UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
Pennsylvania 23-2668356
(State or other jurisdiction of ( I.R.S. Employer
incorporation or organization) Identification No.)
UGI CORPORATION
460 North Gulph Road, King of Prussia, PA
(Address of principal executive offices)
19406
(Zip Code)
(610) 337-1000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
At July 31, 2003, there were 42,679,139 shares of UGI Corporation
Common Stock, without par value, outstanding.
UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
PAGES
-----
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2003,
September 30, 2002 and June 30, 2002 1
Condensed Consolidated Statements of Income for the three
and nine months ended June 30, 2003 and 2002 2
Condensed Consolidated Statements of Cash Flows for the
nine months ended June 30, 2003 and 2002 3
Notes to Condensed Consolidated Financial Statements 4 - 16
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17 - 28
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28 - 30
Item 4. Controls and Procedures 30
PART II OTHER INFORMATION
Item 1. Legal Proceedings 31
Item 6. Exhibits and Reports on Form 8-K 31 - 32
Signatures 33
-i-
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
June 30, September 30, June 30,
2003 2002 2002
--------- ------------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 121.7 $ 194.3 $ 135.2
Short-term investments (at cost, which approximates fair value) 50.0 - -
Accounts receivable (less allowances for doubtful accounts of
$19.6, $11.8 and $15.1, respectively) 240.8 157.7 173.0
Accrued utility revenues 7.9 8.1 7.5
Inventories 97.0 109.2 87.1
Deferred income taxes 33.5 10.4 19.2
Utility regulatory assets - 4.3 -
Prepaid expenses and other current assets 34.0 46.0 30.0
--------- --------- ---------
Total current assets 584.9 530.0 452.0
Property, plant and equipment, at cost (less accumulated depreciation
and amortization of $787.8, $720.5 and $703.7, respectively) 1,336.9 1,271.9 1,266.8
Goodwill and excess reorganization value 665.1 644.9 645.1
Intangible assets (less accumulated amortization of $14.6, $10.3 and $9.5, respectively) 38.4 25.8 27.6
Utility regulatory assets 60.1 57.7 54.8
Other assets 86.3 84.1 109.8
--------- --------- ---------
Total assets $ 2,771.7 $ 2,614.4 $ 2,556.1
========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 124.6 $ 148.7 $ 89.0
AmeriGas Propane bank loans - 10.0 -
UGI Utilities bank loans 2.3 37.2 45.6
Other bank loans 12.6 8.6 7.9
Accounts payable 176.7 166.1 142.4
Other current liabilities 237.3 215.8 189.7
--------- --------- ---------
Total current liabilities 553.5 586.4 474.6
Long-term debt 1,115.9 1,127.0 1,149.3
Deferred income taxes 221.4 200.2 193.2
Other noncurrent liabilities 107.5 87.5 81.4
Commitments and contingencies (note 7)
Minority interests in AmeriGas Partners 167.4 276.0 308.9
UGI Utilities preferred shares subject to mandatory redemption 20.0 20.0 20.0
Common stockholders' equity:
Common Stock, without par value (authorized - 150,000,000 shares;
issued - 49,798,097 shares) 577.0 396.6 395.3
Retained earnings 108.7 39.7 57.7
Accumulated other comprehensive income 9.3 6.6 4.8
--------- --------- ---------
695.0 442.9 457.8
Treasury stock, at cost (109.0) (125.6) (129.1)
--------- --------- ---------
Total common stockholders' equity 586.0 317.3 328.7
--------- --------- ---------
Total liabilities and stockholders' equity $ 2,771.7 $ 2,614.4 $ 2,556.1
========= ========= =========
See accompanying notes to condensed consolidated financial statements.
-1-
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions, except per share amounts)
Three Months Ended Nine Months Ended
June 30, June 30,
-------------------------------------------
2003 2002 2003 2002
-------- -------- --------- ---------
Revenues $ 623.1 $ 446.3 $ 2,498.9 $ 1,829.7
Costs and expenses:
Cost of sales 430.1 255.2 1,638.1 1,075.4
Operating and administrative expenses 159.5 140.1 490.3 434.6
Utility taxes other than income taxes 3.4 2.9 9.8 8.7
Depreciation and amortization 26.1 23.2 75.7 69.9
Other income, net (4.4) (4.1) (15.2) (12.9)
-------- -------- --------- ---------
614.7 417.3 2,198.7 1,575.7
-------- -------- --------- ---------
Operating income 8.4 29.0 300.2 254.0
Income from equity investees 0.2 0.7 7.1 8.2
Loss on extinguishments of debt - - (3.0) (0.7)
Interest expense (26.5) (26.9) (81.8) (82.5)
Minority interests in AmeriGas Partners 14.1 5.1 (51.2) (45.5)
-------- -------- --------- ---------
Income (loss) before income taxes and subsidiary preferred
stock dividends (3.8) 7.9 171.3 133.5
Income tax (expense) benefit 2.2 (3.5) (65.6) (50.2)
Dividends on UGI Utilities Series Preferred Stock (0.4) (0.4) (1.2) (1.2)
-------- -------- --------- ---------
Net income (loss) $ (2.0) $ 4.0 $ 104.5 $ 82.1
======== ======== ========= =========
Earnings (loss) per share - basic $ (0.05) $ 0.10 $ 2.49 $ 1.99
======== ======== ========= =========
Earnings (loss) per share - diluted $ (0.05) $ 0.09 $ 2.43 $ 1.95
======== ======== ========= =========
Average common shares outstanding:
Basic 42.451 41.390 42.031 41.256
======== ======== ========= =========
Diluted 42.451 42.320 43.038 42.053
======== ======== ========= =========
Dividends declared per common share $ 0.285 $ 0.275 $ 0.845 $ 0.808
======== ======== ========= =========
See accompanying notes to condensed consolidated financial statements.
- 2 -
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
Nine Months Ended
June 30,
-------- --------
2003 2002
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 104.5 $ 82.1
Reconcile to net cash provided by operating activities:
Depreciation and amortization 75.7 69.9
Minority interests in AmeriGas Partners 51.2 45.5
Deferred income taxes, net (11.4) 8.5
Other, net 25.9 4.7
Net change in:
Accounts receivable and accrued utility revenues (94.7) 2.0
Inventories 14.2 41.8
Deferred fuel costs 35.9 1.5
Accounts payable 9.0 (24.6)
Other current assets and liabilities (5.0) (31.7)
-------- --------
Net cash provided by operating activities 205.3 199.7
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (72.5) (63.3)
Net proceeds from disposals of assets 4.9 5.5
Acquisition of additional interest in Conemaugh Station (51.3) -
Acquisitions of businesses, net of cash acquired (38.3) (0.7)
Increase in short-term investments (50.0) -
Other, net 8.4 0.8
-------- --------
Net cash used by investing activities (198.8) (57.7)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends on UGI Common Stock (35.6) (33.3)
Distributions on AmeriGas Partners publicly held Common Units (41.1) (39.8)
Issuance of long-term debt 122.8 41.1
Repayment of long-term debt (175.1) (102.9)
AmeriGas Propane bank loans decrease (10.0) -
UGI Utilities bank loans decrease (34.9) (12.2)
Other bank loans increase (decrease) 2.4 (2.9)
Issuance of AmeriGas Partners Common Units 75.0 49.6
Issuance of UGI Common Stock 17.4 6.1
-------- --------
Net cash used by financing activities (79.1) (94.3)
-------- --------
EFFECT OF EXCHANGE RATE CHANGES ON CASH - -
-------- --------
Cash and cash equivalents (decrease) increase $ (72.6) $ 47.7
======== ========
Cash and cash equivalents:
End of period $ 121.7 $ 135.2
Beginning of period 194.3 87.5
-------- --------
(Decrease) increase $ (72.6) $ 47.7
======== ========
See accompanying notes to condensed consolidated financial statements.
-3-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(Millions of dollars, except per share amounts)
1. BASIS OF PRESENTATION
UGI Corporation ("UGI") is a holding company that owns and operates
natural gas and electric utility, electricity generation, propane
distribution, energy marketing and related businesses in the United
States. Through foreign subsidiaries and joint-venture affiliates, UGI
also distributes propane in Austria, the Czech Republic, Slovakia,
France and China.
Our natural gas and electric distribution utility businesses are
conducted through our wholly owned subsidiary, UGI Utilities, Inc.
("UGI Utilities"). UGI Utilities owns and operates a natural gas
distribution utility ("Gas Utility") in parts of eastern and
southeastern Pennsylvania and owns and operates an electricity
distribution utility ("Electric Utility") in northeastern Pennsylvania.
We conduct a national propane distribution business through AmeriGas
Partners, L.P. ("AmeriGas Partners") and its principal operating
subsidiaries AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas OLP's
subsidiary, AmeriGas Eagle Propane, L.P. ("Eagle OLP"). AmeriGas
Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships.
UGI's wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the
"General Partner") serves as the general partner of AmeriGas Partners
and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to
as "the Operating Partnerships") comprise the largest retail propane
distribution business in the United States serving residential,
commercial, industrial, motor fuel and agricultural customers from
locations in 46 states. We refer to AmeriGas Partners and its
subsidiaries together as "the Partnership" and the General Partner and
its subsidiaries, including the Partnership, as "AmeriGas Propane." At
June 30, 2003, the General Partner and its wholly owned subsidiary
Petrolane Incorporated ("Petrolane") collectively held a 1% general
partner interest and a 46.4% limited partner interest in AmeriGas
Partners, and effective 47.9% and 47.8% ownership interests in AmeriGas
OLP and Eagle OLP, respectively. Our limited partnership interest in
AmeriGas Partners comprises 24,525,004 Common Units. The remaining
52.6% interest in AmeriGas Partners comprises 27,808,204 publicly held
Common Units representing limited partner interests.
Our wholly owned subsidiary, UGI Enterprises, Inc. ("Enterprises"),
conducts an energy marketing business primarily in the Middle Atlantic
region of the United States through its wholly owned subsidiary, UGI
Energy Services, Inc. ("Energy Services"). Energy Services' wholly
owned subsidiary UGI Development Company ("UGID"), and UGID's
subsidiaries and joint-venture affiliate Hunlock Creek Energy Ventures,
own and operate interests in Pennsylvania-based electricity generation
assets. Prior to its transfer to Energy Services in June 2003, UGID was
a wholly owned subsidiary of UGI Utilities. Through other subsidiaries,
Enterprises (1) owns and operates a propane distribution business in
Austria, the Czech Republic and Slovakia ("FLAGA"); (2) owns and
operates a heating, ventilation and air-conditioning service business
in the Middle Atlantic states ("HVAC"); and (3) participates in propane
joint-venture businesses in France ("Antargaz") and China.
-4-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
Our condensed consolidated financial statements include the accounts of
UGI and its majority-owned subsidiaries, together referred to as "we"
or "the Company." We eliminate all significant intercompany accounts
and transactions when we consolidate. We report the public's limited
partner interests in the Partnership's results of operations and net
assets as minority interests in the condensed consolidated statements
of income and balance sheets.
The accompanying condensed consolidated financial statements are
unaudited and have been prepared in accordance with the rules and
regulations of the U.S. Securities and Exchange Commission ("SEC").
They include all adjustments which we consider necessary for a fair
statement of the results for the interim periods presented. Such
adjustments consisted only of normal recurring items unless otherwise
disclosed. The September 30, 2002 condensed consolidated balance sheet
data was derived from audited financial statements, but does not
include all disclosures required by accounting principles generally
accepted in the United States of America. These financial statements
should be read in conjunction with the financial statements and related
notes included in our Annual Report on Form 10-K for the year ended
September 30, 2002 ("Company's 2002 Annual Report"). Due to the
seasonal nature of our businesses, the results of operations for
interim periods are not necessarily indicative of the results to be
expected for a full year.
EARNINGS (LOSS) PER COMMON SHARE. On January 28, 2003, UGI's Board of
Directors approved a 3-for-2 split of UGI's Common Stock. On April 1,
2003, UGI issued one additional common share for every two common
shares outstanding to shareholders of record on February 28, 2003.
Average shares outstanding, earnings (loss) per share and dividends
declared per share for the three and nine months ended June 30, 2003
are reflected on a post-split basis. Prior-year amounts have been
restated to reflect the effects of the common stock split.
Basic earnings (loss) per share reflect the weighted-average number of
common shares outstanding. Diluted earnings (loss) per share include
the effects of dilutive stock options and common stock awards. Shares
used in computing basic and diluted earnings (loss) per share are as
follows:
- -------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
------------------ -----------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------------
Denominator (millions of shares):
Average common shares
outstanding for basic computation 42.451 41.390 42.031 41.256
Incremental shares issuable for stock
options and awards - (a) 0.930 1.007 0.797
- -------------------------------------------------------------------------------------
Average common shares outstanding for
diluted computation 42.451 42.320 43.038 42.053
- -------------------------------------------------------------------------------------
(a) As a result of the net loss for the three months ended June 30, 2003,
incremental shares issuable for stock options and awards are
antidilutive.
-5-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
STOCK-BASED COMPENSATION. As permitted by Statement of Financial
Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), we apply the provisions of Accounting
Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees" ("APB 25"), in recording compensation expense for grants
of stock, stock options, and other equity instruments to employees. We
use the intrinsic value method prescribed by APB 25 for our stock-based
employee compensation plans.
We recognized total stock and unit-based compensation expense of $3.1
million and $9.7 million in the three and nine months ended June 30,
2003, respectively, and $1.2 million and $2.7 million in the three and
nine months ended June 30, 2002, respectively. If we had determined
stock-based compensation expense under the fair value method prescribed
by SFAS 123, net income (loss) and diluted earnings (loss) per share
for the three and nine months ended June 30, 2003 and 2002 would have
been as follows:
- -----------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
------------------ ------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Net income (loss), as reported $ (2.0) $ 4.0 $ 104.5 $ 82.1
Add: Stock and unit-based employee
compensation expense included in
reported net income, net of related tax effects 1.8 0.7 5.8 1.6
Deduct: Total stock and unit-based
employee compensation expense
determined under the fair value method
for all awards, net of related tax effects (2.1) (1.0) (6.5) (2.2)
- -----------------------------------------------------------------------------------------
Pro forma net income (loss) $ (2.3) $ 3.7 $ 103.8 $ 81.5
- -----------------------------------------------------------------------------------------
Basic earnings (loss) per share:
As reported $ (0.05) $ 0.10 $ 2.49 $ 1.99
Pro forma $ (0.05) $ 0.09 $ 2.47 $ 1.98
Diluted earnings (loss) per share:
As reported $ (0.05) $ 0.09 $ 2.43 $ 1.95
Pro forma $ (0.05) $ 0.09 $ 2.41 $ 1.94
- ----------------------------------------------------------------------------------------
COMPREHENSIVE INCOME (LOSS). The following table presents the
components of comprehensive income (loss) for the three and nine months
ended June 30, 2003 and 2002:
Three Months Ended Nine Months Ended
June 30, June 30,
------------------ -----------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------
Net income (loss) $ (2.0) $ 4.0 $ 104.5 $ 82.1
Other comprehensive income (loss) (0.8) 3.6 2.7 18.3
- ----------------------------------------------------------------------------------------
Comprehensive income (loss) $ (2.8) $ 7.6 $ 107.2 $ 100.4
- ----------------------------------------------------------------------------------------
-6-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
Other comprehensive (loss) income principally comprises (1) changes in
the fair value of derivative commodity instruments and interest rate
protection agreements qualifying as hedges and (2) foreign currency
translation adjustments, net of reclassifications to net income.
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.
RECLASSIFICATIONS. In order to more appropriately classify direct costs
associated with the Partnership's Prefilled Propane Xchange ("PPX(R)")
program, for the three and nine months ended June 30, 2003, certain
costs previously considered operating and administrative expenses have
been included in cost of sales. We have reclassified $6.8 million and
$12.8 million of such costs incurred during the three and nine months
ended June 30, 2002, respectively, to conform to the current-period
presentation.
In January 2003, the Partnership recorded a loss on an early
extinguishment of long-term debt. This loss has been reflected in the
Condensed Consolidated Statement of Income for the nine months ended
June 30, 2003 as "loss on extinguishments of debt." A loss associated
with a November 2001 early extinguishment of long-term debt previously
included in other income, net, in the Condensed Consolidated Statement
of Income for the nine months ended June 30, 2002 has been reclassified
to conform to the current-period presentation (see Note 5).
2. SEGMENT INFORMATION
We have organized our business units into five reportable segments
generally based upon products sold, geographic location (domestic or
international), or regulatory environment. Our reportable segments are:
(1) AmeriGas Propane; (2) Gas Utility; (3) Electric Operations
(comprising Electric Utility and UGID's electricity generation
business); (4) Energy Services; and (5) an international propane
segment comprising FLAGA and our international propane equity
investments ("International Propane").
The accounting policies of the five segments disclosed are the same as
those described in the Significant Accounting Policies note contained
in the Company's 2002 Annual Report. We evaluate our AmeriGas Propane
and International Propane segments' profitability principally based
upon their earnings before interest expense, income taxes, depreciation
and amortization, minority interests, loss on extinguishments of debt
and income from equity investees ("Modified EBITDA"). Although we use
Modified EBITDA to evaluate these segments' profitability, it should
not be considered as an alternative to net income (as an indicator of
operating performance) or as an alternative to cash flow (as a measure
of liquidity or ability to service debt obligations) and is not a
measure of performance or financial condition under accounting
principles generally accepted in the United States. The
-7-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
Company's definition of Modified EBITDA may be different from that used
by other companies. We evaluate the performance of Gas Utility,
Electric Operations, and Energy Services principally based upon their
earnings before income taxes.
-8-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
2. SEGMENT INFORMATION (CONTINUED)
Three Months Ended June 30, 2003:
Reportable Segments
------------------------------------------------------
AmeriGas Gas Electric Energy International Corporate
Total Elims. Propane Utility Operations Services Propane & Other (a)
--------- ------- ---------- ------- ---------- -------- ------------- -----------
Revenues $ 623.1 $ (0.6) $ 287.1 $ 99.7 $ 23.3 $ 188.6 $ 11.6 $ 13.4
========= ======= ========== ======= ======= ======= ======= =======
Cost of sales $ 430.1 $ - $ 158.0 $ 65.2 $ 12.3 $ 180.9 $ 5.8 $ 7.9
========= ======= ========== ======= ======= ======= ======= =======
Segment profit (loss):
Modified EBITDA $ 34.5 $ - $ 13.2 $ 9.9 $ 5.7 $ 4.6 $ 0.1 $ 1.0
Depreciation and amortization (26.1) - (19.0) (4.4) (0.9) (0.6) (1.1) (0.1)
--------- ------- ---------- ------- ------- ------- ------- -------
Operating income (loss) 8.4 - (5.8) 5.5 4.8 4.0 (1.0) 0.9
Income (loss) from equity investees 0.2 - (0.6) - - - 0.8 -
Loss on extinguishments of debt - - - - - - - -
Interest expense (26.5) - (21.5) (3.5) (0.4) - (1.0) (0.1)
Minority interests 14.1 - 14.1 - - - - -
--------- ------- ---------- ------- ------- ------- ------- -------
Income (loss) before income taxes and
subsidiary preferred stock dividends $ (3.8) $ - $ (13.8) $ 2.0 $ 4.4 $ 4.0 $ (1.2) $ 0.8
========= ======= ========== ======= ======= ======= ======= =======
Segment assets (at period end) $ 2,771.7 $ (41.1) $ 1,500.9 $ 711.2 $ 160.4 $ 104.4 $ 171.4 $ 164.5
========= ======= ========== ======= ======= ======= ======= =======
Investments in equity investees
(at period end) $ 41.0 $ - $ 2.9 $ - $ 9.9 $ - $ 28.2 $ -
========= ======= ========== ======= ======= ======= ======= =======
Goodwill and excess reorganization value
(at period end) $ 665.1 $ - $ 598.8 $ - $ - $ - $ 62.0 $ 4.3
========= ======= ========== ======= ======= ======= ======= =======
Three Months Ended June 30, 2002:
Reportable Segments
-----------------------------------------------------
AmeriGas Gas Electric Energy International Corporate
Total Elims. Propane Utility Operations Services Propane & Other (a)
--------- ------- --------- ------- ---------- -------- ------------- -----------
Revenues $ 446.3 $ (0.3) $ 254.5 $ 68.1 $ 20.2 $ 85.1 $ 9.2 $ 9.5
========= ======= ========= ======= ====== ====== ======= ======
Cost of sales $ 255.2 $ - $ 118.0 $ 37.0 $ 11.3 $ 79.1 $ 4.7 $ 5.1
========= ======= ========= ======= ====== ====== ======= ======
Segment profit (loss):
Modified EBITDA $ 52.2 $ - $ 28.5 $ 14.7 $ 3.8 $ 3.8 $ 0.5 $ 0.9
Depreciation and amortization (23.2) - (16.7) (4.5) (0.7) (0.3) (0.8) (0.2)
--------- ------- --------- ------- ------ ------ ------- ------
Operating income (loss) 29.0 - 11.8 10.2 3.1 3.5 (0.3) 0.7
Income (loss) from equity investees 0.7 - - - - - 0.8 (0.1)
Loss on extinguishments of debt - - - - - - - -
Interest expense (26.9) - (21.8) (3.4) (0.6) - (1.0) (0.1)
Minority interests 5.1 - 5.1 - - - - -
--------- ------- --------- ------- ------ ------ ------- ------
Income (loss) before income taxes and
subsidiary preferred stock dividends $ 7.9 $ - $ (4.9) $ 6.8 $ 2.5 $ 3.5 $ (0.5) $ 0.5
========= ======= ========= ======= ====== ====== ======= ======
Segment assets (at period end) $ 2,556.1 $ (31.8) $ 1,486.2 $ 669.4 $ 106.0 $ 53.1 $ 163.7 $109.5
========= ======= ========= ======= ====== ====== ======= ======
Investments in equity investees
(at period end) $ 55.5 $ - $ 3.5 $ - $ 10.4 $ - $ 41.6 $ -
========= ======= ========= ======= ====== ====== ======= ======
Goodwill and excess reorganization value
(at period end) $ 645.1 $ - $ 589.0 $ - $ - $ - $ 52.6 $ 3.5
========= ======= ========= ======= ====== ====== ======= ======
a) Principally comprises UGI, UGI Enterprises' HVAC operations, and UGI
Enterprises' corporate and general expenses.
-9-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
2. SEGMENT INFORMATION (CONTINUED)
Nine Months Ended June 30, 2003:
Reportable Segments
-------------------------------------------------------
AmeriGas Gas Electric Energy International Corporate
Total Elims. Propane Utility Operations Services Propane & Other (a)
--------- ------- --------- ------- ---------- --------- ------------- -----------
Revenues $ 2,498.9 $ (1.8) $ 1,357.7 $ 484.7 $ 75.9 $ 504.3 $ 44.0 $ 34.1
========= ======= ========= ======= ======== ======= ======= =======
Cost of sales $ 1,638.1 $ - $ 762.0 $ 312.6 $ 38.5 $ 481.7 $ 24.4 $ 18.9
========= ======= ========= ======= ======== ======= ======= =======
Segment profit:
Modified EBITDA $ 375.9 $ - $ 229.0 $ 107.7 $ 20.9 $ 13.3 $ 3.5 $ 1.5
Depreciation and amortization (75.7) - (55.0) (13.6) (2.4) (1.1) (2.9) (0.7)
--------- ------- --------- ------- -------- ------- ------- -------
Operating income 300.2 - 174.0 94.1 18.5 12.2 0.6 0.8
Income from equity investees 7.1 - (0.5) - - - 7.6 -
Loss on extinguishments of debt (3.0) - (3.0) - - - - -
Interest expense (81.8) - (66.0) (10.7) (1.7) - (3.1) (0.3)
Minority interests (51.2) - (51.2) - - - - -
--------- ------- --------- ------- -------- ------- ------- -------
Income before income taxes and
subsidiary preferred stock dividends $ 171.3 $ - $ 53.3 $ 83.4 $ 16.8 $ 12.2 $ 5.1 $ 0.5
========= ======= ========= ======= ======== ======= ======= =======
Segment assets (at period end) $ 2,771.7 $ (41.1) $ 1,500.9 $ 711.2 $ 160.4 $ 104.4 $ 171.4 $ 164.5
========= ======= ========= ======= ======== ======= ======= =======
Investments in equity investees
(at period end) $ 41.0 $ - $ 2.9 $ - $ 9.9 $ - $ 28.2 $ -
========= ======= ========= ======= ======== ======= ======= =======
Goodwill and excess reorganization value
(at period end) $ 665.1 $ - $ 598.8 $ - $ - $ - $ 62.0 $ 4.3
========= ======= ========= ======= ======== ======= ======= =======
Nine Months Ended June 30, 2002:
Reportable Segments
------------------------------------------------------
AmeriGas Gas Electric Energy International Corporate
Total Elims. Propane Utility Operations Services Propane & Other (a)
--------- ------- -------- ------- ---------- -------- ------------- -----------
Revenues $ 1,829.7 $ (1.4) $1,086.0 $ 347.5 $ 62.2 $ 272.3 $ 35.6 $ 27.5
========= ======= ======== ======= ======= ======= ======= =======
Cost of sales $ 1,075.4 $ - $ 541.8 $ 209.0 $ 35.5 $ 257.0 $ 17.9 $ 14.2
========= ======= ======== ======= ======= ======= ======= =======
Segment profit:
Modified EBITDA $ 323.9 $ - $ 208.1 $ 88.0 $ 11.1 $ 8.4 $ 5.5 $ 2.8
Depreciation and amortization (69.9) - (49.5) (14.5) (2.4) (0.7) (2.2) (0.6)
--------- ------- -------- ------- ------- ------- ------- -------
Operating income 254.0 - 158.6 73.5 8.7 7.7 3.3 2.2
Income from equity investees 8.2 - 0.5 - - - 7.8 (0.1)
Loss on extinguishments of debt (0.7) - (0.7) - - - - -
Interest expense (82.5) - (66.5) (10.7) (1.8) - (3.1) (0.4)
Minority interests (45.5) - (45.5) - - - - -
--------- ------- -------- ------- ------- ------- ------- -------
Income before income taxes and
subsidiary preferred stock dividends $ 133.5 $ - $ 46.4 $ 62.8 $ 6.9 $ 7.7 $ 8.0 $ 1.7
========= ======= ======== ======= ======= ======= ======= =======
Segment assets (at period end) $ 2,556.1 $ (31.8) $1,486.2 $ 669.4 $ 106.0 $ 53.1 $ 163.7 $ 109.5
========= ======= ======== ======= ======= ======= ======= =======
Investments in equity investees
(at period end) $ 55.5 $ - $ 3.5 $ - $ 10.4 $ - $ 41.6 $ -
========= ======= ======== ======= ======= ======= ======= =======
Goodwill and excess reorganization value
(at period end) $ 645.1 $ - $ 589.0 $ - $ - $ - $ 52.6 $ 3.5
========= ======= ======== ======= ======= ======= ======= =======
- 10 -
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
3. INTANGIBLE ASSETS
The Company's intangible assets comprise the following:
- ---------------------------------------------------------------
June 30, September 30,
2003 2002
- ---------------------------------------------------------------
Subject to amortization:
Customer relationships, noncompete
agreements and other $ 53.0 $ 36.1
Accumulated amortization (14.6) (10.3)
- ---------------------------------------------------------------
$ 38.4 $ 25.8
- ---------------------------------------------------------------
Not subject to amortization:
Goodwill $ 571.8 $ 551.6
Excess reorganization value 93.3 93.3
- ---------------------------------------------------------------
$ 665.1 $ 644.9
- ---------------------------------------------------------------
The increase in intangible assets during the nine months ended June 30,
2003 principally reflects business acquisitions and, with respect to
goodwill, the effects of foreign currency translation. Amortization
expense of intangible assets was $1.9 million and $4.4 million for the
three and nine months ended June 30, 2003, respectively, and $1.2
million and $3.7 million for the three and nine months ended June 30,
2002, respectively. Our expected aggregate amortization expense of
intangible assets for the next five fiscal years is as follows: Fiscal
2003 - $6.2 million; Fiscal 2004 - $5.7 million; Fiscal 2005 - $4.8
million; Fiscal 2006 - $4.3 million; Fiscal 2007 - $3.7 million.
4. CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS AND COMMON UNIT
ISSUANCE
In December 2002, the General Partner determined that the cash-based
performance and distribution requirements for the conversion of the
then-remaining 9,891,072 Subordinated Units of AmeriGas Partners, all
of which were held by the General Partner, had been met in respect of
the quarter ended September 30, 2002. As a result, in accordance with
the Amended and Restated Agreement of Limited Partnership of AmeriGas
Partners, L.P., the Subordinated Units were converted to an equivalent
number of Common Units effective November 18, 2002. Concurrent with the
Subordinated Unit conversion, the Company recorded a $157.0 million
increase in common stockholders' equity, and a corresponding decrease
in minority interests in AmeriGas Partners, associated with gains from
sales of Common Units by AmeriGas Partners in conjunction with, and
subsequent to, the Partnership's April 19, 1995 initial public
offering. These gains were determined in accordance with the guidance
in SEC Staff Accounting Bulletin No. 51, "Accounting for Sales of
Common Stock by a Subsidiary" ("SAB 51"). The gains resulted because
the public offering prices of the AmeriGas Partners Common Units
exceeded the associated carrying amount of our investment in the
Partnership on the dates of their sale. Due to the preference nature of
the Common Units, the Company was precluded from recording these gains
until the Subordinated Units converted to Common Units. No deferred
income taxes were recorded on these gains due to the Company's intent
to hold its investment in the Partnership
-11-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
indefinitely. The changes to the Company's balance sheet resulting from
the Subordinated Unit conversion had no effect on the Company's net
income or cash flow and did not result in an increase in the number of
AmeriGas Partners limited partner units outstanding.
On June 17, 2003, AmeriGas Partners sold 2,900,000 Common Units in an
underwritten public offering at a public offering price of $27.12 per
unit. The net proceeds of the public offering totaling $75.0 million
and associated capital contributions from the General Partner totaling
$1.5 million, were contributed to AmeriGas OLP and used to reduce
indebtedness under its bank credit agreement and for general
partnership purposes. The underwriters' overallotment option expired
unexercised. Concurrent with this sale of Common Units, the Company
recorded a gain in the amount of $22.6 million which is reflected in
the Company's balance sheet as an increase in common stockholders'
equity in accordance with the guidance in SAB 51. The gain had no
effect on the Company's net income or cash flow.
5. LONG-TERM DEBT
On October 1, 2002, UGI Utilities repaid $26 million of its maturing
6.73% Medium-Term Notes. On December 3, 2002, AmeriGas Partners issued
$88 million face amount of 8.875% Senior Notes due 2011 at an effective
interest rate of 8.30%. The net proceeds, including debt premium, of
$89.1 million were used on January 6, 2003 to redeem prior to maturity
AmeriGas Partners' $85 million face amount of 10.125% Senior Notes due
2007 at a redemption price of 102.25%, plus accrued interest. The
Partnership recognized a pre-tax loss of $3.0 million in the quarter
ended March 31, 2003 related to the redemption premium and other
associated costs and expenses. In November 2001, AmeriGas Partners
redeemed prior to maturity $15 million face amount of its 10.125%
Senior Notes at a redemption price of 103.375%. The Partnership
recognized a pre-tax loss of $0.8 million in the quarter ended December
31, 2001 related to the redemption premium and other associated costs
and expenses.
In April 2003, AmeriGas OLP repaid $53.8 million of maturing First
Mortgage Notes. In conjunction with this repayment, in April 2003
AmeriGas Partners issued $32 million face amount of 8.875% Series B
Senior Notes due 2011 at an effective interest rate of 7.72% and
contributed the net proceeds of $33.7 million, including debt premium,
to AmeriGas OLP.
6. ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY
Energy Services has a receivables purchase facility ("Receivables
Facility") with an issuer of receivables-backed commercial paper
expiring on November 30, 2004. Under the Receivables Facility, Energy
Services transfers, on an ongoing basis and without recourse, its trade
accounts receivable to its wholly owned, special purpose,
bankruptcy-remote subsidiary, Energy Services Funding Corporation
("ESFC") which is consolidated for financial statement purposes. ESFC,
in turn, has sold, and subject to certain conditions, may from time to
time sell, an undivided ownership interest in the receivables to a
commercial paper conduit of a major bank. The level of funding
available at any one time from this facility (representing
-12-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
sales of accounts receivable net of remittances of amounts collected)
is currently $50 million. Sales of undivided interests to third parties
under this program result in a reduction of accounts receivable in the
Company's consolidated balance sheet. The proceeds of these sales are
less than the face amount of the accounts receivable sold by an amount
that approximates the purchaser's financing cost of issuing its own
receivables-backed commercial paper. This two-step transaction is
accounted for as a sale of receivables following the provisions of SFAS
No. 140, "Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities." Energy Services continues to
service, administer and collect trade receivables on behalf of the
commercial paper issuer and ESFC.
During the three and nine months ended June 30, 2003, Energy Services
sold trade receivables totaling $211.1 million and $500.0 million,
respectively, to ESFC. During the three and nine months ended June 30,
2003, ESFC sold an aggregate $93 million and $108 million,
respectively, of undivided interests in its trade receivables to the
commercial paper conduit. At June 30, 2003, the outstanding balance of
ESFC trade receivables was $51.6 million which is net of an undivided
interest of $19 million in trade receivables sold by ESFC to the
commercial paper conduit.
7. COMMITMENTS AND CONTINGENCIES
The Partnership has succeeded to certain lease guarantee obligations of
Petrolane relating to Petrolane's divestiture of nonpropane operations
before its 1989 acquisition by QFB Partners. Future lease payments
under these leases total approximately $17.0 million at June 30, 2003.
The leases expire through 2010 and some of them are currently in
default. The Partnership has succeeded to the indemnity agreement of
Petrolane by which Texas Eastern Corporation ("Texas Eastern"), a prior
owner of Petrolane, agreed to indemnify Petrolane against any
liabilities arising out of the conduct of businesses that do not relate
to, and are not a part of, the propane business, including lease
guarantees. In December 1999, Texas Eastern filed for dissolution under
the Delaware General Corporation Law. In May 2001, Petrolane filed a
declaratory judgment action in the Delaware Chancery Court seeking
confirmation of Texas Eastern's indemnification obligations and
judicial supervision of Texas Eastern's dissolution to ensure that its
indemnification obligations to Petrolane are paid or adequately
provided for in accordance with law. Those proceedings are pending.
Pursuant to a Liquidation and Winding Up Agreement dated September 17,
2002, PanEnergy Corporation ("PanEnergy"), Texas Eastern's sole
stockholder, assumed all of Texas Eastern's liabilities as of December
20, 2002, to the extent of the value of Texas Eastern's assets
transferred to PanEnergy as of that date (which was estimated to exceed
$94 million), and to the extent that such liabilities arise within ten
years from Texas Eastern's date of dissolution. Notwithstanding the
dissolution proceeding, and based on Texas Eastern previously having
satisfied directly defaulted lease obligations without the
Partnership's having to honor its guarantee, we believe that the
probability that the Partnership will be required to directly satisfy
the lease obligations subject to the indemnification agreement is
remote.
-13-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired
the propane distribution businesses of Columbia Energy Group (the "2001
Acquisition") pursuant to the terms of a purchase agreement (the "2001
Acquisition Agreement") by and among Columbia Energy Group ("CEG"),
Columbia Propane Corporation ("CPC"), Columbia Propane, L.P. ("CPLP"),
CP Holdings, Inc. ("CPH," and together with CPC and CPLP, the "Company
Parties"), AmeriGas Partners, AmeriGas OLP and the General Partner
(together with AmeriGas Partners and AmeriGas OLP, the "Buyer
Parties"). As a result of the 2001 Acquisition, AmeriGas OLP acquired
all of the stock of CPC and CPH and substantially all of the
partnership interests of CPLP. Under the terms of an earlier
acquisition agreement (the "1999 Acquisition Agreement"), the Company
Parties agreed to indemnify the former general partners of National
Propane Partners, L.P. (a predecessor company of the Columbia Propane
businesses) and an affiliate (collectively, "National General
Partners") against certain income tax and other losses that they may
sustain as a result of the 1999 acquisition by CPLP of National Propane
Partners, L.P. (the "1999 Acquisition") or the operation of the
business after the 1999 Acquisition ("National Claims"). At June 30,
2003, the potential amount payable under this indemnity by the Company
Parties was approximately $71.0 million. These indemnity obligations
will expire on the date that CPH acquires the remaining outstanding
partnership interest of CPLP, which is expected to occur on or after
July 19, 2009.
Under the terms of the 2001 Acquisition Agreement, CEG agreed to
indemnify the Buyer Parties and the Company Parties against any losses
that they sustain under the 1999 Acquisition Agreement and related
agreements ("Losses"), including National Claims, to the extent such
claims are based on acts or omissions of CEG or the Company Parties
prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify
CEG against Losses, including National Claims, to the extent such
claims are based on acts or omissions of the Buyer Parties or the
Company Parties after the 2001 Acquisition. CEG and the Buyer Parties
have agreed to apportion certain losses resulting from National Claims
to the extent such losses result from the 2001 Acquisition itself.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants
("MGPs") prior to the general availability of natural gas. Some
constituents of coal tars and other residues of the manufactured gas
process are today considered hazardous substances under the Superfund
Law and may be present on the sites of former MGPs. Between 1882 and
1953, UGI Utilities owned the stock of subsidiary gas companies in
Pennsylvania and elsewhere and also operated the businesses of some gas
companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its
utility operations other than those which now constitute Gas Utility
and Electric Utility.
UGI Utilities does not expect its costs for investigation and
remediation of hazardous substances at Pennsylvania MGP sites to be
material to its results of operations because Gas Utility is currently
permitted to include in rates, through future base rate proceedings,
prudently incurred remediation costs associated with such sites. UGI
Utilities has been
-14-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
notified of several sites outside Pennsylvania on which (1) MGPs were
formerly operated by it or owned or operated by its former subsidiaries
and (2) either environmental agencies or private parties are
investigating the extent of environmental contamination or performing
environmental remediation. UGI Utilities is currently litigating two
claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not
be liable in those instances in which a former subsidiary owned or
operated an MGP. There could be, however, significant future costs of
an uncertain amount associated with environmental damage caused by MGPs
outside Pennsylvania that UGI Utilities directly operated, or that were
owned or operated by former subsidiaries of UGI Utilities, if a court
were to conclude that (i) the subsidiary's separate corporate form
should be disregarded or (ii) UGI Utilities should be considered to
have been an operator because of its conduct with respect to its
subsidiary's MGP.
With respect to a manufactured gas plant site in Manchester, New
Hampshire, EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit
against UGI Utilities seeking contribution from UGI Utilities for
response and remediation costs associated with the contamination on the
site of a former MGP allegedly operated by former subsidiaries of UGI
Utilities. UGI Utilities and EnergyNorth agreed to a settlement of this
matter in June 2003. In June 2003, UGI Utilities recorded its estimated
liability for contingent payments to EnergyNorth under the terms of the
settlement agreement.
In April 2003, Citizens Communications Company ("Citizens") served a
complaint naming UGI Utilities as a third party defendant in a civil
action pending in United States District Court for the District of
Maine. In that action, the plaintiff, City of Bangor, sued Citizens to
recover environmental response costs associated with manufactured gas
plant wastes generated at a plant allegedly operated by Citizens'
predecessors at a site on the Penobscot River. Citizens subsequently
joined UGI Utilities and ten other third party defendants alleging that
the third party defendants are responsible for an equitable share of
any response costs Citizens may be required to pay to the City of
Bangor. Investigations of the site conducted to date are insufficient
to establish what, if any contamination is related to gas plant wastes.
Hence, UGI Utilities is unable to estimate the total cost of cleanup
associated with manufactured gas plant wastes at this site. UGI
Utilities believes that it has good defenses to the claim.
In addition to these matters, there are other pending claims and legal
actions arising in the normal course of our businesses. We cannot
predict with certainty the final results of environmental and other
matters. However, it is reasonably possible that some of them could be
resolved unfavorably to us. Although we currently believe, after
consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a
material adverse effect on our financial position, damages or
settlements could be material to our operating results or cash flows in
future periods depending on the nature and timing of future
developments with respect to these matters and the amounts of future
operating results and cash flows.
-15-
UGI CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(unaudited)
(Millions of dollars, except per share amounts)
8. INVESTMENT IN CONEMAUGH
On June 26, 2003, pursuant to an asset purchase agreement between and
among Allegheny Energy Supply Company, LLC, Allegheny Energy Supply
Conemaugh, LLC ("Allegheny Conemaugh"), UGID and UGI, UGID acquired an
additional 83 megawatt ownership interest in the Conemaugh electricity
generation station ("Conemaugh") from Allegheny Conemaugh, a unit of
Allegheny Energy, Inc. ("Allegheny"), for $51.3 million in cash,
subject to a $3.0 million credit. Conemaugh is a 1,711-megawatt,
coal-fired electricity generation station located near Johnstown,
Pennsylvania and is owned by a consortium of energy companies and
operated by a unit of Reliant Resources, Inc. under contract. The
purchase increased UGID's ownership interest in Conemaugh to 102
megawatts (6.0%) from 19 megawatts (1.1%) previously. Substantially all
of the purchase price for the additional interest in Conemaugh has been
reflected in property, plant and equipment in the Condensed
Consolidated Balance Sheet as of June 30, 2003.
-16-
UGI CORPORATION AND SUBSIDIARIES
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for (1) the three
months ended June 30, 2003 ("2003 three-month period") with the three months
ended June 30, 2002 ("2002 three-month period") and (2) the nine months ended
June 30, 2003 ("2003 nine-month period") with the nine months ended June 30,
2002 ("2002 nine-month period"). Our analyses of results of operations should be
read in conjunction with the segment information included in Note 2 to the
Condensed Consolidated Financial Statements.
-17-
UGI CORPORATION AND SUBSIDIARIES
2003 THREE-MONTH PERIOD COMPARED WITH 2002 THREE-MONTH PERIOD
- ----------------------------------------------------------------------------------------------------------------------
Increase
Three Months Ended June 30, 2003 2002 (Decrease)
- ----------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
AMERIGAS PROPANE:
Revenues $ 287.1 $ 254.5 $ 32.6 12.8%
Total margin (a) $ 129.1 $ 136.5 $ (7.4) (5.4)%
Modified EBITDA (b) $ 13.2 $ 28.5 $ (15.3) (53.7)%
Operating income (loss) $ (5.8) $ 11.8 $ (17.6) (149.2)%
Retail gallons sold (millions) (c) 182.4 182.5 (0.1) (0.1)%
Degree days - % (warmer) colder than normal (d) (0.5) 4.3 - -
GAS UTILITY:
Revenues $ 99.7 $ 68.1 $ 31.6 46.4%
Total margin (a) $ 34.5 $ 31.1 $ 3.4 10.9%
Operating income $ 5.5 $ 10.2 $ (4.7) (46.1)%
System throughput - billions of cubic feet ("bcf") 15.0 14.2 0.8 5.6%
Degree days - % colder (warmer) than normal 16.3 (5.6) - -
ELECTRIC OPERATIONS:
Revenues $ 23.3 $ 20.2 $ 3.1 15.3%
Total margin (a) $ 9.9 $ 7.9 $ 2.0 25.3%
Operating income $ 4.8 $ 3.1 $ 1.7 54.8%
Electric Utility distribution sales - millions
of kilowatt hours ("gwh") 216.3 213.0 3.3 1.5%
ENERGY SERVICES:
Revenues $ 188.6 $ 85.1 $ 103.5 121.6%
Total margin (a) $ 7.7 $ 6.0 $ 1.7 28.3%
Operating income $ 4.0 $ 3.5 $ 0.5 14.3%
INTERNATIONAL PROPANE:
Revenues $ 11.6 $ 9.2 $ 2.4 26.1%
Total margin (a) $ 5.8 $ 4.5 $ 1.3 28.9%
Modified EBITDA (b) $ 0.1 $ 0.5 $ (0.4) (80.0)%
Operating loss $ (1.0) $ (0.3) $ 0.7 233.3%
Income from equity investees $ 0.8 $ 0.8 $ - 0.0%
- ----------------------------------------------------------------------------------------------------------------------
(a) Total margin represents total revenues less cost of sales and, with respect
to Electric Operations, revenue-related taxes, i.e. Electric Utility gross
receipts taxes, of $1.1 million in each of the three month-periods ended
June 30, 2003 and 2002. For financial statement purposes, revenue-related
taxes are included in "Utility taxes other than income taxes" on the
Condensed Consolidated Statements of Income.
(b) Modified EBITDA (earnings before interest expense, income taxes,
depreciation and amortization, minority interests, loss on extinguishments
of debt and income from equity investees) should not be considered as an
alternative to net income (as an indicator of operating performance) or as
an alternative to cash flow (as a measure of liquidity or ability to
service debt obligations) and is not a measure of performance or financial
condition under accounting principles generally accepted in the United
States. Management uses Modified EBITDA as the primary measure of segment
profitability for the AmeriGas Propane and International Propane segments.
The Company's definition of Modified EBITDA may be different from that used
by other companies.
(c) Retail gallons sold in the 2003 three-month period include certain bulk
gallons previously considered wholesale gallons. Prior-period gallon
amounts have been adjusted to conform to the current period classification.
-18-
UGI CORPORATION AND SUBSIDIARIES
(d) Deviation from average heating degree days based upon national weather
statistics provided by the National Oceanic and Atmospheric Administration
("NOAA") for 335 airports in the United States, excluding Alaska.
AMERIGAS PROPANE. Retail gallons sold in the 2003 three-month period were
substantially equal to the prior-year three-month period reflecting the effects
of slightly colder early spring weather on heating-related sales offset
principally by lower commercial and industrial sales resulting from continuing
economic weakness and price-induced conservation. Low-margin wholesale propane
volumes sold in the 2003 three-month period totaled 21.7 million gallons, a
decline of 6.2 million gallons, reflecting a decrease in supply-related product
cost management activity.
Retail propane revenues increased $31.1 million in the 2003 three-month period
due to higher average retail selling prices. Wholesale propane revenues
increased $0.4 million reflecting (1) a $3.3 million increase as a result of
higher average wholesale propane selling prices partially offset by (2) a $2.9
million decrease as a result of the lower wholesale volumes sold. Retail and
wholesale propane selling prices in the 2003 three-month period reflect
significantly higher propane commodity costs. Other revenues increased $1.2
million due in large part to increased hauling activity. Total propane cost of
sales increased $39.6 million in the 2003 three-month period reflecting the
previously mentioned higher propane commodity costs.
The $7.4 million decrease in total margin is principally due to lower unit
margins from our PPX(R) grill cylinder exchange business in the 2003 three-month
period and lower average unit margins from our non-PPX(R) customers. Margins in
the prior-year period benefited from lower propane commodity prices as a result
of reduced demand for propane during the warmer than normal 2002 winter heating
season.
The $15.3 million decrease in Modified EBITDA reflects the previously mentioned
decrease in total margin and a $10.3 million increase in Partnership operating
and administrative expenses partially offset by a $2.2 million increase in other
income. Although Modified EBITDA is not a measure of performance or financial
condition under accounting principles generally accepted in the United States,
management believes Modified EBITDA is a meaningful non-GAAP financial measure
used by investors to compare our operating performance with other companies
within the retail propane industry and to evaluate our ability to meet loan
covenants. The higher 2003 three-month period operating expenses include, among
other things, (1) $3.0 million of expenses associated with a realignment of the
Partnership's management structure announced in June 2003; (2) greater medical
and general insurance expenses; and (3) higher incentive compensation expenses.
The greater other income in the 2003 three-month period reflects greater income
from sales of fixed assets and higher finance charge income. Operating income
decreased $17.6 million in the 2003 three-month period reflecting the previously
mentioned decline in Modified EBITDA and greater depreciation expense
principally associated with PPX(R).
GAS UTILITY. Total distribution system throughput increased 0.8 bcf or 5.6% as
cooler 2003 three-month period weather and customer growth increased firm-
residential, commercial and industrial ("core-market") and retail delivery
service sales. The increase in Gas Utility revenues during the 2003 three-month
period reflects the pass through of higher purchased gas costs to core-market
customers and the greater core-market sales, as well as a $10.1 million increase
in revenues from off-system sales as a result of higher natural gas prices. The
greater 2003 three-month period purchased gas cost ("PGC") rates reflect a
significant increase in the commodity price of natural gas. Gas Utility cost of
gas was $65.2 million in the 2003 three-month period compared to $37.0 million
in the 2002 three-month period reflecting the higher PGC rates and greater
core-market and off-system sales.
-19-
UGI CORPORATION AND SUBSIDIARIES
The increase in Gas Utility total margin is principally the result of greater
core-market and retail delivery service volumes.
Notwithstanding the increase in Gas Utility total margin in the 2003 three-month
period, operating income declined $4.7 million reflecting a $6.2 million
increase in operating and administrative expenses and a $1.8 million decline in
other income. The increase in operating expenses is due in large part to greater
litigation-related costs and expenses and, to a lesser extent, higher
distribution system maintenance, incentive compensation and bad debt expenses.
The decline in other income principally reflects lower pension income and a
decline in non-tariff service income.
ELECTRIC OPERATIONS. Electric Utility's 2003 three-month period kilowatt-hour
sales were slightly higher than in the prior-year period due in part to cooler
spring weather. The increase in Electric Operations' revenues reflects greater
sales of electricity produced by our electric generation assets to third parties
and, to a lesser extent, the greater Electric Utility distribution sales.
Electric Operations' cost of sales increased $1.0 million reflecting higher
costs associated with the greater electric generation third-party sales
partially offset by lower Electric Utility per-unit purchased power costs. On
June 26, 2003, the Company acquired an additional 83 megawatt ownership interest
in the Conemaugh electricity generation station from Allegheny Conemaugh for
$51.3 million, subject to a $3.0 million credit (see Note 8 to Condensed
Consolidated Financial Statements). The purchase of the additional interest did
not have a material impact on Electric Operations' results for the 2003
three-month period.
The increase in Electric Operations' total margin in the 2003 three-month period
principally reflects the effects of the lower Electric Utility per-unit
purchased power costs and increased margin from electric generation sales to
third parties. The increase in operating income primarily resulted from the
greater total margin partially offset by slightly higher operating and
administrative expenses.
ENERGY SERVICES. The significant increase in Energy Services' revenues during
the 2003 three-month period principally reflects volume growth from the March
2003 acquisition of the northeastern U.S. gas marketing business of TXU Energy
Retail Company, L.P., a subsidiary of TXU Energy ("the TXU Energy Acquisition")
as well as higher natural gas prices. The TXU Energy Acquisition increased
Energy Services' natural gas sales by more than 50 percent. The greater 2003
three-month period total margin reflects the significantly higher volumes sold
partially offset by lower average unit margins. Operating income increased $0.5
million as a result of the greater margin partially offset by higher operating
expenses resulting from the TXU Energy Acquisition.
INTERNATIONAL PROPANE. FLAGA's revenues and total margin increased in the 2003
three-month period, notwithstanding a slight decline in total volumes sold,
principally reflecting the effects of a stronger euro versus the U.S. dollar
and, with respect to total margin, slightly higher average unit margins.
Notwithstanding the increase in total margin, Modified EBITDA and operating
income were lower as a result of higher base-currency operating and
administrative expenses and the effects of the stronger euro.
Income from international propane equity investees, principally Antargaz, in the
2003 three-month period was equal to the prior-year period as higher equity
income from Antargaz resulting principally from the stronger euro was offset by
lower interest income from our debt investments in AGZ Holdings. These debt
investments were redeemed in July 2002.
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UGI CORPORATION AND SUBSIDIARIES
2003 NINE-MONTH PERIOD COMPARED WITH 2002 NINE-MONTH PERIOD
- ---------------------------------------------------------------------------------------------------------------------
Increase
Nine Months Ended June 30, 2003 2002 (Decrease)
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
AMERIGAS PROPANE:
Revenues $ 1,357.7 $ 1,086.0 $ 271.7 25.0%
Total margin $ 595.7 $ 544.2 $ 51.5 9.5%
Modified EBITDA $ 229.0 $ 208.1 $ 20.9 10.0%
Operating income $ 174.0 $ 158.6 $ 15.4 9.7%
Retail gallons sold (millions) (a) 900.0 826.2 73.8 8.9%
Degree days - % colder (warmer) than normal 0.9 (9.5) - -
GAS UTILITY:
Revenues $ 484.7 $ 347.5 $ 137.2 39.5%
Total margin $ 172.1 $ 138.5 $ 33.6 24.3%
Operating income $ 94.1 $ 73.5 $ 20.6 28.0%
System throughput - billions of cubic feet ("bcf") 70.7 59.7 11.0 18.4%
Degree days - % colder (warmer) than normal 8.3 (16.5) - -
ELECTRIC OPERATIONS:
Revenues $ 75.9 $ 62.2 $ 13.7 22.0%
Total margin (b) $ 33.8 $ 23.6 $ 10.2 43.2%
Operating income $ 18.5 $ 8.7 $ 9.8 112.6%
Electric Utility distribution sales - millions
of kilowatt hours ("gwh") 741.8 689.0 52.8 7.7%
ENERGY SERVICES:
Revenues $ 504.3 $ 272.3 $ 232.0 85.2%
Total margin $ 22.6 $ 15.3 $ 7.3 47.7%
Operating income $ 12.2 $ 7.7 $ 4.5 58.4%
INTERNATIONAL PROPANE:
Revenues $ 44.0 $ 35.6 $ 8.4 23.6%
Total margin $ 19.6 $ 17.7 $ 1.9 10.7%
Modified EBITDA $ 3.5 $ 5.5 $ (2.0) (36.4)%
Operating income $ 0.6 $ 3.3 $ (2.7) (81.8)%
Income from equity investees $ 7.6 $ 7.8 $ (0.2) (2.6)%
- -----------------------------------------------------------------------------------------------------------------------
(a) Retail gallons sold in the 2003 nine-month period include certain bulk
gallons previously considered wholesale gallons. Prior-period gallon
amounts have been adjusted to conform to the current period classification.
(b) Electric Operations total margin represents total revenues less cost of
sales and Electric Utility gross receipts taxes of $3.6 million and $3.1
million for the nine months ended June 30, 2003 and 2002, respectively.
AMERIGAS PROPANE. Weather based upon heating degree days was 0.9% colder than
normal during the 2003 nine-month period compared to weather that was 9.5%
warmer than normal in the 2002 nine-month period. Although temperatures
nationwide averaged near normal during the 2003 nine-month period, our overall
results reflect weather that was significantly warmer in the West and generally
colder than normal in the East. Retail propane volumes sold increased 73.8
million gallons in the 2003 nine-month period due principally to the effects of
the colder weather partially offset by the effects of price-induced customer
conservation and, with respect to commercial and industrial customers,
continuing economic weakness. Wholesale volumes totaled 188.7 million gallons,
an
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UGI CORPORATION AND SUBSIDIARIES
increase of 23.4 million gallons, reflecting the effects of the colder weather
and supply-related product cost management activities.
Retail propane revenues increased $226.7 million reflecting (1) a $144.2 million
increase due to higher average selling prices and (2) an $82.5 million increase
due to the higher retail volumes sold. Wholesale propane revenues increased
$38.4 million reflecting (1) a $27.8 million increase due to higher average
selling prices and (2) a $10.6 million increase due to the higher volumes sold.
The higher retail and wholesale selling prices reflect significantly higher
propane product costs during the 2003 nine-month period resulting from, among
other things, higher crude oil and natural gas prices and lower propane
inventories. Other revenues increased $6.6 million reflecting higher customer
fee and hauling revenue. Total cost of sales increased $220.2 million reflecting
the higher propane product costs and higher volumes sold.
The $51.5 million increase in total margin is principally due to the higher
propane gallons sold and, to a lesser extent, slightly higher average retail
propane unit margins. Notwithstanding the previously mentioned significant
increase in the commodity price of propane, retail propane unit margins were
slightly higher than the prior-year period reflecting the effects of the higher
average selling prices and the benefits of favorable propane product cost
management activities.
Modified EBITDA increased $20.9 million in the 2003 nine-month period reflecting
the previously mentioned increase in total margin and a $4.9 million increase in
other income partially offset by a $35.7 million increase in Partnership
operating and administrative expenses. Operating and administrative expenses
increased principally due to higher medical and general insurance expenses,
higher distribution expenses due to higher vehicle fuel costs, and higher
incentive compensation and uncollectible accounts expenses. In addition, the
Partnership incurred $3.0 million of costs during the 2003 three-month period as
a result of its management realignment announced in June 2003. Other income in
the 2003 nine-month period includes a gain of $1.1 million from the settlement
of certain hedge contracts and greater income from sales of assets and finance
charges while other income in the prior-year nine-month period was reduced by a
$2.1 million loss from declines in the value of propane commodity option
contracts. Operating income in the 2003 nine-month period increased less than
the increase in Modified EBITDA due to higher depreciation expense principally
associated with PPX(R).
GAS UTILITY. Weather in Gas Utility's service territory was 8.3% colder than
normal during the 2003 nine-month period compared to weather that was 16.5%
warmer than normal during the 2002 nine-month period. The significantly colder
weather resulted in higher heating-related sales to core-market and retail
delivery service customers and, to a lesser extent, greater volumes transported
for commercial and industrial delivery service customers. System throughput also
benefited from year-over-year customer growth.
Gas Utility revenues increased principally as a result of the previously
mentioned greater core-market and retail delivery service sales and higher
average core-market PGC rates resulting from higher natural gas costs. Gas
Utility cost of gas was $312.6 million in the 2003 nine-month period, an
increase of $103.6 million from the prior-year period, reflecting the higher
core-market volumes sold and higher core-market PGC rates.
The increase in Gas Utility total margin principally reflects a $30.9 million
increase in core-market and retail delivery service total margin as well as
higher margin from commercial and industrial delivery service customers.
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UGI CORPORATION AND SUBSIDIARIES
The increase in Gas Utility operating income principally reflects the increase
in total margin partially offset by an $11.7 million increase in operating and
administrative expenses and lower other income. The 2003 nine-month period
operating and administrative expenses include higher litigation-related costs
and expenses, greater distribution system maintenance expenses, increased
incentive compensation costs and higher bad debt expenses. Other income declined
$2.1 million principally reflecting a $1.8 million decrease in pension income.
ELECTRIC OPERATIONS. Electric Utility's 2003 nine-month period kilowatt-hour
sales increased principally as a result of weather that was 9.5% colder than
normal compared to weather that was 13.8% warmer than normal in the prior-year
period.
The higher Electric Operations revenues reflect greater Electric Utility sales
and greater sales of electricity produced by our electric generation assets to
third parties. Notwithstanding the significant increase in Electric Operations'
revenues, cost of sales increased only $3.0 million in the 2003 nine-month
period as the impact on cost of sales resulting from the greater Electric
Utility and electric generation third-party sales was partially offset by lower
Electric Utility per-unit purchased power costs.
The increase in Electric Operations' total margin principally reflects the
increased Electric Utility sales and lower Electric Utility per-unit purchased
power costs as well as increased margin from electric generation sales to third
parties. The higher operating income reflects the greater total margin and
higher other income partially offset by slightly higher 2003 nine-month period
operating and administrative expenses.
ENERGY SERVICES. The increase in Energy Services' revenues in the 2003
nine-month period resulted from higher natural gas prices and, to a lesser
extent, a nearly 40% increase in volumes sold due in large part to the March
2003 TXU Energy Acquisition. The greater Energy Services' total margin reflects
the increase in natural gas volumes sold, higher average unit margins, and an
increase in margin from sales of fuel oil. The increase in total margin was
partially offset by higher operating expenses resulting principally from growth
initiatives and the TXU Energy Acquisition.
INTERNATIONAL PROPANE. FLAGA's revenues increased $8.4 million, notwithstanding
a slight decline in volumes sold, primarily reflecting the effects of a stronger
euro and to a lesser extent higher average selling prices largely attributable
to higher propane product costs. Notwithstanding colder heating-season weather
during the 2003 nine-month period, volumes were lower due in large part to
price-induced conservation and continued weak economic activity. The increase in
2003 nine-month period total margin reflects the effects of the stronger euro.
The decline in FLAGA Modified EBITDA and operating income is substantially the
result of the stronger euro's effect on operating and administrative expenses
and, to a lesser extent, higher base-currency operating and administrative
expenses.
The slight decline in earnings from our equity investees in the 2003 nine-month
period is principally a result of lower interest income from our debt
investments in AGZ Holdings redeemed in July 2002 partially offset by higher
equity income from Antargaz resulting from the stronger euro.
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UGI CORPORATION AND SUBSIDIARIES
FINANCIAL CONDITION AND LIQUIDITY
FINANCIAL CONDITION
The Company's long-term debt outstanding totaled $1,240.5 million at June 30,
2003 (including current maturities of $124.6 million) compared to $1,275.7
million at September 30, 2002 (including current maturities of $148.7 million).
On October 1, 2002, UGI Utilities repaid $26 million of maturing Medium-Term
Notes. On December 3, 2002, AmeriGas Partners issued $88 million face amount of
8.875% Senior Notes due 2011 at an effective interest rate of 8.30%. The net
proceeds of $89.1 million were used on January 6, 2003 to redeem prior to
maturity AmeriGas Partners' $85 million face amount of 10.125% Senior Notes due
April 2007 at a redemption price of 102.25%, plus accrued interest. The Company
recognized a pre-tax loss, net of minority interests, of $1.5 million relating
to the redemption premium and other associated costs and expenses. In April
2003, AmeriGas OLP repaid $53.8 million of maturing First Mortgage Notes. In
conjunction with this repayment, in April 2003 AmeriGas Partners issued $32
million face amount of 8.875% Series B Notes due 2011 at an effective interest
rate of 7.72% and contributed the net proceeds of $33.7 million, including debt
premium, to AmeriGas OLP.
On June 17, 2003, AmeriGas Partners sold 2,900,000 Common Units in an
underwritten public offering at a public offering price of $27.12 per unit. The
net proceeds of the public offering totaling $75.0 million, and associated
capital contributions from the General Partner totaling $1.5 million, were
contributed to AmeriGas OLP and used to reduce indebtedness under its bank
credit agreement and for general partnership purposes. The underwriters'
overallotment option expired unexercised. Concurrent with this sale of Common
Units, the Company recorded a gain in the amount of $22.6 million, which is
reflected in the Company's balance sheet as an increase in common stockholders'
equity, in accordance with the guidance in SEC Staff Accounting Bulletin No. 51,
"Accounting for Sales of Common Stock by a Subsidiary" ("SAB 51"). The gain had
no effect on the Company's net income or cash flow.
AmeriGas OLP's Second Amended and Restated Bank Credit Agreement consists of a
$100 million Revolving Credit Facility and a $75 million Acquisition Facility.
At June 30, 2003, there were no borrowings outstanding under these facilities.
Up to $30 million of the Acquisition Facility may be used for working capital
purposes. Issued and outstanding letters of credit under the Revolving Credit
Facility, which reduce available borrowing capacity, totaled $27 million at June
30, 2003. AmeriGas OLP's Bank Credit Agreement expires October 1, 2003. The
Partnership expects to renew this facility prior to its expiration. AmeriGas
Partners also has debt and equity shelf registration statements with the SEC
under which it may issue up to an additional $28 million of Series B 8.875%
Senior Notes and an additional 1.4 million Common Units.
On August 14, 2003, after the end of the quarter, UGI Utilities issued $25
million of ten-year notes at an interest rate of 5.37%, and $20 million of
30-year notes at an interest rate of 6.50%, under its Medium Term Note program.
The net proceeds along with existing cash balances will be used to repay UGI
Utilities' $50 million 6.50% Senior Notes maturing on August 15, 2003.
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UGI CORPORATION AND SUBSIDIARIES
UGI Utilities has commitments under revolving credit agreements which provide
for borrowings of up to $107 million. These agreements expire in June 2005 and
June 2006. UGI Utilities also has a shelf registration statement with the SEC
under which it may issue up to an additional $40 million of Medium-Term Notes
or other debt securities.
Energy Services has a $50 million receivables purchase facility with an issuer
of receivables-backed commercial paper expiring November 30, 2004. During the
three and nine months ended June 30, 2003, Energy Services sold trade
receivables totaling $211.1 million and $500.0 million, respectively, to its
wholly owned, bankruptcy-remote subsidiary, ESFC, which is consolidated for
financial statement purposes. During the three and nine months ended June 30,
2003, ESFC sold an aggregate $93 million and $108 million, respectively, of
undivided interests in its trade receivables to the facility's commercial paper
conduit. At June 30, 2003, the outstanding balance of ESFC receivables was $51.6
million which is net of $19 million in trade receivables sold to the commercial
paper conduit.
During the nine months ended June 30, 2003, the Partnership declared and paid
the minimum quarterly distribution of $0.55 (the "MQD") on all limited partner
units for the quarters ended September 30, 2002, December 31, 2002 and March 31,
2003. The MQD for the quarter ended June 30, 2003 will be paid on August 18,
2003 to holders of record on August 8, 2003. The ability of the Partnership to
declare and pay the MQD in the future 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.
CASH FLOWS
The Company's cash flows from operating activities are seasonal and are
generally greatest during the second and third fiscal quarters when customers
pay bills incurred during the heating season and are generally lowest during the
first and fourth fiscal quarters. Accordingly, cash flows from operations for
the nine months ended June 30, 2003 are not necessarily indicative of cash flows
to be expected for a full year. Included in the June 30, 2003 Condensed
Consolidated Balance Sheet is $101.5 million of cash, cash equivalents and
short-term investments held by UGI.
OPERATING ACTIVITIES. Cash provided by operating activities was $205.3 million
in the 2003 nine-month period compared to $199.7 million in the prior-year
nine-month period. The increase in operating cash flow reflects the effects of
the improved 2003 nine-month period operating results partially offset by
greater cash required to fund changes in operating working capital. Changes in
operating working capital required $40.6 million of operating cash flow in the
2003 nine-month period compared to $11.0 million required in the prior-year
period. The higher working capital cash needs primarily reflect the effects of
higher 2003 nine-month period natural gas and propane commodity prices on
changes in customer accounts receivable and inventories partially offset by
improved cash flow from changes in accounts payable, Gas Utility fuel cost
overcollections, and accrued income taxes.
INVESTING ACTIVITIES. We spent $72.5 million for property, plant and equipment
during the 2003 nine-month period, an increase of $9.2 million over the
prior-year nine-month period, principally reflecting higher Partnership and, to
a lesser extent, Gas Utility capital expenditures. Cash paid for business
acquisitions in the 2003 nine-month period principally reflects Partnership
business
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UGI CORPORATION AND SUBSIDIARIES
acquisitions and the March 2003 TXU Energy Acquisition. In addition, during the
2003 nine-month period the Company increased its interest in the Conemaugh
electricity generating station for $51.3 million in cash and received a cash
distribution from Antargaz of $5.6 million. During the nine months ended June
30, 2003, UGI invested $50 million of its cash and cash equivalents in
short-term investments.
FINANCING ACTIVITIES. We paid cash dividends on UGI Common Stock of $35.6
million, and the Partnership paid the MQD on all publicly held limited partner
units (as well as the limited partner units we own), during the 2003 nine-month
period. Proceeds from the issuance of long-term debt during the 2003 nine-month
period reflects net proceeds of $89.1 million from the issuance of $88 million
face value of AmeriGas Partners 8.875% Senior Notes in December 2002 and $33.7
million from the issuance of $32 million face amount of AmeriGas Partners Senior
Notes in April 2003. Repayments of long-term debt during the 2003 nine-month
period principally reflects (1) the repayment in October 2002 of $26 million of
maturing UGI Utilities Medium Term Notes; (2) the repayment in January 2003,
prior to maturity, of the then-remaining $85 million face amount of AmeriGas
Partners 10.125% Senior Notes at a redemption price of 102.25%; and (3) the
repayment in April 2003 of $53.8 million of maturing AmeriGas OLP First Mortgage
Notes. Also during the 2003 nine-month period, AmeriGas OLP repaid all
outstanding borrowings under its Revolving Credit Facility and UGI Utilities
reduced its bank loan borrowings by $34.9 million.
In June 2003, AmeriGas Partners received $75.0 million in net proceeds from the
sale of 2.9 million Common Units to the public at a public offering price of
$27.12 per unit. The net proceeds of the public offering of $75.0 million, along
with associated capital contributions from the General Partner, were contributed
to AmeriGas OLP and used to reduce indebtedness under its Bank Credit Agreement
and for general Partnership purposes. The increase in cash from the issuance of
UGI Common Stock is principally the result of stock option exercise activity.
INVESTMENT IN CONEMAUGH
On June 26, 2003, pursuant to an asset purchase agreement between and among
Allegheny Energy Supply Company, LLC, Allegheny Energy Supply Conemaugh, LLC
("Allegheny Conemaugh"), UGID and UGI, UGID acquired an additional 83 megawatt
ownership interest in the Conemaugh electricity generation station ("Conemaugh")
from Allegheny Conemaugh, a unit of Allegheny Energy, Inc. ("Allegheny"), for
$51.3 million in cash, subject to a $3.0 million credit. Conemaugh is a
1,711-megawatt, coal-fired electricity generation station located near
Johnstown, Pennsylvania and is owned by a consortium of energy companies and
operated by a unit of Reliant Resources, Inc. under contract. The purchase
increased UGID's ownership interest in Conemaugh to 102 megawatts (6.0%) from 19
megawatts (1.1%) previously. Substantially all of the purchase price for the
additional interest in Conemaugh has been reflected in property, plant and
equipment in the Condensed Consolidated Balance Sheet as of June 30, 2003.
CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS
In December 2002, the General Partner determined that the cash-based performance
and distribution requirements for the conversion of the remaining 9,891,072
Subordinated Units of AmeriGas Partners, all of which were held by the General
Partner, had been met in respect of the quarter ended September 30, 2002. As a
result, these Subordinated Units were converted to a like number of Common Units
effective November 18, 2002. Concurrent with the Subordinated Unit conversion,
the Company recorded a $157.0 million increase in common stockholders' equity,
and a
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UGI CORPORATION AND SUBSIDIARIES
corresponding decrease in minority interests in AmeriGas Partners, associated
with gains from sales of Common Units by AmeriGas Partners in conjunction with,
and subsequent to, the Partnership's April 19, 1995 initial public offering.
These gains were determined in accordance with the guidance in SAB 51. The gains
resulted because the public offering prices of the AmeriGas Partners Common
Units exceeded the associated carrying amount of our investment in the
Partnership on the dates of their sale. Due to the preference nature of the
Common Units, the Company was precluded from recording these gains until the
Subordinated Units converted to Common Units. No deferred income taxes were
recorded on these gains due to the Company's intent to hold its investment in
the Partnership indefinitely. The changes to the Company's balance sheet
resulting from the Subordinated Unit conversion had no effect on the Company's
net income or cash flow and did not result in an increase in the number of
AmeriGas Partners limited partner units outstanding.
UGI COMMON STOCK SPLIT AND DIVIDEND INCREASE
On January 28, 2003, UGI's Board of Directors approved a 3-for-2 split of UGI's
Common Stock. On April 1, 2003, UGI issued one additional common share for every
two common shares outstanding to shareholders of record February 28, 2003. Also
on January 28, 2003, UGI's Board of Directors approved an increase in the
quarterly dividend rate on UGI Common Stock to $0.2850 per post-split share or
$1.14 per post-split share on an annual basis.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity" ("SFAS 150"); SFAS No. 149, "Amendment of Statement 133
on Derivative Instruments and Hedging Activities" ("SFAS 149"); SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure" ("SFAS
148"); SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" ("SFAS 146"); and FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45").
SFAS 150 establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). Many of the instruments
within the scope of SFAS 150 were previously classified as equity. SFAS 150 is
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise shall be effective for the Company on July 1, 2003. For financial
instruments created before May 31, 2003, and still existing on July 1, 2003,
transition shall be achieved by reporting the cumulative effect of a change in
an accounting principle by initially measuring the financial instruments at fair
value or other measurement attribute required by SFAS 150. The Company will be
required to present UGI Utilities' preferred shares subject to mandatory
redemption in the liabilities section of the balance sheet. The initial adoption
of SFAS 150 did not affect our financial position or results of operations.
SFAS 149 amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 149 amends
SFAS 133 for decisions made (1) as part of the FASB's Derivatives Implementation
Group ("DIG") process; (2) in connection with other FASB projects dealing with
financial instruments; and (3) in connection with implementation issues raised
in relation to the application of the definition of a derivative. SFAS 149 is
effective for contracts entered into or
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UGI CORPORATION AND SUBSIDIARIES
modified after June 30, 2003. Based upon the types of contracts currently
entered into by the Company, we do not believe SFAS 149 will have a material
impact on our financial position or results of operations.
SFAS 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS
123"), to provide alternative methods of transition for a voluntary change to
the fair value based method of accounting for stock-based employee compensation.
In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require
prominent disclosures in both annual and interim financial statements about the
method of accounting for stock-based employee compensation and the effect of the
method used on reported results. As permitted by SFAS 123, we currently apply
the provisions of Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB 25"), in recording compensation
expense for grants of stock, stock options, and other equity instruments to
employees. The disclosures required by SFAS 148 are included in Note 1 to
Condensed Consolidated Financial Statements.
SFAS 146 addresses accounting for costs associated with exit or disposal
activities and replaces the guidance in Emerging Issues Task Force ("EITF") No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity." Generally, SFAS 146 requires that a liability for
costs associated with an exit or disposal activity, including contract
termination costs, employee termination benefits and other associated costs, be
recognized when the liability is incurred. Under EITF No. 94-3, a liability was
recognized at the date an entity committed to an exit plan. SFAS 146 became
effective for disposal activities initiated after December 31, 2002. The initial
adoption of the provisions of SFAS 146 did not affect our financial position or
results of operations.
FIN 45 expands the existing disclosure requirements for guarantees and requires
that companies recognize, at the inception of a guarantee, a liability for the
fair value of the obligations undertaken when issuing the guarantee. The initial
recognition and measurement provisions of FIN 45 are effective for guarantees
issued or modified after December 31, 2002. The disclosure requirements of FIN
45 are included in Note 7 to Condensed Consolidated Financial Statements. The
application of FIN 45 did not have a material effect on our financial position
or results of operations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk exposures are (1) market prices for propane, natural gas
and electricity; (2) changes in interest rates; and (3) foreign currency
exchange rates.
The risk associated with fluctuations in the prices the Partnership and our
International Propane operations pay for propane is principally a result of
market forces reflecting changes in supply and demand for propane and any other
energy commodities. The Partnership's profitability is sensitive to changes in
propane supply costs, and the Partnership generally attempts to pass on
increases in such costs to customers. The Partnership may not, however, always
be able to pass through product cost increases fully, particularly when product
costs rise rapidly. In order to reduce the volatility of the Partnership's
propane market price risk, it uses contracts for the forward purchase or sale of
propane, propane fixed-price supply agreements, and over-the-counter derivative
commodity instruments including price swap and option contracts. International
Propane's profitability is also sensitive to changes in propane supply costs. On
occasion, FLAGA uses derivative commodity instruments to reduce market risk
associated with a portion of its propane purchases. Over-the-counter derivative
commodity instruments utilized by
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UGI CORPORATION AND SUBSIDIARIES
the Partnership and FLAGA are generally settled at expiration of the contract.
In order to minimize credit risk associated with its derivative commodity
contracts, the Partnership monitors established credit limits with the contract
counterparties. Although we use derivative financial and commodity instruments
to reduce market price risk associated with forecasted transactions, we do not
use derivative financial and commodity instruments for speculative or trading
purposes.
Gas Utility's tariffs contain clauses that permit recovery of substantially all
of the prudently incurred cost of natural gas it sells to its customers. The
recovery clauses provide for a periodic adjustment for the difference between
the total amount actually collected from customers and the recoverable costs
incurred. Because of this ratemaking mechanism, there is limited commodity price
risk associated with our Gas Utility operations.
Prior to September 2002, Electric Utility purchased all of its electric power
needs, in excess of the electric power it obtained from its interests in
electric generating facilities, under power supply arrangements of various
lengths and on the spot market. Beginning September 2002, Electric Utility began
purchasing its power needs from electricity suppliers under fixed-price energy
and capacity contracts, and to a much lesser extent on the spot market, and our
electricity generation business began selling its electricity production and
capacity on the spot market to third parties. Prices for electricity can be
volatile especially during periods of high demand or tight supply. Although the
generation component of Electric Utility's rates is subject to various rate cap
provisions, Electric Utility's fixed-price contracts with electricity suppliers
mitigate most risks associated with offering customers a fixed price during the
contract periods. However, should any of the suppliers under these contracts
fail to provide electric power under the terms of the power and capacity
contracts, increases, if any, in the cost of replacement power or capacity could
negatively impact Electric Utility results. In order to reduce this
non-performance risk, Electric Utility has diversified its purchases across
several suppliers and entered into bilateral collateral arrangements with
certain of them.
In order to manage market price risk relating to substantially all of Energy
Services' forecasted fixed-price sales of natural gas, we purchase
exchange-traded natural gas futures contracts or enter into fixed-price supply
arrangements. Exchange-traded natural gas futures contracts are guaranteed by
the New York Mercantile Exchange ("NYMEX") and have nominal credit risk. The
change in market value of these contracts may require Energy Services to make
daily cash deposits in margin accounts with brokers. Although Energy Services'
fixed-price supply arrangements mitigate most risks associated with its
fixed-price sales contracts, should any of the natural gas suppliers under these
arrangements fail to perform, increases, if any, in the cost of replacement
natural gas would adversely impact Energy Services' results. In order to reduce
this risk of supplier nonperformance, Energy Services has diversified its
purchases across a number of suppliers.
Our variable-rate debt includes borrowings under AmeriGas OLP's Bank Credit
Agreement, borrowings under UGI Utilities' revolving credit agreements, and a
substantial portion of FLAGA's debt. These debt agreements have interest rates
that are generally indexed to short-term market interest rates. At June 30,
2003, combined borrowings outstanding under these agreements totaled $84.5
million. Our long-term debt is typically issued at fixed rates of interest based
upon market rates for debt having similar terms and credit ratings. As these
long-term debt issues mature, we may refinance such debt with new debt having
interest rates reflecting then-current market conditions. This debt may have an
interest rate that is more or less than the refinanced debt. In order to reduce
interest rate risk associated with near-term forecasted issuances of fixed-rate
debt, from time to time we enter into interest rate protection agreements.
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UGI CORPORATION AND SUBSIDIARIES
The primary currency for which the Company has exchange rate risk is the U.S.
dollar versus the euro. We do not currently use derivative instruments to hedge
foreign currency exposure associated with our international propane businesses,
principally FLAGA and Antargaz. As a result, the U.S. dollar amounts of our
international propane businesses' assets and liabilities and their results of
operations are affected by changes in foreign currency exchange rates.
The following table summarizes the fair values of unsettled market risk
sensitive derivative instruments held at June 30, 2003. It also includes the
changes in fair value that would result if there were adverse changes in (1) the
market price of propane of 10 cents per gallon; (2) the market price of natural
gas of 50 cents per dekatherm; and (3) interest rates on ten-year U.S. treasury
notes of 50 basis points:
- -------------------------------------------------------------------------------------
Fair Change in
Value Fair Value
- -------------------------------------------------------------------------------------
(Millions of dollars)
June 30, 2003:
Propane commodity price risk $ 1.5 $ (8.9)
Natural gas commodity price risk (1.0) (5.4)
Interest rate risk (3.4) (3.6)
- -------------------------------------------------------------------------------------
Because the Company's derivative instruments generally qualify as hedges under
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," we
expect that changes in the fair value of derivative instruments used to manage
commodity or interest rate market risk would be substantially offset by gains or
losses on the associated anticipated transactions.
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The Company's management, with the participation of the Company's Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness
of the Company's disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Company's
disclosure controls and procedures as of the end of the period covered by
this report were designed and functioning effectively to provide reasonable
assurance that the information required to be disclosed by the Company in
reports filed under the Securities Exchange Act of 1934, as amended, is
recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms. The Company believes that a
controls system, no matter how well designed and operated, cannot provide
absolute assurance that the objectives of the controls system are met, and
no evaluation of controls can provide absolute assurance that all control
issues and instances of fraud, if any, within a company have been detected.
(b) Change in Internal Control over Financial Reporting
No change in the Company's internal control over financial reporting
occurred during the Company's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting.
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UGI CORPORATION AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
EnergyNorth Natural Gas, Inc. v. UGI Utilities, Inc. By letter dated
October 26, 2000, EnergyNorth Natural Gas, Inc. ("EnergyNorth") notified UGI
Utilities that it has filed suit in the United States District Court for the
District of New Hampshire, seeking contribution from UGI Utilities for response
and remediation costs associated with contamination on the site of a former
manufactured gas plant allegedly operated by former subsidiaries of UGI
Utilities. In June 2003, UGI Utilities and EnergyNorth agreed to a settlement in
exchange for dismissal of the suit. See Note 7 to Condensed Consolidated
Financial Statements.
City of Bangor, Maine v. Citizens Communication Co. In April 2003
Citizens Communications Company ("Citizens") served a complaint naming UGI
Utilities as a third party defendant in a civil action pending in United States
District Court for the District of Maine. In that action, the plaintiff, City of
Bangor, sued Citizens to recover environmental response costs associated with
manufactured gas plant wastes generated at a plant allegedly operated by
Citizens' predecessors at a site on the Penobscot River. Citizens subsequently
joined UGI Utilities and ten other third party defendants alleging that the
third party defendants are responsible for an equitable share of any response
costs Citizens may be required to pay to the City of Bangor. Investigations of
the site conducted to date are insufficient to establish what, if any
contamination is related to gas plant wastes. Hence, UGI Utilities is unable to
estimate the total cost of cleanup associated with manufactured gas plant wastes
at this site. UGI Utilities believes that it has good defenses to the claim.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) List of Exhibits:
31.1 Certification by the Chief Executive Officer relating to the
Registrant's Report on Form 10-Q for the quarter ended June
30, 2003 pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
31.2 Certification by the Chief Financial Officer relating to the
Registrant's Report on Form 10-Q for the quarter ended June
30, 2003 pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
32 Certification by the Chief Executive Officer and Chief
Financial Officer relating to the Registrant's Report on Form
10-Q for the quarter ended June 30, 2003 pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
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UGI CORPORATION AND SUBSIDIARIES
(b) The Company filed the following Report on Form 8-K during the fiscal
quarter ended June 30, 2003:
DATE ITEM NUMBERS CONTENT
April 30, 2003 7, 9, 12 Press Release reporting financial results for the
second fiscal quarter ended March 31, 2003.
-32-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UGI Corporation
------------------------------
(Registrant)
Date: August 14, 2003 By: /s/ A. J. Mendicino
------------------------------------------------
A. J. Mendicino, Senior Vice President - Finance
and Chief Financial Officer
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UGI CORPORATION AND SUBSIDIARIES
EXHIBIT INDEX
31.1 Certification by the Chief Executive Officer relating to the
Registrant's Report on Form 10-Q for the quarter ended June 30, 2003
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification by the Chief Financial Officer relating to the
Registrant's Report on Form 10-Q for the quarter ended June 30, 2003
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certification by the Chief Executive Officer and Chief Financial
Officer relating to the Registrant's Report on Form 10-Q for the
quarter ended June 30, 2003 pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.