-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VkCP9DDTjZ0GJikcOEEfUKR0WEDdEVhko2Hsg6FjiDIzX79zhmfVgqSKp6iO+kas dBvwwUXn4rKYV0ubHbBDSA== 0000893220-02-001031.txt : 20020814 0000893220-02-001031.hdr.sgml : 20020814 20020814155029 ACCESSION NUMBER: 0000893220-02-001031 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UGI CORP /PA/ CENTRAL INDEX KEY: 0000884614 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 232668356 STATE OF INCORPORATION: PA FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-11071 FILM NUMBER: 02736254 BUSINESS ADDRESS: STREET 1: 460 N GULPH RD STREET 2: P O BOX 858 CITY: KING OF PRUSSIA STATE: PA ZIP: 19406 BUSINESS PHONE: 6103371000 MAIL ADDRESS: STREET 1: 460 NORTH GULPH ROAD CITY: KING OF PRUSSIA STATE: PA ZIP: 19406 FORMER COMPANY: FORMER CONFORMED NAME: NEW UGI CORP DATE OF NAME CHANGE: 19600201 10-Q 1 w62944e10vq.txt FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2002 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2002 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, 2002, there were 27,567,343 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, 2002 and September 30, 2001 1 Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2002 and 2001 2 Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2002 and 2001 3 Notes to Condensed Consolidated Financial Statements 4 - 14 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 15 - 28 Item 3. Quantitative and Qualitative Disclosures About Market Risk 28 - 30 PART II OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K 30 Signatures 31
-i- UGI CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited) (Millions of dollars)
June 30, September 30, 2002 2001 -------- -------- ASSETS Current assets: Cash and cash equivalents $ 135.2 $ 87.5 Short-term investments, at cost which approximates market value 3.6 3.6 Accounts receivable (less allowances for doubtful accounts of $15.1 and $15.6, respectively) 173.0 180.8 Accrued utility revenues 7.5 11.1 Inventories 87.1 128.6 Deferred income taxes 19.2 25.2 Prepaid expenses and other current assets 26.4 22.1 -------- -------- Total current assets 452.0 458.9 Property, plant and equipment, at cost (less accumulated depreciation and amortization of $703.7 and $645.5, respectively) 1,266.8 1,268.0 Goodwill and excess reorganization value 645.1 641.1 Intangible assets (less accumulated amortization of $9.5 and $5.8, respectively) 27.6 31.3 Utility regulatory assets 54.8 56.2 Other assets 109.8 94.7 -------- -------- Total assets $2,556.1 $2,550.2 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt $ 89.0 $ 98.3 UGI Utilities bank loans 45.6 57.8 Other bank loans 7.9 10.0 Accounts payable 142.4 167.0 Other current liabilities 189.7 234.4 -------- -------- Total current liabilities 474.6 567.5 Long-term debt 1,149.3 1,196.9 Deferred income taxes 193.2 182.4 Other noncurrent liabilities 81.4 81.6 Commitments and contingencies (note 7) Minority interests in AmeriGas Partners 308.9 246.2 UGI Utilities redeemable preferred stock 20.0 20.0 Common stockholders' equity: Common Stock, without par value (authorized - 100,000,000 shares; issued - 33,198,731 shares) 395.3 395.0 Retained earnings 57.7 9.0 Accumulated other comprehensive income (loss) 4.8 (13.5) -------- -------- 457.8 390.5 Treasury stock, at cost (129.1) (134.9) -------- -------- Total common stockholders' equity 328.7 255.6 -------- -------- Total liabilities and stockholders' equity $2,556.1 $2,550.2 ======== ========
See accompanying notes to 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, ------------------------------ ----------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- Revenues: AmeriGas Propane $ 254.5 $ 219.2 $ 1,086.0 $ 1,209.1 UGI Utilities 88.3 103.8 409.7 501.9 International Propane 9.2 10.0 35.6 39.1 Energy Services and other 94.3 78.9 298.4 342.7 ----------- ----------- ----------- ----------- 446.3 411.9 1,829.7 2,092.8 ----------- ----------- ----------- ----------- Costs and expenses: AmeriGas Propane cost of sales 111.2 120.5 529.0 728.7 UGI Utilities - gas, fuel and purchased power 48.3 64.9 244.5 324.0 International Propane cost of sales 4.7 5.2 17.9 22.7 Energy Services and other cost of sales 84.2 70.8 271.2 317.2 Operating and administrative expenses 146.9 117.6 447.4 385.6 Utility taxes other than income taxes 2.9 1.7 8.7 7.2 Depreciation and amortization 23.2 26.2 69.9 78.3 Other income, net (4.1) (3.4) (12.2) (15.4) ----------- ----------- ----------- ----------- 417.3 403.5 1,576.4 1,848.3 ----------- ----------- ----------- ----------- Operating income 29.0 8.4 253.3 244.5 Income (loss) from equity investees 0.7 -- 8.2 (1.5) Interest expense (26.9) (25.2) (82.5) (77.8) Minority interests in AmeriGas Partners 5.1 11.0 (45.5) (38.9) ----------- ----------- ----------- ----------- Income (loss) before income taxes, subsidiary preferred stock dividends and accounting changes 7.9 (5.8) 133.5 126.3 Income tax (expense) benefit (3.5) 1.9 (50.2) (56.8) Dividends on UGI Utilities Series Preferred Stock (0.4) (0.4) (1.2) (1.2) ----------- ----------- ----------- ----------- Income (loss) before accounting changes 4.0 (4.3) 82.1 68.3 Cumulative effect of accounting changes, net -- -- -- 4.5 ----------- ----------- ----------- ----------- Net income (loss) $ 4.0 $ (4.3) $ 82.1 $ 72.8 =========== =========== =========== =========== Earnings (loss) per share: Basic: Income (loss) before accounting changes $ 0.14 $ (0.16) $ 2.99 $ 2.52 Cumulative effect of accounting changes, net -- -- -- 0.16 ----------- ----------- ----------- ----------- Net income (loss) $ 0.14 $ (0.16) $ 2.99 $ 2.68 =========== =========== =========== =========== Diluted: Income (loss) before accounting changes $ 0.14 $ (0.16) $ 2.93 $ 2.50 Cumulative effect of accounting changes, net -- -- -- 0.17 ----------- ----------- ----------- ----------- Net income (loss) $ 0.14 $ (0.16) $ 2.93 $ 2.67 =========== =========== =========== =========== Average common shares outstanding: Basic 27.593 27.182 27.504 27.121 =========== =========== =========== =========== Diluted 28.213 27.182 28.035 27.304 =========== =========== =========== =========== Dividends declared per common share $ 0.4125 $ 0.40 $ 1.2125 $ 1.175 =========== =========== =========== ===========
See accompanying notes to consolidated financial statements. - 2 - UGI CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (Millions of dollars)
Nine Months Ended June 30, ----------------------- 2002 2001 ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 82.1 $ 72.8 Reconcile to net cash provided by operating activities: Depreciation and amortization 69.9 78.3 Cumulative effect of accounting changes -- (4.5) Minority interests in AmeriGas Partners 45.5 38.9 Deferred income taxes, net 8.5 (12.6) Other, net 4.7 (19.9) Net change in: Accounts receivable and accrued utility revenues 2.0 (42.2) Inventories 41.8 15.1 Deferred fuel costs 1.5 14.0 Accounts payable (24.6) (38.3) Other current assets and liabilities (31.7) 4.5 ------- ------- Net cash provided by operating activities 199.7 106.1 ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for property, plant and equipment (63.3) (54.2) Net proceeds from disposals of assets 5.5 2.2 Acquisitions of businesses, net of cash acquired (0.7) 1.6 Investments in joint venture entities -- (32.6) Other, net 0.8 1.6 ------- ------- Net cash used by investing activities (57.7) (81.4) ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES: Dividends on Common Stock (33.3) (42.3) Distributions on Partnership public Common Units (39.8) (33.2) Issuance of long-term debt 41.1 114.0 Repayment of long-term debt (102.9) (87.2) AmeriGas Propane bank loans decrease -- (21.0) UGI Utilities bank loans decrease (12.2) (47.1) Other bank loans increase (decrease) (2.9) 6.7 Issuance of AmeriGas Partners Common Units 49.6 39.8 Issuance of Common Stock 6.1 4.1 ------- ------- Net cash used by financing activities (94.3) (66.2) ------- ------- EFFECT OF EXCHANGE RATE CHANGES ON CASH -- (0.3) ------- ------- Cash and cash equivalents increase (decrease) $ 47.7 $ (41.8) ======= ======= Cash and cash equivalents: End of period $ 135.2 $ 52.1 Beginning of period 87.5 93.9 ------- ------- Increase (decrease) $ 47.7 $ (41.8) ======= =======
See accompanying notes to 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, 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 wholly owned subsidiary, UGI Utilities, Inc. ("UGI Utilities"), owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania. UGI Utilities also owns and operates an electricity distribution utility and, through a subsidiary and its joint-venture partnership Hunlock Creek Energy Ventures ("Energy Ventures"), an electricity generation business (collectively, "Electric Utility") in northeastern Pennsylvania. Electric Utility's investment in Energy Ventures is accounted for under the equity method. We conduct a national propane distribution business through AmeriGas Partners, L.P. ("AmeriGas Partners") and its principal operating subsidiaries AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle OLP"). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI's wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the "General Partner") serves as the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as "the Operating Partnerships") comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. We refer to AmeriGas Partners and its subsidiaries together as "the Partnership" and the General Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane." At June 30, 2002, the General Partner and its wholly owned subsidiary Petrolane Incorporated ("Petrolane") collectively held a 1% general partner interest and a 49.1% limited partner interest in AmeriGas Partners, and effective 50.6% and 50.5% ownership interests in AmeriGas OLP and Eagle OLP, respectively. Our limited partnership interest in AmeriGas Partners comprises 14,633,932 Common Units and 9,891,072 Subordinated Units. The remaining 49.9% interest in AmeriGas Partners comprises 24,905,354 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"). Through other subsidiaries, Enterprises (1) owns and operates a propane distribution business in Austria, the Czech Republic and Slovakia ("FLAGA"); (2) owns and operates a heating, ventilation and air-conditioning service business in the Middle Atlantic states ("HVAC"); and (3) participates in propane joint-venture businesses in France and China. 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 interest in the condensed consolidated statements of income and balance sheets. We have reclassified certain prior-period balances to conform with the current period presentation. 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. These financial statements should be read in conjunction with the financial statements and the related notes included in our Annual Report on Form 10-K for the year ended September 30, 2001 ("Company's 2001 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. Shares used in the diluted earnings per share calculation reflect incremental shares issuable for stock options and restricted stock awards. The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2002 and 2001:
Three Months Nine Months Ended Ended June 30, June 30, - ----------------------------------------------------------------------------- 2002 2001 2002 2001 - ----------------------------------------------------------------------------- Net income (loss) $4.0 $ (4.3) $ 82.1 $ 72.8 Other comprehensive income (loss) 3.6 (14.8) 18.3 (15.2) - ----------------------------------------------------------------------------- Comprehensive income (loss) $7.6 $(19.1) $100.4 $ 57.6 - -----------------------------------------------------------------------------
Other comprehensive income (loss) 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 (loss). 2. SEGMENT INFORMATION Based upon SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," we have determined that the Company has five reportable segments: (1) AmeriGas Propane; (2) Gas Utility; (3) Electric Utility; (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 2001 Annual Report and 5 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) those described in Note 3 below. We evaluate our AmeriGas Propane and International Propane segments' performance principally based on their earnings before interest expense, income taxes, depreciation and amortization, minority interests, income from equity investees and cumulative effect of accounting changes ("EBITDA"). Although we use EBITDA to evaluate these segments' performance, 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 Company's definition of EBITDA may be different from that used by other companies. We evaluate the performance of Gas Utility, Electric Utility, and Energy Services principally based upon their earnings before income taxes. 6 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, 2002:
Reportable Segments ------------------------------------------------------- AmeriGas Gas Electric Energy International Corporate Total Elims. Propane Utility Utility Services Propane and Other(a) -------- --------- --------- ------- --------- --------- ------------- ---------- Revenues $ 446.3 $ (0.3) $ 254.5 $ 68.1 $ 20.2 $ 85.1 $ 9.2 $ 9.5 ======== ====== ======== ======= ======= ======= ======= ====== Segment profit (loss): 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 from equity investees 0.7 -- -- -- -- -- 0.8 (0.1) 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, subsidiary preferred stock dividends, and accounting changes $ 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 $ 645.1 $ -- $ 589.0 $ -- $ -- $ -- $ 52.6 $ 3.5 ======== ====== ======== ======= ======= ======= ======= ======
Three Months Ended June 30, 2001:
Reportable Segments ------------------------------------------------------- AmeriGas Gas Electric Energy International Corporate Total Elims. Propane Utility Utility Services Propane and Other(a) -------- --------- --------- ------- --------- --------- ------------- ---------- Revenues $ 411.9 $ (0.7) $ 219.2 $ 84.5 $ 19.3 $ 68.6 $ 10.0 $ 11.0 ======== ======= ======== ======= ======= ======= ======= ====== Segment profit (loss): EBITDA $ 34.6 $ (0.2) $ 12.9 $ 15.9 $ 2.8 $ 2.6 $ 0.7 $ (0.1) Depreciation and amortization (26.2) -- (18.7) (5.1) (0.9) -- (1.0) (0.5) ------- ------ -------- ------- ------- ------- ------- ------ Operating income (loss) 8.4 (0.2) (5.8) 10.8 1.9 2.6 (0.3) (0.6) Income from equity investees -- -- -- -- -- -- -- -- Interest expense (25.2) 0.2 (19.3) (3.8) (0.6) (0.2) (1.2) (0.3) Minority interests 11.0 -- 11.0 -- -- -- -- -- ------- ------ -------- ------- ------- ------- ------- ------ Income (loss) before income taxes, subsidiary preferred stock dividends, and accounting changes $ (5.8) $ -- $ (14.1) $ 7.0 $ 1.3 $ 2.4 $ (1.5) $ (0.9) ======== ======= ======== ======= ======= ======= ======= ====== Segment assets (at period end) $2,282.2 $ (50.8) $1,279.3 $ 672.1 $ 101.6 $ 46.4 $ 134.7 $ 98.9 ======== ======= ======== ======= ======= ======= ======= ====== Investments in equity investees (at period end) $ 40.7 $ -- $ -- $ -- $ 11.4 $ -- $ 29.3 $ -- ======== ======= ======== ======= ======= ======= ======= ====== Goodwill and excess reorganization value $ 646.6 $ -- $ 598.1 $ -- $ -- $ 0.2 $ 44.9 $ 3.4 ======== ======= ======== ======= ======= ======= ======= ======
(a) Principally comprises UGI, UGI Enterprises' HVAC and Hearth USA (TM) operations, and UGI Enterprises' corporate and general expenses. Hearth USA (TM) ceased operations in October 2001. 7 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, 2002:
Reportable Segments ------------------------------------------------ Inter- AmeriGas Gas Electric Energy national Corporate Total Elims Propane Utility Utility Services Propane and Other -------- ------ -------- ------- -------- -------- -------- --------- Revenues $1,829.7 $ (1.4) $1,086.0 $347.5 $ 62.2 $272.3 $ 35.6 $ 27.5 ======== ====== ======== ====== ====== ====== ====== ====== Segment profit: EBITDA $ 323.2 $ -- $ 207.4 $ 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 253.3 -- 157.9 73.5 8.7 7.7 3.3 2.2 Income (loss) from equity investees 8.2 -- 0.5 -- -- -- 7.8 (0.1) Interest expense (82.5) -- (66.5) (10.7) (1.8) -- (3.1) (0.4) Minority interests (45.5) -- (45.5) -- -- -- -- -- -------- ------ -------- ------ ------ ------ ------ ------ Income before income taxes, subsidiary preferred stock dividends, and accounting changes $ 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 express reorganization value $ 645.1 $ -- $ 589.0 $ -- $ -- $ -- $ 52.6 $ 3.5 ======== ====== ======== ====== ====== ====== ====== ====== Nine Months Ended June 30, 2001: Reportable Segments ------------------------------------------------ Inter- AmeriGas Gas Electric Energy national Corporate Total Elims Propane Utility Utility Services Propane and Other -------- ------ -------- ------- -------- -------- -------- --------- Revenues $2,092.8 $ (2.3) $1,209.1 $439.7 $ 62.2 $309.7 $ 39.1 $ 35.3 ======== ====== ======== ====== ====== ====== ====== ====== Segment profit (loss): EBITDA $ 322.8 $ (0.3) $ 201.5 $ 99.2 $ 11.3 $ 7.7 $ 3.2 $ 0.2 Depreciations and amortization (78.3) -- (55.8) (15.1) (2.7) (0.1) (3.2) (1.4) -------- ------ -------- ------ ------ ------ ------ ------ Operating income (loss) 244.5 (0.3) 145.7 84.1 8.6 7.6 -- (1.2) Loss from equity investees (1.5) -- -- -- -- -- (1.5) -- Interest expense (77.8) 0.3 (59.1) (12.5) (2.0) (0.3) (3.7) (0.5) Minority interests (38.9) -- (38.9) -- -- -- -- -- -------- ------ -------- ------ ------ ------ ------ ------ Income (loss) before income taxes, subsidiary preferred stock dividends, and accounting changes $ 126.3 $ -- $ 47.7 $ 71.6 $ 6.6 $ 7.3 $ (5.2) $ (1.7) ======== ====== ======== ====== ====== ====== ====== ====== Segment assets (at period end) $2,282.2 $(50.8) $1,279.3 $672.1 $101.6 $ 46.4 $134.7 $ 98.9 ======== ====== ======== ====== ====== ====== ====== ====== Investments in equity investees (at period end) $ 40.7 $ -- $ -- $ -- $ 11.4 $ -- $ 29.3 $ -- ======== ====== ======== ====== ====== ====== ====== ====== Goodwill and express reorganization value $ 646.6 $ -- $ 598.1 $ -- $ -- $ 0.2 $ 44.9 $ 3.4 ======== ====== ======== ====== ====== ====== ====== ======
8 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) 3. ADOPTION OF SFAS NO. 142 Effective October 1, 2001, we adopted the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board ("APB") Opinion No. 17, "Intangible Assets." SFAS 142 addresses the financial accounting and reporting for intangible assets acquired individually or with a group of other assets (excluding those acquired in a business combination) at acquisition and also addresses the financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under SFAS 142, an intangible asset is amortized over its useful life unless that life is determined to be indefinite. Goodwill, including excess reorganization value, and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. In accordance with the provisions of SFAS 142, we ceased the amortization of goodwill and excess reorganization value effective October 1, 2001. The Company's intangible assets comprise the following:
June 30, 2002 September 30, 2001 -------------------------------------------------------------------------------------------------- Gross Gross Carrying Accumulated Carrying Accumulated Amount Amortization Amount Amortization -------------------------------------------------------------------------------------------------- Subject to amortization: Customer relationships, noncompete agreements and other $ 37.1 $(9.5) $ 37.1 $(5.8) Net subject to amortization: Goodwill (a) $551.8 $547.8 Excess reorganization value 93.3 93.3 ------------------------------------------------------------------------------------------------- $645.1 $641.1 -------------------------------------------------------------------------------------------------
(a) The change in the carrying amount of goodwill from September 30, 2001 to June 30, 2002 is principally the result of foreign currency translation. Amortization expense of intangible assets for the three and nine months ended June 30, 2002 was $1.2 million and $3.7 million, respectively. Amortization expense of intangible assets for the three and nine months ended June 30, 2001, including amortization of goodwill and excess reorganization value prior to the adoption of SFAS 142, was $7.0 million and $21.1 million, respectively. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2002 - $4.1 million; Fiscal 2003 - $3.6 million; Fiscal 2004 - $3.5 million; Fiscal 2005 - $3.1 million; Fiscal 2006 - $2.6 million. 9 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) The following tables provide reconciliations of reported and adjusted net income (loss) and diluted earnings (loss) per share as if SFAS 142 had been adopted as of October 1, 2000. Basic earnings (loss) per share is not materially different from diluted earnings (loss) per share and, therefore, is not presented:
Three Months Nine Months Ended Ended June 30, June 30, ----------------------------------------------------------------------------------------------------- 2002 2001 2002 2001 ----------------------------------------------------------------------------------------------------- NET INCOME (LOSS): Reported income (loss) before accounting changes $ 4.0 $ (4.3) $82.1 $ 68.3 Add back goodwill and excess reorganization value amortization - 6.3 - 19.0 Adjust minority interest in AmeriGas Partners - (2.6) - (7.9) Adjust income tax expense - (1.5) - 1.9 ----------------------------------------------------------------------------------------------------- Adjusted income (loss) before accounting changes 4.0 (2.1) 82.1 81.3 Cumulative effect of accounting changes - - - 4.5 ----------------------------------------------------------------------------------------------------- Adjusted net income (loss) $ 4.0 $ (2.1) $82.1 $ 85.8 ----------------------------------------------------------------------------------------------------- DILUTED EARNINGS (LOSS) PER SHARE: Reported income (loss) before accounting changes $0.14 $(0.16) $2.93 $ 2.50 Add back goodwill and excess reorganization value amortization - 0.23 - 0.70 Adjust minority interest in AmeriGas Partners - (0.10) - (0.29) Adjust income tax expense - (0.05) - 0.07 ----------------------------------------------------------------------------------------------------- Adjusted income before accounting changes 0.14 (0.08) 2.93 2.98 Cumulative effect of accounting changes - - - 0.16 ----------------------------------------------------------------------------------------------------- Adjusted net income (loss) $0.14 $(0.08) $2.93 $ 3.14 -----------------------------------------------------------------------------------------------------
In accordance with the provisions of SFAS 142, we were required to perform transitional goodwill impairment tests for each of our reporting units having goodwill by March 31, 2002. In addition, we must perform impairment tests annually and whenever events or circumstances indicate that the value of goodwill might be impaired. In connection with these goodwill impairment tests, SFAS 142 prescribes a two-step method for determining goodwill impairment. In the first step, we determine the fair value of our reporting units that have goodwill. If the carrying amount of the reporting unit exceeds its fair value, we will then perform the second step of the impairment test which requires the calculation of the implied fair value of goodwill by allocating the reporting unit's fair value to all of its assets and liabilities in a manner similar to a business combination, with any residual fair value being allocated to goodwill. If the carrying value of the goodwill exceeds its implied fair value, an impairment loss is recognized for the excess. We have completed the transitional impairment tests with respect to those reporting units which have goodwill, principally the Partnership and FLAGA, and have determined that, based upon each of these units' fair value, their goodwill was not impaired as of October 1, 2001. We will perform our annual goodwill impairment tests during the fourth fiscal quarter. 10 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) 4. CHANGES IN ACCOUNTING Effective October 1, 2000, the Partnership (1) applied the provisions of SEC Staff Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101") with respect to its nonrefundable tank fees and (2) changed its method of accounting for costs to install Partnership-owned tanks at customer locations. These accounting changes are further described below. Tank Fee Revenue Recognition. In order to comply with the provisions of SAB 101, effective October 1, 2000, the Partnership changed its method of accounting for annually billed nonrefundable tank fees. Prior to the change, nonrefundable tank fees for installed Partnership-owned tanks were recorded as revenue when billed. Under the new accounting method, revenues from such fees are recorded on a straight-line basis over one year. As a result of the new accounting method, on October 1, 2000, we recorded an after-tax charge of $2.1 million representing the cumulative effect of the change in accounting method on prior years. The change in accounting method for nonrefundable tank fees did not have a material impact on reported revenues for the periods presented. Accounting for Tank Installation Costs. Effective October 1, 2000, the Partnership changed its method of accounting for tank installation costs which are not billed to customers. Prior to the change in accounting method, all such costs to install Partnership-owned tanks at a customer location were expensed as incurred. Under the new accounting method, all such costs, net of amounts billed to customers, are capitalized in property, plant and equipment and amortized over the estimated period of benefit not exceeding ten years. The Partnership believes that the new accounting method better matches the costs of installing Partnership-owned tanks with the periods benefited. As a result of this change in accounting, we recorded after-tax income of $6.9 million representing the cumulative effect of the change in accounting method on prior years. Cumulative Effect of Accounting Changes. The cumulative effect impact of these accounting changes reflected on the Condensed Consolidated Statements of Income for the nine months ended June 30, 2001 and the related diluted per share amounts, as well as the cumulative effect impact resulting from the adoption of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," comprise the following:
- -------------------------------------------------------------------------------------- Income Tax Diluted Pre-Tax Income (Expense) After-Tax Earnings (Loss) (Loss) Benefit Income (Loss) Per Share - -------------------------------------------------------------------------------------- Tank fees $(3.5) $ 1.4 $(2.1) $(0.08) Tank installation costs 11.3 (4.4) 6.9 0.26 SFAS 133 (0.4) 0.1 (0.3) (0.01) - -------------------------------------------------------------------------------------- Total $ 7.4 $(2.9) $ 4.5 $ 0.17 - --------------------------------------------------------------------------------------
11 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) 5. ACQUISITION OF COLUMBIA PROPANE On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group ("Columbia Propane Businesses") in a series of equity and asset purchases pursuant to the terms of the Purchase Agreement dated January 30, 2001 and Amended and Restated August 7, 2001 ("Columbia Purchase Agreement") by and among Columbia Energy Group ("CEG"), Columbia Propane Corporation ("Columbia Propane"), Columbia Propane, L.P. ("CPLP"), CP Holdings, Inc. ("CPH"), AmeriGas Partners, AmeriGas OLP, and the General Partner. The acquired businesses comprised the seventh largest retail marketer of propane in the United States with annual sales of over 300 million gallons from locations in 29 states. The acquired businesses were principally conducted through Columbia Propane and its approximate 99% owned subsidiary, CPLP (referred to after the acquisition as "Eagle OLP"). AmeriGas OLP acquired substantially all of the assets of Columbia Propane, including an indirect 1% general partner interest and an approximate 99% limited partnership interest in Eagle OLP. The purchase price of the Columbia Propane Businesses consisted of $201.8 million in cash. In addition, AmeriGas OLP agreed to pay CEG for the amount of working capital, as defined, in excess of $23 million. In April 2002, the Partnership's management and CEG agreed upon the amount of working capital acquired by AmeriGas OLP and AmeriGas OLP made an additional payment for working capital and other adjustments totaling $0.7 million. The Columbia Purchase Agreement also provided for the purchase by CEG of limited partnership interests in AmeriGas OLP valued at $50 million for $50 million in cash, which interests were exchanged for 2,356,953 Common Units of AmeriGas Partners having an estimated fair value of $54.4 million. Concurrently with the acquisition, AmeriGas Partners issued $200 million of 8.875% Senior Notes due 2011, the net proceeds of which were contributed to AmeriGas OLP to finance the acquisition of the Columbia Propane Businesses, to fund related fees and expenses, and to repay debt outstanding under AmeriGas OLP's Bank Credit Agreement. The following table identifies the components of the purchase price: --------------------------------------------------------------------------- Cash paid $202.5 Cash received from sale of AmeriGas OLP limited partner interests (50.0) Fair value of AmeriGas Partners' Common Units issued in exchange for the AmeriGas OLP limited partner interests 54.4 Transaction costs and expenses 7.0 Involuntary employee termination benefits and relocation costs 5.3 Other liabilities and obligations assumed 6.1 --------------------------------------------------------------------------- $225.3 ---------------------------------------------------------------------------
12 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) The purchase price of the Columbia Propane Businesses has been preliminarily allocated to the assets acquired and liabilities assumed as follows: - --------------------------------------------------------------------------- Working capital $ 24.5 Property, plant and equipment 181.4 Customer relationships and noncompete agreements (estimated useful life of 15 and 5 years, respectively) 21.0 Other assets and liabilities (1.6) - --------------------------------------------------------------------------- Total $225.3 - ---------------------------------------------------------------------------
The Partnership is currently in the process of completing the review and determination of the fair value of the Columbia Propane Businesses' assets acquired and liabilities assumed, principally the fair values of property, plant and equipment and identifiable intangible assets. The final allocation of the purchase price is not expected to differ materially from the preliminary allocation. The operating results of the Columbia Propane Businesses are included in our consolidated results from August 21, 2001. The following table presents unaudited pro forma income statement and diluted per share data for the nine months ended June 30, 2001 as if the acquisition of the Columbia Propane Businesses had occurred as of October 1, 2000:
Nine Months Ended June 30, 2001 - -------------------------------------------------------------------------------- Revenues $2,438.7 Income before accounting changes $ 71.2 Net income $ 75.7 Diluted earnings per share: Income before accounting changes $ 2.61 Net income $ 2.77 - --------------------------------------------------------------------------------
The pro forma results of operations reflect the Columbia Propane Businesses' historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing impact. They are not adjusted for, among other things, the impact of normal weather conditions, operating synergies and anticipated cost savings. In our opinion, the unaudited pro forma results are not necessarily indicative of the actual results that would have occurred had the acquisition of the Columbia Propane Businesses occurred as of the beginning of the period presented or of future operating results under our management. 13 UGI CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (unaudited) (Millions of dollars, except per share amounts) 6. ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY On November 30, 2001, Energy Services entered into a three-year receivables purchase facility ("Receivables Facility") with an issuer of receivables-backed commercial paper. 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 interest in these receivables for up to $50 million in proceeds to a commercial paper conduit of a major bank. The proceeds of these sales are less than the face amount of the accounts receivable sold by an amount that approximates the purchaser's financing cost of issuing its own receivables-backed commercial paper. ESFC has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. In accordance with a servicing arrangement, Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. 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." At June 30, 2002, no receivables had been sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables that occurred during the nine-months ended June 30, 2002, which losses are included in other income, net, were not material. 7. COMMITMENTS AND CONTINGENCIES There have been no significant subsequent developments to the commitments and contingencies reported in the Company's 2001 Annual Report. 14 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, 2002 ("2002 three-month period") with the three months ended June 30, 2001 ("2001 three-month period") and (2) the nine months ended June 30, 2002 ("2002 nine-month period") with the nine months ended June 30, 2001 ("2001 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. 15 UGI CORPORATION AND SUBSIDIARIES 2002 THREE-MONTH PERIOD COMPARED WITH 2001 THREE-MONTH PERIOD
- ----------------------------------------------------------------------------------------------------- Increase Three Months Ended June 30, 2002 2001 (Decrease) - ----------------------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE: Revenues $254.5 $219.2 $ 35.3 16.1% Total margin (a) $143.3 $ 98.7 $ 44.6 45.2% EBITDA (b) $ 28.5 $ 12.9 $ 15.6 120.9% Operating income (loss) $ 11.8 $ (5.8) $ 17.6 303.4% Retail gallons sold (millions) 171.0 133.2 37.8 28.4% Degree days - % colder (warmer) than normal (c) 4.3 (12.7) -- -- GAS UTILITY: Revenues $ 68.1 $ 84.5 $(16.4) (19.4)% Total margin (a) $ 31.1 $ 31.4 $ (0.3) (1.0)% Operating income $ 10.2 $ 10.8 $ (0.6) (5.6)% System throughput - billions of cubic feet ("bcf") 14.2 13.4 0.8 6.0% Degree days - % (warmer) than normal (5.6) (12.8) -- -- ELECTRIC UTILITY: Revenues $ 20.2 $ 19.3 $ 0.9 4.7% Total margin (a) $ 7.9 $ 6.8 $ 1.1 16.2% Operating income $ 3.1 $ 1.9 $ 1.2 63.2% Distribution sales - millions of kilowatt hours ("gwh") 213.0 209.6 3.4 1.6% ENERGY SERVICES: Revenues $ 85.1 $ 68.6 $ 16.5 24.1% Total margin $ 6.0 $ 3.6 $ 2.4 66.7% Operating income $ 3.5 $ 2.6 $ 0.9 34.6% INTERNATIONAL PROPANE: Revenues $ 9.2 $ 10.0 $ (0.8) (8.0)% Total margin $ 4.5 $ 4.8 $ (0.3) (6.3)% EBITDA (b) $ 0.5 $ 0.7 $ (0.2) (28.6)% Operating loss $ (0.3) $ (0.3) $ -- 0.0% Income from equity investees $ 0.8 $ -- $ 0.8 -- - ------------------------------------------------------------------------------------------------------
(a) AmeriGas Propane's and Gas Utility's total margin represents total revenues less cost of sales. Electric Utility's total margin represents revenues less cost of sales and revenue-related taxes, i.e. gross receipts taxes. For financial statement purposes, revenue-related taxes are included in "Utility taxes other than incomes taxes" on the Condensed Consolidated Statements of Income. (b) EBITDA (earnings before interest expense, income taxes, depreciation and amortization, minority interests, income from equity investees and the cumulative effect of accounting changes) 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. EBITDA is included to provide additional information for evaluating the Company's performance. The Company's definition of EBITDA may be different from that used by other companies. (c) Deviation from average heating degree days based upon national weather statistics provided by the National Oceanic and Atmospheric Administration ("NOAA") for 335 airports in the continental United States. 16 UGI CORPORATION AND SUBSIDIARIES AMERIGAS PROPANE. Based upon national heating degree day data, temperatures in the 2002 three-month period were 4.3% colder than normal compared to weather that was 12.7% warmer than normal in the 2001 three-month period. Retail gallons sold increased 37.8 million gallons (28.4%) principally as a result of the August 21, 2001 acquisition of Columbia Propane and, to a lesser extent, increased sales from our PPX(R) grill cylinder exchange business. The increase in PPX(R) sales reflects the impact on grill cylinder exchanges resulting from new National Fire Protection Association ("NFPA") guidelines requiring that propane cylinders refilled after April 1, 2002 be fitted with overfill protection devices ("OPDs") and an increase in the number of PPX(R) distribution outlets. Although sales to commercial, industrial and motor fuel customers increased during the 2002 three-month period due to the Columbia Propane acquisition, volumes from these customers were negatively impacted by a weak U.S. economy in the 2002 three-month period. Retail propane revenues increased $32.2 million to $206.3 million reflecting a $49.4 million increase due to the higher retail volumes sold partially offset by a $17.2 million decrease as a result of lower average selling prices. Wholesale propane revenues decreased $3.5 million reflecting a $5.3 million decrease resulting from lower average selling prices partially offset by a $1.8 million increase as a result of higher wholesale volumes sold. The lower retail and wholesale selling prices reflect lower propane product costs in the 2002 three-month period. Other revenues increased $6.6 million primarily due to the impact of the Columbia Propane acquisition. Cost of sales decreased $9.3 million reflecting the previously mentioned lower average propane product costs partially offset by the higher gallons sold. Total margin increased $44.6 million principally reflecting (1) the impact of the Columbia Propane acquisition; (2) a $15.4 million increase in margin from our PPX(R) grill cylinder exchange business reflecting the higher volumes and greater PPX(R) unit margins; and (3) higher average propane unit margins on non-PPX(R) retail volumes. PPX(R) unit margins in the 2002 three-month period were higher than in the prior-year period due to increases in PPX(R) margins to fund the additional capital cost of installing OPDs on out-of-compliance grill cylinders. Because a significant portion of the improvement in PPX(R) margin in the 2002 three-month period was due to the impact of the NFPA guidelines, the extent to which this greater level of PPX(R) margin is sustainable in the future will depend upon a number of factors including the saturation rate of OPD value replacement and competitive market conditions. EBITDA increased $15.6 million in the 2002 three-month period as the $44.6 million increase in total margin was partially offset principally by a $28.9 million increase in Partnership operating and administrative expenses. The increase in operating and administrative expenses primarily resulted from incremental expenses associated with Columbia Propane's operations and higher volume-driven expenses associated with PPX(R). Operating income increased more than the increase in EBITDA as the elimination of goodwill and excess reorganization value amortization resulting from the adoption of SFAS 142 on October 1, 2001 was partially offset principally by higher depreciation and amortization resulting from the Columbia Propane acquisition. The prior-year three-month period includes $6.0 million of goodwill and excess reorganization value amortization. GAS UTILITY. Weather in Gas Utility's service territory during the 2002 three-month period was slightly colder than in the prior-year period. Total system throughput increased 0.8 bcf reflecting higher firm and interruptible delivery service volumes. 17 UGI CORPORATION AND SUBSIDIARIES Gas Utility revenues declined $16.4 million in the 2002 three-month period reflecting the impact of lower purchased gas cost ("PGC") rates associated with our firm- residential, commercial and industrial ("core market") customers as a result of lower natural gas costs. Gas Utility cost of gas was $37.0 million in the 2002 three-month period compared to $53.1 million in the prior-year period reflecting the pass through of the lower natural gas costs. Gas Utility total margin for the 2002 three-month period was approximately equal to the prior-year period as greater margin from core market customers was offset by lower margin from interruptible customers. In accordance with Gas Utility's Restructuring Order issued pursuant to Pennsylvania's Gas Competition Act, Gas Utility was required to reduce its PGC rates, beginning December 1, 2001, by an amount equal to the margin it receives from interruptible customers who use pipeline capacity contracted for core market customers. As a result of this ratemaking, beginning December 1, 2001, core market unit margins effectively increased and total margins from interruptible customers decreased. Gas Utility's operating income declined $0.6 million in the 2002 three-month period reflecting the previously mentioned decline in total margin and greater operating expenses partially offset by a $0.5 million decline in depreciation expense resulting from a change in the estimated useful lives of Gas Utility's distribution assets. Total operating expenses in the prior year were net of $1.5 million of income from an insurance recovery and a reduction to accruals for taxes other than income taxes. ELECTRIC UTILITY. Distribution system sales for the 2002 three-month period were slightly higher than in the prior-year period. Revenues increased as a result of increased state tax surcharge revenue and higher distribution system and off-system sales. Electric Utility cost of sales was $11.2 million in the 2002 three-month period compared to $11.7 million in the prior-year period reflecting the impact of lower purchased power units costs partially offset by the increased distribution system sales. Total margin increased $1.1 million in the 2002 three-month period principally as a result of lower purchased power unit costs and the increased distribution system sales. Electric Utility's $1.2 million increase in operating income principally reflects the previously mentioned increase in total margin. ENERGY SERVICES. Revenues from Energy Services increased $16.5 million reflecting a more than 45% increase in volumes, principally from the July 2001 acquisition of the energy marketing businesses of PG Energy. Total margin was higher in the 2002 three-month period reflecting the greater volumes and seasonally higher margins from certain customer segments. Operating income increased $0.9 million as the increase in total margin was partially offset by higher operating expenses subsequent to the PG Energy acquisition. INTERNATIONAL PROPANE. Revenues from FLAGA were lower due to lower average selling prices and a decrease in volumes sold, reflecting a later start to FLAGA's summer sales promotion program. The lower selling prices reflect the impact of lower propane product costs in the 2002 three-month period. The impact of these decreases was partially offset by the effect of a stronger EURO versus the U.S. dollar during the 2002 three-month period. The decline in FLAGA's total margin reflects the lower volumes sold partially offset by the effect of the stronger EURO. FLAGA's results for the 2002 three-month period also benefited from lower operating expenses and lower amortization expense resulting from the adoption of SFAS 142. The increase in income from International Propane equity investees reflects greater equity income from Antargaz. Antargaz adopted the provisions of SFAS 142 effective April 1, 2002. The adoption 18 UGI CORPORATION AND SUBSIDIARIES of SFAS 142 increased equity income from Antargaz by approximately $0.5 million during the 2002 three-month period. INTEREST EXPENSE AND INCOME TAXES. The increase in interest expense principally reflects higher Partnership long-term debt outstanding related to the Columbia Propane acquisition partially offset by lower levels of UGI Utilities and Partnership bank loans outstanding and lower short-term interest rates. The higher effective income tax rate in the 2002 three-month period is primarily due to the impact of a change in the estimated annual effective income tax rate on year to date pretax income. 2002 NINE-MONTH PERIOD COMPARED WITH 2001 NINE-MONTH PERIOD
- ---------------------------------------------------------------------------------------- Increase Nine Months Ended June 30, 2002 2001 (Decrease) - ---------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE: Revenues $1,086.0 $1,209.1 $(123.1) (10.2)% Total margin $ 557.0 $ 480.4 $ 76.6 15.9 % EBITDA $ 207.4 $ 201.5 $ 5.9 2.9 % Operating income $ 157.9 $ 145.7 $ 12.2 8.4 % Retail gallons sold (millions) 782.8 678.1 104.7 15.4 % Degree days - % (warmer) colder than normal (9.5) 3.0 -- -- GAS UTILITY: Revenues $ 347.5 $ 439.7 $ (92.2) (21.0)% Total margin $ 138.5 $ 152.2 $ (13.7) (9.0)% Operating income $ 73.5 $ 84.1 $ (10.6) (12.6)% System throughput - billions of cubic feet ("bcf") 59.7 66.1 (6.4) (9.7)% Degree days - % (warmer) colder than normal (16.5) 2.0 -- -- ELECTRIC UTILITY: Revenues $ 62.2 $ 62.2 $ -- 0.0 % Total margin $ 23.6 $ 23.2 $ 0.4 1.7 % Operating income $ 8.7 $ 8.6 $ 0.1 1.2 % Distribution sales - millions of kilowatt hours ("gwh") 689.0 716.8 (27.8) (3.9)% ENERGY SERVICES: Revenues $ 272.3 $ 309.7 $ (37.4) (12.1)% Total margin $ 15.3 $ 11.1 $ 4.2 37.8 % Operating income $ 7.7 $ 7.6 $ 0.1 1.3 % INTERNATIONAL PROPANE: Revenues $ 35.6 $ 39.1 $ (3.5) (9.0)% Total margin $ 17.7 $ 16.4 $ 1.3 7.9 % EBITDA $ 5.5 $ 3.2 $ 2.3 71.9 % Operating income $ 3.3 $ -- $ 3.3 -- Income (loss) from equity investees $ 7.8 $ (1.5) $ 9.3 620.0 % - ----------------------------------------------------------------------------------------
AMERIGAS PROPANE. Temperatures based upon national heating degree days were 9.5% warmer than normal in the 2002 nine-month period compared to weather that was 3.0% colder than normal in the 2001 nine-month period. According to the National Climatic Data Center, U.S. weather in the November 2001 through January 2002 period was the warmest November through January period on record. Although the significantly warmer weather and 19 UGI CORPORATION AND SUBSIDIARIES a weak U.S. economy adversely affected our sales volumes, retail gallons sold increased 104.7 million gallons principally as a result of the August 21, 2001 acquisition of Columbia Propane. Retail propane revenues decreased $44.5 million to $897.9 million reflecting a $190.0 million decrease as a result of lower average selling prices partially offset by a $145.5 million increase due to the higher retail volumes sold. Wholesale propane revenues decreased $94.7 million reflecting (1) a $57.5 million decrease resulting from lower average selling prices and (2) a $37.2 million decrease as a result of lower wholesale volumes sold. The lower retail and wholesale selling prices reflect significantly lower propane product costs during the 2002 nine-month period compared to the prior-year period. Other revenues increased $16.1 million primarily due to the impact of the Columbia Propane acquisition. Cost of sales decreased $199.7 million reflecting the lower average propane product costs partially offset by the impact of the higher retail gallons sold. Total margin increased $76.6 million reflecting the impact of the Columbia Propane acquisition and a $22.7 million increase in total margin from PPX(R) as a result of higher unit margins and volumes. Average retail propane unit margins were comparable with the prior year. Average unit margins in the current year benefited from greater PPX(R) unit margins and volumes while the prior year unit margins benefited from derivative hedge gains and favorably priced supply arrangements during a period of rapidly escalating product costs and market volatility. EBITDA increased $5.9 million in the 2002 nine-month period as the $76.6 million increase in total margin was partially offset by (1) a $68.3 million increase in Partnership operating and administrative expenses and (2) a $1.6 million decrease in other income. The increase in operating expenses in the current year includes operating and administrative expenses of Columbia Propane's operations and higher volume-driven expenses associated with PPX(R). Operating income increased more than the increase in EBITDA principally due to the elimination of goodwill amortization resulting from the adoption of SFAS 142 on October 1, 2001 partially offset principally by higher depreciation and amortization resulting from the Columbia Propane acquisition. The prior-year nine-month period includes $17.9 million of goodwill and excess reorganization value amortization. GAS UTILITY. Weather in Gas Utility's service territory during the 2002 nine-month period was 16.5% warmer than normal compared to weather that was 2.0% colder than normal in the prior-year period. As a result of the significantly warmer weather and the effects of a slowing economy on commercial and industrial natural gas usage, distribution system throughput declined 9.7%. The decrease in Gas Utility revenues reflects the impact of lower PGC rates, reflecting the pass through of lower natural gas costs in the 2002 nine-month period, and the lower distribution system throughput. Gas Utility cost of gas was $209.0 million in the 2002 nine-month period compared to $287.5 million in the prior-year period. The decrease in cost of gas resulted from the pass through of lower natural gas costs and the decline in system throughput. The decline in Gas Utility margin principally reflects (1) a $5.7 million decline in core market margin due to the lower sales; (2) a $5.9 million decline in interruptible margin due principally to the flowback of certain interruptible customer margin to core market customers beginning December 1, 2001; and (3) lower firm delivery service total margin. Gas Utility operating income declined $10.6 million in the 2002 nine-month period reflecting the previously mentioned decline in total margin partially offset by lower operating expenses. Operating 20 UGI CORPORATION AND SUBSIDIARIES expenses declined $2.9 million primarily as a result of lower distribution system expenses and lower charges for uncollectible accounts. ELECTRIC UTILITY. The decline in kilowatt-hour sales in the 2002 nine-month period reflects the effects of weather that was nearly 19% warmer than in the prior-year nine-month period. Notwithstanding the decrease in kilowatt-hour sales, revenues were unchanged due principally to differences in customer sales mix and an increase in state tax surcharge revenue. Electric Utility cost of sales was $35.5 million in the 2002 nine-month period compared to $36.4 million in the 2001 nine-month period reflecting the impact of the lower sales and lower purchased power unit costs partially offset by the full-period impact on cost of sales resulting from the transfer of generation assets to Hunlock Creek Energy Ventures ("Energy Ventures") in December 2000. Subsequent to the formation of Energy Ventures, Electric Utility must purchase substantially all of its electricity needs from power producers, including Energy Ventures. Electric Utility total margin increased $0.4 million as a result of lower purchased power unit costs partially offset by the weather-driven decline in sales. Operating income increased $0.1 million reflecting the greater total margin and lower operating costs subsequent to the formation of Energy Ventures offset by a decline in Electric Utility other income. ENERGY SERVICES. Revenues from Energy Services declined $37.4 million, notwithstanding a more than 33% increase in natural gas volumes principally as a result of the PG Energy acquisition, reflecting lower natural gas prices. Total margin increased as a result of the PG Energy acquisition, customer growth and income from providing winter storage services partially offset by lower 2002 nine-month period average unit margins. The increase in total margin was offset by higher operating expenses resulting in large part from the PG Energy acquisition. INTERNATIONAL PROPANE. FLAGA's revenues in the 2002 nine-month period were lower than in the prior-year period as a result of lower average selling prices reflecting the impact of lower average propane product costs. Weather was approximately 11% warmer than normal in the 2002 nine-month compared to weather that was 15% warmer than normal in the prior-year period. The increase in FLAGA's total margin reflects higher average unit margins in the 2002 nine-month period. FLAGA's operating income also benefited from lower operating expenses, principally reduced payroll costs, and a $0.9 million decrease in amortization expense resulting from the adoption of SFAS 142. Income from equity investees in the 2002 nine-month period includes the full-period impact of income from our debt and equity investments in Antargaz acquired on March 27, 2001. Results of Antargaz in the 2002 nine-month period benefited from higher than normal unit margins principally as a result of lower propane product costs. Loss from International Propane equity investees in the 2001 nine-month period includes a loss of $1.1 million from our March 2001 write-off of our propane joint venture investment located in Romania. INTEREST EXPENSE AND INCOME TAXES. The increase in interest expense principally reflects higher Partnership long-term debt outstanding partially offset by lower levels of UGI Utilities and Partnership bank loans outstanding and lower short-term interest rates. The lower effective income tax rate in the 2002 nine-month period principally reflects the elimination of nondeductible goodwill amortization resulting from the adoption of SFAS 142. 21 UGI CORPORATION AND SUBSIDIARIES FINANCIAL CONDITION AND LIQUIDITY FINANCIAL CONDITION The Company's debt outstanding totaled $1,291.8 million at June 30, 2002 compared to $1,363.0 million at September 30, 2001. The decline in total debt outstanding principally reflects lower Partnership debt. In November 2001, AmeriGas Partners redeemed prior to maturity $15 million of its 10.125% Senior Notes at a redemption price of 103.375%. In April 2002, AmeriGas OLP repaid $60 million of maturing First Mortgage Notes with a combination of existing cash balances and borrowings under AmeriGas OLP's Bank Credit Agreement. On May 3, 2002, AmeriGas Partners issued $40 million of 8 7/8 % Senior Notes with an effective interest rate of 8.25%. AmeriGas Partners contributed the proceeds to AmeriGas OLP to reduce indebtedness under its Revolving Credit Facility and for working capital and general business purposes. AmeriGas OLP's Bank Credit Agreement consists of a $100 million Revolving Credit Facility and a $75 million Acquisition Facility. At June 30, 2002, there were no borrowings outstanding under either of these facilities. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce available borrowing capacity, totaled $9.5 million at June 30, 2002. Although these facilities have a September 15, 2002 termination date, management expects these facilities to be extended through October 1, 2003 pursuant to a Second Amended and Restated Bank Credit Agreement anticipated to be finalized in August 2002. At June 30, 2002, UGI Utilities had commitments under revolving credit agreements providing for borrowings up to $97 million of which $45.6 million was outstanding. These agreements expire at various dates from June 2003 through June 2004. UGI Utilities expects to refinance $26 million of maturing Medium-Term Notes due October 2002 through debt issued pursuant to its shelf registration statements with the SEC covering a total of $125 million of debt securities. On October 5, 2001, AmeriGas Partners sold 350,000 Common Units to the General Partner at a market price of $19.81 per unit. The proceeds of this sale and related capital contributions from the General Partner totaling $7.1 million were contributed to AmeriGas OLP and used to reduce Bank Credit Agreement borrowings and for working capital. On December 11, 2001, AmeriGas Partners sold 1,843,047 Common Units in an underwritten public offering at a public offering price of $21.50 per unit. On January 8, 2002, the underwriters partially exercised their overallotment option in the amount of 585,000 Common Units. The net proceeds of the public offering and related capital contributions from the General Partner totaling $50.6 million were contributed to AmeriGas OLP and used to reduce Bank Credit Agreement borrowings and for working capital. As more fully described in Note 6 to Condensed Consolidated Financial Statements, on November 30, 2001, Energy Services entered into a receivables purchase facility with an issuer of receivables-backed commercial paper. Under this arrangement, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to a wholly-owned, special purpose, bankruptcy-remote subsidiary, Energy Services Funding Corporation ("ESFC"), which in turn has the ability to sell an undivided interest in these receivables. The level of funding available under this three-year facility is limited to $50 million. At June 30, 2002, no receivables had been sold and removed from the balance sheet. 22 UGI CORPORATION AND SUBSIDIARIES During the nine months ended June 30, 2002, the Partnership declared and paid the minimum quarterly distribution of $0.55 (the "MQD") on all units for the quarters ended September 30, 2001, December 31, 2001 and March 31, 2002. The MQD for the quarter ended June 30, 2002 will be paid on August 18, 2002 to holders of record on August 9, 2002. The ability of the Partnership to declare and pay the MQD on all units depends upon a number of factors. These factors include (1) the level of Partnership earnings; (2) the cash needs of the Partnership's operations (including cash needed for maintaining and increasing operating capacity); (3) changes in operating working capital; and (4) the Partnership's ability to borrow under its Bank Credit Agreement, to refinance maturing debt, and to increase its long-term debt. Some of these factors are affected by conditions beyond our control including weather, competition in markets we serve, and the cost of propane. Pursuant to the Agreement of Limited Partnership of AmeriGas Partners, the remaining 9.9 million AmeriGas Partners Subordinated Units held by the General Partner are eligible to convert to Common Units on the first day after the record date for any quarter ending on or after March 31, 2000 in which certain cash-based performance and distribution requirements are met. Based upon current projections of operating results and changes in working capital, it is reasonably possible that the Partnership could satisfy the requirements for conversion in respect of the quarter ending September 30, 2002. If and when the remaining Subordinated Units convert to Common Units, the Company will recognize accumulated gains resulting from AmeriGas Partners sales of Common Units in conjunction with, and subsequent to, its April 19, 1995 initial public offering. Such gains, which are currently estimated to total approximately $165 million, will be reflected in the Company's balance sheet as an increase in stockholders' equity and a decrease in minority interests in AmeriGas Partners. In July 2002, subsequent to the end of the quarter, the Company received $19.3 million in cash from AGZ Holdings ("AGZ") representing repayment of 18 million EURO face value (90%) of the redeemable bonds of AGZ ("AGZ Bonds") held by the Company, plus accrued interest. This repayment was funded from the proceeds of an AGZ placement of high-yield debt. The Company purchased the AGZ Bonds on March 27, 2001 in conjunction with its joint-venture investment, through AGZ, in Elf Antargaz, S.A., a leading distributor of liquefied petroleum gas in France. Concurrent with the repayment, the remaining 2.0 million EURO investment in AGZ Bonds was redeemed in the form of additional shares of AGZ. After these transactions, the Company continues to hold an approximate 19.5% equity investment in shares of AGZ. On April 30, 2002, UGI's Board of Directors increased the quarterly dividend rate on UGI Common Stock to $0.4125 a share, or $1.65 on an annual basis. 23 UGI CORPORATION AND SUBSIDIARIES CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS The following table presents significant contractual cash obligations under long-term agreements existing as of June 30, 2002 (in millions).
- ------------------------------------------------------------------------------------------------------------ Three Months Ended September 30, Fiscal Fiscal 2002 2003 - 2004 2005 - 2006 Thereafter Total - ------------------------------------------------------------------------------------------------------------ Long-term debt $ 2.8 $212.6 $346.7 $676.2 $1,238.3 UGI Utilities redeemable preferred stock -- -- 2.0 18.0 20.0 Operating leases 13.0 71.7 53.8 69.6 208.1 Energy Services supply contracts 30.4 47.1 0.1 -- 77.6 Electric supply contracts 9.0 67.2 33.7 -- 109.9 Gas supply contracts 16.6 130.4 42.7 109.8 299.5 - ------------------------------------------------------------------------------------------------------------ Total $71.8 $529.0 $479.0 $873.6 $1,953.4 - ------------------------------------------------------------------------------------------------------------
CASH FLOWS Our cash flows are seasonal and are generally greatest during the second and third fiscal quarters when customers pay bills incurred during the heating season and are typically at their lowest levels during the first and fourth fiscal quarters. Accordingly, cash flows from operations during the nine months ended June 30, 2002 are not necessarily indicative of the cash flows to be expected for a full year. Our consolidated cash and short-term investments totaled $138.8 million at June 30, 2002 compared to $55.7 million at June 30, 2001. The higher consolidated cash and short-term investment balances at June 30, 2002 reflects in large part strong operating cash flows from the Partnership, UGI Utilities and Energy Services. Included in consolidated cash and short-term investments at June 30, 2002 and 2001 are $57.2 million and $17.2 million, respectively, of cash and short-term investments held by UGI. OPERATING ACTIVITIES. Cash provided by operating activities was $199.7 million during the nine months ended June 30, 2002 compared to $106.1 million during the prior-year nine-month period. Cash flow from operating activities before changes in working capital was $210.7 million in the 2002 nine-month period compared to $153.0 million in the prior year nine-month period principally reflecting significantly higher noncash charges for income taxes and the impact on prior-year operating cash flows of $16.8 million in settlement payments associated with Energy Services' exchange-traded natural gas futures contracts. Changes in operating working capital during the 2002 nine-month period used $11.0 million of operating cash flow compared with $46.9 million of cash used in the prior year nine-month period. The significant decline is due in large part to the effects of lower 2002 nine-month period commodity prices on working capital. INVESTING ACTIVITIES. We spent $63.3 million for property, plant and equipment in the 2002 nine-month period, an increase of $9.1 million from the prior year, reflecting higher Partnership expenditures for PPX(R), principally grill cylinder OPDs to comply with NFPA guidelines, and higher capital expenditures associated with the Columbia Propane Businesses. FINANCING ACTIVITIES. During the nine month periods ended June 30, 2002 and 2001, we paid cash dividends on UGI Common Stock of $33.3 million and $42.3 million, respectively, and the Partnership 24 UGI CORPORATION AND SUBSIDIARIES paid the MQD on all publicly held Common Units (as well as the Common and Subordinated units we own). The higher dividends paid on UGI Common Stock in the prior year reflects the one-time impact of a change in the timing of funding the quarterly dividend. During the 2002 nine-month period, AmeriGas Partners received net proceeds of $49.6 million from its public offering of 2.4 million Common Units. During the 2002 nine-month period, AmeriGas OLP repaid $20 million of Acquisition Facility borrowings and $60 million of maturing First Mortgage Notes, and AmeriGas Partners redeemed $15 million of its 10.125% Senior Notes. AmeriGas Partners issued $40 million of 8 7/8% Senior Notes and contributed the proceeds to AmeriGas OLP to reduce indebtedness under its Revolving Credit Facility and for working capital and general business purposes. ADOPTION OF SFAS NO. 142 Effective October 1, 2001, we adopted the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." SFAS 142 addresses the financial accounting and reporting for intangible assets acquired individually or with a group of other assets (excluding those acquired in a business combination) at acquisition and also addresses the financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under SFAS 142, an intangible asset is amortized over its useful life unless that life is determined to be indefinite. Goodwill, including excess reorganization value, and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. As a result of the adoption of SFAS 142, we ceased the amortization of goodwill and excess reorganization value effective October 1, 2001. For a more detailed discussion of SFAS 142 and its impact on the Company's results, see Note 3 to Condensed Consolidated Financial Statements. UTILITY REGULATORY MATTERS The Pennsylvania Public Utility Commission ("PUC") approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively the "POLR Settlement"). Under the terms of the POLR Settlement, Electric Utility will terminate stranded cost recovery through its Competitive Transition Charge ("CTC") from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and will no longer be subject to the statutory rate cap as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Charges for generation service will initially be set at a level equal to the rates currently paid by Electric Utility customers for POLR service, may be raised at certain designated times up to certain specified caps through December 2004, and may be set at market rates thereafter. Electric Utility may also offer multiple year POLR contracts to its customers. The POLR Settlement provides for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. Under the June 13, 2002 settlement, the Office of Consumer Advocate also agreed to withdraw a complaint challenging 25 UGI CORPORATION AND SUBSIDIARIES Electric Utility's recovery of $1.2 million through an increase in the state tax adjustment surcharge for 2002. On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16.7 million in additional net annual revenues. The Gas Restructuring Order also required Gas Utility to reduce its core-market PGC rates by an annualized amount of $16.7 million in the first 14 months following the October 1, 2000 base rate increase. Beginning December 1, 2001, Gas Utility was required to reduce its PGC rates by an amount equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for core-market customers. As a result, beginning December 1, 2001, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels. CRITICAL ACCOUNTING POLICIES AND ESTIMATES In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," the Company has identified the following critical accounting policies that are most important to the portrayal of the Company's financial condition and results of operations. The following policies require management's most subjective or complex judgments, often as a result of the need to make estimates regarding matters that are inherently uncertain. LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. The Company is involved in litigation regarding pending claims and legal actions that arise in the normal course of its businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants in Pennsylvania and elsewhere at which hazardous substances may be present. In accordance with generally accepted accounting principles, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability, and such reserves may change materially as more information becomes available and estimated reserves are adjusted. REGULATORY ASSETS AND LIABILITIES. Gas Utility, and Electric Utility's distribution business, are subject to regulation by the Pennsylvania Public Utility Commission. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations. 26 UGI CORPORATION AND SUBSIDIARIES IMPAIRMENT OF GOODWILL. Certain of the Company's business units have goodwill resulting from purchase business combinations. In accordance with SFAS 142, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit's fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to writedown all or a portion of its goodwill which would adversely impact our results of operations. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"), SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145") and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with a corresponding increase in the carrying value of the related asset. Entities shall subsequently charge the retirement cost to expense using a systematic and rational method over the related asset's useful life and adjust the fair value of the liability resulting from the passage of time through charges to interest expense. We are required to adopt SFAS 143 effective October 1, 2002. We are currently in the process of evaluating the impact of SFAS 143 on our financial condition and results of operations. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," as it relates to the disposal of a segment of a business. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of based upon the framework of SFAS 121, and resolves significant implementation issues of SFAS 121. SFAS 144 is effective for the Company October 1, 2002. We believe that the adoption of SFAS 144 will not have a material impact on our financial condition or results of operations. SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective May 15, 2002. SFAS 4 had required that material gains and losses on extinguishment of debt be classified as an extraordinary item. Under SFAS 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in our Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS 13, "Accounting for Leases," to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. The provisions of SFAS 145 relating to leases are effective for transactions occurring after May 15, 2002. 27 UGI CORPORATION AND SUBSIDIARIES We believe that SFAS 145 will not have a material effect on our financial condition or results of operations. SFAS 146 addresses accounting for costs associated with exit or disposal activities and nullifies 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 of an entity's commitment to an exit plan. SFAS 146 will be effective for disposal activities initiated after December 31, 2002. We believe SFAS 146 will not have a material effect on our financial condition 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. Price 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. The Partnership's profitability is sensitive to changes in propane supply costs, and the Partnership generally attempts to pass on increases in such costs to customers. The Partnership may not, however, always be able to pass through product cost increases fully, particularly when product costs rise rapidly. In order to manage a portion of the Partnership's propane market price risk, it uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts. FLAGA's profitability is also sensitive to changes in propane supply costs and, on occasion, FLAGA also uses derivative commodity instruments to reduce market risk associated with purchases of propane. Over-the-counter derivative commodity instruments utilized by the Partnership and FLAGA to hedge forecasted purchases of propane are generally settled at expiration of the contract. In order to minimize credit risk associated with these contracts, we monitor 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 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. Electric Utility's electricity distribution business purchases all of its electric power needs, in excess of the electric power it obtains from its interests in electric generating facilities, under power supply arrangements of various lengths and on the spot market. Commencing September 2002, Electric Utility's transmission and distribution business will purchase substantially all of its anticipated power needs from electricity marketers under fixed-price energy and capacity contracts and expects to sell electric power produced from its interests in electricity generating assets to third parties under contract or on the spot market. Prices for electricity can be volatile especially during periods of high 28 UGI CORPORATION AND SUBSIDIARIES demand or tight supply. Although the generation component of Electric Utility's rates is subject to various rate cap provisions as a result of the Electricity Restructuring Order and the POLR Settlement, Electric Utility's fixed-price contracts with electricity marketers mitigate most risks with offering customers a fixed price during the rate cap 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 would negatively impact Electric Utility results. In order to reduce this non-performance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. In order to manage market price risk relating to substantially all of Energy Services' forecasted fixed-price sales of natural gas, 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 generally requires daily cash deposits in margin accounts with brokers. Although Energy Services' fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services' results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers. 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. 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 an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with forecasted issuances of fixed-rate debt, we generally enter into interest rate protection agreements. The primary currency for which the Company has exchange rate risk is the U.S. dollar versus the EURO. We do not currently use derivative instruments to hedge foreign currency exposure associated with our international propane operations and investments, principally FLAGA and Antargaz. As a result, the U.S. dollar value of our foreign denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. With respect to FLAGA, our exposure to changes in foreign currency exchange rates has been significantly limited because the purchase of FLAGA was financed primarily with EURO denominated debt, and FLAGA's U.S. dollar denominated financial instrument assets and liabilities are substantially equal in amount. With respect to our equity investment in Antargaz, a 10% decline in the value of the EURO versus the U.S. dollar would reduce the book value of this investment by approximately $2.0 million, which amount would be reflected in other comprehensive income. 29 UGI CORPORATION AND SUBSIDIARIES The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at June 30, 2002. 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 100 basis points:
- ------------------------------------------------------------------------------------ Fair Change in Value Fair Value - ------------------------------------------------------------------------------------ (Millions of dollars) June 30, 2002: Propane commodity price risk $ 2.4 $(7.5) Natural gas commodity price risk 3.3 (5.7) Interest rate risk (1.6) (4.8) - ------------------------------------------------------------------------------------
PART II OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) List of Exhibits: 99 Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended June 30, 2002. (b) The following Current Reports on Form 8-K were filed during the fiscal quarter ended June 30, 2002:
DATE ITEM NUMBER CONTENT April 29, 2002 5 Notice of webcast of Chairman's presentation to the American Gas Association Financial Forum conference May 21, 2002 4, 7 Changes in Registrant's Certifying Accountant
30 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 13, 2002 By: /s/ A.J. Mendicino ---------------------------- A.J. Mendicino, Vice President - Finance and Chief Financial Officer 31 UGI CORPORATION AND SUBSIDIARIES EXHIBIT INDEX 99 Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended June 30, 2002 EX-99 3 w62944exv99.txt CERTIFICATION OF CEO AND CFO EXHIBIT 99 CERTIFICATION BY THE CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER RELATING TO A PERIODIC REPORT CONTAINING FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- I, Lon R. Greenberg, Chief Executive Officer, and I, Anthony J. Mendicino, Chief Financial Officer, of UGI Corporation, a Pennsylvania corporation (the "Company"), hereby certify that: (1) The Company's periodic report on Form 10-Q for the period ended June 30, 2002 (the "Form 10-Q") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and (2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company. * * * CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER /s/ Lon R. Greenberg /s/ Anthony J. Mendicino - --------------------------- ------------------------ Lon R. Greenberg Anthony J. Mendicino Date: August 13, 2002 Date: August 13, 2002 -----END PRIVACY-ENHANCED MESSAGE-----