55.7 $ 1.74 $ (11.0) $ (0.10)
- --------------------------------------------------------------------------------------------------------------------------
(a) Comprised principally of Hearth USA(TM), HVAC, and Enterprises' corporate
and general expenses.
(b) 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 14 to Consolidated Financial Statements.
SEGMENT RESULTS. The following table presents certain financial and statistical
information by business segment for 2000 and 1999:
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 (a) $ 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 (b) 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 (a) $ 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 (c)
Revenues $ 77.9 $ 75.0 $ 2.9 3.9%
Total margin $ 40.5 $ 38.6 $ 1.9 4.9%
EBITDA (a) $ 19.6 $ 16.7 $ 2.9 17.4%
Operating income $ 15.1 $ 12.7 $ 2.4 18.9%
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 (a) $ 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 (a) $ 1.9 $ (0.1) $ 2.0 N.M.
Operating loss $ (2.7) $ (0.1) $ 2.6 N.M.
- -------------------------------------------------------------------------------------------
N.M. - Not Meaningful
(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 generally accepted accounting principles.
(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.
(c) Electric Utility comprises the Company's regulated electric utility
distribution business and its nonutility electric generation operations.
13
2
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
AMERIGAS PROPANE. Based upon national heating degree day information,
temperatures in 2000 were 13.7% warmer than normal and 3.8% warmer than in 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 our growing grill cylinder exchange business, PPX Prefilled Propane Xchange
("PPX(R)"), and acquisition-related volume increases.
Total revenues from retail propane sales increased $160.5 million in 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
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 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 2000 was comparable to 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 2000 compared with $329.6 million in 1999 reflecting
incremental expenses from growth and operational initiatives and higher vehicle
fuel costs. Our growth and operational initiatives in 2000 included
significantly expanding PPX(R), acquiring retail propane businesses, and
developing and implementing more efficient methods of operating the business.
Although EBITDA in 2000 was about equal to 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 2000 but 3.8% colder than in 1999. The increase in system throughput
during 2000 resulted from higher interruptible delivery service volumes and
higher sales to our firm retail ("core market") customers.
The increase in Gas Utility's revenues during 2000 principally resulted from
(1) a $13.1 million increase in core market revenues reflecting higher sales and
higher average purchased gas cost ("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 2000 compared with $172.0 million
in 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 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 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 2000 from $33.2 million in
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 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 2000 were slightly higher than in
1999 due to the impact of the higher sales on total margin.
14
3
UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
INTERNATIONAL PROPANE. International Propane results include equity in our joint
venture projects in Romania and China and, in 2000, the results of FLAGA. The
results of FLAGA during 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 2000 from our China propane joint venture partnership was also
negatively impacted by higher propane product costs and customer conservation.
CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income in
2000 was $5.1 million, a decrease of $0.8 million from 1999, primarily
reflecting lower interest income on cash investments. Other Enterprises' results
in 2000 primarily reflect start-up costs and initial operating losses of Hearth
USA(TM). Results in 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 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 2000. The effective income tax rate was 46.4% in 2000 compared to
43.0% in 1999 which rate reflected a lower tax rate on merger termination fee
income.
1999 COMPARED WITH 1998
CONSOLIDATED RESULTS. Our consolidated net income in 1999 increased $15.4
million compared to 1998. The improvement in net income was due to one-time net
merger termination fee income of $12.9 million and higher net income from UGI
Utilities and AmeriGas Partners, offset in part by costs associated with
Enterprises' new business activities.
Variance-
Favorable
1999 1998 (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 $ 1.9 $ 0.06 $ 2.6 $ 0.08
Utilities 37.4 1.17 33.0 1.00 4.4 0.17
Energy Services 1.5 0.05 1.1 0.03 0.4 0.02
International Propane (0.1) - (0.5) (0.01) 0.4 0.01
Other Enterprises (3.6) (0.11) (1.3) (0.04) (2.3) (0.07)
Corporate & Other 3.1 0.09 6.1 0.18 (3.0) (0.09)
Merger termination
fee, net 12.9 0.40 - - 12.9 0.40
- --------------------------------------------------------------------------------------------------------------------------
Total $ 55.7 $ 1.74 $ 40.3 $ 1.22 $ 15.4 $ 0.52
- --------------------------------------------------------------------------------------------------------------------------
SEGMENT RESULTS. The following table presents certain financial and statistical
information by business segment for 1999 and 1998:
Increase
1999 1998 (Decrease)
- -------------------------------------------------------------------------------------------
(Millions of dollars)
AMERIGAS PROPANE
Revenues $872.5 $914.4 $(41.9) (4.6)%
Total margin $481.7 $470.6 $ 11.1 2.4%
EBITDA $158.8 $153.3 $ 5.5 3.6%
Operating income $ 92.5 $ 87.9 $ 4.6 5.2%
Retail gallons sold (millions) 783.2 785.3 (2.1) (0.3)%
Degree days - % warmer than normal 9.9% 8.7% - -
GAS UTILITY
Revenues $345.6 $350.2 $ (4.6) (1.3)%
Total margin $160.6 $157.2 $ 3.4 2.2%
EBITDA $ 87.0 $ 83.0 $ 4.0 4.8%
Operating income $ 68.0 $ 64.8 $ 3.2 4.9%
System throughput - bcf 76.1 74.9 1.2 1.6%
Degree days - % warmer than normal 12.8% 16.3% - -
ELECTRIC UTILITY
Revenues $ 75.0 $ 72.1 $ 2.9 4.0%
Total margin $ 38.6 $ 34.0 $ 4.6 13.5%
EBITDA $ 16.7 $ 13.6 $ 3.1 22.8%
Operating income $ 12.7 $ 9.7 $ 3.0 30.9%
Sales - gwh 900.4 876.4 24.0 2.7%
ENERGY SERVICES
Revenues $ 90.4 $103.0 $(12.6) (12.2)%
Total margin $ 6.0 $ 4.7 $ 1.3 27.7%
EBITDA $ 2.7 $ 2.1 $ 0.6 28.6%
Operating income $ 2.6 $ 2.0 $ 0.6 30.0%
INTERNATIONAL PROPANE
EBITDA $ (0.1) $ (1.0) $ 0.9 90.0%
Operating loss $ (0.1) $ (1.0) $ (0.9) (90.0)%
AMERIGAS PROPANE. Based upon national weather data, temperatures in 1999 were
9.9% warmer than normal and 1.3% warmer than in 1998. Retail volumes of propane
sold were slightly lower in 1999 primarily as a result of a 7.3 million decline
in agricultural gallons as a dry autumn reduced demand for crop drying.
Partially offsetting the decrease in agricultural gallons were higher motor fuel
sales, increased gallons sold through PPX(R), and, notwithstanding the warmer
weather, higher sales to our targeted residential customer market.
Total revenues from retail propane sales declined $36.3 million in 1999
primarily due to lower average selling prices. The lower
15
4
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
average selling prices resulted from lower propane product costs. Wholesale
propane revenues declined $13.2 million reflecting (1) a $6.9 million decrease
as a result of lower average wholesale prices and (2) a $6.3 million decrease as
a result of lower wholesale volumes sold. Nonpropane revenues increased $7.6
million in 1999 reflecting higher appliance and cylinder sales, increased
terminal and hauling revenues, and greater customer fee revenues. Cost of sales
declined $53.0 million primarily as a result of lower propane product costs.
Total margin increased $11.1 million in 1999 due to (1) slightly higher
average retail unit margin per gallon; (2) greater total margin from PPX; and
(3) an increase in total margin from appliance sales, customer fees and hauling
and terminal revenue.
EBITDA and operating income were higher in 1999 as a result of (1) the higher
total margin and (2) higher other income. These increases were partially offset
by an increase in operating expenses. Other income, net, in 1998 included a $4.0
million loss from two interest rate protection agreements. Operating expenses of
the Partnership were $329.6 million in 1999 compared with $320.2 million in
1998. Operating expenses in 1998 are net of (1) $2.7 million of income from
lower required accruals for environmental matters and (2) $2.0 million of income
from lower required accruals for property taxes. Excluding the impact of these
items in the prior year, operating expenses of the Partnership increased $4.7
million in 1999 principally due to expenses associated with new business
initiatives.
GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than
normal in 1999 but 4.2% colder than in 1998. Total system throughput increased
1.6% as a result of the slightly colder weather as well as an increase in total
customers.
The decrease in Gas Utility revenues in 1999 is principally due to several of
our core market industrial customers switching from retail to delivery service.
Under retail service, we bill our customers for the transportation of gas
through our distribution system as well as the cost of the gas, for which we get
dollar-for-dollar recovery. Under delivery service, we bill customers for the
transportation of the gas but not for the gas itself. Our revenues from
customers who switch to delivery service are therefore lower, but there is
little impact on our total margin. Partially offsetting the decline in revenues
from our core market industrial customers was an increase in revenues from sales
to our core market residential and commercial customers. Gas Utility cost of gas
was $172.0 million in 1999, a decrease of $7.6 million from 1998, reflecting the
impact of core market industrial customers switching to delivery service.
The increase in Gas Utility total margin in 1999 includes a $3.6 million
increase from sales to our core market residential and commercial customers.
Total margin from interruptible customers (who have the ability to switch to
alternate fuels, principally oil) was slightly lower in 1999. The decline in
total margin from our interruptible customers reflects lower interruptible rates
due to a decline in the spread between oil and natural gas prices during most of
1999.
Gas Utility operating income was higher in 1999 reflecting the increase in
total margin and higher other income partially offset by slightly higher
operating and administrative expenses and increased charges for depreciation.
Operating expenses in 1998 are net of $1.6 million of income from an insurance
recovery. Excluding the impact of the insurance recovery in 1998, total Gas
Utility operating and administrative expenses in 1999 were essentially
unchanged.
ELECTRIC UTILITY. The increase in 1999 sales of electricity reflects slightly
colder heating season weather and warmer weather during the summer air
conditioning season. Electric Utility revenues increased $2.9 million in 1999
principally as a result of the higher sales. Although Electric Utility's
Restructuring Order filed pursuant to Pennsylvania's Electricity Customer Choice
Act gives all of our customers the ability to choose their electricity
generation supplier effective January 1, 1999, only approximately 5% of our
sales during 1999 represented electricity we distributed for alternate
suppliers. Notwithstanding the increase in Electric Utility sales in 1999, cost
of sales decreased $1.8 million to $33.2 million. The impact of the higher 1999
sales on purchased power costs was more than offset by (1) the benefit of a
power supply agreement settlement and (2) lower average purchased power costs
Electric Utility's total margin increased $4.6 million as a result of (1) the
power supply agreement settlement; (2) lower average purchased power costs; and
(3) the higher sales. EBITDA and operating income were also higher as the
greater total margin was partially offset by higher maintenance costs associated
with our generation assets, higher customer service and information expenses,
and lower other income.
ENERGY SERVICES. Total revenues from energy marketing in 1999 declined $12.6
million as a result of lower average gas prices and, to a lesser extent, a
decrease in billed volumes. Total margin increased $1.3 million reflecting
higher average margins from gas marketing and greater income from power
marketing and other services. EBITDA and operating income increased $0.6 million
in 1999 as a result of the higher margin offset by slightly higher operating
expenses.
INTERNATIONAL PROPANE. Results for 1999 and 1998 principally reflect the equity
results in our international propane joint venture projects.
CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income
was $5.9 million in 1999 compared with $8.6 million in 1998. Income in both
years principally comprises inter-
16
5
UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
est income on short-term investments and, in 1998, income from the sale of
certain equity securities. The decrease in operating income from Other
Enterprises in 1999 resulted from start-up costs associated with Hearth USA(TM)
retail and due diligence expenses associated with international propane business
opportunities.
INTEREST EXPENSE AND INCOME TAXES. The Company's interest expense in 1999 was
$84.6 million, comparable to the $84.4 million recorded in 1998. The effective
income tax rate in 1999 was 43.0% compared to an effective tax rate of 44.7% in
1998. The lower effective tax rate in 1999 is principally a result of a lower
tax rate on the merger termination fee income.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Our cash and short-term investments totaled $101.7 million at September 30, 2000
compared with $55.6 million at September 30, 1999. Included in these amounts are
$56.3 million and $23.3 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 wholly owned 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 2000, 1999 and 1998, AmeriGas, Inc. and UGI
Utilities paid cash dividends to UGI as follows:
Year Ended September 30, 2000 1999 1998
- ---------------------------------------------------------------
(Millions of dollars)
AmeriGas $51.6 $47.6 $55.2
UGI Utilities 44.0 29.0 22.6
- ---------------------------------------------------------------
Total dividends to UGI $95.6 $76.6 $77.8
- ---------------------------------------------------------------
THE PARTNERSHIP. The Operating Partnership's primary sources of cash since its
formation in 1995 have been (1) cash generated by operations; (2) borrowings
under its Bank Credit Agreement; and (3) the issuance of $80 million of
long-term debt in 2000 and $70 million of long-term debt in 1999. On September
22, 2000, a shelf registration statement for the issuance of 9 million AmeriGas
Common Units was declared effective by the Securities and Exchange Commission.
In October 2000, the Partnership issued 2.3 million of its registered Common
Units in an underwritten public offering and received $40.6 million in cash
proceeds, including related capital contributions from our wholly owned,
second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"). These
proceeds were used to reduce Bank Credit Agreement indebtedness and for working
capital purposes.
The Operating Partnership's Bank Credit Agreement, as amended, consists of
(1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition
Facility. The Revolving Credit Facility may be used for (1) working capital; (2)
capital expenditures; and (3) interest and Partnership distribution payments.
Revolving Credit Facility loans were $30 million at September 30, 2000 and $22
million at September 30, 1999. The Operating Partnership may borrow under its
Acquisition Facility to finance the purchase of propane businesses or propane
business assets. Loans outstanding under the Acquisition Facility at September
30, 2000 and 1999 were $70 million and $23 million, respectively. During 2000,
the Bank Credit Agreement was amended to, among other changes, extend the
Acquisition Facility termination date to September 15, 2002. Then-outstanding
borrowings under the Acquisition Facility will be due in their entirety on such
date.
The Operating Partnership also has a credit agreement with the General
Partner to borrow up to $20 million on an unsecured, subordinated basis, to fund
(1) working capital; (2) capital expenditures; and (3) interest and Partnership
distribution payments. UGI has agreed to contribute up to $20 million to the
General Partner to fund such borrowings.
During 2000, the Operating Partnership issued $80 million of Series E First
Mortgage Notes at an effective interest rate of 8.47%. The proceeds were used
principally to reduce Acquisition Facility borrowings and $10 million of
maturing First Mortgage Note debt.
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 2001. For a more detailed discussion of the Partnership's credit
facilities, including financial covenant ratios, see Note 3.
UGI UTILITIES. UGI Utilities' primary sources of cash have been (1) cash
generated by operations; (2) borrowings under its revolving credit agreements;
and (3) debt issued under its Medium-Term Note program. UGI Utilities can issue
up to an additional $52 million under its Medium-Term Note program.
UGI Utilities may borrow up to a total of $122 million under its revolving
credit agreements. Borrowings under revolving credit agreements totaled $100.4
million at September 30, 2000 and $87.4 million at September 30, 1999.
Management believes that UGI Utilities' cash flow from operations and
borrowings under its Medium-Term Note program and
17
6
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
bank credit facilities will satisfy UGI Utilities' cash needs in fiscal 2001.
For a more detailed discussion of UGI Utilities' debt and credit facilities,
including financial covenants and ratios, see Note 3.
FLAGA. FLAGA has a 9 million EURO working capital loan commitment and a 15
million EURO special purpose commitment from a foreign bank. Borrowings under
these commitments totaled 4.9 million EUROs and 13.5 million EUROs,
respectively, at September 30, 2000. Management believes that cash flow from
operations and borrowings under its special purpose facility, working capital
facility and a short-term credit facility from UGI will satisfy FLAGA's cash
needs in fiscal 2001.
CASH FLOWS
OPERATING ACTIVITIES. Cash flow from operating activities was $132.7 million in
2000 compared to $141.9 million in 1999 which included $12.9 million of
after-tax proceeds from the merger termination fee. As a result of significantly
higher propane and natural gas costs, cash flows from operating activities in
2000 reflect significantly higher accounts receivable, inventories and accounts
payable. Cash flow from operating activities before changes in operating working
capital declined modestly from $170.3 million in 1999 to $167.5 million in 2000.
INVESTING ACTIVITIES. We spent $71.0 million for property, plant and equipment
in 2000 compared with $70.2 million in 1999. The increase in 2000 resulted from
expenditures of FLAGA. Net cash paid for acquisitions, principally comprising
Partnership propane and HVAC business acquisitions, totaled $65.3 million in
2000 compared to $77.6 million in 1999 including $73.7 million for the purchase
of FLAGA.
FINANCING ACTIVITIES. We paid cash dividends on our Common Stock of $41.2
million in 2000 compared to $47.9 million in 1999 on fewer shares outstanding.
In 2000 and 1999, the Partnership paid (1) distributions to its public
unitholders totaling approximately $39 million; (2) the full minimum quarterly
distribution of $0.55 ("MQD") on all units we hold totaling $53.2 million; and
(3) $1.1 million to the General Partner. During 2000, the Operating Partnership
borrowed $116 million under the Acquisition Facility, and made Acquisition
Facility repayments totaling $69 million. In 2000, we used $9.6 million to
repurchase 0.5 million shares of UGI Common Stock. In 1999, we spent $133.1
million (including transaction costs) for the repurchase of 5.9 million shares
of UGI Common Stock, including 4.5 million shares repurchased through our Dutch
auction tender offer.
DIVIDENDS AND DISTRIBUTIONS
In April 2000, our board of directors increased the annual dividend rate to
$1.55 a share from $1.50. Dividends declared in 2000 totaled $41.4 million.
At September 30, 2000, our 58.4% effective 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 41.6% effective interest
consists of 17.8 million publicly held Common Units. As a result of the
Partnership's October 2000 issue of 2.3 million Common Units pursuant to a
public offering, our effective interest in the Partnership declined to 55.5%.
Approximately 45 days after the end of each fiscal quarter, the Partnership
distributes all of its Available Cash (as defined in the 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 2000, 1999 and 1998
was approximately $94 million. In fiscal 2001, as a result of the additional
Common Units issued in October 2000, this amount will increase to approximately
$99 million. One measure of the amount of cash available for distribution that
is generated by the Partnership can be determined by subtracting (1) cash
interest expense and (2) capital expenditures needed to maintain operating
capacity, from the Partnership's EBITDA. Partnership distributable cash flow as
calculated for 2000, 1999 and 1998 is as follows:
Year Ended September 30, 2000 1999 1998
- ------------------------------------------------------------------
(Millions of dollars)
EBITDA $157.6 $157.5 $151.1
Cash interest expense (a) (76.7) (68.3) (67.6)
Maintenance capital expenditures (11.6) (11.1) (10.3)
- ------------------------------------------------------------------
Distributable cash flow $ 69.3 $ 78.1 $ 73.2
- ------------------------------------------------------------------
(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 it is not a measure of performance or financial condition under generally
accepted accounting principles but provides additional information for
evaluating the Partnership's ability to declare and pay the MQD. Although the
18
7
UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
levels of distributable cash flow in these years were less than the full MQD,
borrowings in 2000 and 1999, and cash generated from changes in working capital
in 1998, were more than sufficient to permit the Partnership to declare and pay
the full MQD. The ability of the Partnership to declare and 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.
CONVERSION OF SUBORDINATED UNITS
Pursuant to the Partnership Agreement, a total of 9,891,074 Subordinated Units
held by the General Partner were converted to Common Units on May 18, 1999
because certain historical and projected cash generation-based requirements were
achieved as of March 31, 1999. The Partnership's ability to attain the
cash-based performance and distribution requirements necessary to convert the
remaining 9,891,072 Subordinated Units depends upon a number of factors,
including highly seasonal operating results, changes in working capital, asset
sales and debt refinancings. Due to significantly warmer-than-normal weather and
the impact of higher propane product costs on working capital, we did not
achieve the cash-based performance requirements as of any relevant quarter
through September 30, 2000. Due to the historical "look-back" provisions 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 March 31, 2002.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures of our consolidated
operations (which include expenditures for capital leases but exclude
acquisitions) for 2000, 1999 and 1998. We also provide amounts we expect to
spend in fiscal 2001. We expect to finance a substantial portion of fiscal 2001
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.
Year Ended September 30, 2001 2000 1999 1998
- ----------------------------------------------------------------------
(Millions of dollars) (estimate)
AmeriGas Propane $28.9 $30.4 $34.6 $31.9
Utilities 40.9 36.4 36.4 37.2
International Propane 2.9 1.8 - -
Other 2.2 2.4 2.7 0.1
- ----------------------------------------------------------------------
Total $74.9 $71.0 $73.7 $69.2
- ----------------------------------------------------------------------
UTILITY MATTERS
On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act ("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") like Gas Utility may
continue to sell gas to customers, and such sales of gas, as well as
distribution services provided by LDCs, continue to be subject to price
regulation by the Pennsylvania Public Utility Commission ("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. LDCs are generally precluded from increasing rates for
the recovery of costs, other than gas costs, until January 1, 2001. 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. The PUC, however, may only grant the petition if certain
findings are made and 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 substantially as filed. Among other things, the
restructuring plan (1) provides for recovery of costs associated with existing
pipeline capacity and gas supply contracts; (2) increases Gas Utility's base
rates for firm customers; and (3) changes the calculation of the PGC rates. The
effect of (2) and (3) above is to reduce the financial impact of volatility in
revenues from customers who have the ability to switch to an alternate fuel
under interruptible rates and increase our sensitivity to changes in weather.
Because the Gas Competition Act requires alternate suppliers to accept
assignment of a portion of the LDC's pipeline capacity and storage contracts, we
do not believe the Gas Competition Act and the Gas Restructuring Order will have
a material adverse impact on our financial condition or results of operations.
In September 2000, UGI Development Company ("UGIDC"), a subsidiary of UGI
Utilities, agreed to joint venture with a subsidiary of Allegheny Energy, Inc.
("Allegheny") to own and operate electric generation facilities, including
Electric Utility's coal-fired Hunlock Creek generating station ("Hunlock").
Initially, UGIDC will contribute to the joint venture Hunlock, certain related
assets, and approximately $6 million in cash. Allegheny will contribute a
newly-constructed gas-fired combustion turbine generator to be operated at the
existing Hunlock site. Each partner will be entitled
19
8
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
to purchase 50% of the output of the joint venture at cost. The joint venture is
expected to become operational in December 2000.
MANUFACTURED GAS PLANTS
Prior to the general availability of natural gas, in the 1800s through the
mid-1900s, most gas for lighting and heating nationwide was manufactured from
combustibles such as coal, oil and coke. Some constituents of coal tars and
other residues of the manufactured gas process are today considered hazardous
substances under the federal "Comprehensive Environmental Response, Compensation
and Liability Act," or "Superfund Law," and may be present on the sites of
former manufactured gas plants ("MGPs").
UGI Utilities and its former subsidiaries owned and operated a number of
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. By the mid-1930s, UGI Utilities was one of the
largest public utility holding companies in the country. 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 has been notified of several sites outside Pennsylvania on
which (1) gas plants 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 UGI Utilities should not have significant liability
in those instances in which a former subsidiary operated an MGP because UGI
Utilities generally is not legally liable for the obligations of its
subsidiaries. Under certain circumstances, however, a court could find a parent
company liable for environmental damage caused by a subsidiary company when the
parent company either (1) itself operated the facility causing the environmental
damage or (2) otherwise so controlled the subsidiary that the subsidiary's
separate corporate form should be disregarded. There could be, therefore,
significant future costs of an uncertain amount associated with environmental
damage caused by MGPs that UGI Utilities owned or 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 identified 40 sites in Pennsylvania where either (1) UGI
Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at
one time owned the site. Because Gas Utility is currently permitted to include
in rates, through future base rate proceedings, prudently incurred remediation
costs associated with Pennsylvania sites, the Company does not expect its costs
for Pennsylvania sites to be material to future results of operations.
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 2000, UGI Utilities entered
into settlement agreements with several of the insurers and recorded pre-tax
income of $4.5 million.
MARKET RISK DISCLOSURES
Our primary market risk exposures are (1) fluctuations in market prices for
propane, natural gas and electricity; (2) changes in interest rates; and (3)
foreign currency exchange rates.
The Partnership's profitability is sensitive to changes in propane supply
costs, and the Partnership generally attempts to pass on promptly increases in
such costs to customers. There is no assurance, however, that the Partnership
will be able to do so. In order to manage a portion of the Partnership's propane
market price risk, it uses contracts for the forward purchase of propane,
propane fixed-price supply agreements, and derivative commodity instruments such
as price swap and option contracts. Due to competitive and business conditions
in the markets it serves, FLAGA is less able than the Partnership to recover
promptly increases in product costs. FLAGA does not currently use derivative
commodity instruments to hedge propane market risk. 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, we occasionally utilize 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.
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 purchases electricity it does not otherwise pro-
20
9
UGI Corporation 2000 Annual Report
- --------------------------------------------------------------------------------
duce, representing approximately 50% of its electric power needs in 2000, under
power supply arrangements of varying length terms with other producers and on
the spot market. Spot market prices for electricity and, to a lesser extent,
monthly market-based contracts can be volatile, especially during periods of
high demand. Because Electric Utility's generation rates are capped through
approximately December 2002 under its Restructuring Order, any increases in
costs to produce or purchase electricity will negatively impact Electric
Utility's results.
We have market risk exposure from changes in interest rates on floating rate
borrowings under the Operating Partnership's Bank Credit Agreement, UGI
Utilities' revolving credit agreements and substantially all of FLAGA's debt.
These debt agreements have interest rates that are generally indexed to
short-term market interest rates. At September 30, 2000 and 1999, combined
borrowings outstanding under these facilities totaled $282.1 million and $221.0
million, respectively. Based upon average borrowings under these agreements
during 2000 and 1999, an increase in short-term interest rates of 100 basis
points (1%) would have increased interest expense by $2.5 million and $1.2
million, respectively. We also use fixed-rate long-term debt as a source of
capital. As these fixed-rate long-term debt issues mature, we intend to
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. On occasion, we enter into interest rate protection
agreements to reduce interest rate risk associated with a forecasted issuance of
debt.
We do not currently use derivative instruments to hedge foreign currency
exposure associated with our investments in international propane operations,
principally FLAGA. 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. Our exposure to changes in foreign currency exchange
rates has been significantly limited, however, because our net investment in
FLAGA, our principal international propane operation, was financed with EURO
denominated debt.
The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at September 30, 2000 and 1999. 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; (3) interest rates on ten-year
U.S. treasury notes of 100 basis points; and (4) the market price of oil of 10
cents a gallon:
Change in
Fair Value Fair Value
- ------------------------------------------------------------------------
(Millions of dollars)
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)
September 30, 1999:
Propane commodity price risk $2.9 $(2.5)
Natural gas commodity price risk 2.6 (5.2)
Interest rate risk 3.2 (3.8)
Oil commodity price risk (0.2) (0.5)
- ------------------------------------------------------------------------
We expect that adverse changes in the fair value of derivative instruments used
to manage commodity or interest rate market risk would be substantially offset
by gains on the associated underlying transactions.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" ("SFAS 138"), which
addressed a limited number of issues causing implementation difficulties. SFAS
133, as amended, establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires that an entity recognize all
derivative instruments as either assets or liabilities and measure them 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 derivative instruments qualify and are designated as
hedges of the variability in cash flows associated with forecasted transactions,
the effective portion of the gain or loss on such derivative instruments will
generally be reported in other comprehensive income and the ineffective portion,
if any, will be reported in net income. Such amounts recorded in accumulated
other comprehensive income will be reclassified into net income when the
forecasted transaction affects earnings. 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, the gain or loss on the hedging instrument
will be recognized currently in earnings along with changes in the fair value of
the hedged asset, liability or firm commitment attributable to the hedged risk.
21
10
- --------------------------------------------------------------------------------
FINANCIAL REVIEW (continued)
The Company was required to adopt the provisions of SFAS 133 effective
October 1, 2000. Virtually all of the Company's derivative instruments
outstanding as of October 1, 2000 qualify and have been designated as hedging
the variability in cash flows associated with forecasted transactions. The
adoption of SFAS 133 will result 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. Because the Company's
derivative instruments historically have been highly effective in hedging the
exposure to changes in cash flows associated with forecasted purchases or sales
of natural gas and propane, changes in the fair value of propane inventories,
and changes in the risk-free rate of interest on anticipated issuances of
long-term debt, we do not expect the adoption of SFAS 133 to have a material
impact on our future results of operations.
Although the Company expects the derivative instruments it currently uses to
hedge to continue to be highly effective, if they are determined not to be
highly effective in the future, or if the Company uses derivative instruments
that do not meet the stringent requirements for hedge accounting under SFAS 133,
our future earnings could reflect greater volatility. Additionally, if a cash
flow hedge is discontinued because the forecasted transaction is no longer
expected to occur, any gain or loss in accumulated comprehensive income
associated with the hedged transaction will be immediately recognized in net
income.
In order to comply with the provisions of the Securities and Exchange
Commission Staff Accounting Bulletin No. 101 ("SAB 101") entitled "Revenue
Recognition", which is effective for the Company on October 1, 2000, the Company
will record a cumulative effect charge to net income of approximately $2.3
million related to the Partnership's method of recognizing revenue associated
with nonrefundable tank fees largely for residential customers. Consistent with
a number of its competitors in the propane industry, the Partnership receives
nonrefundable fees for installed Partnership-owned tanks. Historically, such
fees, which are generally received annually, were recorded as revenue when
billed. In accordance with SAB 101, effective October 1, 2000, the Partnership
will record such nonrefundable fees on a straight-line basis over one year. The
adoption of SAB 101 is not expected to have a material impact on the Company's
future financial condition or results of operations.
Also, during fiscal 2001, the Partnership plans to change its method of
accounting for tank installation costs which are not billed to customers.
Currently, all direct costs to install Partnership-owned tanks at a customer
location are expensed as incurred. The Partnership believes that these costs
should now be capitalized and amortized over the period benefited. On date of
adoption, this change in accounting method will result in a cumulative effect
increase to net income. The Company is in the process of evaluating the impact
of such change on its financial condition and results of operations.
PROPOSED FOREIGN EQUITY INVESTMENT
On October 30, 2000, the Company, together with Paribas Affaires Industrielles
("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), submitted to Total Fina
Elf S. A. ("TFE"), a large French petroleum and chemical company, a bid to
acquire the stock and certain related assets of Elf AntarGaz S.A. ("EAZ"). EAZ,
a subsidiary of TFE, is one of the largest distributors of liquefied petroleum
gas in France with an approximate 24% market share. Under the terms of the bid,
the Company would acquire a 20% interest in EAZ; PAI a 70% interest; and Medit a
10% interest. PAI is a leading private equity fund manager in Europe and an
affiliate of BNP Partners. BNP Partners is 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. The amount of the Company's
investment in EAZ is not expected to exceed $30 million. The bid is subject to
approval by the Commission of the European Communities. There can be no
assurance, however, that the bid will be approved or that other requirements for
consummation of the transaction will be met.
FORWARD-LOOKING STATEMENTS
Information contained in this Financial Review and elsewhere in this Annual
Report with respect to expected financial results and future events is
forward-looking, based on our estimates and assumptions and subject to risks and
uncertainties. For those statements, we claim the protection of the safe harbor
for forward looking statements contained in the Private Securities Litigation
Reform Act of 1995.
The following important factors could affect our future results and could
cause actual 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 product 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)
22
11
liability for environmental claims; (6) improvements in energy efficiency and
technology resulting in reduced demand; (7) labor relations; (8) large customer
or supplier defaults; (9) operating hazards and risks incidental to generating
and distributing electricity and transporting, storing and distributing natural
gas and propane including the risk of explosions and fires resulting in personal
injury and property damage; (10) regional economic conditions; (11) political,
regulatory and economic conditions in foreign countries; (12) interest rate
fluctuations and other capital market conditions, including foreign currency
rate fluctuations; (13) reduced distributions from subsidiaries; and (14) the
timing and success of the Company's efforts to develop new business
opportunities.
These factors are not necessarily all of the important factors that could
cause actual results to differ materially from those expressed in any of our
forward-looking statements. Other unknown or unpredictable factors could also
have material adverse effects on future results. We undertake no obligation to
update publicly any forward-looking statement whether as a result of new
information or future events.
23
12
UGI Corporation 2000 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 judgements 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, 2000 and 1999, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended September 30, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based upon our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. These 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 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, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2000, in conformity with accounting principles
generally accepted in the United States.
/s/ Arthur Andersen LLP
Philadelphia, Pennsylvania
November 10, 2000
24
13
UGI Corporation 2000 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
Year Ended September 30,
----------------------------------------------
2000 1999 1998
---------- ---------- ----------
REVENUES
AmeriGas Propane $ 1,120.1 $ 872.5 $ 914.4
UGI Utilities 436.9 420.6 422.3
International Propane 50.5 -- --
Energy Services and other 154.2 90.5 103.0
---------- ---------- ----------
1,761.7 1,383.6 1,439.7
---------- ---------- ----------
COSTS AND EXPENSES
AmeriGas Propane cost of sales 628.3 390.8 443.8
UGI Utilities - gas, fuel and purchased power 218.1 205.2 214.6
International Propane cost of sales 29.7 -- --
Energy Services and other cost of sales 145.5 84.4 98.3
Operating and administrative expenses 461.2 429.2 412.5
Utility taxes other than income taxes 17.1 25.2 25.2
Depreciation and amortization 97.5 89.7 87.8
Other income, net (26.9) (16.8) (12.7)
---------- ---------- ----------
1,570.5 1,207.7 1,269.5
---------- ---------- ----------
OPERATING INCOME 191.2 175.9 170.2
Merger fee income and expenses, net -- 19.9 --
Interest expense (98.5) (84.6) (84.4)
Minority interest in AmeriGas Partners (6.3) (10.7) (8.9)
---------- ---------- ----------
INCOME BEFORE INCOME TAXES AND SUBSIDIARY
PREFERRED STOCK DIVIDENDS 86.4 100.5 76.9
Income taxes (40.1) (43.2) (34.4)
Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (2.2)
---------- ---------- ----------
NET INCOME $ 44.7 $ 55.7 $ 40.3
---------- ---------- ----------
EARNINGS PER COMMON SHARE
Basic $ 1.64 $ 1.74 $ 1.22
Diluted $ 1.64 $ 1.74 $ 1.22
AVERAGE COMMON SHARES OUTSTANDING (MILLIONS)
Basic 27.219 31.954 32.971
Diluted 27.255 32.016 33.123
========== ========== ==========
See accompanying notes to consolidated financial statements.
25
14
UGI Corporation 2000 Annual Report
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30,
------------------------
ASSETS 2000 1999
-------- --------
CURRENT ASSETS
Cash and cash equivalents $ 93.9 $ 40.5
Short-term investments, at cost which approximates market value 7.8 15.1
Accounts receivable (less allowances for doubtful accounts of
$9.3 and $8.0, respectively) 165.7 107.5
Accrued utility revenues 10.5 6.9
Inventories 117.4 87.1
Deferred income taxes 11.8 13.7
Prepaid expenses and other current assets 19.0 24.7
-------- --------
Total current assets 426.1 295.5
-------- --------
PROPERTY, PLANT AND EQUIPMENT
AmeriGas Propane 722.1 680.7
UGI Utilities 857.8 826.8
Other 72.2 91.5
-------- --------
1,652.1 1,599.0
Accumulated depreciation and amortization (578.9) (514.9)
-------- --------
Net property, plant and equipment 1,073.2 1,084.1
-------- --------
OTHER ASSETS
Intangible assets (less accumulated amortization of $190.2 and
$165.9, respectively) 675.5 653.1
Utility regulatory assets 62.3 61.1
Other assets 41.7 46.7
-------- --------
TOTAL ASSETS $2,278.8 $2,140.5
======== ========
See accompanying notes to consolidated financial statements.
26
15
UGI Corporation 2000 Annual Report
September 30,
-------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2000 1999
-------- --------
CURRENT LIABILITIES
Current maturities of long-term debt $ 85.9 $ 26.7
Operating Partnership bank loans 30.0 22.0
UGI Utilities bank loans 100.4 87.4
Other bank loans 4.3 11.6
Accounts payable 156.7 100.6
Employee compensation and benefits accrued 26.5 34.4
Dividends and interest accrued 47.3 44.1
Income taxes accrued 10.3 0.6
Deposits and refunds 39.0 40.2
Other current liabilities 39.0 39.3
-------- --------
Total current liabilities 539.4 406.9
-------- --------
DEBT AND OTHER LIABILITIES
Long-term debt 1,029.7 989.6
Deferred income taxes 172.9 174.3
Deferred investment tax credits 9.2 9.6
Other noncurrent liabilities 83.3 81.0
Commitments and contingencies (note 11)
-------- --------
MINORITY INTEREST
Minority interest in AmeriGas Partners 177.1 209.9
-------- --------
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) 394.5 394.8
Accumulated deficit (4.9) (8.2)
Accumulated other comprehensive income -- 0.5
Unearned compensation-restricted stock (0.7) (1.7)
-------- --------
388.9 385.4
Treasury stock, at cost (141.7) (136.2)
-------- --------
Total common stockholders' equity 247.2 249.2
-------- --------
Total liabilities and stockholders' equity $2,278.8 $2,140.5
======== ========
27
16
UGI Corporation 2000 Annual Report
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30,
-----------------------------------
2000 1999 1998
------ ------ ------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 44.7 $ 55.7 $ 40.3
Reconcile to net cash provided by operating activities:
Depreciation and amortization 97.5 89.7 87.8
Minority interest in AmeriGas Partners 6.3 10.7 8.9
Deferred income taxes, net 3.2 7.7 10.1
Other, net 15.8 6.5 4.9
------ ------ ------
167.5 170.3 152.0
Net change in:
Receivables and accrued utility revenues (63.4) (25.1) 22.0
Inventories and prepaid propane purchases (26.1) (5.0) 39.0
Deferred fuel costs (3.8) (5.1) (5.8)
Accounts payable 52.0 17.4 (23.5)
Other current assets and liabilities 6.5 (10.6) (5.2)
------ ------ ------
Net cash provided by operating activities 132.7 141.9 178.5
------ ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (71.0) (70.2) (69.2)
Acquisitions of businesses, net of cash acquired (65.3) (77.6) (8.1)
Short-term investments (increase) decrease 7.3 66.7 (16.4)
Net proceeds from disposals of assets 8.4 4.9 7.9
Investments in joint venture partnerships -- (4.9) (2.0)
Other, net (0.9) (5.4) (2.3)
------ ------ ------
Net cash used by investing activities (121.5) (86.5) (90.1)
------ ------ ------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on Common Stock (41.2) (47.9) (47.6)
Distributions on Partnership public Common Units (39.1) (39.0) (39.0)
Issuance of long-term debt 209.7 173.7 58.0
Repayment of long-term debt (95.4) (70.9) (22.3)
AmeriGas Propane bank loans increase (decrease) 8.0 12.0 (18.0)
UGI Utilities bank loans increase 13.0 19.0 1.4
Other bank loans decrease (6.8) -- --
Issuance of Common Stock 3.8 4.7 8.5
Repurchases of Common Stock (9.6) (133.1) (11.3)
Redemption of UGI Utilities Series Preferred Stock -- -- (15.5)
------ ------ ------
Net cash provided (used) by financing activities 42.4 (81.5) (85.8)
------ ------ ------
Effect of exchange rate changes on cash (0.2) -- --
------ ------ ------
Cash and cash equivalents increase (decrease) $ 53.4 $(26.1) $ 2.6
====== ====== ======
CASH AND CASH EQUIVALENTS
End of period $ 93.9 $ 40.5 $ 66.6
Beginning of period 40.5 66.6 64.0
------ ------ ------
Increase (decrease) $ 53.4 $(26.1) $ 2.6
====== ====== ======
See accompanying notes to consolidated financial statements.
28
17
UGI Corporation 2000 Annual Report
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Millions of dollars, except per share amounts)
Accumulated Unearned
Other Compensation-
Common Accumulated Comprehensive Restricted Treasury
Stock Deficit Income Stock Stock Total
------ ----------- ------------- ------------- --------- ------
BALANCE SEPTEMBER 30, 1997 $393.7 $ (9.2) $ -- $ -- $ (8.4) $376.1
Net income 40.3 40.3
Cash dividends on Common Stock
($1.45 per share) (47.8) (47.8)
Common Stock issued:
Employee and director plans 0.5 (0.7) 6.3 6.1
Dividend reinvestment plan 2.8 2.8
Acquisition 0.1 1.1 1.2
Redemption of UGI Utilities Series
Preferred Stock (0.3) (0.3)
Common Stock repurchased (11.3) (11.3)
------ ------ ----- ------ ------- ------
BALANCE SEPTEMBER 30, 1998 394.3 (17.7) -- -- (9.5) 367.1
Net income 55.7 55.7
Net unrealized gain on available
for sale securities 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 gain on
available for sale securities (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
====== ====== ===== ====== ======= ======
See accompanying notes to consolidated financial statements.
29
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE PAGE
- ---- ----
1. Organization and Significant Accounting Policies 30
2. Utility Regulatory Matters 34
3. Debt 35
4. Income Taxes 37
5. Employee Retirement Plans 38
6. Inventories 39
7. Series Preferred Stock 39
8. Common Stock and Incentive Stock Award Plans 40
9. Preference Stock Purchase Rights 41
10. Partnership Distributions 42
11. Commitments and Contingencies 43
12. Financial Instruments 44
13. Acquisitions 45
14. Terminated Merger-Unisource Worldwide, Inc. 45
15. Other Income, Net 45
16. Quarterly Data (Unaudited) 46
17. Segment Information 46
NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. UGI Corporation ("UGI") is a holding company that operates gas and
electric utility, propane distribution, energy marketing and related businesses
through subsidiaries. Our utility business is conducted through a wholly owned
subsidiary, UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and
operates a natural gas distribution utility ("Gas Utility") in parts of eastern
and southeastern Pennsylvania and an electric distribution utility and
electricity generation business ("Electric Utility") in northeastern
Pennsylvania (together we refer to them as "Utilities").
We conduct a national propane distribution business through AmeriGas
Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas
Propane, L.P. (the "Operating Partnership"), both of which are Delaware limited
partnerships. Our wholly owned second-tier subsidiary, AmeriGas Propane, Inc.
(the "General Partner"), serves as the general partner of AmeriGas Partners and
the Operating Partnership. At September 30, 2000, the General Partner and its
wholly owned subsidiary Petrolane Incorporated ("Petrolane") held an effective
2% general partner interest and a 56.4% limited partner interest in the
Operating Partnership. We refer to AmeriGas Partners and the Operating
Partnership together as "the Partnership," and the General Partner and its
subsidiaries, including the Partnership, as "AmeriGas Propane." The Operating
Partnership is one of the largest retail propane distributors in the United
States serving residential, commercial, industrial, motor fuel and agricultural
customers from locations in 45 states, including Alaska and Hawaii. At September
30, 2000, our limited partner interest in AmeriGas Partners consisted of
14,283,932 Common Units and 9,891,072 Subordinated Units. The remaining 41.6%
effective interest in the Partnership comprises 17,794,361 publicly held Common
Units representing limited partner interests. In October 2000, AmeriGas Partners
issued 2,300,000 Common Units in a public offering for net cash proceeds of
approximately $40 million. After this transaction, the General Partner and
Petrolane held an effective 2% general partner interest and 53.5% limited
partner interest in the Operating Partnership.
AmeriGas Partners and the Operating Partnership have no employees. Employees
of the General Partner conduct, direct and manage the activities of the
Partnership. The General Partner does not receive management fees or other
compensation in connection with managing the Partnership, but 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 through its wholly owned subsidiary, UGI Energy
Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (1)
owns and operates a propane distribution business, FLAGA GmbH ("FLAGA") in
Austria, the Czech Republic and Slovakia; (2) owns and operates a heating,
ventilation and air-conditioning service business ("HVAC") and a retail hearth,
spa and grill products business in the Middle Atlantic region of the U.S.; and
(3) participates in propane joint-venture projects in Romania 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").
30
19
CONSOLIDATION PRINCIPLES. Our 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 unitholders' interest in AmeriGas Partners as minority
interest in the consolidated financial statements. The Company's investments in
international propane joint-venture projects are accounted for by the equity
method. Such investments did not materially impact the Company's results of
operations for the periods presented.
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 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 the Company to record the financial
statement effects of the rate regulation to which such operations are currently
subject. 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.
In June 1998, the PUC approved Electric Utility's restructuring plan which we
submitted pursuant to Pennsylvania's Electricity Customer Choice Act
("Electricity Customer Choice Act"). In accordance with the Financial Accounting
Standards Board's ("FASB's") Emerging Issues Task Force ("EITF") Statement No.
97-4, "Deregulation of the Pricing of Electricity - Issues Related to the
Application of FASB Statements 71 and 101" ("EITF 97-4"), we discontinued the
application of SFAS 71 as it related to the electric generation portion of
Electric Utility's business in June 1998. This discontinuance of SFAS 71 did not
have a material effect on our financial position or results of 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 Electricity Customer Choice Act
and the Gas Competition Act, see Note 2.
DERIVATIVE INSTRUMENTS. We use derivative instruments, including futures
contracts, price swap agreements and option contracts, to hedge exposure to
market risk associated with (1) fluctuations in the price of forecasted
purchases of natural gas Energy Services sells under firm commitments and (2)
fluctuations in propane prices associated with a portion of our anticipated
propane purchases. On occasion we enter into interest rate protection agreements
to reduce interest rate risk associated with anticipated issuances of debt. In
addition, we occasionally utilize a managed program of derivative instruments
including natural gas and oil futures contracts to preserve gross margin
associated with certain of the Company's natural gas customers, which margin
otherwise could be affected by major energy commodity price movements.
We defer gains or losses on futures contracts associated with forecasted
purchases of natural gas and record them in cost of sales when such purchases
affect earnings. We recognize gains or losses on derivative instruments
associated with forecasted purchases of propane or issuances of debt when such
transactions affect earnings. When it is probable that the original forecasted
transaction will not occur, we immediately recognize in earnings any gain or
loss on the related derivative instrument. If such derivative instrument is
terminated early for other economic reasons, we defer any gain or loss as of the
termination date until such time as the forecasted transaction affects earnings.
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 $96.9 million in 2000, $84.6 million in 1999,
and $83.5 million in 1998. We paid income taxes totaling $26.6 million in 2000,
$36.2 million in 1999, and $29.8 million in 1998.
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' revenues for service provided to the end of each month. 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. See "Accounting Principles Not Yet Adopted" below.
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.
31
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
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 2000, 1999 and 1998:
2000 1999 1998
------ ------ ------
Denominator (millions of shares):
Average common shares
outstanding for basic computation 27.219 31.954 32.971
Incremental shares issuable for stock
options and awards .036 .062 .152
------ ------ ------
Average common shares outstanding for
diluted computation 27.255 32.016 33.123
------ ------ ------
INCOME TAXES. AmeriGas Partners and the Operating Partnership 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 Partnership does, however, 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 UGI Utilities'
plant additions over the service lives of the related property. UGI Utilities
reduces its deferred income tax liability for the future tax benefits that will
occur when the deferred investment tax credits, which are not taxable, are
amortized. We also reduce the regulatory income tax asset for the probable
reduction in future revenues that will result when such deferred investment tax
credits amortize.
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION.
We record property, plant and equipment at cost. 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 2000, and 2.7% in 1999 and
1998. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 3.5% in 2000, and 3.2% in 1999 and 1998. 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 $69.3
million in 2000, $63.6 million in 1999, and $61.4 million in 1998.
INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2000 1999
------ ------
Goodwill (less accumulated amortization of $126.6
million and $109.8 million, respectively) $566.8 $538.4
Excess reorganization value (less accumulated
amortization of $60.2 million and $52.3 million, respectively) 101.3 109.2
Other (less accumulated amortization of $3.4 million
and $3.8 million, respectively) 7.4 5.5
------ ------
Total intangible assets $675.5 $653.1
====== ======
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 over the
estimated periods of benefit which do not exceed ten years. Amortization expense
of intangible assets was $26.5 million in 2000, $24.3 million in 1999, and $24.9
million in 1998.
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 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.
32
21
UGI Corporation 2000 Annual Report
OTHER ASSETS. Included in other assets are net deferred debt issuance costs of
$10.8 million at September 30, 2000 and $10.9 million at September 30, 1999. We
are amortizing these costs over the term of the related debt.
COMPUTER SOFTWARE COSTS. Prior to October 1, 1999, we included in property,
plant and equipment external and incremental internal costs associated with
computer software we developed or obtained for use in our businesses. Effective
October 1, 1999, we adopted Statement of Position No. 98-1, "Accounting for the
Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1"),
which requires companies to capitalize the cost of computer software, including
nonincremental internal costs, once certain criteria have been met. We amortize
computer software costs on a straight-line basis over periods of three to seven
years once the installed software is ready for its intended use. The adoption of
SOP 98-1 did not have a material effect on our financial position or results of
operations.
DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery
of certain purchased gas costs ("PGCs") in excess of the level of such costs
included in base rates. The clauses provide for a periodic adjustment 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. Financial statements of international subsidiaries
are translated into U.S. dollars using the exchange rate at each balance sheet
date for assets and liabilities and a weighted-average exchange rate for each
period for revenues and expenses. Where the local currency is the functional
currency, translation adjustments are recorded in accumulated other
comprehensive income. Where the local currency is not the functional currency,
translation adjustments are recorded in net income. Currency adjustments did not
materially impact the Company's results of operations or accumulated
comprehensive income in 2000, 1999 or 1998.
COMPREHENSIVE INCOME. Our comprehensive income principally includes net earnings
or loss and unrealized gains or losses on available for sale securities. In
1998, our comprehensive income was the same as our net income. The net changes
in accumulated comprehensive income in 1999 and 2000, which resulted principally
from changes in unrealized gains on securities, is reflected net of income taxes
of $0.3 million.
ACCOUNTING PRINCIPLES NOT YET ADOPTED. In June 1998, the FASB issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"). SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities" ("SFAS 138")
which addressed a limited number of issues causing implementation difficulties.
SFAS 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. It requires that an entity
recognize all derivative instruments as either assets or liabilities and measure
them 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 derivative instruments qualify and are
designated as hedges of the variability in cash flows associated with forecasted
transactions, the effective portion of the gain or loss on such derivative
instruments will generally be reported in other comprehensive income and the
ineffective portion, if any, will be reported in net income. Such amounts
recorded in accumulated other comprehensive income will be reclassified into net
income when the forecasted transaction affects earnings. 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, the gain or loss
on the hedging instrument will be recognized currently in earnings along with
changes in the fair value of the hedged asset, liability or firm commitment
attributable to the hedged risk.
The Company was required to adopt the provisions of SFAS 133 effective
October 1, 2000. Virtually all of the Company's derivative instruments
outstanding as of October 1, 2000 qualify and have been designated as hedging
the variability in cash flows associated with forecasted transactions. The
adoption of SFAS 133 will result 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. Because the Company's
derivative instruments historically have been highly effective in hedging the
exposure to changes in cash flows associated with forecasted purchases or sales
of natural gas and propane, changes in the fair value of propane inventories,
and changes in the risk-free rate of interest on anticipated issuances of
long-term debt, we do not expect the adoption of SFAS 133 to have a material
impact on our future results of operations.
Although the Company expects the derivative instruments it currently uses to
hedge to continue to be highly effective, if they are deemed not highly
effective in the future, or if the Company uses
33
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
derivative instruments that do not meet the stringent requirements for hedge
accounting under SFAS 133, our future earnings could reflect greater volatility.
Additionally, if a cash flow hedge is discontinued because the original
forecasted transaction is no longer expected to occur, any gain or loss in
accumulated comprehensive income associated with the hedged transaction will be
immediately recognized in net income.
In order to comply with the provisions of the Securities and Exchange
Commission Staff Accounting Bulletin No. 101 entitled "Revenue Recognition"
("SAB 101"), which is effective for the Company on October 1, 2000, the Company
will record a cumulative effect charge to net income of approximately $2.3
million related to the Partnership's method of recognizing revenue associated
with nonrefundable tank fees largely for residential customers. Consistent with
a number of its competitors in the propane industry, the Partnership receives
nonrefundable fees for installed Partnership-owned tanks. Historically, such
fees, which are generally received annually, were recorded as revenue when
billed. In accordance with SAB 101, effective October 1, 2000, the Partnership
will record such nonrefundable fees on a straight-line basis over one year. The
adoption of SAB 101 is not expected to have a material impact on the Company's
future financial condition or results of operations.
Also, during fiscal 2001, the Partnership plans to change its method of
accounting for tank installation costs which are not billed to customers.
Currently, all direct costs to install Partnership-owned tanks at a customer
location are expensed as incurred. The Partnership believes that these costs
should now be capitalized and amortized over the period benefited. On date of
adoption, this change in accounting method will result in a cumulative effect
increase to net income. The Company is in the process of evaluating the impact
of such change on its financial condition and results of operations.
NOTE 2 -UTILITY REGULATORY MATTERS
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 Customer 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 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. Electric Utility's 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 Customer Choice Act, Electric Utility's rates for transmission
and distribution services are capped through July 1, 2001. In addition, 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 December 31, 2002. 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").
In June 1998, Electric Utility discontinued the application of SFAS 71 as it
relates to the electric generation portion of its business, which assets
comprise less than 15% of Electric Utility's total assets. The discontinuance of
SFAS 71 did not have a material effect on our financial position or results of
operations.
NATURAL 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. LDCs are generally precluded from increasing rates for
the recovery of costs, other than gas costs, until January 1, 2001. 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. The PUC, however, may only grant the petition if certain
findings are made and 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 substantially as filed. Among other things, the
restructuring plan (1) provides for the recovery of costs associated with
existing pipeline capacity and supply contracts; (2) increases Gas Utility's
base rates for firm customers; and (3) changes the calculation of PGC rates. The
effect of (2) and
34
23
UGI Corporation 2000 Annual Report
(3) above is to reduce the financial impact of volatility in revenues from
customers who have the ability to switch to an alternate fuel under
interruptible rates and increase our sensitivity to changes in weather.
Because the Gas Competition Act requires alternate suppliers to accept
assignment of a portion of the LDC's pipeline capacity and storage contracts, we
do not believe the Gas Competition Act and the Gas Restructuring Order will have
a material adverse impact on our financial condition or results of operations.
REGULATORY ASSETS AND LIABILITIES. The following regulatory assets and
liabilities are included in our accompanying balance sheets at September 30:
2000 1999
- ---------------------------------------------------------------
Regulatory assets:
Income taxes recoverable $47.7 $46.9
Power agreement buy-out 3.5 6.8
Other postretirement benefits 2.9 3.1
Deferred fuel costs 7.2 3.4
Other 1.0 0.9
- ---------------------------------------------------------------
Total regulatory assets $62.3 $61.1
- ---------------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 4.0 $2.8
Refundable state taxes -- 1.0
- ---------------------------------------------------------------
Total regulatory liabilities $ 4.0 $3.8
- ---------------------------------------------------------------
NOTE 3 - DEBT
Long-term debt comprises the following at September 30:
2000 1999
- -----------------------------------------------------------------------------------
AmeriGas Propane:
AmeriGas Partners Senior Notes, 10.125%,
due April 2007 $ 100.0 $ 100.0
Operating Partnership First Mortgage Notes:
Series A, 9.34%-11.71%, due April 2000 through
April 2009 (including unamortized premium
of $10.6 and $12.1, respectively, calculated at
an 8.91% effective rate) 208.6 220.1
Series B, 10.07%, due April 2001 through
April 2005 (including unamortized premium
of $5.9 and $8.0, respectively, calculated at
an 8.74% effective rate) 205.9 208.0
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 $2.7
and $2.9, respectively, calculated at a
6.52% effective rate) 72.7 72.9
Series E, 8.50%, due July 2010
(including unamortized premium of $0.2
calculated at an 8.47% effective rate) 80.2 --
Operating Partnership Acquisition Facility 70.0 23.0
Other 9.8 10.7
- -----------------------------------------------------------------------------------
Total AmeriGas Propane 857.2 744.7
- -----------------------------------------------------------------------------------
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 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
6.50% Senior Notes, due August 2003
(less unamortized discount of $0.1) 49.9 49.9
9.71% Notes, due September 2000 -- 7.1
- -----------------------------------------------------------------------------------
Total UGI Utilities 172.9 180.0
- -----------------------------------------------------------------------------------
Other:
FLAGA EURO note, due September 2001
through September 2006 65.5 77.0
FLAGA Austrian shilling debt -- 6.8
FLAGA EURO special purpose facility 11.9 --
Other 8.1 7.8
- -----------------------------------------------------------------------------------
Total long-term debt 1,115.6 1,016.3
Less current maturities (85.9) (26.7)
- -----------------------------------------------------------------------------------
Total long-term debt due after one year $1,029.7 $ 989.6
- -----------------------------------------------------------------------------------
35
24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Long-term debt due in fiscal years 2001 to 2005 follows:
2001 2002 2003 2004 2005
- ---------------------------------------------------------------
AmeriGas Propane $64.5 $66.5 $60.0 $56.7 $56.2
UGI Utilities 15.0 -- 76.0 -- 20.0
Other 6.4 10.8 16.6 9.9 15.7
- ---------------------------------------------------------------
Total $85.9 $77.3 $152.6 $66.6 $91.9
- ---------------------------------------------------------------
AMERIGAS PROPANE
AMERIGAS PARTNERS SENIOR NOTES. The 10.125% Senior Notes of AmeriGas Partners
are redeemable prior to their maturity date. A redemption premium applies until
April 15, 2004. In addition, 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.
OPERATING PARTNERSHIP FIRST MORTGAGE NOTES. The Operating Partnership's First
Mortgage Notes are collateralized by substantially all of its assets. The
General Partner and its wholly owned subsidiary 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. The Operating Partnership 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, the
Operating Partnership may be required to offer to prepay the First Mortgage
Notes, in whole or in part.
OPERATING PARTNERSHIP BANK CREDIT AGREEMENT. The Operating Partnership's Bank
Credit Agreement consists of a Revolving Credit Facility and an Acquisition
Facility. The Operating Partnership'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, the Operating Partnership may borrow up
to $100 million (including a $35 million sublimit for letters of credit) subject
to restrictions in the 10.125% Senior Notes of AmeriGas Partners (see
"Restrictive Covenants" below). 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 the Operating Partnership 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 (9.50% at September 30, 2000), 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 the Operating Partnership's
ratio of funded debt to earnings before interest expense, income taxes,
depreciation and amortization ("EBITDA"), each as defined in the Bank Credit
Agreement. The Operating Partnership had borrowings under the Revolving Credit
Facility totaling $30 million at September 30, 2000 and $22 million at September
30, 1999, which we classify as bank loans. The weighted-average interest rates
on the bank loans outstanding were 8.11% as of September 30, 2000 and 6.26% as
of September 30, 1999. Issued outstanding letters of credit under the Revolving
Credit Facility totaled $1.5 million at September 30, 2000 and $5.9 million at
September 30, 1999.
The Acquisition Facility provides the Operating Partnership with the ability
to borrow up to $75 million to finance the purchase of propane businesses or
propane business assets. 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 the Operating
Partnership 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 the Operating Partnership's
ratio of funded debt to EBITDA, as defined. The weighted-average interest rates
on Acquisition Facility loans outstanding were 8.12% as of September 30, 2000
and 6.02% as of September 30, 1999.
GENERAL PARTNER FACILITY. The Operating Partnership also has a revolving credit
agreement with the General Partner under which it may borrow up to $20 million
to fund working capital, capital expenditures, and interest and Partnership
distribution payments. This agreement is coterminous with, and generally
comparable to, the Operating Partnership's Revolving Credit Facility except that
borrowings under the General Partner Facility are unsecured and subordinated to
all senior debt of the Partnership. 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 10.125% 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 Indenture, 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.
36
25
UGI Corporation 2000 Annual Report
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, 2000, such ratio was 2.14-to-1.
The Bank Credit Agreement and the First Mortgage Notes restrict the
incurrence of additional indebtedness and also restrict certain liens,
guarantees, investments, loans and advances, payments, mergers, consolidations,
sales of assets 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 the
Operating Partnership 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, the Operating Partnership 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, 2000, the Partnership was in compliance with
its financial covenants.
UGI UTILITIES
REVOLVING CREDIT AGREEMENTS. At September 30, 2000, UGI Utilities had revolving
credit agreements with four banks providing for borrowings of up to $122 million
through June 2003. 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
$100.4 million at September 30, 2000 and $87.4 million at September 30, 1999,
which we classify as bank loans. The weighted-average interest rates on UGI
Utilities bank loans were 7.12% at September 30, 2000 and 5.90% at September 30,
1999.
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, 2000, UGI Utilities was in compliance with its
financial covenants.
OTHER
FLAGA's EURO note bears interest at a rate of 1.25% over one- to twelve-month
EURIBOR rates (as chosen by the Company from time to time). The effective
interest rates on the EURO note at September 30, 2000 and September 30, 1999
were 5.71% and 5.00%, respectively. On or after September 10, 2003, the Company
may prepay the EURO note, in whole or in part. Prior to March 11, 2005, such
prepayments shall be at a premium.
FLAGA has EURO loan commitments from a foreign bank in the form of (1) a 15
million EURO special purpose facility and (2) a 9 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 September 28,
2001, but may be extended for an additional three-year period 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,
2000 were 5.78% and 5.25%, respectively. Borrowings under the EURO working
capital facility at September 30, 2000, and FLAGA's now terminated Swiss franc
denominated bank loan facility at September 30, 1999, totaled $4.3 million and
$11.6 million, respectively.
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 4 -- INCOME TAXES
Income before income taxes comprises the following:
2000 1999 1998
- ----------------------------------------------------------------
Domestic $93.4 $100.5 $76.9
Foreign (7.0) -- --
- ----------------------------------------------------------------
Total income before income taxes $86.4 $100.5 $76.9
- ----------------------------------------------------------------
The provisions for income taxes consist of the following:
2000 1999 1998
- ----------------------------------------------------------------
Current:
Federal $28.6 $29.2 $19.6
State 8.3 6.3 4.7
- ----------------------------------------------------------------
Total current 36.9 35.5 24.3
Deferred:
Federal 5.7 6.8 10.0
State (0.2) 1.3 0.5
Foreign (1.9) -- --
Investment tax credit amortization (0.4) (0.4) (0.4)
- ----------------------------------------------------------------
Total deferred 3.2 7.7 10.1
- ----------------------------------------------------------------
Total income tax expense $40.1 $43.2 $34.4
- ----------------------------------------------------------------
37
26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
2000 1999 1998
- -----------------------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 7.5 5.2 6.1
Nondeductible amortization of goodwill 5.8 4.6 6.2
Other, net (1.9) (1.8) (2.6)
- -----------------------------------------------------------------------------------
Effective tax rate 46.4% 43.0% 44.7%
- -----------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2000 1999
- ------------------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and equipment $ 172.5 $ 177.0
Regulatory assets 25.6 25.3
Other 13.7 10.1
- ------------------------------------------------------------------------------------------
Gross deferred tax liabilities 211.8 212.4
- ------------------------------------------------------------------------------------------
Self-insured property and casualty liability (8.2) (8.6)
Employee-related benefits (12.0) (12.3)
Premium on long-term debt (4.4) (5.2)
Deferred investment tax credits (3.8) (4.0)
Power purchase agreement liability (2.2) (3.2)
Operating loss carryforwards (8.3) (4.2)
Allowance for doubtful accounts (2.6) (2.5)
Other (11.1) (13.8)
- ------------------------------------------------------------------------------------------
Gross deferred tax assets (52.6) (53.8)
- ------------------------------------------------------------------------------------------
Deferred tax assets valuation allowance 1.9 2.0
- ------------------------------------------------------------------------------------------
Net deferred tax liabilities $ 161.1 $ 160.6
- ------------------------------------------------------------------------------------------
UGI Utilities had recorded deferred tax liabilities of approximately $31.7
million as of September 30, 2000 and $31.4 million as of September 30, 1999
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 $3.8 million at September 30, 2000 and $4.0 million at
September 30, 1999, pertaining to utility deferred investment tax credits. UGI
Utilities had recorded a regulatory income tax asset related to these net
deferred taxes of $47.7 million as of September 30, 2000 and $46.9 million as of
September 30, 1999. This regulatory income tax asset represents 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.
At September 30, 2000, the amount of federal operating loss carryforwards
which were generated by a domestic subsidiary prior to its acquisition totaled
$5.2 million. These operating loss carryforwards expire through the year 2010.
The use of pre-acquisition operating loss carryforwards is subject to Internal
Revenue Code limitations. We do not believe these limitations will affect our
ability to utilize these carryforwards prior to their expiration.
Foreign operating loss carryforwards of FLAGA totaled approximately $19.0
million at September 30, 2000. Approximately $3.0 million of these operating
loss carryforwards expire through 2005. The remaining approximately $16.0
million have no expiration date. The tax benefit of these foreign operating loss
carryforwards of $6.4 million has been reduced by a valuation allowance of $1.7
million due to the uncertainty of realizing certain of these operating loss
carryforwards.
NOTE 5 -- EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS
We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for
employees of UGI, UGI Utilities, and certain of UGI's other wholly owned
subsidiaries. In addition, we provide postretirement health care benefits to
certain retirees and a limited number of active employees meeting certain age
and service requirements, and postretirement life insurance benefits to nearly
all active and retired employees.
The following provides a reconciliation of benefit obligations, plan assets,
and funded status of the plans as of September 30:
Other
Pension Postretirement
Benefits Benefits
--------------------- ---------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 149.5 $ 164.8 $ 16.8 $ 16.9
Service cost 3.2 3.8 0.1 0.1
Interest cost 11.8 11.2 1.4 1.2
Actuarial (gain) loss (4.4) (21.4) 3.0 (0.2)
Benefits paid (9.2) (8.9) (1.6) (1.2)
- ----------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 150.9 $ 149.5 $ 19.7 $ 16.8
- ----------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -
beginning of year $ 202.1 $ 183.3 $ 4.9 $ 4.9
Actual return on plan assets 30.6 27.7 0.3 0.2
Employer contributions -- -- 2.2 1.0
Benefits paid (9.2) (8.9) (1.0) (1.2)
- ----------------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $ 223.5 $ 202.1 $ 6.4 $ 4.9
- ----------------------------------------------------------------------------------------------------
Funded status of the plans $ 72.6 $ 52.6 $ (13.3) $ (11.9)
Unrecognized net actuarial gain (54.8) (36.8) (3.0) (5.8)
Unrecognized prior service cost 4.0 4.7 -- --
Unrecognized net transition (asset) obligation (6.3) (7.9) 10.5 11.4
- ----------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 15.5 $ 12.6 $ (5.8) $ (6.3)
- ----------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 8.2% 7.8% 8.2% 7.8%
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
- ----------------------------------------------------------------------------------------------------
38
27
UGI Corporation 2000 Annual Report
Net periodic pension income and other postretirement benefit costs include the
following components:
Pension Other
Benefits Postretirement Benefits
--------------------------------- ---------------------------------
2000 1999 1998 2000 1999 1998
- ------------------------------------------------------------------------------------------------------
Service cost $ 3.2 $ 3.8 $ 3.4 $ 0.1 $ 0.1 $ 0.1
Interest cost 11.8 11.2 10.9 1.4 1.2 1.2
Expected return on assets (17.0) (16.3) (15.2) (0.3) (0.2) (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) loss -- -- -- (0.2) (0.2) (0.3)
- ------------------------------------------------------------------------------------------------------
Net postretirement
cost (income) (3.0) (2.3) (1.9) 1.9 1.8 1.7
Change in regulatory
assets & liabilities -- -- -- 1.4 1.7 1.9
- ------------------------------------------------------------------------------------------------------
Net expense (income) $ (3.0) $ (2.3) $ (1.9) $ 3.3 $ 3.5 $ 3.6
- ------------------------------------------------------------------------------------------------------
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 comprises less than 2% of trust assets at
September 30, 2000.
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 10% for fiscal 2001, decreasing
to 5.5% in fiscal 2005. A one percentage point change in the assumed health care
cost trend rate would change the 2000 postretirement benefit cost and obligation
as follows:
1% 1%
Increase Decrease
- ----------------------------------------------------------------------
Effect on total service and interest costs $0.1 $(0.1)
Effect on postretirement benefit obligation $1.1 $(1.1)
- ----------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 2000 and 1999, the projected benefit obligations of these plans
were not material. We recorded expense for these plans of $0.9 million in 2000,
$1.6 million in 1999, and $2.4 million in 1998.
DEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees of UGI, UGI Utilities,
and certain of UGI's other wholly owned subsidiaries ("UGI Utilities Savings
Plan"). Generally, participants in the UGI Utilities Savings Plan may contribute
a portion of their compensation on a before-tax and after-tax basis. We may, at
our discretion, match a portion of participants' contributions. We also sponsor
a 401(k) savings plan for eligible employees of the General Partner ("AmeriGas
Propane Savings Plan"). Participants in the AmeriGas Propane Savings Plan may
contribute a portion of their compensation on a before-tax basis. We match
employee contributions to the AmeriGas Propane Savings Plan on a
dollar-for-dollar basis up to 5% of eligible compensation. The cost of benefits
under the savings plans totaled $5.9 million in 2000, $4.8 million in 1999, and
$5.1 million in 1998.
NOTE 6 -- INVENTORIES
Inventories comprise the following at September 30:
2000 1999
- ----------------------------------------------------------------
Propane gas $ 47.3 $38.1
Utility fuel and gases 33.6 24.5
Materials, supplies and other 36.5 24.5
- ----------------------------------------------------------------
Total inventories $117.4 $87.1
- ----------------------------------------------------------------
NOTE 7 -- 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, 2000
or 1999.
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, 2000 and 1999, 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.
39
28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 8 -- COMMON STOCK AND INCENTIVE STOCK AWARD PLANS
On September 7, 1999, pursuant to strategic and financial initiatives announced
on July 28, 1999, we repurchased 4.5 million 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 the Company's proposed merger with Unisource (see Note 14), we
purchased 1.4 million shares of Common Stock for $23.2 million.
Common Stock share activity for 1998, 1999 and 2000 follows:
Issued Treasury Outstanding
======================================================================================
Balance September 30, 1997 33,198,731 (336,715) 32,862,016
Issued:
Employee and director plans -- 243,915 243,915
Dividend reinvestment plan -- 108,353 108,353
Acquisitions -- 42,078 42,078
Reacquired -- (433,100) (433,100)
- -------------------------------------------------------------------------------------
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 -- (5,864,496) (5,864,496)
- -------------------------------------------------------------------------------------
Balance 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
- -------------------------------------------------------------------------------------
STOCK OPTION 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 all 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, 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. At September 30, 2000, no grants have been made 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 the Company'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, the Company may grant options
to acquire up to a total of 200,000 shares of Common Stock to each of the
Company'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 participant is a Director.
Stock option transactions under all of our plans for 1998, 1999 and 2000
follow:
Shares Average Option Price
================================================================================
Shares under option - September 30, 1997 1,175,001 $21.670
- -------------------------------------------------------------------------
Granted 54,583 22.469
Exercised (198,121) 20.650
Forfeited (1,708) 23.962
- -------------------------------------------------------------------------
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
- -------------------------------------------------------------------------
Options exercisable 1998 1,014,755 21.921
Options exercisable 1999 984,061 21.725
Options exercisable 2000 947,144 21.696
- -------------------------------------------------------------------------
For options outstanding as of September 30, 2000, the exercise prices range
from $18.625 to $26.25. The weighted-average remaining contractual life of these
options is 7.1 years. At September 30, 2000, 1,453,103 shares of Common Stock
were available for future option grants under all of our stock option plans.
OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS
On December 13, 1999, the General Partner adopted the AmeriGas Propane, Inc.
2000 Long-Term Incentive Plan ("2000 Propane Plan"). Under the 2000 Propane
Plan, the General Partner may
40
29
UGI Corporation 2000 Annual Report
grant to key employees the right to receive a total of 500,000 AmeriGas Partners
Common Units, or cash generally equivalent to the fair market value of such
Common Units, upon the achievement of objective performance goals. In addition,
the 2000 Propane Plan provides that grants may provide for the crediting of
Partnership distribution equivalents to participants' accounts. Distribution
equivalents will be paid in cash, and such payment may, at the participant's
request, be deferred. Generally, each grant, unless paid, will terminate when
the participant ceases to be employed by the General Partner. At September 30,
2000, no grants have been made under the 2000 Propane Plan.
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 participant's 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 Board 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. Board
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 12,017, 9,137 and 7,043 in 2000, 1999
and 1998, respectively. At September 30, 2000 and 1999, there were 53,294 and
41,277 Units, respectively, outstanding.
In June 1999, we awarded 103,000 shares of restricted stock to key
executives. These awards vest four years from date of issuance but may vest
earlier if certain Common Stock performance goals are met. Recipients have the
right to vote the shares and to receive dividends during the restriction period.
FAIR VALUE INFORMATION
The per share weighted-average fair value of stock options granted under our
option plans was $3.76 in 2000, $2.58 in 1999, and $1.98 in 1998. These amounts
were determined using the Black-Scholes option pricing model, which values
options based on the stock price at the grant date, the expected life of the
option, the estimated volatility of the stock, expected dividend payments, and
the risk-free interest rate over the expected life of the option. The
assumptions we used for option grants during 2000, 1999 and 1998 are as follows:
2000 1999 1998
- ---------------------------------------------------------------
Expected life of option 6 years 6 years 6 years
Expected volatility 26.5% 19.3% 16.2%
Expected dividend yield 6.2% 6.2% 6.0%
Risk free interest rate 6.6% 5.9% 4.6%
- ---------------------------------------------------------------
We use the intrinsic value method prescribed by APB 25 for our stock-based
employee compensation plans. We recognized, under the provisions of APB 25,
total stock-based compensation expense (income) of $(0.8) million in 2000, $1.9
million in 1999, and $1.0 million in 1998. 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 2000, 1999 and 1998 would have been as follows:
2000 1999 1998
- ---------------------------------------------------------------
Net earnings:
As reported $44.7 $55.7 $40.3
Pro forma 44.2 55.3 40.2
Diluted earnings per share:
As reported $1.64 $1.74 $1.22
Pro forma 1.62 1.73 1.21
- ---------------------------------------------------------------
STOCK OWNERSHIP POLICY
The Company has a stock ownership policy ("Stock Ownership Policy") for
executives and key employees. Under the terms of the Stock Ownership Policy,
executives and certain key employees are required to own UGI Common Stock having
a fair value equal to 40% to 450% of their base salaries. Participants have from
three months to three years to comply with the Stock Ownership Policy. 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, 2000 and 1999,
loans outstanding totaled $5.2 million and $4.1 million, respectively.
NOTE 9 - 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:
41
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
1. acquires 20% or more of our Common Stock ("Acquiring Person") or
2. announces or commences a tender offer for 30% or more of our Common Stock.
We are entitled to redeem the rights at five cents per right at any time before
the earlier of:
1. the expiration of the rights in April 2006 or
2. ten days after a person or group has acquired 20% of our Common Stock if a
majority of continuing Directors concur and, in certain circumstances,
thereafter.
Each holder of a right, other than an Acquiring Person, is entitled to purchase,
at the exercise price of the right, Common Stock having a market value of twice
the exercise price of the right if:
1. an Acquiring Person merges with UGI or engages in certain other
transactions with us or
2. a person acquires 40% or more of our Common Stock.
In addition, if, after UGI (or an Acquiring Person) publicly announces that an
Acquiring Person has become such, UGI engages in a merger or other business
combination transaction in which:
1. we are not the surviving corporation, or
2. we are the surviving corporation, but our Common Stock is changed or
exchanged, or
3. 50% or more of our assets or earning power is sold or transferred, then
each holder of a right is entitled to purchase, at the exercise price of
the right, common stock of the acquiring company having a market value of
twice the exercise price of the right.
The rights have no voting or dividend rights and, until exercisable, have no
dilutive effect on our earnings.
NOTE 10 - PARTNERSHIP DISTRIBUTIONS
The Partnership makes distributions to its partners approximately 45 days after
the end of each fiscal quarter in a total amount equal to its Available Cash for
such quarter. Available Cash generally means:
1. all cash on hand at the end of such quarter,
2. plus all additional cash on hand as of the date of determination resulting
from borrowings after the end of such quarter,
3. less the amount of cash reserves established by the General Partner in its
reasonable discretion.
The General Partner may establish reserves for the proper conduct of the
Partnership's business and for distributions during the next four quarters. In
addition, certain of the Partnership's debt agreements require reserves be
established for the payment of debt principal and interest.
Distributions of Available Cash 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.
Pursuant to the Agreement of Limited Partnership of AmeriGas Partners
("Partnership Agreement"), because the 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 its wholly owned subsidiary, 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 (1) each of the two immediately preceding
nonoverlapping four-quarter periods and (2) 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 "look-back" provisions 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 March 31, 2002.
42
31
UGI Corporation 2000 Annual Report
NOTE 11 - 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 $34.1 million in 2000, $35.3 million in 1999, and $33.5 million
in 1998.
Minimum future payments under operating leases that have initial or remaining
noncancelable terms in excess of one year are as follows:
After
2001 2002 2003 2004 2005 2005
- ---------------------------------------------------------------------------------------------
AmeriGas Propane $ 27.2 $ 22.0 $ 16.8 $ 13.7 $ 11.3 $ 24.7
UGI Utilities 3.6 3.1 2.5 1.7 0.9 0.7
International Propane 0.1 0.1 0.1 -- -- --
Other 2.4 2.3 2.1 1.8 1.7 6.7
- ---------------------------------------------------------------------------------------------
Total $ 33.3 $ 27.5 $ 21.5 $ 17.2 $ 13.9 $ 32.1
- ---------------------------------------------------------------------------------------------
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. 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.
Prior to August 1, 1999, Pennsylvania Power & Light Company ("PP&L"),
pursuant to a 1992 power supply agreement for bundled energy and capacity,
supplied all of Electric Utility's electric power requirements above that
provided by other sources. As part of a settlement of all disputes concerning
the 1992 power supply agreement, during 1999 Electric Utility and PP&L entered
into a new power supply agreement under which PP&L will supply all of Electric
Utility's capacity requirements in excess of its capacity resources acquired
from other sources through February 2001, and 32 megawatts of energy in each
hour of the day through December 2000. Electric Utility has a number of other
power supply agreements with PP&L and other power producers having various
length terms expiring through December 2001. In high usage months, Electric
Utility meets its additional electric power needs, above those provided by these
contracts and its own generation facilities, through monthly market-based
contracts and through spot purchases at market prices as delivered.
In September 2000, UGIDC agreed to joint venture with a subsidiary of
Allegheny Energy, Inc. ("Allegheny") to own and operate electric generation
facilities, including Electric Utility's coal-fired Hunlock Creek generating
station ("Hunlock"). Initially, UGIDC will contribute to the joint venture
Hunlock, certain related assets, and approximately $6 million in cash. Allegheny
will contribute a newly-constructed gas-fired combustion turbine generator to be
operated at Hunlock's site. Each partner will be entitled to purchase 50% of the
output of the joint venture at cost. The joint venture is expected to become
operational in December 2000.
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, a predecessor company of the Partnership, relating to Petrolane's
divestiture of nonpropane operations before its 1989 acquisition by QFB
Partners. Future lease payments under these leases total approximately $32
million at September 30, 2000. 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. To date, Texas
Eastern has directly satisfied defaulted lease obligations without the
Partnership's having to honor its guarantee.
In addition, the Partnership has succeeded to Petrolane's agreement to
indemnify Shell Petroleum N.V. ("Shell") for various scheduled claims, including
claims related to antitrust actions, that were pending against Tropigas de
Puerto Rico ("Tropigas"). Petrolane had entered into this indemnification
agreement in conjunction with its sale of the international operations of
Tropigas to Shell in 1989. The Partnership also succeeded to Petrolane's right
to seek indemnity on these claims first from International Controls Corp., which
sold Tropigas to Petrolane, and then from Texas Eastern. To date, neither the
Partnership nor Petrolane has paid any sums under this indemnity. In 1999, a
case brought by an unsuccessful entrant into the Puerto Rican propane market was
dismissed by the Supreme Court of Puerto Rico for lack of subject matter
jurisdiction, with the Court concluding that the Public Service Commission of
Puerto Rico has exclusive jurisdiction over the matter. In the only pending
litigation, the Supreme Court of Puerto Rico denied the motion of the defendants
to dismiss, remanding the matter to the trial court for proceedings consistent
with its ruling. In this case the plaintiff seeks treble damages in excess of
$11.7 million.
We believe that the probability the Partnership will be required to directly
satisfy the above lease obligations and the remaining claim subject to the
indemnification agreements is remote.
We, along with other companies, have been named as a potentially responsible
party ("PRP") in several administrative proceedings and private party recovery
actions for the cleanup, or recovery of costs associated with cleanup, of
various waste sites, including some Superfund sites. In addition, we have
identified environmental contamination at several of our properties and have
voluntarily undertaken investigation and, as appropriate, remediation of these
sites in cooperation with appropriate environmental agencies or private parties.
43
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
Prior to the general availability of natural gas, in the 1800s through the
mid-1900s, most gas for lighting and heating nationwide was manufactured from
combustibles such as coal, oil and coke. Some constituents of coal tars and
other residues of the manufactured gas process are today considered hazardous
substances under the federal "Comprehensive Environmental Response, Compensation
and Liability Act," or "Superfund Law," and may be present on the sites of
former manufactured gas plants ("MGPs").
UGI Utilities and its former subsidiaries owned and operated a number of
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. By the mid-1930s, UGI Utilities was one of the
largest public utility holding companies in the country. 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 has been notified of several sites outside Pennsylvania on
which (1) gas plants 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 UGI Utilities should not have significant liability
in those instances in which a former subsidiary operated an MGP because UGI
Utilities generally is not legally liable for the obligations of its
subsidiaries. Under certain circumstances, however, a court could find a parent
company liable for environmental damage caused by a subsidiary company when the
parent company either (1) itself operated the facility causing the environmental
damage or (2) otherwise so controlled the subsidiary that the subsidiary's
separate corporate form should be disregarded. There could be, therefore,
significant future costs of an uncertain amount associated with environmental
damage caused by MGPs that UGI Utilities owned or 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 identified 40 sites in Pennsylvania where either (1) UGI
Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at
one time owned the site. Because Gas Utility is currently permitted to include
in rates, through future base rate proceedings, prudently incurred remediation
costs associated with Pennsylvania sites, the Company does not expect its costs
for Pennsylvania sites to be material to future results of operations.
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 2000, UGI Utilities entered
into settlement agreements with several of the insurers and recorded pre-tax
income of $4.5 million which amount is included in operating and administrative
expenses in the 2000 Consolidated Statement 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.
Management believes, 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 12 -- FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding 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 long-term debt and UGI Utilities Series Preferred
Stock at September 30 are as follows:
Carrying Estimated
Amount Fair Value
- ------------------------------------------------------------------
2000:
Long-term debt:
AmeriGas Propane $857.2 $882.5
UGI Utilities 172.9 167.8
Other 85.5 85.6
UGI Utilities Series Preferred Stock 20.0 21.0
1999:
Long-term debt:
AmeriGas Propane $744.7 $761.3
UGI Utilities 180.0 174.8
Other 91.6 91.1
UGI Utilities Series Preferred Stock 20.0 20.9
- -----------------------------------------------------------------
We estimate the fair value of long-term debt by using current market prices
and by discounting future cash flows using rates available for similar type
debt. The estimated fair value of UGI Utilities Series Preferred Stock is based
on the fair value of redeemable preferred stock with similar credit ratings and
redemption features.
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.
44
33
UGI Corporation 2000 Annual Report
We utilize derivative instruments to hedge market risk resulting from changes
in the price of natural gas and propane, and changes in interest rates. We
attempt to minimize our credit risk with our counterparties through the
application of credit policies.
At September 30, 2000 and 1999, the Partnership was a party to an interest
rate protection agreement covering $50 million of long-term debt to be issued in
fiscal 2001. The counterparty to this agreement is a large financial
institution. The estimated fair value of this agreement was $2.5 million at
September 30, 2000 and $3.2 million at September 30, 1999.
At September 30, 2000 and 1999, Energy Services held exchange traded natural
gas futures contracts with total notional amounts of $30.2 million and $26.6
million, respectively. Net deferred gains on settled and unsettled contracts
totaled $6.6 million at September 30, 2000 and $3.3 million at September 30,
1999. At September 30, 1999, Energy Services also held exchange traded heating
oil futures and option contracts with a total notional amount of $6.5 million
and an estimated fair value of $(0.2) million.
At September 30, 2000 and 1999, the Partnership was a party to propane price
swap and option agreements with private counterparties with total notional
amounts of $74.8 million and $12.9 million, respectively. Agreements outstanding
at September 30, 2000 mature through March 2001. The estimated fair values of
these swap and option agreements were $6.5 million and $2.9 million at September
30, 2000 and 1999, respectively.
NOTE 13 - ACQUISITIONS
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 preliminarily
allocated to the net assets acquired was approximately $42 million. During 1999
and 1998, the Partnership acquired several retail propane distribution
businesses for net cash consideration of $3.9 million and $8.1 million,
respectively. These acquisitions were recorded using the purchase method of
accounting. Under the purchase method, the purchase price has been allocated to
assets acquired and liabilities assumed based upon estimated fair values. The
operating results of these businesses have been included in the consolidated
results from their respective dates of acquisition. In addition to these
acquisitions, during 1999 the Company paid $4.9 million for a 25% equity
interest in a propane distribution business in Nantong, China, which is being
accounted for on the equity method of accounting.
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
$57.5 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
the Company's 1999 results of operations.
The unaudited pro forma revenues, net income and diluted earnings per share
of the Company for 1999, as if the acquisition of FLAGA had occurred as of
October 1, 1998, are $1,434.0 million, $52.0 million, and $1.62, respectively.
The pro forma results of operations give effect to FLAGA's historical operating
results in accordance with U.S. generally accepted accounting principles and
adjustments for interest expense, goodwill amortization and depreciation
expense, and income taxes, but do not adjust for normal weather conditions and
anticipated operating efficiencies. In management's opinion, the unaudited pro
forma results are not indicative of the actual results that would have occurred
had the acquisition of FLAGA occurred as of October 1, 1998, or of future
operating results under the ownership and management of the Company. The pro
forma effect of the other businesses acquired during 2000, 1999 and 1998 was not
material to our results of operations.
NOTE 14 - TERMINATED MERGER - UNISOURCE WORLDWIDE, INC.
On May 25, 1999, the Company 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 the Company and Unisource. Because the board of
directors of Unisource decided to enter into a merger agreement with GP,
Unisource was required to pay the Company a $25 million merger termination fee
pursuant to the terms of the Merger Agreement. The Company 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 15 - OTHER INCOME, NET
Other income, net, comprises the following:
2000 1999 1998
- ---------------------------------------------------------------------------
Interest and interest-related income $ (9.3) $ (8.5) $ (8.6)
Loss on Partnership's interest rate
protection agreements -- -- 4.0
Gain on sales of investments (1.8) -- (2.3)
Gain on sales of fixed assets (3.6) (2.2) (2.0)
Pension income (3.0) (2.3) (1.9)
Other (9.2) (3.8) (1.9)
- ---------------------------------------------------------------------------
Total other income, net $ (26.9) $ (16.8) $ (12.7)
- ---------------------------------------------------------------------------
45
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Millions of dollars, except per share amounts and where indicated otherwise)
NOTE 16-- QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30,
1999 1998 2000(a) 1999(b) 2000 1999(c) 2000(d) 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 466.6 $ 373.7 $ 610.4 $ 499.2 $ 335.9 $ 259.3 $ 348.8 $ 251.4
Operating income (loss) 70.7 61.5 117.9 115.6 8.7 9.4 (6.1) (10.6)
Net income (loss) 21.1 18.0 38.8 37.5 (4.7) 11.4 (10.5) (11.2)
Net income (loss) per share-
Basic 0.77 0.55 1.42 1.15 (0.17) 0.36 (0.39) (0.37)
Diluted 0.77 0.55 1.42 1.14 (0.17) 0.36 (0.39) (0.37)
- ----------------------------------------------------------------------------------------------------------------------------------
The quarterly data above includes all adjustments (consisting only of normal
recurring adjustments with the exception of those indicated below) which we
consider necessary for a fair presentation.
Our quarterly results fluctuate because of the seasonal nature of our
businesses.
(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 merger expenses of $1.6 million which decreased net income by $1.1
million or $0.03 per share.
(c) Includes merger termination fee income of $25 million, less $3.5 million of
merger related expenses, which increased net income by $14.0 million or $0.44
per share.
(d) 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.
NOTE 17 -- SEGMENT INFORMATION
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("SFAS 131"), defines operating segments as components of an
enterprise for which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. We have determined that the
Company has five such business segments: (1) AmeriGas Propane; (2) Gas Utility;
(3) Electric Utility; (4) Energy Services; and (5) an international propane
segment comprising FLAGA and our equity investments in China and Romania.
AmeriGas Propane derives its revenues principally from the sale of propane
and related equipment and supplies principally to retail customers from
locations in 45 states. Gas Utility revenues are derived principally from the
sale and distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Utility derives its revenues from the sale and
distribution of electricity in two northeastern Pennsylvania counties. Although
the Electricity Customer Choice Act unbundled the pricing for Electric Utility's
electric generation, transmission and distribution services, we currently manage
and evaluate these business components on a combined basis. Energy Services
revenues are derived from the sale of natural gas and, to a lesser extent,
electricity to customers located primarily in the Middle Atlantic and New
England states. Our International Propane segment revenues result principally
from the distribution of propane to retail customers in Austria, the Czech
Republic and Slovakia.
The accounting policies of our reportable segments are substantially 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:
46
35
AmeriGas Gas Electric Energy
Total Eliminations Propane Utility Utility Services
- ----------------------------------------------------------------------------------------------------------------------------------
2000
Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9
EBITDA $ 288.7 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0
Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 191.2 -- 90.2 86.2 15.1 2.8
Interest expense (98.5) -- (74.7) (16.2) (2.2) --
Minority interest (6.3) -- (6.3) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8
Total assets $2,278.8 $ (19.0) $1,281.7 $ 656.7 $ 97.4 $ 36.2
Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1
Investments in foreign equity investees $ 5.5 $ -- $ -- $ -- $ -- $ --
==================================================================================================================================
1999
Revenues $1,383.6 $ (2.3) $ 872.5 $ 345.6 $ 75.0 $ 90.4
EBITDA $ 265.6 $ -- $ 158.8 $ 87.0 $ 16.7 $ 2.7
Depreciation and amortization (89.7) -- (66.3) (19.0) (4.0) (0.1)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 175.9 -- 92.5 68.0 12.7 2.6
Merger fee income, net 19.9 -- -- -- -- --
Interest expense (84.6) -- (66.5) (15.2) (2.3) --
Minority interest (10.7) -- (10.7) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes $ 100.5 $ -- $ 15.3 $ 52.8 $ 10.4 $ 2.6
Total assets $2,140.5 $ (15.6) $1,221.9 $ 620.4 $ 95.3 $ 17.4
Capital expenditures $ 73.7 $ -- $ 34.6(a) $ 31.9 $ 4.5 $ 0.2
Investments in foreign equity investees $ 6.3 $ -- $ -- $ -- $ -- $ --
==================================================================================================================================
1998
Revenues $1,439.7 $ (3.0) $ 914.4 $ 350.2 $ 72.1 $ 103.0
EBITDA $ 258.0 $ -- $ 153.3 $ 83.0 $ 13.6 $ 2.1
Depreciation and amortization (87.8) -- (65.4) (18.2) (3.9) (0.1)
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 170.2 -- 87.9 64.8 9.7 2.0
Interest expense (84.4) -- (66.1) (15.3) (2.3) --
Minority interest (8.9) -- (8.9) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes $ 76.9 $ -- $ 12.9 $ 49.5 $ 7.4 $ 2.0
Total assets $2,074.6 $ (17.1) $1,238.2 $ 594.4 $ 95.6 $ 14.3
Capital expenditures $ 69.2 $ -- $ 31.9 $ 32.0 $ 5.2 $ 0.1
Investments in foreign equity investees $ 2.1 $ -- $ -- $ -- $ -- $ --
==================================================================================================================================
International Other Corporate &
Propane Enterprises Other
- ------------------------------------------------------------------------------------
2000
Revenues $ 50.5 $ 7.3 $ 3.1
EBITDA $ 1.9 $ (5.0) $ 5.3
Depreciation and amortization (4.6) (0.5) (0.2)
- ------------------------------------------------------------------------------------
Operating income (loss) (2.7) (5.5) 5.1
Interest expense (4.8) -- (0.6)
Minority interest -- -- --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes $ (7.5) $ (5.5) $ 4.5
Total assets $ 113.7 $ 28.2 $ 83.9
Capital expenditures $ 1.8 $ 2.3 $ --
Investments in foreign equity investees $ 5.5 $ -- $ --
==================================================================================
1999
Revenues $ -- $ 0.1 $ 2.3
EBITDA $ (0.1) $ (5.7) $ 6.2
Depreciation and amortization -- -- (0.3)
- ------------------------------------------------------------------------------------
Operating income (loss) (0.1) (5.7) 5.9
Merger fee income, net -- -- 19.9
Interest expense -- -- (0.6)
Minority interest -- -- --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes $ (0.1) $ (5.7) $ 25.2
Total assets $ 143.2 $ 3.7 $ 54.2
Capital expenditures $ -- $ 2.5 $ --
Investments in foreign equity investees $ 6.3 $ -- $ --
==================================================================================
1998
Revenues $ -- $ -- $ 3.0
EBITDA $ (1.0) $ (1.8) $ 8.8
Depreciation and amortization -- -- (0.2)
- ------------------------------------------------------------------------------------
Operating income (loss) (1.0) (1.8) 8.6
Interest expense -- -- (0.7)
Minority interest -- -- --
- ------------------------------------------------------------------------------------
Income (loss) before income taxes $ (1.0) $ (1.8) $ 7.9
Total assets $ 2.3 $ 0.1 $ 146.8
Capital expenditures $ -- $ -- $ --
Investments in foreign equity investees $ 2.1 $ -- $ --
==================================================================================
(a) Includes capital leases of $3.5 million.
47