Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2006
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
| Pennsylvania | 23-2668356 | |
(State or other jurisdiction of incorporation or organization) | (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)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
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 filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
At July 31, 2006, there were 105,413,596 shares of UGI Corporation Common Stock, without par value, outstanding.
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
| PAGES | ||||
Part I Financial Information | ||||
Item 1. | Financial Statements | |||
| Condensed Consolidated Balance Sheets as of June 30, 2006, September 30, 2005 and June 30, 2005 | 1 | |||
| Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2006 and 2005 | 2 | |||
| Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2006 and 2005 | 3 | |||
| Notes to Condensed Consolidated Financial Statements | 4 -22 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 23 -38 | ||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 38 - 41 | ||
Item 4. | Controls and Procedures | 42 | ||
Part II Other Information | ||||
Item 1. | Legal Proceedings | 42 | ||
Item 1A. | Risk Factors | 42 | ||
Item 6. | Exhibits | 44 - 45 | ||
| 46 | ||||
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
| June 30, 2006 | September 30, 2005 | June 30, 2005 | ||||||||||
ASSETS | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 292.6 | $ | 315.0 | $ | 207.4 | ||||||
Short-term investments (at cost, which approximates fair value) | 115.0 | 70.0 | 65.0 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $37.5, $29.2 and $33.0, respectively) | 421.6 | 421.8 | 424.3 | |||||||||
Accrued utility revenues | 12.2 | 10.4 | 8.5 | |||||||||
Inventories | 217.2 | 239.9 | 168.8 | |||||||||
Deferred income taxes | 31.4 | 24.4 | 39.6 | |||||||||
Derivative financial instruments | 22.8 | 60.3 | 7.2 | |||||||||
Prepaid expenses | 14.7 | 26.2 | 15.8 | |||||||||
Other current assets | 5.2 | 4.3 | 7.6 | |||||||||
Total current assets | 1,132.7 | 1,172.3 | 944.2 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,065.4, $986.9 and $966.7, respectively) | 1,832.2 | 1,802.7 | 1,787.3 | |||||||||
Goodwill | 1,240.9 | 1,231.2 | 1,233.9 | |||||||||
Intangible assets (less accumulated amortization of $59.2, $45.4 and $41.4, respectively) | 168.1 | 172.6 | 176.4 | |||||||||
Utility regulatory assets | 61.3 | 61.3 | 66.8 | |||||||||
Investments in equity investees | 57.7 | 12.8 | 13.5 | |||||||||
Other assets | 124.8 | 118.6 | 106.6 | |||||||||
Total assets | $ | 4,617.7 | $ | 4,571.5 | $ | 4,328.7 | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||
Current liabilities: | ||||||||||||
Current maturities of long-term debt | $ | 78.6 | $ | 252.0 | $ | 208.7 | ||||||
AmeriGas Propane bank loans | — | — | 15.0 | |||||||||
UGI Utilities bank loans | 112.1 | 81.2 | 49.5 | |||||||||
Other bank loans | 15.1 | 16.2 | 16.5 | |||||||||
Accounts payable | 306.4 | 399.7 | 276.8 | |||||||||
Deferred fuel refunds | 10.1 | 17.4 | 19.1 | |||||||||
Employee compensation and benefits accrued | 69.0 | 78.6 | 87.3 | |||||||||
Dividends and interest accrued | 14.7 | 40.8 | 31.1 | |||||||||
Income taxes accrued | 18.9 | 40.1 | 69.3 | |||||||||
Deposits and advances | 77.9 | 124.1 | 58.0 | |||||||||
Other current liabilities | 93.1 | 113.0 | 99.8 | |||||||||
Total current liabilities | 795.9 | 1,163.1 | 931.1 | |||||||||
Long-term debt | 1,642.7 | 1,392.5 | 1,458.6 | |||||||||
Deferred income taxes | 496.3 | 477.5 | 468.9 | |||||||||
Other noncurrent liabilities | 339.8 | 334.5 | 324.1 | |||||||||
Total liabilities | 3,274.7 | 3,367.6 | 3,182.7 | |||||||||
Commitments and contingencies (note 8) | ||||||||||||
Minority interests | 201.3 | 206.3 | 166.7 | |||||||||
Common stockholders’ equity: | ||||||||||||
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,152,994 shares) | 805.1 | 793.6 | 769.9 | |||||||||
Retained earnings | 392.6 | 266.3 | 292.6 | |||||||||
Accumulated other comprehensive income (loss) | 18.6 | 16.5 | (1.6 | ) | ||||||||
| 1,216.3 | 1,076.4 | 1,060.9 | ||||||||||
Treasury stock, at cost | (74.6 | ) | (78.8 | ) | (81.6 | ) | ||||||
Total common stockholders’ equity | 1,141.7 | 997.6 | 979.3 | |||||||||
Total liabilities and stockholders’ equity | $ | 4,617.7 | $ | 4,571.5 | $ | 4,328.7 | ||||||
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)
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Revenues | $ | 919.1 | $ | 932.5 | $ | 4,342.5 | $ | 4,082.6 | ||||||||
Costs and expenses: | ||||||||||||||||
Cost of sales | 611.6 | 628.8 | 3,059.3 | 2,764.6 | ||||||||||||
Operating and administrative expenses | 236.2 | 233.6 | 735.9 | 736.7 | ||||||||||||
Utility taxes other than income taxes | 3.2 | 3.2 | 10.2 | 10.1 | ||||||||||||
Depreciation and amortization | 36.5 | 36.5 | 108.7 | 111.8 | ||||||||||||
Other income, net | (6.9 | ) | (7.2 | ) | (32.9 | ) | (40.9 | ) | ||||||||
| 880.6 | 894.9 | 3,881.2 | 3,582.3 | |||||||||||||
Operating income | 38.5 | 37.6 | 461.3 | 500.3 | ||||||||||||
Loss from equity investees | — | (0.7 | ) | (1.2 | ) | (2.0 | ) | |||||||||
Interest expense | (29.1 | ) | (32.1 | ) | (92.1 | ) | (98.9 | ) | ||||||||
Loss on early extinguishments of debt | — | (33.6 | ) | (18.5 | ) | (33.6 | ) | |||||||||
Income (loss) before income taxes and minority interests | 9.4 | (28.8 | ) | 349.5 | 365.8 | |||||||||||
Income tax (expense) benefit | (2.1 | ) | 1.6 | (105.0 | ) | (123.9 | ) | |||||||||
Minority interests, principally in AmeriGas Partners | 11.4 | 27.9 | (64.3 | ) | (45.7 | ) | ||||||||||
Net income | $ | 18.7 | $ | 0.7 | $ | 180.2 | $ | 196.2 | ||||||||
Earnings per common share: | ||||||||||||||||
Basic | $ | 0.18 | $ | 0.01 | $ | 1.71 | $ | 1.89 | ||||||||
Diluted | $ | 0.18 | $ | 0.01 | $ | 1.69 | $ | 1.86 | ||||||||
Average common shares outstanding (millions): | ||||||||||||||||
Basic | 105.603 | 104.312 | 105.374 | 103.542 | ||||||||||||
Diluted | 106.850 | 106.024 | 106.585 | 105.422 | ||||||||||||
Dividends declared per common share | $ | 0.1763 | $ | 0.1688 | $ | 0.5138 | $ | 0.4813 | ||||||||
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)
| Nine Months Ended June 30, | ||||||||
| 2006 | 2005 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income | $ | 180.2 | $ | 196.2 | ||||
Adjustments to reconcile to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 108.7 | 111.8 | ||||||
Provision for uncollectible accounts | 21.3 | 19.8 | ||||||
Minority interests | 64.3 | 45.7 | ||||||
Deferred income taxes, net | 6.4 | 7.2 | ||||||
Loss on early extinguishments of debt | 18.5 | 33.6 | ||||||
Net change in settled accumulated other comprehensive income | (17.7 | ) | (3.9 | ) | ||||
Other, net | 22.7 | (3.8 | ) | |||||
Net change in: | ||||||||
Accounts receivable and accrued utility revenues | 26.3 | (76.1 | ) | |||||
Inventories | 24.4 | 41.8 | ||||||
Deferred fuel costs | (18.0 | ) | 11.2 | |||||
Accounts payable | (134.3 | ) | (57.3 | ) | ||||
Other current assets and liabilities | (109.8 | ) | (9.5 | ) | ||||
Net cash provided by operating activities | 193.0 | 316.7 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Expenditures for property, plant and equipment | (132.8 | ) | (112.0 | ) | ||||
Net proceeds from disposals of assets | 7.4 | 14.1 | ||||||
Net proceeds from sale of Energy Ventures | 17.7 | — | ||||||
Investment in Flaga joint venture | (10.1 | ) | — | |||||
Acquisitions of businesses, net of cash acquired | (3.5 | ) | (31.7 | ) | ||||
Short-term investments increase | (45.0 | ) | (15.0 | ) | ||||
Other, net | 0.7 | 6.6 | ||||||
Net cash used by investing activities | (165.6 | ) | (138.0 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Dividends on UGI Common Stock | (54.1 | ) | (49.9 | ) | ||||
Distributions on AmeriGas Partners publicly held Common Units | (54.9 | ) | (49.7 | ) | ||||
Issuances of debt including bank loans with maturities greater than three months | 863.4 | 506.0 | ||||||
Repayments of debt including bank loans with maturities greater than three months | (897.4 | ) | (526.2 | ) | ||||
AmeriGas Propane bank loans increase | — | 15.0 | ||||||
Other bank loans decrease | (2.1 | ) | (0.3 | ) | ||||
Increase (decrease) in UGI Utilities bank loans with maturities of three months or less | 80.9 | (11.4 | ) | |||||
Redemption of UGI Utilities preferred shares subject to mandatory redemption | — | (20.0 | ) | |||||
Issuance of UGI Common Stock | 9.3 | 22.8 | ||||||
Net cash used by financing activities | (54.9 | ) | (113.7 | ) | ||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH | 5.1 | (7.2 | ) | |||||
Cash and cash equivalents (decrease) increase | $ | (22.4 | ) | $ | 57.8 | |||
Cash and cash equivalents: | ||||||||
End of period | $ | 292.6 | $ | 207.4 | ||||
Beginning of period | 315.0 | 149.6 | ||||||
(Decrease) increase | $ | (22.4 | ) | $ | 57.8 | |||
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)
| 1. | Basis of Presentation |
UGI Corporation (“UGI”) is a holding company that owns and operates natural gas and electric distribution utility, 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 June 30, 2006, the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”) collectively held a 1% general partner interest and a 42.7% limited partner interest in AmeriGas Partners, and effective 44.3% ownership interests 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 32,272,101 publicly held Common Units representing limited partner interests.
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”) (1) owns and operates LPG distribution businesses in France (“Antargaz”); (2) owns and operates LPG distribution businesses and participates in a LPG joint-venture business in central and eastern Europe (collectively, “Flaga”); and (3) participates in a propane joint-venture business in China. We refer to our foreign operations collectively as “International Propane.”
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”). UGI Utilities owns and operates a natural gas distribution utility (“Gas Utility”) in parts of eastern and southeastern Pennsylvania and an electric distribution utility (“Electric Utility”) in northeastern Pennsylvania. Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”).
In addition, Enterprises conducts an energy marketing business primarily in the eastern region of the United States through its wholly owned subsidiary, UGI Energy Services, Inc. (“Energy Services”). Energy Services’ wholly owned subsidiary UGI Development Company (“UGID”), and UGID’s subsidiaries own and operate a 48-megawatt coal-fired electric generation station and interests 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,
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
air-conditioning, refrigeration and electrical contracting services business in the Middle Atlantic states (“HVAC/R”).
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, 2005 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, 2005 (“Company’s 2005 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.
Earnings 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. Shares used in computing basic and diluted earnings per share are as follows:
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||
| 2006 | 2005 | 2006 | 2005 | |||||
Denominator (millions of shares): | ||||||||
Average common shares outstanding for basic computation | 105.603 | 104.312 | 105.374 | 103.542 | ||||
Incremental shares issuable for stock options and awards | 1.247 | 1.712 | 1.211 | 1.880 | ||||
Average common shares outstanding for diluted computation | 106.850 | 106.024 | 106.585 | 105.422 | ||||
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
Equity-Based Compensation. Under UGI’s 2004 Omnibus Equity Compensation Plan (“OECP”), we may grant options to acquire shares of UGI’s Common Stock (“Common Stock”), or issue stock-based awards (“Units”), to key employees and non-employee directors. Under the OECP, awards representing up to 7,000,000 shares of Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or dividend equivalents is 1,600,000 shares.
The exercise price for options may not be less than the fair market value on the grant date. Grants of stock options may vest immediately or ratably over a period of years (generally three to four year periods) and generally can be exercised no later than ten years from the grant date. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or eliminate further service requirements.
Units may vest immediately or ratably over a period of years (generally three to four year periods). Units granted typically provide for the crediting of Common Stock dividend equivalents to participants’ accounts. Dividend equivalents on employee awards will be paid in cash. It is the Company’s practice to issue treasury shares to satisfy option exercises and Unit awards. The Company does not expect to repurchase shares for such purposes during the year ending September 30, 2006. Dividend equivalents on non-employee director Unit awards are paid in additional Common Stock Units. Stock-based awards granted to employees prior to January 1, 2006 may be settled, at the option of the Company, in shares of Common Stock, cash, or a combination of Common Stock and cash. The actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions.
During the current year, the Company modified the terms of all Unit awards made to non-employee directors. Unit awards made to UGI’s seven non-employee directors are now settled 65% in shares of Common Stock and 35% in cash. Prior to this modification, these Unit awards were settled 100% in Common Stock. As a result of the modification and in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), the Company recorded additional pre-tax compensation expense of $1.0 million which is reflected in the Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2006.
Effective October 1, 2005, the Company adopted SFAS 123R. Prior to October 1, 2005, as permitted, we applied the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), in recording compensation expense for grants of stock, stock options and other equity instruments to employees. Under APB 25, the Company did not record any compensation expense for stock options, but provided the required pro forma disclosures as if we had determined compensation expense under the fair value method prescribed by the provisions of SFAS No. 123. Under SFAS 123R, all equity-based compensation cost is measured on the grant date or at the end of each period based on the fair value of that award and is recognized in the income statement over the requisite service period.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
As permitted by SFAS 123R, under the modified prospective approach, effective October 1, 2005, we began recording compensation expense for awards that were not vested as of that date and we did not restate any prior periods.
For the periods prior to and subsequent to the adoption of SFAS 123R, we used the Black-Scholes option-pricing model to estimate the fair value of each option. The adoption of SFAS 123R resulted in pre-tax stock option expense of $0.5 million and $3.3 million during the three and nine month periods ended June 30, 2006, respectively.
Both prior to and subsequent to the adoption of SFAS 123R, we measured and recorded compensation cost of Units awarded to employees prior to January 1, 2006 (that can be settled at our option in cash or shares of Common Stock, or a combination of both) based upon their fair value as of the end of each period. Such awards are presented in the Condensed Consolidated Balance Sheets as liabilities. The fair value of these Units is generally dependent upon the Company’s stock price and its performance in comparison to a group of peer companies and is expensed over requisite service periods.
Effective in June 2006, the Company modified the settlement terms of those Units awarded to 46 employees having an original grant date of January 1, 2006. As a result of this modification, a portion of these Unit awards are presented as equity and a portion remains presented as liabilities. For these Unit awards, we used the Monte Carlo valuation model to estimate their fair value. Compensation costs associated with the portion of awards classified as equity are measured based upon the fair value on the date of modification and recorded over requisite service periods. Compensation costs associated with the portion of awards classified as liabilities are measured based upon fair value as of the end of each period and recorded over requisite service periods. The Company did not incur any incremental compensation expense as a result of this modification.
Certain employees of the General Partner have been granted the right to receive AmeriGas Partners Common Units. A total of 700,000 AmeriGas Partners Common Unit awards may be granted under the General Partner’s plans. Up to 500,000 of these awards may have performance terms similar to UGI Unit awards and compensation expense is estimated and recorded in the same manner and up to 200,000 have service requirements only. The General Partner made a modification to the settlement of certain of its AmeriGas Partner Common Unit awards. The Partnership did not incur any incremental compensation expense as a result of this modification.
Total net pre-tax equity-based compensation expense recorded during the three and nine months ended June 30, 2006 was $5.9 million ($3.9 million after-tax) and $8.3 million ($5.4 million after-tax), respectively. Our compensation expense reflects awards of UGI stock options, UGI Units and AmeriGas Partners Common Unit 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)
The following table illustrates the effects on net income and basic and diluted earnings per share as if we had applied the provisions of SFAS 123R to all equity-based compensation awards for the periods prior to the adoption of SFAS 123R.
| Three Months Ended June 30, 2005 | Nine Months Ended June 30, 2005 | |||||||
Net income, as reported | $ | 0.7 | $ | 196.2 | ||||
Add: Equity-based employee compensation expense included in reported net income, net of related tax effects | 3.1 | 7.2 | ||||||
Deduct: Total equity-based employee compensation expense determined under the fair value method for all awards, net of related tax effects | (3.4 | ) | (8.7 | ) | ||||
Pro forma net income | $ | 0.4 | $ | 194.7 | ||||
Basic earnings per share: | ||||||||
As reported | $ | 0.01 | $ | 1.89 | ||||
Pro forma | $ | — | $ | 1.88 | ||||
Diluted earnings per share: | ||||||||
As reported | $ | 0.01 | $ | 1.86 | ||||
Pro forma | $ | — | $ | 1.85 | ||||
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
The following table provides stock option activity information:
| Shares | Weighted Average Exercise Price | Weighted Average Remaining Term (years) | Intrinsic Value | ||||||||
Shares under option - September 30, 2005 | 4,953,018 | $ | 15.95 | ||||||||
Granted | 1,159,100 | $ | 20.67 | ||||||||
Exercised | (213,600 | ) | $ | 10.99 | $ | 2.5 million | |||||
Forfeited | (31,500 | ) | $ | 18.85 | |||||||
Shares under option - June 30, 2006 | 5,867,018 | $ | 17.04 | 7.6 | $ | 44.5 million | |||||
Options exercisable - June 30, 2006 | 3,133,852 | $ | 14.45 | 6.6 | $ | 31.9 million | |||||
Unvested options - June 30, 2006 | 2,733,166 | $ | 20.02 | 8.7 | $ | 12.6 million | |||||
Cash received from the exercises of stock options and any associated tax benefits were $2.3 million and $0.9 million, respectively, during the nine months ended June 30, 2006.
The assumptions used to estimate the fair value of stock options were as follows:
Expected life of option | 6 years | |
Expected volatility | 17.7% to 22.6% | |
Expected dividend yield | 2.8% to 6.1% | |
Risk free interest rate | 3.1% to 4.9% |
The expected term of option awards represents the period of time which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on the historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on the historical UGI dividend rates. The risk free interest rate is based upon U.S. Treasury bonds with comparable terms to the options in effect on the date of grant. As of June 30, 2006, there was $3.7 million of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 2.2 years.
During the nine months ended June 30, 2006, a portion of vested UGI Unit awards were settled in shares of UGI Common Stock and approximately $2.3 million in cash. As of June 30, 2006, there was a total of approximately $7.4 million of unrecognized pre-tax compensation cost associated with 656,417 UGI Unit awards that is expected to be recognized over a weighted average period of 1.6 years. There was a total of $1.7 million of unrecognized pre-tax compensation expense associated with 113,517 AmeriGas Partners Common Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At June 30, 2006 total liabilities of $13.7 million associated with both UGI’s and the General Partner’s plans are reflected in other current liabilities and other noncurrent liabilities in the Condensed Consolidated Balance Sheet.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
The following tables illustrate UGI Unit and AmeriGas Partners Common Unit award activity:
| Number of UGI Units | Weighted-Average Grant Date Fair Value (per Unit) | |||||
Non-vested Units - September 30, 2005 | 313,227 | $ | 21.35 | |||
Granted | 158,450 | $ | 22.84 | |||
Forfeited | (967 | ) | $ | 21.25 | ||
Vested | (220,279 | ) | $ | 21.30 | ||
Non-vested Units - June 30, 2006 | 250,431 | $ | 22.47 | |||
| Number of AmeriGas Partners Common Units | Weighted-Average Grant Date Fair Value (per Unit) | |||||
Non-vested Units - September 30, 2005 | 116,000 | $ | 31.81 | |||
Granted | 38,350 | $ | 35.33 | |||
Forfeited | (9,000 | ) | $ | 30.89 | ||
Vested | (6,750 | ) (a) | $ | 23.20 | ||
Performance criteria not met | (25,083 | ) | $ | 30.43 | ||
Non-vested Units - June 30, 2006 | 113,517 | $ | 33.89 | |||
| (a) | Represents awards under the non-executive plan of 4,500 that were settled through the issuance of new AmeriGas Partners Common Units and 2,250 that were settled in cash. |
Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2006 and 2005.
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||
Net income | $ | 18.7 | $ | 0.7 | $ | 180.2 | $ | 196.2 | ||||||
Other comprehensive income (loss) | 24.6 | (31.1 | ) | 2.1 | (24.2 | ) | ||||||||
Comprehensive income (loss) | $ | 43.3 | $ | (30.4 | ) | $ | 182.3 | $ | 172.0 | |||||
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. Due to the seasonality of our earnings, changes in management’s estimates of income taxes made during the third or fourth fiscal quarter can have a significant impact on such quarters’ effective tax rates and make the comparisons to effective tax rates in prior periods not meaningful. The effective income tax rates for the three months ended June 30, 2006 and 2005 were 10.1% and 177.8%, respectively. The effective income tax rates for the nine months ended June 30, 2006 and 2005 were 36.8% and 38.7%, respectively. The differences in our effective tax rates principally reflect the beneficial effects of changes in management’s estimate (made during the three months ended June 30, 2006) of taxes associated with planned repatriation of foreign earnings.
Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
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 Issues 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. SFAS 156 is effective as of the beginning of our fiscal year ending September 30, 2007. We are currently evaluating the impact that the adoption of SFAS 156 will have on our Consolidated Financial Statements.
In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. FIN 48 is effective for our fiscal year beginning October 1, 2007. We are currently evaluating the impact that this standard will have on our Consolidated Financial Statements.
| 2. | Acquisitions and Investments |
On January 26, 2006, UGI signed a definitive agreement to acquire the natural gas utility assets of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments. UGI expects the acquisition to be funded with a combination of debt and existing cash. PG Energy serves approximately 158,000 customers in 13 counties in northeastern and central Pennsylvania. The proposed transaction is subject to PUC approval and is currently expected to close during our fourth fiscal quarter ending September 30, 2006. We anticipate that UGI Utilities will acquire and operate, through a subsidiary, the regulated assets of PG Energy immediately following completion of the acquisition.
On February 15, 2006, Flaga entered into a joint venture with a subsidiary of Progas GmbH & Co KG (“Progas”) to create a company for the retail distribution of LPG in central and eastern Europe. Headquartered in Dortmund, Germany, Progas is controlled by Thyssen’sche Handelsgesellschaft m.b.H. The joint venture company, Zentraleuropa LPG Holding (the “Flaga JV”), an Austrian limited liability company, through its subsidiaries engages in the business of retail distribution of LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. In forming the joint venture, Flaga contributed the shares of its LPG subsidiaries operating in the Czech Republic and Slovakia to the Flaga JV and paid cash of €9.1 million to Progas. Progas
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
contributed the shares of its LPG subsidiaries operating in the Czech Republic, Hungary, Poland, Romania and Slovakia to the Flaga JV. These LPG operating subsidiaries distributed approximately 77 million gallons of LPG in these five countries in 2005. The Flaga JV is owned and controlled equally by Flaga and Progas. In a related transaction, Flaga purchased Progas’ retail LPG business in Austria.
In March 2006, UGID sold its 50% ownership interest in Hunlock Creek Energy Ventures (“Energy Ventures”) to Allegheny Energy Supply Hunlock Creek, LLC. Energy Ventures’ assets primarily comprised a 44-megawatt gas-fired combustion turbine electric generator and a 48-megawatt coal-fired electric generation facility. As part of the consideration in this sale, Energy Ventures transferred the 48-megawatt coal-fired electric generation station to UGID. UGID recorded a net pre-tax gain of $9.1 million ($5.3 million after-tax) associated with this transaction, which is reflected in other income, net in the Condensed Consolidated Statements of Income for the nine months ended June 30, 2006.
| 3. | 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, the Flaga JV, and our international LPG equity investment in China (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services (comprising Energy Services’ gas marketing business, UGID’s electric generation business and Asset Management’s propane terminal business). 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 the Organization and Significant Accounting Policies note contained in the Company’s 2005 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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements (continued)
(unaudited)
(Millions of dollars, except per share amounts)
| 3. | Segment Information (continued) |
Three Months Ended June 30, 2006:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Total | Elims. | AmeriGas Propane | Gas Utility | Electric Utility | Energy Services | International Propane | Corporate & Other (b) | |||||||||||||||||||||||||||||
| Antargaz | Other (a) | |||||||||||||||||||||||||||||||||||
Revenues | $ | 919.1 | $ | (44.3 | ) | $ | 379.1 | $ | 106.3 | $ | 22.9 | $ | 268.7 | $ | 155.9 | $ | 11.5 | $ | 19.0 | |||||||||||||||||
Cost of sales | $ | 611.6 | $ | (43.3 | ) | $ | 234.4 | $ | 71.6 | $ | 11.2 | $ | 248.4 | $ | 70.8 | $ | 6.5 | $ | 12.0 | |||||||||||||||||
Segment profit: | ||||||||||||||||||||||||||||||||||||
Operating income (c) | $ | 38.5 | $ | — | $ | 2.9 | $ | 6.6 | $ | 5.2 | $ | 10.4 | $ | 11.4 | $ | 0.2 | $ | 1.8 | ||||||||||||||||||
Interest expense | (29.1 | ) | — | (17.9 | ) | (4.7 | ) | (0.6 | ) | (0.1 | ) | (5.1 | ) | (0.3 | ) | (0.4 | ) | |||||||||||||||||||
Minority interests | 11.4 | — | 8.3 | — | — | — | 3.1 | — | — | |||||||||||||||||||||||||||
Income (loss) before income taxes | $ | 20.8 | $ | — | $ | (6.7 | ) | $ | 1.9 | $ | 4.6 | $ | 10.3 | $ | 9.4 | $ | (0.1 | ) | $ | 1.4 | ||||||||||||||||
Depreciation and amortization | $ | 36.5 | $ | — | $ | 17.8 | $ | 5.6 | $ | 0.8 | $ | 1.6 | $ | 9.6 | $ | 0.8 | $ | 0.3 | ||||||||||||||||||
Partnership EBITDA (c) | $ | 20.7 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) | $ | 4,617.7 | $ | (345.8 | ) | $ | 1,596.5 | $ | 817.5 | $ | 106.5 | $ | 243.4 | $ | 1,494.6 | $ | 155.6 | $ | 549.4 | |||||||||||||||||
Investments in equity investees (at period end) | $ | 57.7 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 0.5 | $ | 57.2 | $ | — | ||||||||||||||||||
Goodwill (at period end) | $ | 1,240.9 | $ | (4.0 | ) | $ | 618.3 | $ | — | $ | — | $ | 11.8 | $ | 565.5 | $ | 42.9 | $ | 6.4 | |||||||||||||||||
Three Months Ended June 30, 2005: | ||||||||||||||||||||||||||||||||||||
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Total | Elims. | AmeriGas Propane | Gas Utility | Electric Utility | Energy Services | International Propane | Corporate & Other (b) | |||||||||||||||||||||||||||||
| Antargaz | Other (a) | |||||||||||||||||||||||||||||||||||
Revenues | $ | 932.5 | $ | (1.1 | ) | $ | 349.5 | $ | 89.5 | $ | 22.0 | $ | 290.6 | $ | 148.1 | $ | 15.0 | $ | 18.9 | |||||||||||||||||
Cost of sales | $ | 628.8 | $ | — | $ | 209.0 | $ | 54.6 | $ | 10.6 | $ | 271.9 | $ | 62.3 | $ | 8.4 | $ | 12.0 | ||||||||||||||||||
Segment profit: | ||||||||||||||||||||||||||||||||||||
Operating income (c) | $ | 37.6 | $ | — | $ | 1.6 | $ | 7.7 | $ | 4.9 | $ | 10.6 | $ | 12.7 | $ | 0.5 | $ | (0.4 | ) | |||||||||||||||||
Loss from equity investees | (0.7 | ) | — | — | — | — | — | (0.7 | ) | — | — | |||||||||||||||||||||||||
Loss on extinguishment of debt | (33.6 | ) | — | (33.6 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
Interest expense | (32.1 | ) | — | (19.7 | ) | (3.9 | ) | (0.5 | ) | — | (7.1 | ) | (0.7 | ) | (0.2 | ) | ||||||||||||||||||||
Minority interests | 27.9 | — | 27.8 | — | — | — | 0.1 | — | — | |||||||||||||||||||||||||||
Income (loss) before income taxes | $ | (0.9 | ) | $ | — | $ | (23.9 | ) | $ | 3.8 | $ | 4.4 | $ | 10.6 | $ | 5.0 | $ | (0.2 | ) | $ | (0.6 | ) | ||||||||||||||
Depreciation and amortization | $ | 36.5 | $ | — | $ | 18.2 | $ | 5.3 | $ | 0.8 | $ | 1.5 | $ | 9.4 | $ | 1.2 | $ | 0.1 | ||||||||||||||||||
Partnership EBITDA (c) | $ | (13.7 | ) | |||||||||||||||||||||||||||||||||
Segment assets (at period end) | $ | 4,328.7 | $ | (342.9 | ) | $ | 1,517.7 | $ | 768.7 | $ | 97.2 | $ | 254.8 | $ | 1,410.4 | $ | 153.1 | $ | 469.7 | |||||||||||||||||
Investments in equity investees (at period end) | $ | 13.5 | $ | — | $ | — | $ | — | $ | — | $ | 8.6 | $ | 2.2 | $ | 2.7 | $ | — | ||||||||||||||||||
Goodwill (at period end) | $ | 1,233.9 | $ | — | $ | 618.0 | $ | — | $ | — | $ | 5.9 | $ | 536.5 | $ | 67.9 | $ | 5.6 | ||||||||||||||||||
| (a) | International Propane-Other principally comprises Flaga, its joint venture 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’s 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 June 30, | 2006 | 2005 | ||||||
Partnership EBITDA | $ | 20.7 | $ | (13.7 | ) | |||
Depreciation and amortization | (17.8 | ) | (18.2 | ) | ||||
Minority interests (i) | — | (0.1 | ) | |||||
Loss on extinguishments of debt | — | 33.6 | ||||||
Operating income | $ | 2.9 | $ | 1.6 | ||||
| (i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements (continued)
(unaudited)
(Millions of dollars, except per share amounts)
| 3. | Segment Information (continued) |
Nine Months Ended June 30, 2006:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Total | Elims. | AmeriGas Propane | Gas Utility | Electric Utility | Energy Services | International Propane | Corporate & Other (b) | |||||||||||||||||||||||||||||
| Antargaz | Other (a) | |||||||||||||||||||||||||||||||||||
Revenues | $ | 4,342.5 | $ | (110.3 | ) | $ | 1,727.5 | $ | 622.3 | $ | 72.2 | $ | 1,158.9 | $ | 763.1 | $ | 54.0 | $ | 54.8 | |||||||||||||||||
Cost of sales | $ | 3,059.3 | $ | (107.3 | ) | $ | 1,089.5 | $ | 454.5 | $ | 37.7 | $ | 1,093.5 | $ | 422.8 | $ | 34.6 | $ | 34.0 | |||||||||||||||||
Segment profit: | ||||||||||||||||||||||||||||||||||||
Operating income (d) | $ | 461.3 | $ | — | $ | 193.9 | $ | 82.2 | $ | 15.0 | $ | 44.7 | $ | 118.6 | $ | 3.1 | $ | 3.8 | ||||||||||||||||||
Loss from equity investees | (1.2 | ) | — | — | — | — | — | (1.2 | ) | — | — | |||||||||||||||||||||||||
Loss on extinguishments of debt | (18.5 | ) | — | (17.1 | ) | — | — | — | (1.4 | ) | — | — | ||||||||||||||||||||||||
Interest expense | (92.1 | ) | — | (56.2 | ) | (14.4 | ) | (1.9 | ) | (0.1 | ) | (18.0 | ) | (1.2 | ) | (0.3 | ) | |||||||||||||||||||
Minority interests | (64.3 | ) | (0.2 | ) | (67.0 | ) | — | — | — | 2.9 | — | — | ||||||||||||||||||||||||
Income before income taxes | $ | 285.2 | $ | (0.2 | ) | $ | 53.6 | $ | 67.8 | $ | 13.1 | $ | 44.6 | $ | 100.9 | $ | 1.9 | $ | 3.5 | |||||||||||||||||
Depreciation and amortization | $ | 108.7 | $ | — | $ | 54.0 | $ | 16.4 | $ | 2.5 | $ | 4.8 | $ | 27.4 | $ | 3.0 | $ | 0.6 | ||||||||||||||||||
Partnership EBITDA (d) | $ | 229.1 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) | $ | 4,617.7 | $ | (345.8 | ) | $ | 1,596.5 | $ | 817.5 | $ | 106.5 | $ | 243.4 | $ | 1,494.6 | $ | 155.6 | $ | 549.4 | |||||||||||||||||
Investments in equity investees (at period end) | $ | 57.7 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 0.5 | $ | 57.2 | $ | — | ||||||||||||||||||
Goodwill (at period end) | $ | 1,240.9 | $ | (4.0 | ) | $ | 618.3 | $ | — | $ | — | $ | 11.8 | $ | 565.5 | $ | 42.9 | $ | 6.4 | |||||||||||||||||
Nine Months Ended June 30, 2005: | ||||||||||||||||||||||||||||||||||||
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Total | Elims. | AmeriGas Propane | Gas Utility | Electric Utility | Energy Services | International Propane | Corporate & Other (b) | |||||||||||||||||||||||||||||
| Antargaz | Other (a) | |||||||||||||||||||||||||||||||||||
Revenues | $ | 4,082.6 | $ | (3.6 | ) | $ | 1,604.0 | $ | 506.6 | $ | 69.9 | $ | 1,051.8 | $ | 747.1 | $ | 57.3 | $ | 49.5 | |||||||||||||||||
Cost of sales | $ | 2,764.6 | $ | — | $ | 989.9 | $ | 338.5 | $ | 33.5 | $ | 995.0 | $ | 346.2 | $ | 32.9 | $ | 28.6 | ||||||||||||||||||
Segment profit: | ||||||||||||||||||||||||||||||||||||
Operating income (c) (d) | $ | 500.3 | $ | — | $ | 178.1 | $ | 84.4 | $ | 16.8 | $ | 30.7 | $ | 184.4 | $ | 5.2 | $ | 0.7 | ||||||||||||||||||
Loss from equity investees | (2.0 | ) | — | — | — | — | — | (2.0 | ) | — | — | |||||||||||||||||||||||||
Loss on extinguishment of debt | (33.6 | ) | — | (33.6 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
Interest expense | (98.9 | ) | — | (60.9 | ) | (12.0 | ) | (1.5 | ) | — | (22.0 | ) | (2.3 | ) | (0.2 | ) | ||||||||||||||||||||
Minority interests | (45.7 | ) | 3.9 | (48.6 | ) | — | — | — | (1.0 | ) | — | — | ||||||||||||||||||||||||
Income before income taxes (c) | $ | 320.1 | $ | 3.9 | $ | 35.0 | $ | 72.4 | $ | 15.3 | $ | 30.7 | $ | 159.4 | $ | 2.9 | $ | 0.5 | ||||||||||||||||||
Depreciation and amortization | $ | 111.8 | $ | — | $ | 56.0 | $ | 15.5 | $ | 2.3 | $ | 4.3 | $ | 29.2 | $ | 3.8 | $ | 0.7 | ||||||||||||||||||
Partnership EBITDA (d) | $ | 208.0 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) | $ | 4,328.7 | $ | (342.9 | ) | $ | 1,517.7 | $ | 768.7 | $ | 97.2 | $ | 254.8 | $ | 1,410.4 | $ | 153.1 | $ | 469.7 | |||||||||||||||||
Investments in equity investees (at period end) | $ | 13.5 | $ | — | $ | — | $ | — | $ | — | $ | 8.6 | $ | 2.2 | $ | 2.7 | $ | — | ||||||||||||||||||
Goodwill (at period end) | $ | 1,233.9 | $ | — | $ | 618.0 | $ | — | $ | — | $ | 5.9 | $ | 536.5 | $ | 67.9 | $ | 5.6 | ||||||||||||||||||
| (a) | International Propane-Other principally comprises Flaga, its joint venture 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’s 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) | International Propane-Antargaz’ results for the nine months ended June 30, 2005 include $19.9 million of operating income and income before income taxes due to the resolution of certain non-income tax contingencies (see Note 8). |
| (d) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
Nine months ended June 30, | 2006 | 2005 | ||||||
Partnership EBITDA (i) | $ | 229.1 | $ | 208.0 | ||||
Depreciation and amortization (ii) | (54.0 | ) | (55.9 | ) | ||||
Minority interests (iii) | 1.7 | 1.5 | ||||||
Loss on extinguishments of debt | 17.1 | 33.6 | ||||||
Gain on sale of Atlantic Energy | — | (9.1 | ) | |||||
Operating income | $ | 193.9 | $ | 178.1 | ||||
| (i) | Includes a $9.1 million gain on the sale of Atlantic Energy to Energy Services during the nine months ended June 30, 2005. |
| (ii) | Excludes General Partner depreciation and amortization of $0.1 million in the nine months ended June 30, 2005. |
| (iii) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
| 4. | Long-term Debt |
In December 2005, UGI Utilities refinanced $50 million of its maturing 7.14% Medium-Term Notes with proceeds from the issuance of $50 million of 5.64% Medium-Term Notes due in December 2015. These Medium-Term Notes were issued pursuant to the UGI Utilities’ $125 million shelf registration statement with the SEC.
On December 7, 2005, Antargaz executed a new five-year, floating rate Senior Facilities Agreement with a major French bank providing for a €380 million term loan and a €50 million revolving credit facility. The proceeds of the term loan were used in December 2005 to repay immediately the existing €175 million Senior Facilities term loan, to fund the redemption of the €165 million High Yield Bonds in January 2006, including a premium, and for general corporate purposes. As a result of this refinancing, we incurred a pre-tax loss on extinguishment of debt of $1.4 million ($0.9 million after-tax). In addition, Antargaz executed interest rate swap agreements with the same bank to fix the rate of interest on the term loan for the duration of the loan at a rate of approximately 3.25%, plus a margin.
In January 2006, the Partnership and AP Eagle Finance Corp. issued $350 million of 7.125% Senior Notes due 2016. The proceeds of this registered public debt offering were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C First Mortgage Notes, including a make-whole premium, its $35 million term loan due October 1, 2006 and $59.6 million of the Partnership’s $60 million 10% Senior Notes due 2006 pursuant to a tender offer, plus a premium. We recorded a loss on extinguishment of debt associated with the refinancings of approximately $17.1 million ($4.6 million after-tax).
On July 26, 2006, Flaga entered into a euro-based term loan facility in the amount of €48 million ($61.4 million) and a working capital facility of up to €8 million. These facilities are subject to guarantees by UGI. In addition, on July 26, 2006, the Flaga JV entered into a multi-currency working capital facility of up to €8 million which is also subject to guarantees by UGI.
| 5. | Intangible Assets |
The Company’s intangible assets comprise the following:
| June 30, 2006 | September 30, 2005 | |||||||
Goodwill (not subject to amortization) | $ | 1,240.9 | $ | 1,231.2 | ||||
Other intangible assets: | ||||||||
Customer relationships, noncompete agreements and other | $ | 183.9 | $ | 177.2 | ||||
Trademark (not subject to amortization) | 43.4 | 40.8 | ||||||
Gross carrying amount | 227.3 | 218.0 | ||||||
Accumulated amortization | (59.2 | ) | (45.4 | ) | ||||
Net carrying amount | $ | 168.1 | $ | 172.6 | ||||
Changes in intangible assets during the nine months ended June 30, 2006 principally reflect the effects of our investment in the Flaga JV and foreign currency translation. Amortization expense of intangible assets was $3.9 million and $12.1 million for the three and nine months ended June 30, 2006, respectively, and $4.2 million and $13.0 million for the three and nine months ended June 30, 2005, respectively. Our expected aggregate amortization expense of intangible assets for
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
the next five fiscal years is as follows: Fiscal 2006 - $16.3 million; Fiscal 2007 - $15.6 million; Fiscal 2008 - $15.2 million; Fiscal 2009 - $14.6 million; Fiscal 2010 - $13.3 million.
| 6. | Energy Services Accounts Receivable Securitization Facility |
Energy Services has a $150 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009. In order to provide additional short-term liquidity during the peak heating season due to increased product costs, the maximum level of funding available at any one point in time from this facility was temporarily increased to $300 million for the period from November 1, 2005 to April 24, 2006. The fees associated with temporarily increasing the maximum level of funding were not material. After April 24, 2006, the maximum level of funding available at any one time from this facility is $150 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. The proceeds of these sales are less than the face amount of the accounts receivable sold by an amount that approximates the purchaser’s financing cost of issuing its own receivables-backed commercial paper. ESFC 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.
During the nine months ended June 30, 2006, Energy Services sold trade receivables totaling $1,073.4 million to ESFC. During the nine months ended June 30, 2006, ESFC sold an aggregate $724.5 million of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2006, the outstanding balance of ESFC trade receivables was $30.2 million, which is net of $42.0 million that was sold to the commercial paper conduit and removed from the balance sheet.
In addition, a major bank has committed to Energy Services to issue up to $50 million of standby letters of credit, secured by cash or marketable securities (“LC Facility”). At June 30, 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 expires in April 2007.
| 7. | Defined Benefit Pension and Other Postretirement Plans |
We sponsor a defined benefit pension plan (“UGI Utilities Pension Plan”) for employees of UGI, UGI Utilities, and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all domestic active and retired employees. Antargaz provides certain pension and postretirement health care benefits for its employees.
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
Net periodic pension expense and other postretirement benefit costs include the following components:
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| Three Months Ended June 30, | Three Months Ended June 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Service cost | $ | 1.5 | $ | 1.4 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost | 3.5 | 3.5 | 0.3 | 0.5 | ||||||||||||
Expected return on assets | (4.7 | ) | (4.5 | ) | (0.2 | ) | (0.1 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 0.1 | 0.2 | ||||||||||||
Prior service cost (benefit) | 0.2 | 0.2 | (0.1 | ) | — | |||||||||||
Actuarial loss | 0.4 | 0.3 | — | 0.1 | ||||||||||||
Net benefit cost | 0.9 | 0.9 | 0.2 | 0.8 | ||||||||||||
Change in regulatory and other assets and liabilities | (0.1 | ) | — | 0.7 | 0.2 | |||||||||||
Net expense | $ | 0.8 | $ | 0.9 | $ | 0.9 | $ | 1.0 | ||||||||
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| Nine Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Service cost | $ | 4.5 | $ | 4.2 | $ | 0.2 | $ | 0.3 | ||||||||
Interest cost | 10.5 | 10.6 | 0.9 | 1.6 | ||||||||||||
Expected return on assets | (14.2 | ) | (13.5 | ) | (0.5 | ) | (0.4 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 0.2 | 0.7 | ||||||||||||
Prior service cost (benefit) | 0.6 | 0.5 | (0.2 | ) | — | |||||||||||
Actuarial loss | 1.3 | 1.0 | 0.1 | 0.2 | ||||||||||||
Net benefit cost | 2.7 | 2.8 | 0.7 | 2.4 | ||||||||||||
Change in regulatory and other assets and liabilities | (0.3 | ) | — | 2.1 | 0.7 | |||||||||||
Net expense | $ | 2.4 | $ | 2.8 | $ | 2.8 | $ | 3.1 | ||||||||
UGI Utilities 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 UGI Utilities Pension Plan during the year ending September 30, 2006 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 Utilities’ rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the nine months ended June 30, 2006, nor are they expected to be material for the year ending September 30, 2006.
We also sponsor unfunded and non-qualified supplemental executive retirement income plans. We recorded pre-tax expense for these plans of $0.5 million and $1.5 million for the three and nine
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
months ended June 30, 2006, respectively, and $0.5 million and $1.3 million for the three and nine months ended June 30, 2005, respectively.
| 8. | Commitments and Contingencies |
The Partnership has succeeded to certain lease guarantee obligations of Petrolane relating to Petrolane’s divestiture of non-propane operations before its 1989 acquisition by QFB Partners. Future lease payments under these leases total approximately $8 million at June 30, 2006. The leases expire through 2010 and some of them are currently in default. The Partnership has succeeded to the indemnity agreement of Petrolane by which Texas Eastern Corporation (“Texas Eastern”), a prior owner of Petrolane, agreed to indemnify Petrolane against any liabilities arising out of the conduct of businesses that do not relate to, and are not a part of, the propane business, including lease guarantees. In December 1999, Texas Eastern filed for dissolution under the Delaware General Corporation Law. PanEnergy Corporation (“PanEnergy”), Texas Eastern’s sole stockholder, assumed all of Texas Eastern’s liabilities as of December 20, 2002, to the extent of the value of Texas Eastern’s assets transferred to PanEnergy as of that date (which was estimated to exceed $94 million), and to the extent that such liabilities arise within ten years from Texas Eastern’s date of dissolution. Notwithstanding the dissolution proceeding, and based on Texas Eastern previously having satisfied directly defaulted lease obligations without the Partnership’s having to honor its guarantee, we believe that the probability that the Partnership will be required to directly satisfy the lease obligations subject to the indemnification agreement is remote.
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 Columbia Propane businesses) and an affiliate (collectively, “National General Partners”) against certain income tax and other losses that they may sustain as a result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999 Acquisition”) or the operation of the business after the 1999 Acquisition (“National Claims”). At June 30, 2006, the potential amount payable under this indemnity by the Company Parties was approximately $58 million. These indemnity obligations will expire on the date that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG agreed to indemnify the Buyer Parties and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including National Claims, to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and the Buyer Parties have agreed
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
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 million plus punitive damages, civil penalties and attorneys’ fees. We believe we have good defenses to the claims of the class members and intend to vigorously 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 Gas Utility and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. UGI Utilities has been notified of several sites outside Pennsylvania on which 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 three 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
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
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.
By letter dated July 14, 2006, SCANA Corporation (“SCANA”) demanded contribution from UGI Utilities for a portion of past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. According to the letter, the plant operated from 1855 to 1954. SCANA alleges that UGI Utilities controlled operations of the plant from 1910 to 1926. SCANA asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site. It estimates that future remediation costs could be as high as $2.5 million and asserts that it has received a demand from the United States Justice Department for natural resource damages. SCANA claims that UGI Utilities is liable for 47% of the costs associated with the site. UGI Utilities is in the process of reviewing the information provided by SCANA and is investigating this claim.
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 Court 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 million 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 of 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. 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 July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. In March 2005, the court granted UGI Utilities’ motion for summary judgment dismissing AGL’s complaint. AGL has appealed.
AGL previously informed UGI Utilities that it has begun remediation of MGP wastes at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL believes that the total cost of remediation could be as high as $55 million.
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
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 million.
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. On January 17, 2006, the Second Circuit denied UGI Utilities’ request for reconsideration of the panel’s order.
By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million 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 million. KeySpan believes that the cost could go as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the “Northeast Companies”), demanded 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. By letter dated March 17, 2006, the Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and claimed that UGI Utilities is responsible for approximately $103 million 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 million. UGI Utilities believes that it will have good defenses to any action that may arise out of the remaining sites.
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
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. Prior to the Antargaz Acquisition, Antargaz filed suit against French tax authorities in connection with the assessment of business tax related to the tax treatment of certain of its owned tanks at customer locations. Elf Antar France and Elf Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify Antargaz for all payments that would have been due from Antargaz in respect of the tax related to its tanks for the period from January 1, 1997 through December 31, 2000. Antargaz has recorded liabilities for business taxes related to various classes of equipment. On February 4, 2005, Antargaz received a letter that was issued by the French government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry group, concerning the business tax, that eliminated the requirement for Antargaz to pay business tax associated with tanks at certain customer locations. In addition, during Fiscal 2005, resolution was reached relating to business taxes relating to a prior year. Further changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations. Our Condensed Consolidated Statement of Income for the nine months ended June 30, 2005 includes a pre-tax gain of $19.9 million and a net after-tax gain of $14.9 million associated with the resolution of certain business tax matters related principally to prior years.
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 possible losses in excess of recorded amounts. 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 analyses compare our results of operations for (1) the three months ended June 30, 2006 (“2006 three-month period”) with the three months ended June 30, 2005 (“2005 three-month period”) and (2) the nine months ended June 30, 2006 (“2006 nine-month period”) with the nine months ended June 30, 2005 (“2005 nine-month period”). Our analysis of results of operations should be read in conjunction with the segment information included in Note 3 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 process resulting in customer conservation.
During the 2006 nine-month period, temperatures within each of our domestic business units’ service territories were significantly warmer than normal and were warmer than in the prior-year nine-month period. Net income during the 2006 nine-month period declined $16.0 million compared to the prior year. The decline in earnings reflects (1) the absence of $14.9 million (equal to $0.14 per diluted share) of income recorded in the 2005 nine-month period resulting from the resolution of certain of Antargaz’ non-income tax contingencies and (2) Antargaz’ unusually high LPG margins per gallon reflected in the prior year. The effects of these two factors were partially offset by approximately $3.9 million lower after-tax losses on early extinguishments of debt primarily associated with AmeriGas Propane refinancings and a $5.3 million after-tax gain on Energy Services’ sale of its 50% partnership interest in Hunlock Creek Energy Ventures (“Energy Ventures”). In addition, the stronger dollar versus the euro accounted for approximately $7 million of the decrease in net income in the 2006 nine-month period. The effective tax rate during the 2006 nine-month period was almost 2% lower than in the 2005 nine-month period principally due to the beneficial effects of changes in management’s estimate of taxes to be paid associated with the planned repatriation of foreign earnings. As a result of this rate change made during our fiscal third quarter, the effective tax rate for the 2006 three-month period was 10.1% compared to 177.8% for the 2005 three-month period.
In January 2006, we announced that we signed a definitive agreement to acquire the natural gas utility assets of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments. The acquisition, which is subject to PUC approval, is expected to close during our fourth fiscal quarter ending September 30, 2006. We expect to fund the acquisition with debt and existing cash. In February 2006, Flaga entered into a joint venture with a subsidiary of Progas GmbH & Co KG expanding our international presence in central and eastern Europe (the “Flaga JV”).
Net income by business unit:
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||
| (millions of dollars) | ||||||||||||||
Net income (loss): | ||||||||||||||
AmeriGas Propane (a) | $ | (4.1 | ) | $ | (14.5 | ) | $ | 32.0 | $ | 22.9 | ||||
International Propane | 13.1 | 6.4 | 73.0 | 100.6 | ||||||||||
Gas Utility | 0.8 | 2.3 | 40.7 | 43.5 | ||||||||||
Electric Utility | 2.7 | 2.7 | 7.7 | 9.1 | ||||||||||
Energy Services | 6.4 | 6.3 | 26.7 | 18.2 | ||||||||||
Corporate & Other | (0.2 | ) | (2.5 | ) | 0.1 | 1.9 | ||||||||
Total net income | $ | 18.7 | $ | 0.7 | $ | 180.2 | $ | 196.2 | ||||||
| (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:
For the three months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||||
Revenues | $ | 379.1 | $ | 349.5 | $ | 29.6 | 8.5 | % | |||||||
Total margin (a) | $ | 144.7 | $ | 140.5 | $ | 4.2 | 3.0 | % | |||||||
Partnership EBITDA (b) | $ | 20.7 | $ | (13.7 | ) | $ | 34.4 | N.M. | |||||||
Operating income | $ | 2.9 | $ | 1.6 | $ | 1.3 | 81.3 | % | |||||||
Retail gallons sold (millions) | 171.1 | 181.9 | (10.8 | ) | (5.9 | )% | |||||||||
Degree days - % (warmer) than normal (c) | (21.9 | )% | (4.9 | )% | — | — | |||||||||
N.M. – Not meaningful
| (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 3 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 national heating degree-day data, temperatures during the 2006 three-month period were 21.9% warmer than normal and 18.0% warmer than the prior-year period. Retail propane volumes sold decreased approximately 6% principally due to the warmer weather and the negative effects of customer conservation driven by continued high propane selling prices.
Retail propane revenues increased $21.0 million reflecting a $38.7 million increase due to higher average selling prices partially offset by a $17.7 million decrease due to the lower retail volumes sold. Wholesale propane revenues increased $1.0 million reflecting a $3.6 million increase resulting from higher average selling prices partially offset by a $2.6 million decrease due to the lower volumes sold. In the 2006 three-month period, our average retail propane product cost per retail gallon sold was approximately 19% higher than in the 2005 three-month period, which resulted in higher year-over-year prices to our customers. Total cost of sales increased to $234.4 million in the 2006 three-month period from $209.0 million in the 2005 three-month period, primarily reflecting the increase in propane product costs partially offset by the decreased volumes sold. Total margin increased $4.2 million compared to the 2005 three-month period due to increased customer pricing of propane and ancillary sales and services in response to increases in costs incurred.
Partnership EBITDA during the 2006 three-month period was $20.7 million compared to $(13.7) million during the 2005 three-month period. This $34.4 million increase in Partnership EBITDA primarily reflects (1) the absence of a $33.6 million loss on the early extinguishment of debt recognized in May 2005 resulting from the Partnership’s refinancing of $373.4 million of its 8.875% Senior Notes due 2011 through the issuance of $415 million of 7.25% Senior Notes due 2015 and (2) the aforementioned increase in total margin, partially offset by a $3.8 million increase in operating and administrative expenses. The increase in operating and administrative expenses principally resulted from higher vehicle fuel and lease expense and higher employee compensation and benefits expenses. These
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increases were partially offset by a $2.7 million favorable expense reduction related to general insurance, mainly reflecting continued improvement in claims history.
Operating income increased $1.3 million primarily reflecting the increase in total margin and a decrease in depreciation and amortization expense, partially offset by the previously mentioned increase in operating and administrative expenses.
International Propane:
For the three months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||
Revenues | $ | 167.4 | $ | 163.1 | $ | 4.3 | 2.6 | % | |||||
Total margin (a) | $ | 90.1 | $ | 92.4 | $ | (2.3 | ) | (2.5 | )% | ||||
Operating income | $ | 11.6 | $ | 13.2 | $ | (1.6 | ) | (12.1 | )% | ||||
Income before income taxes | $ | 9.3 | $ | 4.8 | $ | 4.5 | 93.8 | % | |||||
Antargaz retail gallons sold (millions) | 54.0 | 59.2 | (5.2 | ) | (8.8 | )% | |||||||
Antargaz total margin, millions of euros (a) | € | 67.5 | € | 68.0 | (€0.5 | ) | (0.7 | )% | |||||
| (a) | Total margin represents total revenues less total cost of sales. |
Based upon heating degree day data, weather in Antargaz’ service territory was approximately 22% warmer than normal in the 2006 three-month period compared to weather that was approximately 20% warmer than normal in the 2005 three-month period. Flaga experienced warmer than normal weather across its service territories in both the 2006 and 2005 three-month periods. The monthly average currency translation rate was $1.26 per euro during both the 2006 and 2005 three-month periods. Antargaz’ retail LPG volumes sold decreased to 54.0 million gallons in the 2006 three-month period from 59.2 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 part to warmer than normal weather and price-induced customer conservation. In addition, competition in the LPG business in France and competition among LPG and other fuels continues to intensify. In particular, in the butane cylinder market, certain hyper/supermarkets have expanded vertically and are marketing their own cylinders.
International Propane revenues increased slightly during the 2006 three-month period primarily due to higher retail LPG selling prices reflecting the effects of significantly higher LPG product cost largely offset by the lower retail gallons sold. Both Antargaz and Flaga experienced higher LPG product costs per retail gallon of LPG compared to the prior-year three-month period. Despite the lower volumes sold, International Propane’s total cost of sales increased to $80.4 million in the 2006 three-month period from $70.9 million in the 2005 three-month period reflecting the higher LPG costs.
Total margin declined $2.3 million in the 2006 three-month period primarily reflecting (1) the effects of Antargaz’ lower retail volumes sold partially offset by higher average margin per gallon of LPG (“unit margin”) and (2) the absence of margin from Flaga’s Czech Republic and Slovakia businesses that were contributed to the Flaga JV in February 2006. Antargaz’ total base currency margin declined €0.5 million reflecting the lower retail LPG volumes sold largely offset by the higher unit margins.
International Propane operating income declined $1.6 million in the 2006 three-month period principally reflecting the decline in total margin and $1.4 million lower other income partially offset by $1.8 million in lower operating and administrative expenses and lower depreciation and amortization expense. The lower other income largely reflects expenses associated with the shut-down of two of Antargaz’ filling and distribution centers. The decline in operating and administrative expenses largely reflects the absence of expenses associated with Flaga’s operations that were contributed to the Flaga JV.
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The decrease in income before income taxes principally reflects the decrease in operating income, a $3.1 million increase in Antargaz’ minority interests share of expenses primarily associated with the shut-down of one its majority-owned filling centers and lower interest expense largely attributable to Antargaz’ refinancing of its High Yield Bonds in January 2006.
Gas Utility:
For the three months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||||
Revenues (a) | $ | 106.3 | $ | 89.5 | $ | 16.8 | 18.8 | % | |||||||
Total margin (a) (b) | $ | 34.7 | $ | 34.9 | $ | (0.2 | ) | (0.6 | )% | ||||||
Operating income | $ | 6.6 | $ | 7.7 | $ | (1.1 | ) | (14.3 | )% | ||||||
Income before income taxes | $ | 1.9 | $ | 3.8 | $ | (1.9 | ) | (50.0 | )% | ||||||
System throughput - billions of cubic feet (“bcf”) (a) | 14.3 | 15.3 | (1.0 | ) | (6.5 | )% | |||||||||
Degree days - % (warmer) colder than normal (c) | (13.5 | )% | (3.5 | )% | — | — | |||||||||
| (a) | Beginning in Fiscal 2006, Gas Utility adjusted its method of estimating unbilled throughput and associated revenues for service provided through the end of the month by more closely correlating such estimated throughput to distribution system sendout data. The Company believes that the new method of estimating Gas Utility’s unbilled throughput results in a more accurate quarterly estimate of unbilled revenues and associated total margin. The change in the method of estimating unbilled throughput did not have a material impact on Gas Utility’s throughput, revenues or margin for the 2006 three-month period. |
| (b) | Total margin represents total revenues less total cost of sales. |
| (c) | Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 4 airports located within our service territory. The 2005 three-month period degree day statistics have been restated to reflect the current-year, four-location average from the previous single location statistic. |
Weather in Gas Utility’s service territory based upon heating degree days was 13.5% warmer than normal during the 2006 three-month period compared to 3.5% warmer than normal in the prior-year three-month period. Notwithstanding year-over-year growth in the number of Gas Utility’s customers, total distribution system throughput decreased 6.5% in the 2006 three-month period reflecting a 0.7 bcf decrease in sales to firm- residential, commercial and industrial (“retail core-market”) customers and lower firm delivery service volumes. The decrease in retail core-market throughput largely reflects the effects of significantly warmer spring weather and, to a lesser extent, the continued effects of lower average usage per customer resulting from significantly higher natural gas prices.
Notwithstanding the decline in distribution system throughput, Gas Utility revenues increased $16.8 million during the 2006 three-month period principally reflecting (1) a $10.9 million increase in revenues from low-margin off-system sales and (2) increased retail core-market revenues, reflecting the result of higher average purchased gas cost (“PGC”) rates partially offset by the effects of the lower volumes sold. Increases or decreases in retail core-market customer revenues and cost of sales result principally 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 $71.6 million in the 2006 three-month period compared to $54.6 million in the 2005 three-month period largely reflecting greater costs associated with the higher off-system sales and the impact of the higher retail core-market purchased gas costs.
Gas Utility total margin in the 2006 three-month period decreased $0.2 million reflecting decreased retail core-market margin principally resulting from the lower sales to retail core-market customers partially offset by higher total margin from interruptible customers reflecting higher interruptible unit margins.
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Gas Utility operating income decreased to $6.6 million in the 2006 three-month period from $7.7 million in the 2005 three-month period principally reflecting the $0.3 million decrease in total margin, slightly lower other income and higher depreciation and amortization expense. Total operating and administrative expenses were comparable to the prior-year period as higher uncollectible accounts and customer assistance program costs were largely offset by lower incentive compensation and distribution system expenses.
The decrease in Gas Utility income before income taxes reflects the previously mentioned decrease in operating income and an increase in interest expense. The increase in interest expense is principally attributable to higher short-term debt outstanding, largely reflecting the effects of higher natural gas prices and higher short-term interest rates.
Electric Utility:
For the three months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||
Revenues (a) | $ | 22.9 | $ | 22.0 | $ | 0.9 | 4.1 | % | |||||
Total margin (a) (b) | $ | 10.5 | $ | 10.2 | $ | 0.3 | 2.9 | % | |||||
Operating income | $ | 5.2 | $ | 4.9 | $ | 0.3 | 6.1 | % | |||||
Income before income taxes | $ | 4.6 | $ | 4.4 | $ | 0.2 | 4.5 | % | |||||
Distribution sales - millions of kilowatt hours (“gwh”) (a) | 222.4 | 222.5 | (0.1 | ) | (0.0 | )% | |||||||
| (a) | Similar to Gas Utility, Electric Utility adjusted its method of estimating unbilled sales volumes and associated revenues for electricity consumed through the end of the month by more closely correlating such estimated sales volumes to distribution system sendout data. The change in the method of estimating unbilled sales resulted in a 1.6 gwh decrease in distribution system sales and associated decreases in Electric Utility revenues and total margin of $0.1 million for the 2006 three-month period. |
| (b) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.2 million in each of the three-month periods ended June 30, 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 were comparable to the prior-year period. Electric Utility revenues increased by $0.9 million in the 2006 three-month period largely reflecting the effects of a 3% increase in its Provider of Last Resort (“POLR”) rates effective January 1, 2006. Electric Utility’s cost of sales increased to $11.2 million in the 2006 three-month period from $10.6 million in the 2005 three-month period reflecting higher per unit purchased power costs.
Electric Utility total margin in the 2006 three-month period increased $0.3 million principally reflecting lower 2006 three-month period transmission and congestion costs and the higher POLR rates partially offset by the higher per unit purchased power costs.
Operating income increased in the 2006 three-month period principally reflecting the increase in total margin. The increase in income before income taxes principally reflects the higher operating income partially offset by higher interest expense on short-term debt.
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Energy Services:
For the three months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase | ||||||||||
Revenues | $ | 268.7 | $ | 290.6 | $ | (21.9 | ) | (7.5 | )% | ||||
Total margin (a) | $ | 20.3 | $ | 18.7 | $ | 1.6 | 8.6 | % | |||||
Operating income | $ | 10.4 | $ | 10.6 | $ | (0.2 | ) | (1.9 | )% | ||||
Income before income taxes | $ | 10.3 | $ | 10.6 | $ | (0.3 | ) | (2.8 | )% | ||||
| (a) | Total margin represents total revenues less total cost of sales. |
Energy Services revenues decreased to $268.7 million in the 2006 three-month period from $290.6 million in the 2005 three-month period reflecting an approximate 17% decline in natural gas volumes sold and a 25% decline in propane volumes sold, slightly offset by increased electric generation revenues. The decline in natural gas and propane volumes sold reflects the effects of warmer spring weather conditions in Energy Services’ service territories and customer losses associated with, among other things, maintenance of our credit risk management policy in a high natural gas price environment.
Total margin increased $1.6 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 margin contributed by electric generation and peaking supply and storage management activities partially offset by the effects of lower propane volumes sold.
The decrease in Energy Services operating income and income before income taxes principally reflects a $1.7 million increase in operating and administrative expenses. The increase in operating and administrative expenses primarily reflects increased costs associated with our electric generation business partially offset by a decrease in uncollectible accounts expense. As part of the consideration in the sale of our 50% ownership interest, Energy Ventures transferred its 48-megawatt coal-fired electric generation facility to UGID. As a result, UGID is no longer incurring cost of sales associated with purchasing a portion of its power needs from Energy Ventures, but is incurring operating and administrative expenses associated with the operation of the electric generation station.
2006 nine-month period compared to the 2005 nine-month period
AmeriGas Propane:
For the nine months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||||
Revenues | $ | 1,727.5 | $ | 1,604.0 | $ | 123.5 | 7.7 | % | |||||||
Total margin (a) | $ | 638.0 | $ | 614.1 | $ | 23.9 | 3.9 | % | |||||||
Partnership EBITDA (b) | $ | 229.1 | $ | 208.0 | $ | 21.1 | 10.1 | % | |||||||
Operating income | $ | 193.9 | $ | 178.1 | $ | 15.8 | 8.9 | % | |||||||
Retail gallons sold (millions) | 804.4 | 857.5 | (53.1 | ) | (6.2 | )% | |||||||||
Degree days - % (warmer) colder than normal (c) | (10.3 | )% | (6.1 | )% | — | — | |||||||||
| (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 3 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. |
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Temperatures during the 2006 nine-month period were 10.3% warmer than normal and 4.5% warmer than the prior-year period. Retail propane volumes sold decreased approximately 6% principally due to the warmer winter weather and the negative effects of customer conservation driven by continued high propane selling prices.
Retail propane revenues increased $108.4 million reflecting a $194.3 million increase due to higher average selling prices partially offset by an $85.9 million decrease due to the lower retail volumes sold. Wholesale propane revenues were comparable with the prior year reflecting a $22.5 million decrease due to lower volumes sold offset by a $21.7 million increase due to higher average selling prices. In the 2006 nine-month period, our average retail propane product cost per retail gallon sold was approximately 19% higher than in the 2005 nine-month period, which resulted in higher year-over-year prices to our customers. The average wholesale cost per gallon of propane at Mont Belvieu, one of the major propane supply points in the United States, was approximately 24% greater than the average cost per gallon during the 2005 nine-month period. Total cost of sales increased to $1,089.5 million in the 2006 nine-month period from $989.9 million in the 2005 nine-month period, primarily reflecting the increase in propane product costs partially offset by the decreased volumes sold. Total margin increased $23.9 million compared to the 2005 nine-month period due to increased customer pricing of propane and ancillary sales and services in response to increase in costs incurred.
Partnership EBITDA during the 2006 nine-month period was $229.1 million compared to $208.0 million during the 2005 nine-month period. This $21.1 million increase in Partnership EBITDA primarily reflects the previously mentioned increase in total margin and a $16.5 million decrease in the loss on the early extinguishment of debt from $33.6 million in the 2005 nine-month period to $17.1 million in the 2006 nine-month period. These changes were partially offset by an $11.1 million increase in operating and administrative expenses and an $8.2 million decrease in other income primarily reflecting the absence of the $9.1 million pre-tax gain on the sale of Atlantic Energy recognized during the 2005 nine-month period. The $17.1 million loss on the early extinguishment of debt that was incurred during the 2006 nine-month period was associated with the refinancings of AmeriGas OLP’s Series A and Series C First Mortgage Notes totaling $228.8 million and $59.6 million of the Partnership’s $60 million 10% Senior Notes with $350 million of 7.125% Senior Notes due 2016. The increase in operating and administrative expenses principally resulted from higher vehicle fuel and lease expense and higher employee compensation and benefits expenses. These increases were partially offset by a $5.9 million favorable net expense reduction related to general insurance, litigation and medical claims, primarily reflecting improved claims history.
Operating income increased $15.8 million reflecting the previously mentioned increase in total margin and a $2.0 million decrease in depreciation and amortization expense, largely offset by the previously mentioned increase in operating and administrative expenses and decrease in other income.
International Propane:
For the nine months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||
Revenues | $ | 817.1 | $ | 804.4 | $ | 12.7 | 1.6 | % | |||||
Total margin (a) | $ | 359.7 | $ | 425.3 | $ | (65.6 | ) | (15.4 | )% | ||||
Operating income | $ | 121.7 | $ | 189.6 | $ | (67.9 | ) | (35.8 | )% | ||||
Income before income taxes | $ | 102.8 | $ | 162.3 | $ | (59.5 | ) | (36.7 | )% | ||||
Antargaz retail gallons sold (millions) | 272.1 | 289.6 | (17.5 | ) | (6.0 | )% | |||||||
Antargaz total margin, millions of euros (a) | € | 280.8 | € | 307.7 | (€26.9 | ) | (8.7 | )% | |||||
| (a) | Total margin represents total revenues less total cost of sales. |
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Weather in Antargaz’ service territory was approximately 1% warmer than normal compared to 3% warmer than normal in the 2005 nine-month period. Flaga experienced colder than normal weather in the 2006 nine-month period compared to warmer than normal weather in the prior-year nine-month period. During the 2006 nine-month period, the monthly average currency translation rate was $1.22 per euro compared to $1.29 per euro in the 2005 nine-month period. Antargaz’ retail LPG volumes sold decreased to 272.1 million gallons from 289.6 million gallons in the 2005 nine-month period due in large part to the late onset of winter weather in December, lower agricultural volumes sold and customer conservation.
International Propane revenues increased during the 2006 nine-month period reflecting significantly higher retail LPG selling prices per gallon on lower retail gallons sold, largely offset by the effect of the stronger dollar versus the euro. Higher average LPG product cost per retail gallon sold than in the 2005 nine-month period resulted in higher year-over-year prices to our customers. International Propane’s total cost of sales increased to $457.4 million during the 2006 nine-month period from $379.1 million during the 2005 nine-month period reflecting the significantly higher LPG product costs partially offset by the effect of the stronger dollar.
Total International Propane margin declined $65.6 million in the 2006 nine-month period compared to the prior-year period primarily reflecting the absence of higher than normal LPG unit margin experienced in the prior year and approximately $29 million due to the negative currency translation effect of a stronger dollar. Antargaz’ total base currency margin declined €26.9 million reflecting the lower unit margins and, to a much lesser extent, lower volumes sold.
International Propane operating income declined $67.9 million in the 2006 nine-month period principally reflecting the decline in total margin, the absence of $19.9 million from the reversal of certain non-income related tax reserves which were recorded in the prior-year period (see discussion in “Antargaz Tax Matter”) partially offset by an approximate $15.0 million decrease in operating and administrative expenses and slight decreases in depreciation and amortization. These decreases reflect the effects of the stronger dollar versus the euro with only a modest decrease attributed to the Czech Republic and Slovakia operations being contributed to the Flaga JV. Antargaz’ total base-currency operating and administrative expenses were comparable with the 2005 nine-month period.
The decrease in income before income taxes principally reflects the decrease in operating income and a $1.4 million loss on early extinguishment of debt partially offset by changes in minority interest and lower interest expense. The changes in minority interest reflect the minority interest holder’s (in one of Antargaz’ subsidiaries) share of costs associated with the closure of a filling and distribution center, as previously mentioned.
Gas Utility:
For the nine months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||||
Revenues (a) | $ | 622.3 | $ | 506.6 | $ | 115.7 | 22.8 | % | |||||||
Total margin (a) (b) | $ | 167.8 | $ | 168.1 | $ | (0.3 | ) | (0.2 | )% | ||||||
Operating income | $ | 82.2 | $ | 84.4 | $ | (2.2 | ) | (2.6 | )% | ||||||
Income before income taxes | $ | 67.8 | $ | 72.4 | $ | (4.6 | ) | (6.4 | )% | ||||||
System throughput - billions of cubic feet (“bcf”) (a) | 64.4 | 69.2 | (4.8 | ) | (6.9 | )% | |||||||||
Degree days - % (warmer) than normal (c) | (8.8 | )% | (0.7 | )% | — | — | |||||||||
| (a) | Beginning in Fiscal 2006, Gas Utility adjusted its method of estimating unbilled throughput and associated revenues for service provided through the end of the month by more closely correlating such estimated throughput to |
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distribution system sendout data. The Company believes that the new method of estimating unbilled throughput results in a more accurate quarterly estimate of unbilled revenues and associated total margin. The change in the method of estimating unbilled throughput did not have a material impact on Gas Utility’s throughput, revenues or margin for the 2006 nine-month period. |
| (b) | Total margin represents total revenues less total cost of sales. |
| (c) | Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 4 airports located within our service territory. The 2005 nine-month period degree day statistics have been restated to reflect the current-year, four-location average from the previous single location statistic. |
Weather in Gas Utility’s service territory based upon heating degree days was 8.8% warmer than normal during the 2006 nine-month period and approximately normal in the prior-year nine-month period. Notwithstanding year-over-year growth in the number of our customers, total distribution system throughput decreased 4.8 bcf due to a decrease in sales to retail core-market customers reflecting the warmer weather and price-induced customer conservation, and lower volumes transported for firm and interruptible delivery service customers.
Gas Utility revenues increased $115.7 million during the 2006 nine-month period principally reflecting an $81.9 million increase in retail core-market revenues, the result of higher average PGC rates, and a $33.8 million increase in revenues from low-margin off-system sales. Gas Utility’s cost of gas was $454.5 million in the 2006 nine-month period compared to $338.5 million in the 2005 nine-month period reflecting the impact of the previously mentioned higher retail core-market purchased gas costs and greater costs associated with the higher off-system sales.
Gas Utility total margin in the 2006 nine-month period was comparable to the prior-year nine-month period as the decrease in retail core-market margin resulting from the lower sales was offset by higher total margin from interruptible customers and customer assistance tariff revenues.
Gas Utility operating income decreased $2.2 million in the 2006 nine-month period principally reflecting $0.9 million of increased depreciation and amortization expense, a $0.6 million decrease in other income and a $0.4 million increase in operating and administrative expenses. The increase in operating and administrative expenses reflects increased required environmental remediation reserves and higher uncollectible accounts and customer assistance expenses largely offset by lower 2006 nine-month period stock-based incentive compensation costs and lower distribution system maintenance expenses resulting, in large part, from the mild heating-season weather.
The decrease in Gas Utility income before income taxes reflects the previously mentioned decrease in operating income and an increase in interest expense attributable to higher short-term debt outstanding, largely reflecting the effects of higher natural gas prices, and higher short-term interest rates.
Electric Utility:
For the nine months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase (Decrease) | ||||||||||
Revenues (a) | $ | 72.2 | $ | 69.9 | $ | 2.3 | 3.3 | % | |||||
Total margin (a) (b) | $ | 30.5 | $ | 32.5 | $ | (2.0 | ) | (6.2 | )% | ||||
Operating income | $ | 15.0 | $ | 16.8 | $ | (1.8 | ) | (10.7 | )% | ||||
Income before income taxes | $ | 13.1 | $ | 15.3 | $ | (2.2 | ) | (14.4 | )% | ||||
Distribution sales - millions of kilowatt hours (“gwh”)(b) | 748.8 | 753.7 | (4.9 | ) | (0.7 | )% | |||||||
| (a) | Similar to Gas Utility, Electric Utility adjusted its method of estimating unbilled sales volumes and associated revenues for electricity consumed through the end of the month by more closely correlating such estimated sales volumes to distribution system sendout data. The change in the method of estimating unbilled sales volumes did not have a material effect on sales, revenues or margin for the 2006 nine-month period. |
| (b) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $4.0 million and $3.9 million in the nine-month periods ended June 30, 2006 and 2005, respectively. For |
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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 nine-month period kilowatt-hour sales decreased 0.7% compared to the prior-year period. Electric Utility revenues increased $2.3 million in the 2006 nine-month period largely reflecting higher POLR electric generation rates partially offset by the effects of the lower sales. Electric Utility’s cost of sales increased to $37.7 million in the 2006 nine-month period from $33.5 million in the 2005 nine-month period reflecting higher per unit purchased power costs partially offset by the effects of lower sales.
Electric Utility total margin in the 2006 nine-month period decreased $2.0 million compared to the 2005 nine-month period principally reflecting the higher per unit purchased power costs partially offset by the increase in POLR electric generation rates.
Operating income decreased in the 2006 nine-month period principally reflecting the decrease in total margin partially offset by slightly lower 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:
For the nine months ended June 30, (Millions of dollars) | 2006 | 2005 | Increase | |||||||||
Revenues | $ | 1,158.9 | $ | 1,051.8 | $ | 107.1 | 10.2 | % | ||||
Total margin (a) | $ | 65.4 | $ | 56.8 | $ | 8.6 | 15.1 | % | ||||
Operating income | $ | 44.7 | $ | 30.7 | $ | 14.0 | 45.6 | % | ||||
Income before income taxes | $ | 44.6 | $ | 30.7 | $ | 13.9 | 45.3 | % | ||||
| (a) | Total margin represents total revenues less total cost of sales. |
Energy Services revenues increased $107.1 million in the 2006 nine-month period compared to the 2005 nine-month period. Revenues generated by Energy Services’ natural gas and oil marketing business increased approximately $81 million in the 2006 nine-month period despite a 26% decrease in natural gas volumes sold reflecting the effects of higher natural gas product costs. The decline in natural gas volumes sold reflects the effects of warmer weather conditions in Energy Services’ service territories and customer losses associated with, among other things, maintenance of our credit risk management policy in a high natural gas price environment. Asset Management provided approximately $20 million in higher revenues largely reflecting higher propane product costs and, to a lesser extent, sales associated with the full-period ownership of its propane terminal. The terminal was purchased in November 2004. The remaining increase in revenues is attributed to our electric generation marketing activities.
Total margin increased $8.6 million in the 2006 nine-month period compared to the prior-year nine-month period. The increase in total margin is primarily attributed to higher margin from electric generation, peaking supply and storage management activities, and propane terminal operations, partially offset by lower natural gas margin attributed to the lower natural gas volumes sold.
The increase in Energy Services operating income and income before income taxes principally reflects a $9.1 million gain on the sale of its 50% ownership interest in Energy Ventures in March 2006 and the previously mentioned increase in total margin partially offset by $2.6 million higher operating and administrative expenses and $0.5 million higher depreciation and amortization expense. The increase in operating and administrative expenses principally reflects increased operating expenses associated with electric generation partially offset by a decrease in uncollectible accounts expense.
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FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
Our cash, cash equivalents and short-term investments totaled $407.6 million at June 30, 2006 compared with $385.0 million at September 30, 2005. Excluding cash, cash equivalents and short-term investments that reside at UGI’s operating subsidiaries at June 30, 2006 and September 30, 2005, we have $250.3 million and $138.7 million, respectively, of cash, cash equivalents and short-term investments.
The Company’s long-term debt outstanding at June 30, 2006 totaled $1,721.3 million (including current maturities of $78.6 million) compared to $1,644.5 million of long-term debt (including current maturities of $252.0 million) at September 30, 2005.
AmeriGas OLP’s Credit Agreement expires on October 15, 2008 and consists of (1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. 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 June 30, 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 $58.9 million at June 30, 2006 and was approximately the same amount outstanding during the entire nine-month period ended June 30, 2006. 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. Due in part to the issuance of 2.3 million Common Units in September 2005, during the 2006 nine-month period generally, the Partnership did not need to use its Revolving Credit Facility to fund its operations. During the nine months ended June 30, 2005, the average daily borrowings outstanding under the Credit Agreement were $32.0 million and the peak borrowings outstanding were $98.0 million. 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.
In January 2006, the Partnership and AP Eagle Finance Corp. issued $350 million of 7.125% Senior Notes due 2016. The proceeds of this registered public debt offering were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C First Mortgage Notes, including a make-whole premium, its $35 million term loan due October 1, 2006 and $59.6 million of the Partnership’s $60 million 10% Senior Notes due 2006 pursuant to a tender offer, plus a premium. UGI incurred a pre-tax loss on extinguishment of debt associated with the refinancings of approximately $17.1 million ($4.6 million after-tax).
On December 7, 2005, Antargaz executed a new five-year, floating rate Senior Facilities Agreement with a major French bank providing for a €380 million term loan and a €50 million revolving credit facility which expires March 31, 2011. At June 30, 2006, there were no borrowings outstanding under the revolver. The proceeds of the term loan were used in December 2005 to repay immediately the existing €175 million Senior Facilities term loan, to fund the redemption of the €165 million High Yield Bonds in January 2006, including a premium, and for general corporate purposes. As a result of this refinancing, we incurred a pre-tax loss on extinguishment of debt of $1.4 million ($0.9 million
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after-tax). In addition, AGZ executed interest rate swap agreements with the same bank to fix the rate of interest on the term loan for the duration of the loan at a rate of approximately 3.25%, plus a margin.
At June 30, 2006, Flaga had approximately $54.4 million of long-term debt maturing during 2006. On July 26, 2006, Flaga entered into a euro-based term loan facility in the amount of €48 million ($61.4 million) and a working capital facility of up to €8 million. These facilities are subject to guarantees by UGI. In addition, on July 26, 2006, the Flaga JV entered into a multi-currency working capital facility of up to €8 million which is also subject to guarantees by UGI.
UGI Utilities has revolving credit agreements under which it may borrow up to a total of $110 million. These agreements expire in June 2007 through June 2008. From time to time, UGI Utilities makes short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. At June 30, 2006, UGI Utilities had $20 million in short-term borrowings outstanding under these uncommitted arrangements and $92.1 million in borrowings outstanding under the revolving credit agreements. Short-term borrowings, including borrowings under revolving credit agreements, are classified as bank loans on the Condensed Consolidated Balance Sheets. During the nine months ended June 30, 2006 and 2005, average daily bank loan borrowings were $111.8 million and $50.4 million, respectively, and peak bank loan borrowings totaled $175.9 million and $90.4 million, respectively. The increase in average and peak bank loan borrowings during the 2006 nine-month period reflects, in large part, borrowings to fund increased working capital resulting principally from higher natural gas prices. UGI Utilities expects to increase its revolving credit agreement commitments to $350 million prior to September 30, 2006. The size of the increase takes into account expected working capital requirements of PG Energy (see “PG Energy Acquisition” described below). 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.
Energy Services has a $150 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009. In order to provide additional short-term liquidity during the peak heating season due to increased energy product costs, the maximum level of funding available at any one time from this facility was temporarily increased to $300 million for the period from November 1, 2005 to April 24, 2006. The fees associated with temporarily increasing the maximum level of funding were not material. After April 24, 2006, the maximum level of funding available at any one time from this facility is $150 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. The proceeds of these sales are less than the face amount of the accounts receivable sold by an amount that approximates the purchaser’s financing cost of issuing its own receivables-backed commercial paper. ESFC 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. At June 30, 2006, the outstanding balance of ESFC receivables was $30.2 million which is net of $42.0 million in trade receivables sold to the commercial paper conduit.
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In addition, a major bank has committed to Energy Services to issue up to $50 million of standby letters of credit, secured by cash or marketable securities (“LC Facility”). At June 30, 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 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, propane and other LPG and electricity 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 revolving credit facilities and Energy Services uses its Receivables Facility to satisfy their seasonal operating cash flow needs. Antargaz has historically been successful funding its operating cash flow needs without the use of its revolver.
Cash flow provided by operating activities was $193.0 million in the 2006 nine-month period compared to $316.7 million in the 2005 nine-month period. Cash flow from operating activities before changes in operating working capital was $404.4 million in the 2006 nine-month period compared with $406.6 million in the prior-year nine-month period. Changes in operating working capital used $211.4 million in the 2006 nine-month period and $89.9 million in the 2005 nine-month period. The greater cash requirements to fund working capital reflect, in part, the effects of higher energy commodity prices.
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 $165.6 million in the 2006 nine-month period compared to $138.0 million in the prior-year period. The increase in investing activities largely reflects our increased investments in short-term investments, our international operations and property, plant and equipment partially offset by the net proceeds received from Energy Services’ sale of its 50% ownership interest in Energy Ventures in March 2006 and lower AmeriGas Propane acquisition activity.
Financing Activities. Cash flow used by financing activities was $54.9 million in the 2006 nine-month period compared with $113.7 million of cash used in the prior-year nine-month period. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt, net borrowings under revolving credit facilities, dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units, and proceeds from public offerings of AmeriGas Partners Common Units and issuances of UGI common stock. In December 2005, Antargaz entered into a €380 million term loan. The proceeds were used to repay the existing €175 million Senior Facilities term loan, redeem its €165 million of High Yield Bonds and for general corporate purposes. Antargaz incurred a $1.4 million loss on extinguishment of debt associated with its refinancings. Also, in December 2005, UGI Utilities refinanced $50 million of its maturing 7.14% Medium-Term Notes with the proceeds from the issuance of $50 million of 5.64% Medium-Term Notes. In January 2006, the Partnership and AP Eagle Finance Corp. issued $350 million of 7.125% Senior Notes due 2016. The proceeds of this registered public debt offering were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C First Mortgage Notes, including a make-whole premium, its $35 million term loan due October 1, 2006 and $59.6 million of the Partnership’s $60 million 10% Senior Notes due 2006 pursuant to a tender offer, plus a premium. The Partnership incurred a $17.1 million loss on early extinguishment of debt associated with these refinancings. UGI Utilities’ net bank loan borrowings during the 2006 nine-month period include repayments of two $35 million borrowings with maturities greater than three months and a $20 million borrowing made on June 1, 2006, which matures on September 8, 2006.
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We paid cash dividends on UGI Common Stock of $54.1 million and $49.9 million during the nine months ended June 30, 2006 and 2005, respectively. During the nine months ended June 30, 2006, the Partnership declared and paid quarterly distributions on its limited partner units for the quarters ended March 31, 2006, December 31, 2005 and September 30, 2005. On April 24, 2006, AmeriGas Propane’s Board of Directors approved an increase in its quarterly distribution rate on AmeriGas Partners Common Units to $0.58 per Common Unit ($2.32 annually) from $0.56 per Common Unit ($2.24 annually). The quarterly distribution of $0.58 for the quarter ended June 30, 2006 will be paid on August 18, 2006 to holders of record on August 10, 2006.
UGI Common Dividend Increase
On April 25, 2006, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.17625 per share or $0.705 per common share on an annual basis. The new quarterly dividend was effective with the dividend payable on July 1, 2006 to shareholders of record on June 15, 2006. On July 25, 2006, UGI’s Board of Directors declared a quarterly dividend on UGI Common Stock of $0.17625 per common share payable on October 1, 2006 to shareholders of record on September 15, 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. Prior to the Antargaz Acquisition, Antargaz filed suit against French tax authorities in connection with the assessment of business tax related to the tax treatment of certain of its owned tanks at customer locations. Elf Antar France and Elf Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify Antargaz for all payments that would have been due from Antargaz in respect of the tax related to its tanks for the period from January 1, 1997 through December 31, 2000. Antargaz has recorded liabilities for business taxes related to various classes of equipment. On February 4, 2005, Antargaz received a letter that was issued by the French government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry group, concerning the business tax, that eliminated the requirement for Antargaz to pay business tax associated with tanks at certain customer locations. In addition, during Fiscal 2005, resolution was reached relating to business taxes relating to a prior year. Further changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations. Our Condensed Consolidated Statements of Income for the nine months ended June 30, 2005 include a pre-tax gain of $19.9 million and a net after-tax gain of $14.9 million associated with the resolution of certain business tax matters related principally to prior years.
PG Energy Acquisition
On January 26, 2006, UGI signed a definitive agreement to acquire the natural gas utility assets of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments. We expect the acquisition to be funded with a combination of debt and existing cash. PG Energy serves approximately 158,000 customers in 13 counties in northeastern and central Pennsylvania. The
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proposed transaction is subject to PUC approval and is expected to close during our fourth fiscal quarter ending September 30, 2006. We anticipate that UGI Utilities will acquire and operate, through a subsidiary, the regulated assets of PG Energy immediately following completion of the acquisition.
Flaga Joint Venture
On February 15, 2006, Flaga entered into a joint venture with a subsidiary of Progas GmbH & Co KG (“Progas”) to create a company for the retail distribution of LPG in central and eastern Europe. Headquartered in Dortmund, Germany, Progas is controlled by Thyssen’sche Handelsgesellschaft m.b.H. The joint venture company, Zentraleuropa LPG Holding (the “Flaga JV”), an Austrian limited liability company, through its subsidiaries engages in the retail distribution of LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. In forming the joint venture, Flaga contributed the shares of its LPG subsidiaries operating in the Czech Republic and Slovakia to the Flaga JV and paid cash of €9.1 million to Progas. Progas contributed the shares of its LPG subsidiaries operating in the Czech Republic, Hungary, Poland, Romania, and Slovakia to the Flaga JV. These LPG operating subsidiaries distributed approximately 77 million gallons of LPG in these five countries in 2005. The Flaga JV is owned and controlled equally by Flaga and Progas. In a related transaction, Flaga purchased Progas’ retail LPG business in Austria.
Recently Issued Accounting Pronouncements
In March 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 156, “Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140” (“SFAS 156”). We are currently evaluating the impact that the adoption of SFAS 156 will have on our financial position or results of operations. See Note 1 to the Condensed Consolidated Financial Statements for additional information.
In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” We are currently evaluating the impact that this standard will have on our financial position or results of operations. See Note 1 to the Condensed Consolidated Financial Statements for additional information.
| 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. International Propane and the Partnership 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. Over-the-counter
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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. Gas Utility uses exchange-traded natural gas call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these call option contracts, net of any associated gains, is included in Gas Utility’s PGC recovery mechanism.
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, to provide retail POLR electric generation service to its customers that do not elect to receive such service from alternate suppliers. Currently, the rates it may charge its customers for POLR service are set at or below certain levels established in settlements approved by the PUC. Under a settlement approved in 2004, Electric Utility increased its POLR rates for all metered customers by a total of 4.5% effective January 2005 and an additional 3% effective January 2006, above the total rates in effect on December 31, 2004. In June 2006, the PUC approved a settlement permitting system average increases in maximum POLR rates, on a total bill basis, of 37.8% for 2007, and additional increases of 5.7% and 1.1% for 2008 and 2009, respectively. Wholesale prices for electricity can be volatile, especially during periods of high demand or tight supply. Currently, Electric Utility’s fixed-price power and capacity contracts with electricity suppliers mitigate a substantial portion of its commodity price risk associated with 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 the risk associated with non-performance, 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.
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 natural gas futures contracts or enters into fixed-price supply arrangements. Exchange-traded natural gas futures contracts are guaranteed by the New York Mercantile Exchange (“NYMEX”) and have nominal credit risk. The change in market value of these contracts generally requires daily cash deposits in margin accounts with brokers. At June 30, 2006, Energy Services had $7.3 million deposited into 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 conjunction with certain of these sales agreements, at June
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30, 2006, UGID had $3.8 million in collateral deposits held by its counterparties which amount is reflected in other assets on the Consolidated Balance Sheet. 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 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, borrowings under UGI Utilities’ revolving credit agreements and a substantial portion of Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At June 30, 2006, combined borrowings outstanding under these agreements totaled approximately $181.8 million. Antargaz has effectively fixed the interest rate on its variable-rate debt through June 2011 through the use of interest rate swaps. 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 June 30, 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 June 30, 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-month Euribor and; (5) value of the euro versus the U.S. dollar.
(Millions of dollars) | Fair Value | Change in Fair Value | ||||||
June 30, 2006: | ||||||||
Propane commodity price risk | $ | 18.1 | $ | (18.9 | ) | |||
Natural gas commodity price risk | (6.0 | ) | (10.4 | ) | ||||
Electricity commodity price risk | 6.7 | (1.4 | ) | |||||
Interest rate risk | 19.6 | (18.7 | ) | |||||
Foreign currency exchange rate risk | (1.1 | ) | (19.2 | ) | ||||
Gas Utility’s exchange-traded natural gas call option contracts are excluded from the table above because any associated net gains are included in Gas Utility’s PGC recovery mechanism. 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.
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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 June 30, 2006, the fair value of unsettled net investment hedges was a loss of $0.8 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 $50.7 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 SEC’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 |
No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II OTHER INFORMATION
| ITEM 1. | LEGAL PROCEEDINGS |
Charleston, South Carolina Gas Plant Matter. By letter dated July 14, 2006, SCANA Corporation (“SCANA”), demanded contribution from UGI Utilities for a portion of past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. According to the letter, the plant operated from 1855 to 1954. SCANA alleges that UGI Utilities controlled operations of the plant from 1910 to 1926. SCANA asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site. It estimates that future remediation costs could be as high as $2.5 million and asserts that it has received a demand from the United States Justice Department for natural resource damages. SCANA claims that UGI Utilities is liable for 47% of the costs associated with the site. UGI Utilities is in the process of reviewing the information provided by SCANA and is investigating this claim.
City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court 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 million 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 of 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. 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.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million 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 million. KeySpan believes that the cost could go as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
| ITEM 1A. | RISK FACTORS |
In addition to the information presented below and 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, 2005, 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.
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THE EXPANSION OF OUR INTERNATIONAL BUSINESS MEANS THAT WE WILL FACE INCREASED RISKS, WHICH MAY NEGATIVELY AFFECT OUR BUSINESS RESULTS.
Our acquisition of Antargaz in March of 2004 significantly increased our international presence. As we continue to grow as a multi-national corporation, with subsidiaries around the world, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:
| • | costs and difficulties in staffing and managing international operations; |
| • | tariffs and other trade barriers; |
| • | difficulties in enforcing contractual rights; |
| • | longer payment cycles; |
| • | local political and economic conditions; |
| • | potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”; |
| • | fluctuations in currency exchange rates, which can affect demand and increase our costs; and |
| • | regulatory requirements and changes in regulatory requirements, including French and EU competition laws that may adversely affect the terms of contracts with customers, and new environmental requirements that have led to stricter regulations of LPG storage sites in France. |
On June 14, 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Management believes that the DGCCRF performed similar unannounced inspections and document seizures at the locations of other distributors of LP gas in France, as well as at the industry association, Comite Francais du Butane et du Propane (“CFBP”). The investigation apparently seeks evidence of unlawful anticompetitive activities affecting the packaged LP gas (i.e., cylinder) business in northern France. Management intends to cooperate with the investigation, if it should receive any further inquiries.
In an apparently unrelated matter, on October 17, 2005, the DGCCRF, with Antargaz’ knowledge and cooperation, interviewed Antargaz’ director of supply and director of logistics regarding the purchase of LP gas by Antargaz, and Antargaz’ distribution network. The agency’s questions appeared to focus solely on the auto gas (i.e., motor fuel) market in France. The DGCCRF indicated at that time that it also intended to interview other industry participants (the agency interviewed CFBP on the same topic in January of 2006). The agency also indicated that it should not require any further interviews of Antargaz personnel and no further inquiries have been received regarding this matter.
Antargaz has not been notified that it is the subject of an investigation by the DGCCRF. In the event Antargaz were found to have violated the competition laws in France, it would be subject to civil penalties up to a maximum of ten percent (10%) of the total revenues of UGI.
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| ITEM 6. | EXHIBITS |
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 | Description of UGI Corporation Senior Executive Employee Severance Pay Plan, amended July 25, 2006 | |||||||
| 10.2 | Description of July 25, 2006 Amendment to the UGI Corporation Supplemental Executive Retirement Plan | |||||||
| 10.3 | Description of AmeriGas Propane, Inc. Executive Employee Severance Pay Plan, amended July 24, 2006 | AmeriGas Partners, L.P. | Form 10-K (8/8/06) | 10.1 | ||||
| 10.4 | Description of AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, amended July 24, 2006 | AmeriGas Partners, L.P. | Form 10-K (8/8/06) | 10.2 | ||||
| 10.5 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the Multi Currency Working Capital Facility dated July 26, 2006 between Zentraleuropa LPG Holding GmbH (“ZLH”) and RZB | |||||||
| 10.6 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Working Capital Facility dated July 26, 2006 between Flaga GmbH (“Flaga”) and RZB | |||||||
| 10.7 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Term Loan Agreement dated July 26, 2006 between Flaga and RZB | |||||||
| 10.8 | Term Loan Agreement, dated July 26, 2006, between Flaga, as Borrower, and RZB, as Lender | |||||||
| 10.9 | Working Capital Facility Agreement, dated July 26, 2006, between Flaga, as Borrower, and RZB, as Lender | |||||||
| 10.10 | Multi Currency Working Capital Facility Agreement, dated July 26, 2006, between ZLH, as Borrower, and RZB, as Lender | |||||||
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| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 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 June 30, 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 June 30, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||||
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
UGI Corporation (Registrant) | ||||||||
| Date: August 8, 2006 | By: | /s/ Anthony J. Mendicino | ||||||
Anthony J. Mendicino Senior Vice President-Finance and Chief Financial Officer | ||||||||
| Date: August 8, 2006 | By: | /s/ Michael J. Cuzzolina | ||||||
Michael J. Cuzzolina Vice President-Accounting and Financial Control and Chief Risk Officer | ||||||||
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EXHIBIT INDEX
| 10.1 | Description of UGI Corporation Senior Executive Employee Severance Pay Plan, amended July 25, 2006. | |
| 10.2 | Description of July 25, 2006 Amendment to the UGI Corporation Supplemental Executive Retirement Plan. | |
| 10.5 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the Multi Currency Working Capital Facility dated July 26, 2006 between Zentraleuropa LPG Holding GmbH (“ZLH”) and RZB. | |
| 10.6 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Working Capital Facility dated July 26, 2006 between Flaga GmbH (“Flaga”) and RZB. | |
| 10.7 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Term Loan Agreement dated July 26, 2006 between Flaga and RZB. | |
| 10.8 | Term Loan Agreement, dated July 26, 2006, between Flaga, as Borrower, and RZB, as Lender. | |
| 10.9 | Working Capital Facility Agreement, dated July 26, 2006, between Flaga, as Borrower, and RZB, as Lender. | |
| 10.10 | Multi Currency Working Capital Facility Agreement, dated July 26, 2006, between ZLH, as Borrower, and RZB, as Lender. | |
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 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 June 30, 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 June 30, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |