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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended December 31, 2006
OR
| o | 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 (State or other jurisdiction of incorporation or organization) | 23-2668356 (I.R.S. Employer 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)
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. Yesþ Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ Accelerated filero Non-accelerated filero
Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ
Yeso Noþ
At January 31, 2007, there were 106,043,071 shares of UGI Corporation Common Stock, without par value, outstanding.
UGI CORPORATION AND SUBSIDIARIES
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
(unaudited)
(Millions of dollars)
| December 31, | September 30, | December 31, | ||||||||||
| 2006 | 2006 | 2005 | ||||||||||
| ASSETS | ||||||||||||
| Current assets: | ||||||||||||
| Cash and cash equivalents | $ | 124.4 | $ | 186.2 | $ | 267.9 | ||||||
| Restricted cash | 25.1 | 14.2 | 254.4 | |||||||||
| Short-term investments (at cost, which approximates fair value) | 4.2 | 0.6 | 75.0 | |||||||||
| Accounts receivable (less allowances for doubtful accounts of $38.6, 38.0 and $31.9, respectively) | 645.0 | 387.2 | 675.7 | |||||||||
| Accrued utility revenues | 58.1 | 16.6 | 59.2 | |||||||||
| Inventories | 340.8 | 340.4 | 262.0 | |||||||||
| Deferred income taxes | 52.1 | 55.9 | 26.3 | |||||||||
| Income taxes recoverable | — | 11.0 | — | |||||||||
| Deferred fuel costs | — | — | 9.4 | |||||||||
| Prepaid expenses and other current assets | 22.4 | 28.5 | 38.3 | |||||||||
| Total current assets | 1,272.1 | 1,040.6 | 1,668.2 | |||||||||
| Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,284.2, $1,246.6 and $1,012.9, respectively) | 2,249.2 | 2,214.7 | 1,805.7 | |||||||||
| Goodwill | 1,443.1 | 1,418.2 | 1,222.1 | |||||||||
| Intangible assets (less accumulated amortization of $67.7, $62.8 and $48.9, respectively) | 164.6 | 163.3 | 166.4 | |||||||||
| Utility regulatory assets | 73.8 | 72.9 | 61.8 | |||||||||
| Investment in equity investees | 60.5 | 58.2 | 12.3 | |||||||||
| Other assets | 113.8 | 112.6 | 121.4 | |||||||||
| Total assets | $ | 5,377.1 | $ | 5,080.5 | $ | 5,057.9 | ||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||
| Current liabilities: | ||||||||||||
| Current maturities of long-term debt | $ | 32.0 | $ | 31.9 | $ | 423.0 | ||||||
| UGI Utilities bank loans | 250.0 | 216.0 | 145.5 | |||||||||
| Other bank loans | 9.4 | 9.4 | 16.7 | |||||||||
| Accounts payable | 524.8 | 373.0 | 619.2 | |||||||||
| Other current liabilities | 391.6 | 396.3 | 380.3 | |||||||||
| Total current liabilities | 1,207.8 | 1,026.6 | 1,584.7 | |||||||||
| Long-term debt | 1,986.3 | 1,965.0 | 1,454.5 | |||||||||
| Deferred income taxes | 505.9 | 491.5 | 483.5 | |||||||||
| Deferred investment tax credits | 6.7 | 6.8 | 7.1 | |||||||||
| Other noncurrent liabilities | 360.1 | 351.5 | 317.3 | |||||||||
| Total liabilities | 4,066.8 | 3,841.4 | 3,847.1 | |||||||||
| Commitments and contingencies (note 9) | ||||||||||||
| Minority interests | 152.3 | 139.5 | 198.0 | |||||||||
| Common stockholders’ equity: | ||||||||||||
| Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,152,994 shares) | 810.8 | 807.5 | 795.0 | |||||||||
| Retained earnings | 413.1 | 370.0 | 306.8 | |||||||||
| Accumulated other comprehensive income (loss) | 5.0 | (3.8 | ) | (10.8 | ) | |||||||
| 1,228.9 | 1,173.7 | 1,091.0 | ||||||||||
| Treasury stock, at cost | (70.9 | ) | (74.1 | ) | (78.2 | ) | ||||||
| Total common stockholders’ equity | 1,158.0 | 1,099.6 | 1,012.8 | |||||||||
| Total liabilities and stockholders’ equity | $ | 5,377.1 | $ | 5,080.5 | $ | 5,057.9 | ||||||
See accompanying notes to condensed consolidated financial statements.
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)
(unaudited)
(Millions of dollars, except per share amounts)
| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| Revenues | $ | 1,463.2 | $ | 1,577.9 | ||||
| Costs and expenses: | ||||||||
| Cost of sales | 994.4 | 1,150.7 | ||||||
| Operating and administrative expenses | 261.2 | 235.4 | ||||||
| Utility taxes other than income taxes | 4.6 | 3.3 | ||||||
| Depreciation and amortization | 41.7 | 36.3 | ||||||
| Other income, net | (6.0 | ) | (8.0 | ) | ||||
| 1,295.9 | 1,417.7 | |||||||
| Operating income | 167.3 | 160.2 | ||||||
| Loss from equity investees | — | (0.6 | ) | |||||
| Interest expense | (36.0 | ) | (32.6 | ) | ||||
| Income before income taxes and minority interests | 131.3 | 127.0 | ||||||
| Income taxes | (38.1 | ) | (38.5 | ) | ||||
| Minority interests, principally in AmeriGas Partners | (31.3 | ) | (31.0 | ) | ||||
| Net income | $ | 61.9 | $ | 57.5 | ||||
| Earnings per common share: | ||||||||
| Basic | $ | 0.58 | $ | 0.55 | ||||
| Diluted | $ | 0.58 | $ | 0.54 | ||||
| Average common shares outstanding (millions): | ||||||||
| Basic | 105.930 | 105.157 | ||||||
| Diluted | 107.573 | 106.623 | ||||||
| Dividends declared per common share | $ | 0.1763 | $ | 0.1688 | ||||
See accompanying notes to condensed consolidated financial statements.
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
(unaudited)
(Millions of dollars)
| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
| Net income | $ | 61.9 | $ | 57.5 | ||||
| Reconcile to net cash provided by operating activities: | ||||||||
| Depreciation and amortization | 41.7 | 36.3 | ||||||
| Minority interests | 31.3 | 31.0 | ||||||
| Deferred income taxes, net | 1.7 | 10.8 | ||||||
| Other, net | 16.2 | (6.5 | ) | |||||
| Net change in: | ||||||||
| Accounts receivable and accrued utility revenues | (301.2 | ) | (312.2 | ) | ||||
| Inventories | 1.1 | (22.7 | ) | |||||
| Deferred fuel costs | (0.3 | ) | (26.8 | ) | ||||
| Accounts payable | 147.1 | 222.0 | ||||||
| Other current assets and liabilities | 0.4 | (7.0 | ) | |||||
| Net cash used by operating activities | (0.1 | ) | (17.6 | ) | ||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
| Expenditures for property, plant and equipment | (53.8 | ) | (42.0 | ) | ||||
| Net proceeds from disposals of assets | 1.8 | 2.2 | ||||||
| Acquisitions of businesses, net of cash acquired | (0.1 | ) | (0.6 | ) | ||||
| Increase in restricted cash | (10.9 | ) | (251.2 | ) | ||||
| Other, net | (3.6 | ) | (5.0 | ) | ||||
| Net cash used by investing activities | (66.6 | ) | (296.6 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
| Dividends on UGI Common Stock | (18.7 | ) | (17.7 | ) | ||||
| Distributions on AmeriGas Partners publicly held Common Units | (18.7 | ) | (18.1 | ) | ||||
| Issuances of debt | 0.1 | 503.1 | ||||||
| Repayments of debt | (1.1 | ) | (259.8 | ) | ||||
| Increase in UGI Utilities bank loans with maturities of three months or less | 34.0 | 64.3 | ||||||
| Other bank loans increase (decrease) | (0.4 | ) | 0.6 | |||||
| Excess tax benefits from equity-based payment arrangements | 1.5 | 0.1 | ||||||
| Issuances of UGI Common Stock | 5.8 | 1.5 | ||||||
| Net cash provided by financing activities | 2.5 | 274.0 | ||||||
| EFFECT OF EXCHANGE RATE CHANGES ON CASH | 2.4 | (2.0 | ) | |||||
| Cash and cash equivalents decrease | $ | (61.8 | ) | $ | (42.2 | ) | ||
| Cash and cash equivalents: | ||||||||
| End of period | $ | 124.4 | $ | 267.9 | ||||
| Beginning of period | 186.2 | 310.1 | ||||||
| Decrease | $ | (61.8 | ) | $ | (42.2 | ) | ||
See accompanying notes to condensed consolidated financial statements.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
| 1. | Basis of Presentation | |
| UGI Corporation (“UGI”) is a holding company that owns and operates natural gas and electric distribution utilities, electricity generation, retail propane distribution, energy marketing and related businesses in the United States. Through foreign subsidiaries and joint-venture affiliates, UGI also distributes liquefied petroleum gases (“LPG”) in France, central and eastern Europe and China. | ||
| We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (“Eagle OLP”). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as “the Operating Partnerships”) comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2006, the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”) collectively held a 1% general partner interest and 42.7% limited partner interest in AmeriGas Partners, and an effective 44.3% ownership interest in AmeriGas OLP and Eagle OLP. Our limited partnership interest in AmeriGas Partners comprises 24,525,004 Common Units. The remaining 56.3% interest in AmeriGas Partners comprises 32,280,601 publicly held Common Units representing limited partner interests. | ||
| Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”) (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts LPG distribution businesses and participates in an LPG joint-venture business in central and eastern Europe (collectively, “Flaga”); and (3) participates in a propane joint-venture business in China. Enterprises’ indirect subsidiary, UGI International Holdings, B.V., holds our interests in Antargaz and Flaga. We refer to our foreign operations collectively as “International Propane.” In addition, Enterprises conducts an energy marketing business primarily in the eastern United States through its wholly owned first- and second-tier subsidiaries (collectively “Energy Services”). Energy Services’ wholly owned subsidiary UGI Development Company (“UGID”), and UGID’s subsidiaries own and operate a 48-megawatt coal-fired electric generation station and a 6% interest in Pennsylvania-based electricity generation assets. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”), owns a propane storage terminal located in Chesapeake, Virginia. Through other subsidiaries, Enterprises owns and operates a heating, ventilation, air-conditioning, refrigeration and electrical contracting services business in the Middle Atlantic states (“HVAC/R”). | ||
| Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). UGI Utilities, Inc. owns and operates (1) a natural gas distribution utility in eastern Pennsylvania (“UGI Gas”), (2) a natural gas distribution utility in northeastern Pennsylvania (“PNG Gas”) which |
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
was acquired effective August 24, 2006 (the “PG Energy Acquisition”), and (3) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Gas, PNG Gas (collectively, “Gas Utility”) and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”). The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc. or UGI Utilities, Inc. and UGIPNG.
Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies, which, except for the Partnership, are majority owned, and are 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 and the outside ownership interest in a subsidiary of Antargaz as minority interests. Entities in which we own 50 percent or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method.
The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2006 condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America. These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2006 (“Company’s 2006 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.
Restricted Cash.Restricted cash representing cash deposited in our natural gas futures accounts to satisfy margin requirements totaled $25.1, $14.2 and $16.7 at December 31, 2006, September 30, 2006 and December 31, 2005, respectively. At December 31, 2005, we also had $237.7 of restricted cash from the proceeds of Antargaz’ new Senior Facilities Agreement which were used to fund the redemption of its High Yield Bonds in January 2006.
Earnings Per Common Share.Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Shares used in computing basic and diluted earnings per share are as follows:
| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| Denominator (millions of shares): | ||||||||
| Average common shares outstanding for basic computation | 105.930 | 105.157 | ||||||
| Incremental shares issuable for stock options and awards | 1.643 | 1.466 | ||||||
| Average common shares outstanding for diluted computation | 107.573 | 106.623 | ||||||
Comprehensive Income.The following table presents the components of comprehensive income for the three months ended December 31, 2006 and 2005.
| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| Net income | $ | 61.9 | $ | 57.5 | ||||
| Other comprehensive income (loss) | 8.8 | (27.3 | ) | |||||
| Comprehensive income | $ | 70.7 | $ | 30.2 | ||||
Other comprehensive income (loss) principally comprises (1) changes in the fair value of derivative commodity instruments, interest rate protection agreements and foreign currency derivatives qualifying as hedges and (2) foreign currency translation adjustments, net of reclassifications to net income.
Income Taxes.Income tax expense is provided on an interim basis using management’s estimate of the annual effective rate. The effective income tax rate was 38.1% and 40.1% for the three months ended December 31, 2006 and 2005, respectively. The difference in our effective tax rates principally reflects the beneficial effects of changes in management’s estimate of taxes to be paid associated with planned repatriation of foreign earnings.
Reclassifications.We have reclassified certain prior-year period balances to conform to the current-period presentation.
Use of Estimates.We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
Recently Issued Accounting Pronouncements.In March 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 156, “Accounting for Servicing of Financial Assets — An Amendment of FASB Statement No. 140” (“SFAS 156”). SFAS 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, unless it is impracticable to do so. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. We adopted SFAS 156 effective October 1, 2006 which did not have a material impact on our Condensed Consolidated Financial Statements.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
| 2. | PG Energy Acquisition | |
| On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division, a natural gas distribution business located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly-owned subsidiary, PG Energy Services, Inc., pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated January 26, 2006 (the “Agreement”). On August 24, 2006 and in accordance with the terms of the Agreement, UGI Utilities paid SU $580 in cash. The preliminary purchase price allocation is subject to adjustment because we are still in the process of reviewing and determining the fair value of certain of PNG Gas’ assets acquired and liabilities assumed, principally working capital adjustments and amounts associated with environmental liabilities. Pursuant to the terms of the Agreement, the purchase price is subject to a working capital adjustment equal to the difference between $68.1 and the actual working capital as of the closing date agreed to by both UGI Utilities and SU. | ||
| 3. | Utility Regulatory Matters | |
| In an order entered on November 30, 2006, the PUC approved a settlement of the base rate proceeding of PG Energy (PNG Gas). The settlement provides for an increase in natural gas distribution base rates of $12.5 annually or approximately 4%, effective December 2, 2006. | ||
| In accordance with Provider of Last Resort (“POLR”) settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. In accordance with these settlements, Electric Utility increased its POLR rates by 4.5% on January 1, 2005 and 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility also increased its POLR rates for all metered customers effective January 1, 2007 which is expected to increase the average cost to residential customers by approximately 35% over such costs in effect during calendar year 2006. | ||
| 4. | Segment Information | |
| We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) or regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga and our international LPG equity investment in China (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. We refer to both international segments collectively as “International Propane.” | ||
| The accounting policies of the six segments disclosed are the same as those described in Note 1, Organization and Significant Accounting Policies, in the Company’s 2006 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. The Company’s definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Energy Services segments principally based upon their income before income taxes. |
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements (continued)
(unaudited)
(Millions of dollars, except per share amounts)
(unaudited)
(Millions of dollars, except per share amounts)
4.Segment Information (continued)
Three Months Ended December 31, 2006:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
| Revenues | $ | 1,463.2 | $ | (42.6 | ) | $ | 616.6 | $ | 274.4 | $ | 24.9 | $ | 344.2 | $ | 215.3 | $ | 11.1 | $ | 19.3 | |||||||||||||||||
| Cost of sales | $ | 994.4 | $ | (41.6 | ) | $ | 388.7 | $ | 193.8 | $ | 12.2 | $ | 318.7 | $ | 105.0 | $ | 5.9 | $ | 11.7 | |||||||||||||||||
| Segment profit: | ||||||||||||||||||||||||||||||||||||
| Operating income | $ | 167.3 | $ | (0.4 | ) | $ | 75.3 | $ | 38.2 | $ | 6.2 | $ | 15.2 | $ | 33.0 | $ | 0.1 | $ | (0.3 | ) | ||||||||||||||||
| Loss from equity investees | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
| Interest expense | (36.0 | ) | — | (18.0 | ) | (10.8 | ) | (0.7 | ) | — | (5.6 | ) | (0.5 | ) | (0.4 | ) | ||||||||||||||||||||
| Minority interests | (31.3 | ) | — | (31.3 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
| Income before income taxes | $ | 100.0 | $ | (0.4 | ) | $ | 26.0 | $ | 27.4 | $ | 5.5 | $ | 15.2 | $ | 27.4 | $ | (0.4 | ) | $ | (0.7 | ) | |||||||||||||||
| Depreciation and amortization | $ | 41.7 | $ | (0.1 | ) | $ | 18.6 | $ | 9.3 | $ | 0.9 | $ | 1.8 | $ | 10.1 | $ | 0.8 | $ | 0.3 | |||||||||||||||||
| Partnership EBITDA (c) | $ | 93.1 | ||||||||||||||||||||||||||||||||||
| Segment assets (at period end) | $ | 5,377.1 | $ | (345.8 | ) | $ | 1,657.0 | $ | 1,603.2 | $ | 106.5 | $ | 300.9 | $ | 1,498.4 | $ | 192.5 | $ | 364.4 | |||||||||||||||||
| Investments in equity investees (at period end) | $ | 60.5 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 60.5 | $ | — | ||||||||||||||||||
| Goodwill (at period end) | $ | 1,443.1 | $ | (4.0 | ) | $ | 619.1 | $ | 182.9 | $ | — | $ | 11.8 | $ | 583.6 | $ | 42.9 | $ | 6.8 | |||||||||||||||||
Three Months Ended December 31, 2005:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
| Revenues | $ | 1,577.9 | $ | (34.1 | ) | $ | 630.2 | $ | 219.8 | $ | 23.9 | $ | 451.4 | $ | 248.8 | $ | 18.8 | $ | 19.1 | |||||||||||||||||
| Cost of sales | $ | 1,150.7 | $ | (33.1 | ) | $ | 407.8 | $ | 159.9 | $ | 11.3 | $ | 433.7 | $ | 146.4 | $ | 12.7 | $ | 12.0 | |||||||||||||||||
| Segment profit: | ||||||||||||||||||||||||||||||||||||
| Operating income | $ | 160.2 | $ | — | $ | 74.7 | $ | 35.7 | $ | 6.5 | $ | 8.2 | $ | 33.2 | $ | 0.4 | $ | 1.5 | ||||||||||||||||||
| Loss from equity investees | (0.6 | ) | — | — | — | — | — | (0.6 | ) | — | — | |||||||||||||||||||||||||
| Interest expense | (32.6 | ) | — | (18.9 | ) | (5.1 | ) | (0.5 | ) | — | (7.6 | ) | (0.5 | ) | — | |||||||||||||||||||||
| Minority interests | (31.0 | ) | (0.1 | ) | (31.0 | ) | — | — | — | 0.1 | — | — | ||||||||||||||||||||||||
| Income before income taxes | $ | 96.0 | $ | (0.1 | ) | $ | 24.8 | $ | 30.6 | $ | 6.0 | $ | 8.2 | $ | 25.1 | $ | (0.1 | ) | $ | 1.5 | ||||||||||||||||
| Depreciation and amortization | $ | 36.3 | $ | — | $ | 18.3 | $ | 5.4 | $ | 0.8 | $ | 1.5 | $ | 9.0 | $ | 1.2 | $ | 0.1 | ||||||||||||||||||
| Partnership EBITDA (c) | $ | 92.2 | ||||||||||||||||||||||||||||||||||
| Segment assets (at period end) | $ | 5,057.9 | $ | (335.9 | ) | $ | 1,720.0 | $ | 896.8 | $ | 104.2 | $ | 307.8 | $ | 1,713.5 | $ | 154.1 | $ | 497.4 | |||||||||||||||||
| Investments in equity investees (at period end) | $ | 12.3 | $ | — | $ | — | $ | — | $ | — | $ | 8.6 | $ | 1.0 | $ | 2.7 | $ | — | ||||||||||||||||||
| Goodwill (at period end) | $ | 1,222.1 | $ | (4.0 | ) | $ | 618.2 | $ | — | $ | — | $ | 11.8 | $ | 523.4 | $ | 66.3 | $ | 6.4 | |||||||||||||||||
(a) International Propane-Other principally comprises Flaga, including its joint-venture business, ZLH, and our joint-venture business in China.
(b) Corporate & Other’s results principally comprise UGI Enterprises’ HVAC/R operations, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses, and interest income. Corporate & Other assets principally comprise cash, short-term investments and an intercompany loan. The intercompany interest associated with the intercompany loan is removed in the segment presentation.
(c) The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
| Three months ended December 31, | 2006 | 2005 | ||||||
| Partnership EBITDA | $ | 93.1 | $ | 92.2 | ||||
| Depreciation and amortization (i) | (18.6 | ) | (18.2 | ) | ||||
| Minority interests (ii) | 0.8 | 0.7 | ||||||
| Operating income | $ | 75.3 | $ | 74.7 | ||||
(i) Excludes General Partner depreciation and amortization of $0.1 in the three months ended December 31, 2005.
(ii) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
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Notes to Condensed Consolidated Financial Statements (continued)
(unaudited)
(Millions of dollars, except per share amounts)
(unaudited)
(Millions of dollars, except per share amounts)
5.Intangible Assets
The Company’s intangible assets comprise the following:
| December 31, | September 30, | |||||||
| 2006 | 2006 | |||||||
| Goodwill (not subject to amortization) | $ | 1,443.1 | $ | 1,418.2 | ||||
| Other intangible assets: | ||||||||
| Customer relationships, noncompete agreements and other | $ | 187.4 | $ | 183.0 | ||||
| Trademark (not subject to amortization) | 44.9 | 43.1 | ||||||
| Gross carrying amount | 232.3 | 226.1 | ||||||
| Accumulated amortization | (67.7 | ) | (62.8 | ) | ||||
| Net carrying amount | $ | 164.6 | $ | 163.3 | ||||
Changes in intangible assets during the three months ended December 31, 2006 principally reflect the effects of foreign currency translation. Amortization expense of intangible assets was $4.1 and $4.0 for the three months ended December 31, 2006 and 2005, respectively. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2007 — $15.7; Fiscal 2008 — $15.4; Fiscal 2009 - $14.7; Fiscal 2010 — $13.3; Fiscal 2011 — $12.7.
| 6. | UGI Utilities’ Revolving Credit Agreement | |
| During the three months ended December 31, 2006, the termination date of UGI Utilities’ $350 Revolving Credit Agreement was automatically extended by UGI Utilities to August 2011. | ||
| 7. | Energy Services Accounts Receivable Securitization Facility | |
| Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009. The maximum level of funding available at any one time from this facility is $200. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. Effective October 1, 2006, we adopted SFAS 156, see Note 1. |
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
| During the three months ended December 31, 2006 and 2005, Energy Services sold trade receivables totaling $299.7 and $393.9, respectively, to ESFC. During the three months ended December 31, 2006 and 2005, ESFC sold an aggregate $150.0 and $242.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2006, the outstanding balance of ESFC trade receivables was $84.7 which is net of $49.5 that was sold to the commercial paper conduit and removed from the balance sheet. At December 31, 2005, the outstanding balance of ESFC trade receivables was $64.5 which is net of $95.0 that was sold to the commercial paper conduit and removed from the balance sheet. | ||
| In addition, a major bank has committed to issue up to $50 of standby letters of credit, secured by cash or marketable securities (“LC Facility”) to Energy Services. At December 31, 2006, there were no letters of credit outstanding. Energy Services expects to fund the collateral requirements with borrowings under its Receivables Facility. The LC Facility, which we intend to renew, expires in April 2007. | ||
| 8. | Defined Benefit Pension and Other Postretirement Plans | |
| We sponsor two defined benefit pension plans (“Pension Plan”) for employees of UGI, UGI Utilities, including employees of UGIPNG, and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by a defined benefit pension plan and a postretirement medical plan. |
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Net periodic pension expense and other postretirement benefit costs include the following components:
| Other | ||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||
| Three Months Ended | Three Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Service cost | $ | 1.6 | $ | 1.5 | $ | 0.1 | $ | 0.1 | ||||||||
| Interest cost | 4.7 | 3.5 | 0.3 | 0.3 | ||||||||||||
| Expected return on assets | (5.9 | ) | (4.7 | ) | (0.2 | ) | (0.2 | ) | ||||||||
| Amortization of: | ||||||||||||||||
| Transition obligation | — | — | 0.1 | 0.1 | ||||||||||||
| Prior service cost (benefit) | 0.1 | 0.2 | (0.1 | ) | (0.1 | ) | ||||||||||
| Actuarial loss | 0.3 | 0.4 | 0.1 | 0.1 | ||||||||||||
| Net benefit cost | 0.8 | 0.9 | 0.3 | 0.3 | ||||||||||||
| Change in regulatory and other assets and liabilities | (0.1 | ) | — | 0.7 | 0.7 | |||||||||||
| Net expense | $ | 0.7 | $ | 0.9 | $ | 1.0 | $ | 1.0 | ||||||||
| Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds. The Company does not believe it will be required to make any contributions to the Pension Plan during the year ending September 30, 2007 for ERISA funding purposes. Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund and pay UGI Utilities’ postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” The difference between the annual amount calculated and the amount included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2006, nor are they expected to be material for the year ending September 30, 2007. | ||
| We also sponsor unfunded and non-qualified supplemental executive retirement income plans. We recorded pre-tax expense for these plans of $0.6 and $0.5 for the three months ended December 31, 2006 and 2005, respectively. | ||
| 9. | Commitments and Contingencies | |
| On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group (the “2001 Acquisition”) pursuant to the terms of a purchase agreement (the “2001 Acquisition Agreement”) by and among Columbia Energy Group (“CEG”), Columbia Propane Corporation (“Columbia Propane”), Columbia Propane, L.P. (“CPLP”), CP Holdings, Inc. (“CPH,” and together with Columbia Propane and CPLP, the “Company Parties”), AmeriGas Partners, AmeriGas OLP and the General Partner (together with AmeriGas Partners and AmeriGas OLP, the “Buyer Parties”). As a result of the 2001 Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane and CPH and substantially all of the partnership interests of CPLP. Under the terms of an earlier acquisition agreement (the “1999 Acquisition Agreement”), the Company Parties agreed to indemnify the former general partners of National Propane Partners, L.P. (a predecessor company of the |
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Columbia Propane businesses) and an affiliate (collectively, “National General Partners”) against certain income tax and other losses that they may sustain as a result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999 Acquisition”) or the operation of the business after the 1999 Acquisition (“National Claims”). At December 31, 2006, the potential amount payable under this indemnity by the Company Parties was approximately $58. These indemnity obligations will expire on the date that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG agreed to indemnify the Buyer Parties and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including National Claims, to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and the Buyer Parties have agreed to apportion certain losses resulting from National Claims to the extent such losses result from the 2001 Acquisition itself.
Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, allegedly resulting from the defendants’ failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane in August 2001 as additional potential class members and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG, former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees. We believe we have good defenses to the claims of the class members and intend to defend against the remaining claims in this lawsuit.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. In accordance with existing regulatory practices of the PUC, PNG Gas currently amortizes as removal cost over a five-year period site-specific environmental investigation and remediation costs.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary, UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at eleven currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, UGIPNG is not required to spend more than $1.1 in any calendar year for such environmental expenditures, including costs to perform work on the Properties. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of fifteen years but may be terminated by either party at the end of any two-year period beginning with the effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating four claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and $26 in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 to clean up the river. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while the City and Citizens discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
By letter dated March 30, 1992, Atlanta Gas Light Company (“AGL”) informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the “Northeast Companies”) in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
The French tax authorities levy taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of certain of the entity’s tangible fixed assets. Changes in the French government’s interpretation of the tax laws or in the tax laws themselves could either adversely or favorably affect our results of operations.
In addition to these matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any such excess losses. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
Information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity and natural gas and the capacity to transport product to our market areas; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) competitive pressures from the same and alternative energy sources; (5) failure to acquire new customers thereby reducing or limiting any increase in revenues; (6) liability for environmental claims; (7) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (8) adverse labor relations; (9) large customer, counterparty or supplier defaults; (10) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, propane and other LPG; (11) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency rate fluctuations, particularly in the euro; (12) reduced access to capital markets and interest rate fluctuations; (13) reduced distributions from subsidiaries; and (14) the timing and success of the Company’s efforts to develop new business opportunities.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
ANALYSIS OF RESULTS OF OPERATIONS
The following analysis compares our results of operations for the three months ended December 31, 2006 (“2006 three-month period”) with the three months ended December 31, 2005 (“2005 three-month period”). Our analysis of results of operations should be read in conjunction with the segment information included in Note 4 to the Condensed Consolidated Financial Statements.
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Executive Overview
Because most of our businesses sell energy products used in large part for heating purposes, our Company’s results are largely seasonal and dependent upon weather conditions, particularly during the peak-heating season months of November through March. As a result, our net income is generally highest in our first and second fiscal quarters. In addition to the effects of weather conditions, our volumes can reflect customers’ responses to volatile and increasing commodity prices resulting in customer conservation. Our 2006 three-month period results include the operations of PNG Gas, the natural gas utility business that we acquired in late August 2006 (the “PG Energy Acquisition”).
During the 2006 three-month period, temperatures within each of our business units’ service territories were significantly warmer than normal and were much warmer than in the prior-year three-month period. Despite the challenges of much warmer heating season weather, net income during the 2006 three-month period increased 7.7% compared to the prior year. The increase in earnings primarily reflects higher income contributed by our energy marketing business, the beneficial effects of a stronger euro versus the dollar on International Propane’s results and incremental income resulting from the PG Energy Acquisition. These increases were partially offset by decreased earnings from UGI Gas. Energy Services’ improved results reflect, in large part, increased income due to higher natural gas margins and higher income from peaking supply and storage management services. UGI Gas’ decline in earnings principally reflects the effects of warmer weather and higher operating and administrative expenses. The effective tax rate during the 2006 three-month period was approximately 2% lower than in the 2005 three-month period principally reflecting the beneficial effects of changes in management’s estimate of taxes to be paid associated with planned repatriation of foreign earnings.
Net income by business unit:
| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| (millions of dollars) | ||||||||
| Net income (loss): | ||||||||
| AmeriGas Propane (a) | $ | 15.4 | $ | 14.9 | ||||
| International Propane | 18.3 | 14.9 | ||||||
| Gas Utility | 16.5 | 18.4 | ||||||
| Electric Utility | 3.2 | 3.5 | ||||||
| Energy Services | 9.0 | 4.9 | ||||||
| Corporate & Other | (0.5 | ) | 0.9 | |||||
| Total net income | $ | 61.9 | $ | 57.5 | ||||
| (a) | Amounts are net of minority interests in AmeriGas Partners, L.P. |
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2006 three-month period compared to the 2005 three-month period
| AmeriGas Propane: | Increase | |||||||||||||||
| For the three months ended December 31, | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 616.6 | $ | 630.2 | $ | (13.6 | ) | (2.2 | )% | |||||||
| Total margin (a) | $ | 227.9 | $ | 222.4 | $ | 5.5 | 2.5 | % | ||||||||
| Partnership EBITDA (b) | $ | 93.1 | $ | 92.2 | $ | 0.9 | 1.0 | % | ||||||||
| Operating income | $ | 75.3 | $ | 74.7 | $ | 0.6 | 0.8 | % | ||||||||
| Retail gallons sold (millions) | 282.9 | 291.9 | (9.0 | ) | (3.1 | )% | ||||||||||
| Degree days – % warmer than normal (c) | 8.6 | % | 4.1 | % | — | — | ||||||||||
(a) Total margin represents total revenues less total cost of sales.
(b) Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 4 to the Condensed Consolidated Financial Statements).
(c) Deviation from average heating degree-days based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska.
Based upon heating degree-day data, temperatures were 8.6% warmer than normal and 4.6% warmer than the prior-year period. Retail propane volumes sold decreased approximately 3% principally due to the warmer weather.
Retail propane revenues decreased $11.7 million reflecting a $16.7 million decrease due to the lower retail volumes sold partially offset by a $5.0 million increase due to higher average selling prices. Wholesale propane revenues decreased $6.7 million reflecting a $4.3 million decrease due to lower wholesale volumes sold and a $2.4 million decrease resulting from lower average selling prices. Total cost of sales decreased to $388.7 million in the 2006 three-month period from $407.8 million in the 2005 three-month period, primarily reflecting the decreased volumes sold and a decrease in propane product costs. Total margin increased $5.5 million compared to the 2005 three-month period principally due to higher average propane margins per gallon and higher fees in response to increases in operating and administrative expenses.
Partnership EBITDA during the 2006 three-month period was $93.1 million compared to $92.2 million during the 2005 three-month period. The $0.9 million increase in Partnership EBITDA mainly reflects the increase in total margin partially offset by a $5.0 million increase in operating and administrative expenses. Operating and administrative expenses increased principally due to higher employee compensation and benefits and higher repair and maintenance expenses.
Operating income increased $0.6 million reflecting the previously mentioned increase in Partnership EBITDA partially offset by an increase in depreciation expense.
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| International Propane: | Increase | |||||||||||||||
| For the three months ended December 31, | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of euros) | ||||||||||||||||
| Revenues | € | 174.0 | € | 225.1 | € | (51.1 | ) | (22.7 | )% | |||||||
| Total margin (a) | € | 88.8 | € | 91.3 | € | (2.5 | ) | (2.7 | )% | |||||||
| Operating income | € | 25.9 | € | 28.3 | € | (2.4 | ) | (8.5 | )% | |||||||
| Income before income taxes | € | 21.4 | € | 21.3 | € | 0.1 | 0.5 | % | ||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 226.4 | $ | 267.6 | $ | (41.2 | ) | (15.4 | )% | |||||||
| Total margin (a) | $ | 115.5 | $ | 108.5 | $ | 7.0 | 6.5 | % | ||||||||
| Operating income | $ | 33.1 | $ | 33.6 | $ | (0.5 | ) | (1.5 | )% | |||||||
| Income before income taxes | $ | 27.0 | $ | 24.9 | $ | 2.1 | 8.4 | % | ||||||||
| Antargaz retail gallons sold | 80.2 | 92.7 | (12.5 | ) | (13.5 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 21.7% warmer than normal in the 2006 three-month period compared to temperatures that were approximately normal in the 2005 three-month period. Flaga experienced similar weather across its service territories. The monthly average currency translation rate was $1.30 per euro during the 2006 three-month period versus $1.19 per euro during the 2005 three-month period. Antargaz’ retail LPG volumes sold decreased to 80.2 million gallons in the 2006 three-month period from 92.7 million gallons in the 2005 three-month period. The decrease in Antargaz’ retail volumes sold was experienced across all of Antargaz’ classes of customers and was due in large part to the significantly warmer than normal weather and, to a much lesser extent, customer conservation. Flaga’s volumes declined reflecting the absence of volumes from its Czech Republic and Slovakia businesses that it contributed to Zentraleuropa LPH Holding GmbH (“ZLH”) and the effects of the significantly warmer weather. The ZLH joint venture was formed in February 2006 and Flaga’s 50% ownership interest in ZLH is accounted for under the equity method.
International Propane euro-based revenues decreased during the 2006 three-month period primarily reflecting (1) a decline of approximately€20 million principally due to Antargaz’ lower retail volumes sold, (2) approximately€22 million in lower revenues from Antargaz’ low-margin wholesale sales and (3) the absence of revenues from Flaga’s Czech Republic and Slovakia businesses that were contributed to ZLH. International Propane’s total cost of sales decreased to approximately€85 million in the 2006 three-month period from€134 million in the 2005 three-month period largely reflecting the effects of the decrease in low-margin wholesale sales, lower retail volumes sold and lower LPG product costs, including the absence of costs of sales from Flaga’s operations that had been contributed ZLH. Antargaz’ LPG purchases are principally denominated in U.S. dollars.
Total margin decreased€2.5 million in the 2006 three-month period reflecting higher average margins per retail gallon of LPG sold partially offset by the lower retail volumes sold. In U.S. dollars, total margin increased $7 million reflecting the decrease in base-currency total margin which was more than offset by the beneficial effects of the stronger euro versus the dollar. The€2.4 million decline in International Propane operating income largely reflects the lower total margin.
The increase in income before income taxes principally reflects an approximate€2 million decline in interest expense largely attributable to Antargaz’ refinancing of its High Yield Bonds in January 2006 and lower equity investee losses partially offset by the decline in operating income.
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| Gas Utility: | Increase | |||||||||||||||
| For the three months ended December 31, | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 274.4 | $ | 219.8 | $ | 54.6 | 24.8 | % | ||||||||
| Total margin (a) | $ | 80.6 | $ | 59.9 | $ | 20.7 | 34.6 | % | ||||||||
| Operating income | $ | 38.2 | $ | 35.7 | $ | 2.5 | 7.0 | % | ||||||||
| Income before income taxes | $ | 27.4 | $ | 30.6 | $ | (3.2 | ) | (10.5 | )% | |||||||
| System throughput - billions of cubic feet (“bcf”) | 33.4 | 22.9 | 10.5 | 45.9 | % | |||||||||||
| Degree days – % warmer than normal (b) | 15.0 | % | 1.3 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for five airports (four airports prior to the PG Energy Acquisition) located within our service territory. |
Weather in Gas Utility’s service territory based upon heating degree days was 15.0% warmer than normal during the 2006 three-month period compared to 1.3% warmer than normal in the prior-year three-month period. Total distribution system throughput increased 10.5 bcf reflecting 12.2 bcf from PNG Gas partially offset by an approximate 1.7 bcf decrease in UGI Gas total distribution system throughput. Notwithstanding year-over-year growth in the number of UGI Gas’ customers, total distribution system throughput decreased in the 2006 three-month period largely reflecting a 1.8 bcf decrease in sales to firm- residential, commercial and industrial (“retail core-market”) customers. The decrease in retail core-market throughput largely reflects the effects of significantly warmer weather.
Gas Utility revenues increased $54.6 million during the 2006 three-month period principally reflecting revenues attributable to PNG Gas and a $9.7 million increase in revenues from low-margin off-system sales partially offset by lower revenues from UGI Gas retail core-market customers. Increases or decreases in retail core-market customer revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under this recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amount included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $193.8 million in the 2006 three-month period compared to $159.9 million in the 2005 three-month period largely reflecting the effects of the PG Energy Acquisition and greater costs associated with the higher off-system sales partially offset by the impact of lower UGI Gas retail core-market volumes sold.
Gas Utility total margin in the 2006 three-month period increased $20.7 million primarily reflecting the effects of the PG Energy Acquisition offset by a $4.1 million decrease in UGI Gas margin.
Gas Utility operating income increased to $38.2 million in the 2006 three-month period from $35.7 million in the 2005 three-month period principally reflecting the $20.7 million increase in total margin, $13.9 million higher operating and administrative expenses, and $3.9 million higher depreciation and amortization expense. The increase in total operating and administrative expenses principally reflects $10.1 million of operating and administrative expenses attributable to PNG Gas and higher long-term equity-based incentive compensation, distribution system and self-insured property and casualty expenses.
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The decrease in Gas Utility income before income taxes, notwithstanding the higher operating income, reflects an increase in interest expense. The increase in interest expense is principally due to higher long- and short-term debt outstanding, primarily as a result of the PG Energy Acquisition, and higher short-term interest rates.
| Electric Utility: | Increase | |||||||||||||||
| For the three months ended December 31, | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 24.9 | $ | 23.9 | $ | 1.0 | 4.2 | % | ||||||||
| Total margin (a) | $ | 11.4 | $ | 11.3 | $ | 0.1 | 0.9 | % | ||||||||
| Operating income | $ | 6.2 | $ | 6.5 | $ | (0.3 | ) | (4.6 | )% | |||||||
| Income before income taxes | $ | 5.5 | $ | 6.0 | $ | (0.5 | ) | (8.3 | )% | |||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 249.0 | 258.0 | (9.0 | ) | (3.5 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.3 million in each of the three-month periods ended December 31, 2006 and 2005. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Condensed Consolidated Statements of Income. |
Electric Utility’s 2006 three-month period kilowatt-hour sales declined 3.5% compared to the 2005 three-month period, due primarily to warmer weather. Electric Utility revenues increased $1.0 million in the 2006 three-month period largely reflecting higher transmission revenues from wholesale transmission services and the effects of a 3% increase in its Provider of Last Resort (“POLR”) rates effective January 1, 2006 partially offset by the lower kilowatt-hour sales. Notwithstanding the effects of the warmer weather, Electric Utility’s cost of sales increased to $12.2 million in the 2006 three-month period from $11.3 million in the 2005 three-month period reflecting higher per unit purchased power costs.
Electric Utility total margin in the 2006 three-month period was comparable to the prior-year three-month period as the effect of the higher POLR rates was partially offset by the higher per unit purchased power costs.
Electric Utility operating income declined in the 2006 three-month period principally reflecting $0.4 million higher operating and administrative expenses. The decrease in income before income taxes principally reflects the lower operating income and higher interest expense on short-term debt.
| Energy Services: | Increase | |||||||||||||||
| For the three months ended December 31, | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 344.2 | $ | 451.4 | $ | (107.2 | ) | (23.7 | )% | |||||||
| Total margin (a) | $ | 25.5 | $ | 17.7 | $ | 7.8 | 44.1 | % | ||||||||
| Operating income | $ | 15.2 | $ | 8.2 | $ | 7.0 | 85.4 | % | ||||||||
| Income before income taxes | $ | 15.2 | $ | 8.2 | $ | 7.0 | 85.4 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Notwithstanding the effects of a 12% increase in natural gas volumes sold and a 22% increase in kilowatt hours sales, Energy Services revenues decreased to $344.2 million in the 2006 three-month period from $451.4 million in the 2005 three-month period principally reflecting a more than 30% decline in natural gas prices.
Total margin increased $7.8 million in the 2006 three-month period compared to the prior-year three-month period. The increase in total margin is primarily attributed to higher natural gas unit margins, greater margin resulting from increased peaking supply and storage management activities and, to a much lesser extent, the increase in natural gas volumes sold.
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The increase in Energy Services operating income and income before income taxes principally reflects the increase in total margin partially offset by a $0.8 million increase in operating and administrative expenses primarily reflecting increased costs associated with electric generation partially offset by a decrease in uncollectible accounts expense.
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
Our cash, cash equivalents and short-term investments totaled $153.7 million at December 31, 2006 compared with $201.0 million at September 30, 2006. Excluding cash, cash equivalents and short-term investments that reside at UGI’s operating subsidiaries at December 31 and September 30, 2006, we had $21.6 million and $16.6 million, respectively, of cash, cash equivalents and short-term investments.
The Company’s long-term debt outstanding at December 31, 2006 totaled $2,018.3 million (including current maturities of $32.0 million) compared to $1,996.9 million of long-term debt (including current maturities of $31.9 million) at September 30, 2006.
AmeriGas OLP’s Credit Agreement expires in October 2011 and consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the AmeriGas Partners Senior Notes indentures. At December 31, 2006, there were no borrowings outstanding under the Credit Agreement. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $58.0 million at December 31, 2006 and was approximately the same amount outstanding during the entire three-month period ended December 31, 2006. Issued and outstanding letters of credit under the Revolving Credit Facility totaled $58.9 million at December 31, 2005 and was approximately the same amount outstanding during the entire three-month period ended December 31, 2005. AmeriGas OLP’s short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. During the 2006 three-month period, the peak and average daily borrowings outstanding were $92.0 million and $4.0 million, respectively. There were no significant borrowings under the Credit Agreement during the 2005 three-month period. AmeriGas Partners has an effective unallocated debt and equity shelf registration statement with the U.S. Securities and Exchange Commission (“SEC”) under which it may issue Common Units or Senior Notes due 2016 in underwritten public offerings.
UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At December 31, 2006, UGI Utilities had $250 million in borrowings outstanding under its Revolving Credit Agreement. From time to time, UGI Utilities has entered into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. Short-term borrowings, including borrowings under its Revolving Credit Agreement, are classified as bank loans on the Condensed Consolidated Balance Sheets. During the three months ended December 31, 2006 and 2005, average daily bank loan borrowings were $225.2 million and $101.6 million, respectively, and peak bank loan borrowings totaled $259.0 million and $155.1 million, respectively. Peak borrowings typically occur
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during the peak heating season months of December and January. The increase in average and peak bank loan borrowings during the 2006 three-month period reflects, in large part, borrowings to fund increased working capital principally related to the working capital of PNG Gas. UGI Utilities also has an effective shelf registration statement with the SEC under which it may issue up to an additional $75 million of Medium-Term Notes or other debt securities. Medium-Term Notes of $20 million maturing in June 2007 are expected to be refinanced through the issuance of debt under this shelf registration.
Energy Services has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009. The maximum level of funding available at any one time from this facility is $200 million. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. During the three months ended December 31, 2006 and 2005, ESFC sold an aggregate $150.0 million and $242.5 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2006, the outstanding balance of ESFC receivables was $84.7 million which is net of $49.5 million that was sold to the commercial paper conduit. At December 31, 2005, the outstanding balance of ESFC receivables was $64.5 million which is net of $95.0 million that was sold to the commercial paper conduit.
In addition, a major bank has committed to issue up to $50 million of standby letters of credit, secured by cash or marketable securities (“LC Facility”) to Energy Services. At December 31, 2006, there were no letters of credit outstanding. Energy Services expects to fund the collateral requirements with borrowings under its Receivables Facility. The LC Facility, which we intend to renew, expires in April 2007.
Cash Flows
Operating Activities.Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and/or inventories, is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to satisfy their seasonal operating cash flow needs. Energy Services uses its Receivables Facility to satisfy its operating cash flow needs. Antargaz has historically been successful funding its operating cash flow needs without the use of its revolver.
Cash flow used by operating activities was $0.1 million in the 2006 three-month period compared to cash used of $17.6 million in the 2005 three-month period. Cash flow from operating activities before changes in operating working capital was $152.8 million in the 2006 three-month period compared with $129.1 million in the prior-year three-month period reflecting greater non-cash charges. Changes in operating working capital used $152.9 million in the 2006 three-month period and $146.7 million in the 2005 three-month period.
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Investing Activities.Investing activity cash flow is principally affected by capital expenditures and investments in property, plant and equipment, cash paid for acquisitions of businesses, changes in short-term investments and proceeds from sales of assets. Net cash used in investing activities was $66.6 million in the 2006 three-month period compared to $296.6 million in the prior-year period. The decrease in investing activities largely reflects the decrease in restricted cash. In the prior-year three-month period, Antargaz was required to use a portion of the proceeds from a refinancing to repay its High Yield Bonds in January 2006.
Financing Activities.Cash flow provided by financing activities was $2.5 million in the 2006 three-month period compared with $274.0 million of cash used in the prior-year three-month period. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt, net bank loan borrowings, dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units, and proceeds from issuances of AmeriGas Partners Common Units and UGI Common Stock.
We paid cash dividends on UGI Common Stock of $18.7 million and $17.7 million during the 2006 and 2005 three-month periods, respectively. During the 2006 three-month period, the Partnership declared and paid quarterly distributions on its limited partner units for the quarter ended September 30, 2006.
PG Energy Acquisition
On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division, a natural gas distribution business located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly-owned subsidiary, PG Energy Services, Inc., pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated January 26, 2006 (the “Agreement”). On August 24, 2006 and in accordance with the terms of the Agreement, UGI Utilities paid SU $580 million in cash. Pursuant to the terms of the Agreement, the purchase price is subject to a working capital adjustment equal to the difference between $68.1 million and the actual working capital as of the closing date agreed to by both UGI Utilities and SU.
Utility Regulatory Matters
In an order entered on November 30, 2006, the PUC approved a settlement of the base rate proceeding of PG Energy (PNG Gas). The settlement provides for an increase in natural gas distribution base rates of $12.5 million annually or approximately 4%, effective December 2, 2006.
In accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. In accordance with these settlements, Electric Utility increased its POLR rates by 4.5% on January 1, 2005 and 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility also increased its POLR rates for all metered customers effective January 1, 2007 which is expected to increase the average cost to residential customers by approximately 35% over such costs in effect during calendar year 2006.
Antargaz Tax Matter
The French tax authorities levy taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of certain of the entity’s tangible fixed assets. Changes in the French government’s interpretation of the tax laws or in the tax laws themselves could adversely or favorably affect our results of operations.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk exposures are (1) market prices for propane and other LPG, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates.
The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for propane and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and International Propane may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts and Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may also enter into other contracts, similar to those used by the Partnership. Flaga has and may use derivative commodity instruments to reduce market risk associated with a portion of its propane purchases. Currently, Flaga’s hedging activities are not material to the Company’s financial position or results of operations. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract. In order to minimize credit risk associated with its derivative commodity contracts, the Partnership monitors established credit limits with the contract counterparties. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations.
Electric Utility purchases power from wholesale electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. Currently, Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power and capacity contracts, should any of the counterparties fail to provide electric power or capacity under the terms of such contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. From time to time, Electric Utility enters into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements.
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In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas, Energy Services purchases exchange-traded and over-the-counter natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas futures contracts are guaranteed by the New York Mercantile Exchange (“NYMEX”) and have nominal credit risk. The change in market value of these contracts generally requires daily cash deposits in margin accounts with brokers. At December 31, 2006, Energy Services had $18.2 million of restricted cash on deposit in such margin accounts. Although Energy Services’ fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services’ results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers.
UGID has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, UGID would be required to purchase such electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact the Company’s results.
Asset Management has entered and may continue to enter into fixed-price sales agreements for a portion of its propane sales. In order to manage the market price risk relating to substantially all of its fixed-price sales contracts for propane, Asset Management enters into price swap and option contracts.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes borrowings under AmeriGas OLP’s Credit Agreement and borrowings under UGI Utilities’ Revolving Credit Agreement and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the interest rate on its variable-rate long-term debt through June 2011 through the use of interest rate swaps. Flaga has effectively fixed a substantial portion of its long-term debt through September 2011 through the use of interest rate swaps. At December 31, 2006, combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled approximately $263.5 million. Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near to medium term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements.
The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at December 31, 2006. Fair values reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts at December 31, 2006. The table also includes the changes in fair value that would result if there were a ten percent adverse change in (1) the market price of propane; (2) the market price of natural gas; (3) the market price of electricity; (4) interest rates on ten-year U.S. treasury notes and the three- and six-month Euribor and; (5) value of the euro versus the U.S. dollar. Gas Utility’s exchange-traded natural gas call option and futures contracts are excluded from the table below because any associated net gains are included in Gas Utility’s PGC recovery mechanism.
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| Change in | ||||||||
| Fair Value | Fair Value | |||||||
| (Millions of dollars) | ||||||||
| December 31, 2006: | ||||||||
| Propane commodity price risk | $ | (25.8 | ) | $ | (14.5 | ) | ||
| Natural gas commodity price risk | (10.2 | ) | (12.2 | ) | ||||
| Electricity commodity price risk | 4.1 | (1.2 | ) | |||||
| Interest rate risk | 14.9 | (13.1 | ) | |||||
| Foreign currency exchange rate risk | (4.2 | ) | (18.7 | ) | ||||
Because our derivative instruments generally qualify as hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”), we expect that changes in the fair value of derivative instruments used to manage commodity or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.
Our primary exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses remain in other comprehensive income until such foreign operations are liquidated. At December 31, 2006, the fair value of unsettled net investment hedges was a loss of $1.0 million, which is included in the foreign currency exchange rate risk in the table above. With respect to our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $53.3 million, which amount would be reflected in other comprehensive income.
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ITEM 4. CONTROLS AND PROCEDURES
| (a) | Evaluation of Disclosure Controls and Procedures | |
| The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report were designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. | ||
| (b) | Change in Internal Control over Financial Reporting | |
| Except as discussed below, during the quarter ended December 31, 2006, there has been no change in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. | ||
| During October 2006, UGI and subsidiaries UGI Utilities and UGID, implemented certain financial components of a new information system (the “UGI System”) that supports human resource, accounting, purchasing and payroll transaction processing functions. The implementation of the UGI System affected processes that include certain internal controls impacting financial reporting, and accordingly, we have updated our internal controls. | ||
| In addition, for an interim period, Southern Union Company is providing certain information technology services to UGI Penn Natural Gas, Inc. (“UGIPNG”), a wholly owned subsidiary of UGI Utilities, and is assisting us in migrating certain transaction-based processes and historical UGIPNG data to UGI Utilities’ systems. The migration plan is expected to be completed during fiscal year 2007. Pursuant to the migration plan, UGIPNG began using certain financial components of the UGI System as of January 1, 2007. We have extended internal control procedures over quarterly financial reporting to include UGIPNG. |
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PART II OTHER INFORMATION
ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2006, which could materially affect our business, financial condition or future results. The risks described below and in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) The following table sets forth information with respect to the Company’s repurchases of its common stock during the quarter ended December 31, 2006.
| (d) | ||||||||||||||||
| (a) | (b) | (c) | Maximum Number (or Approximate | |||||||||||||
| Total Number of | Average Price | Total Number of Shares (or Units) | Dollar Value) of Shares (or Units) that | |||||||||||||
| Shares (or Units) | Paid per | Purchased as Part of Publicly | May Yet Be Purchased Under the | |||||||||||||
| Period | Purchased | Share (or Unit) | Announced Plans or Programs | Plans or Programs | ||||||||||||
| October 1, 2006 to October 31, 2006 | 0 | N/A | 0 | N/A | ||||||||||||
| November 1, 2006 to November 30, 2006 | 0 | N/A | 0 | N/A | ||||||||||||
| December 1, 2006 to December 31, 2006 | 20,000 | 1 | $ | 27.37 | 0 | N/A | ||||||||||
Total | 20,000 | $ | 27.37 | 0 | N/A | |||||||||||
1The shares were purchased from a wholly owned subsidiary.
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The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
| EXHIBIT | ||||||||||
| NO. | EXHIBIT | REGISTRANT | FILING | EXHIBIT | ||||||
| 10.1 | Credit Agreement dated as of November 6, 2006 among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citigroup Global Markets Inc., as Syndication Agent, J.P. Morgan Securities, Inc. and Credit Suisse First Securities (USA) LLC, as Co- Documentation Agents, Wachovia Bank, National Association, as Agent, Issuing Bank and Swing Line Bank, and the other financial institutions party thereto | AmeriGas Partners, L.P. | Form 8-K (11/6/06) | 10.1 | ||||||
| 10.2 | Restricted Subsidiary Guarantee by the Restricted Subsidiaries of AmeriGas Propane, L.P., as Guarantors, for the benefit of Wachovia Bank, National Association and the Banks dated as of November 6, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.2 | ||||||
| 10.3 | Release of Liens and Termination of Security Documents dated November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.3 | ||||||
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2006, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||||
| 31.2 | Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 3, 2006, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||||
| 32 | 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 December 31, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||||||
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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: February 8, 2007 | By: | /s/ Anthony J. Mendicino | ||
| Anthony J. Mendicino | ||||
| Senior Vice President-Finance and Chief Financial Officer | ||||
| Date: February 8, 2007 | By: | /s/ Michael J. Cuzzolina | ||
| Michael J. Cuzzolina | ||||
| Vice President-Accounting and Financial Control and Chief Risk Officer | ||||
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EXHIBIT INDEX
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2006, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2 | Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2006, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32 | 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 December 31, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |