| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| Pennsylvania (State or other jurisdiction of incorporation or organization) |
23-2668356 (I.R.S. Employer Identification No.) |
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
| PAGES | ||||||||
Part I Financial Information |
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Item 1. Financial Statements (unaudited) |
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| 1 | ||||||||
| 2 | ||||||||
| 3 | ||||||||
| 4 – 34 | ||||||||
| 35 – 55 | ||||||||
| 55 – 58 | ||||||||
| 59 | ||||||||
| 60 – 61 | ||||||||
| 61 | ||||||||
| 62 | ||||||||
| 63 | ||||||||
| Exhibit 31.1 | ||||||||
| Exhibit 31.2 | ||||||||
| Exhibit 32 | ||||||||
- i -
| June 30, | September 30, | June 30, | ||||||||||
| 2009 | 2008 | 2008 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 240.1 | $ | 245.2 | $ | 272.2 | ||||||
Restricted cash |
64.8 | 70.3 | 4.3 | |||||||||
Accounts receivable (less allowances for doubtful accounts of
$58.2, $40.8 and $45.5, respectively) |
454.5 | 488.0 | 692.6 | |||||||||
Accrued utility revenues |
21.2 | 20.8 | 22.3 | |||||||||
Inventories |
269.1 | 400.8 | 318.0 | |||||||||
Deferred income taxes |
49.3 | 27.5 | 9.4 | |||||||||
Utility regulatory assets |
28.8 | 16.0 | — | |||||||||
Derivative financial instruments |
12.4 | 12.7 | 104.6 | |||||||||
Prepaid expenses and other current assets |
21.0 | 57.3 | 17.8 | |||||||||
Total current assets |
1,161.2 | 1,338.6 | 1,441.2 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $1,750.5, $1,515.1 and $1,494.4, respectively) |
2,823.3 | 2,449.5 | 2,483.0 | |||||||||
Goodwill |
1,545.5 | 1,489.7 | 1,569.1 | |||||||||
Intangible assets (less accumulated amortization of $103.8, $90.1 and $104.3, respectively) |
161.6 | 155.0 | 173.8 | |||||||||
Utility regulatory assets |
112.7 | 91.4 | 91.8 | |||||||||
Investments in equity investees |
2.9 | 63.1 | 70.8 | |||||||||
Other assets |
94.1 | 97.7 | 137.6 | |||||||||
Total assets |
$ | 5,901.3 | $ | 5,685.0 | $ | 5,967.3 | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Current maturities of long-term debt |
$ | 11.6 | $ | 81.8 | $ | 82.2 | ||||||
UGI Utilities bank loans |
110.0 | 57.0 | 30.0 | |||||||||
AmeriGas Propane bank loans |
— | — | 26.0 | |||||||||
Other bank loans |
15.5 | 79.4 | 10.2 | |||||||||
Accounts payable |
276.4 | 461.8 | 494.9 | |||||||||
Derivative financial instruments |
95.1 | 103.2 | 21.9 | |||||||||
Utility deferred fuel refunds |
13.5 | — | 87.9 | |||||||||
Other current liabilities |
424.2 | 401.0 | 365.8 | |||||||||
Total current liabilities |
946.3 | 1,184.2 | 1,118.9 | |||||||||
Long-term debt |
2,087.9 | 1,987.3 | 2,059.4 | |||||||||
Deferred income taxes |
464.7 | 491.0 | 544.6 | |||||||||
Deferred investment tax credits |
5.8 | 6.0 | 6.1 | |||||||||
Other noncurrent liabilities |
554.5 | 439.6 | 411.8 | |||||||||
Total liabilities |
4,059.2 | 4,108.1 | 4,140.8 | |||||||||
Commitments and contingencies (note 7) |
||||||||||||
Minority interests, principally in AmeriGas Partners |
258.8 | 159.2 | 243.7 | |||||||||
Common
stockholders’ equity: |
||||||||||||
Common Stock, without par value (authorized — 300,000,000 shares;
issued — 115,261,294, 115,247,694 and 115,244,694 shares, respectively) |
870.4 | 858.3 | 852.8 | |||||||||
Retained earnings |
837.0 | 630.9 | 658.0 | |||||||||
Accumulated other comprehensive (loss) income |
(71.7 | ) | (15.2 | ) | 130.2 | |||||||
| 1,635.7 | 1,474.0 | 1,641.0 | ||||||||||
Treasury stock, at cost |
(52.4 | ) | (56.3 | ) | (58.2 | ) | ||||||
Total common stockholders’ equity |
1,583.3 | 1,417.7 | 1,582.8 | |||||||||
Total liabilities and stockholders’ equity |
$ | 5,901.3 | $ | 5,685.0 | $ | 5,967.3 | ||||||
- 1 -
| Three Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenues |
$ | 962.2 | $ | 1,332.8 | $ | 4,878.5 | $ | 5,459.0 | ||||||||
Costs and expenses: |
||||||||||||||||
Cost of sales |
591.6 | 948.6 | 3,142.8 | 3,881.2 | ||||||||||||
Operating and administrative expenses |
281.0 | 283.3 | 929.6 | 886.7 | ||||||||||||
Utility taxes other than income taxes |
4.2 | 4.4 | 13.8 | 13.7 | ||||||||||||
Depreciation and amortization |
51.3 | 46.8 | 148.8 | 137.5 | ||||||||||||
Other expense (income), net |
5.3 | (8.5 | ) | (49.5 | ) | (31.9 | ) | |||||||||
| 933.4 | 1,274.6 | 4,185.5 | 4,887.2 | |||||||||||||
Operating income |
28.8 | 58.2 | 693.0 | 571.8 | ||||||||||||
Loss from equity investees |
— | (0.7 | ) | (0.8 | ) | (2.1 | ) | |||||||||
Interest expense |
(34.6 | ) | (35.4 | ) | (106.7 | ) | (107.6 | ) | ||||||||
(Loss) income before income taxes and minority interests |
(5.8 | ) | 22.1 | 585.5 | 462.1 | |||||||||||
Income taxes |
(6.4 | ) | (11.3 | ) | (172.0 | ) | (138.9 | ) | ||||||||
Minority interests, principally in AmeriGas Partners |
8.6 | 4.9 | (144.0 | ) | (101.4 | ) | ||||||||||
Net (loss) income |
$ | (3.6 | ) | $ | 15.7 | $ | 269.5 | $ | 221.8 | |||||||
Earnings (loss) per common share: |
||||||||||||||||
Basic |
$ | (0.03 | ) | $ | 0.15 | $ | 2.49 | $ | 2.07 | |||||||
Diluted |
$ | (0.03 | ) | $ | 0.14 | $ | 2.47 | $ | 2.05 | |||||||
Average common shares outstanding (millions): |
||||||||||||||||
Basic |
108.592 | 107.421 | 108.407 | 107.172 | ||||||||||||
Diluted |
108.592 | 108.590 | 109.207 | 108.368 | ||||||||||||
Dividends declared per common share |
$ | 0.2000 | $ | 0.1925 | $ | 0.5850 | $ | 0.5625 | ||||||||
- 2 -
| Nine Months Ended | ||||||||
| June 30, | ||||||||
| 2009 | 2008 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income |
$ | 269.5 | $ | 221.8 | ||||
Reconcile to net cash from operating activities: |
||||||||
Depreciation and amortization |
148.8 | 137.5 | ||||||
Minority interests, principally in AmeriGas Partners |
144.0 | 101.4 | ||||||
Gain on sale of California storage facility |
(39.9 | ) | — | |||||
Deferred income taxes, net |
(8.3 | ) | (0.2 | ) | ||||
Provision for uncollectible accounts |
35.8 | 28.1 | ||||||
Net change in settled accumulated other comprehensive income |
(33.2 | ) | 3.3 | |||||
Other, net |
10.4 | (5.5 | ) | |||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
68.3 | (240.0 | ) | |||||
Inventories |
159.0 | 46.4 | ||||||
Utility deferred fuel costs, net of changes in unsettled derivatives |
40.2 | 53.4 | ||||||
Accounts payable |
(238.7 | ) | 51.3 | |||||
Other current assets |
42.0 | (18.1 | ) | |||||
Other current liabilities |
(4.6 | ) | (27.4 | ) | ||||
Net cash provided by operating activities |
593.3 | 352.0 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Expenditures for property, plant and equipment |
(213.4 | ) | (152.8 | ) | ||||
Acquisitions of businesses, net of cash acquired |
(319.5 | ) | (1.5 | ) | ||||
Proceeds from sale of California storage faciliy |
42.4 | — | ||||||
Decrease in restricted cash |
5.5 | 8.5 | ||||||
Other, net |
1.2 | 6.1 | ||||||
Net cash used by investing activities |
(483.8 | ) | (139.7 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Dividends on UGI Common Stock |
(63.3 | ) | (60.2 | ) | ||||
Distributions on AmeriGas Partners publicly held Common Units |
(63.2 | ) | (60.2 | ) | ||||
Issuances of debt |
108.1 | 31.2 | ||||||
Repayments of debt |
(76.5 | ) | (7.1 | ) | ||||
Increase (decrease) in UGI Utilities bank loans |
53.0 | (160.0 | ) | |||||
Increase in AmeriGas Propane bank loans |
— | 26.0 | ||||||
Other bank loans (decrease) increase |
(77.0 | ) | 0.3 | |||||
Issuances of UGI Common Stock |
5.6 | 16.8 | ||||||
Other |
(0.3 | ) | 10.0 | |||||
Net cash used by financing activities |
(113.6 | ) | (203.2 | ) | ||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
(1.0 | ) | 11.3 | |||||
Cash and cash equivalents (decrease) increase |
$ | (5.1 | ) | $ | 20.4 | |||
Cash and cash equivalents: |
||||||||
End of period |
$ | 240.1 | $ | 272.2 | ||||
Beginning of period |
245.2 | 251.8 | ||||||
(Decrease) increase |
$ | (5.1 | ) | $ | 20.4 | |||
- 3 -
| 1. | Basis of Presentation |
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and joint-venture
affiliates, distributes and markets energy products and related services. In the United
States, we own and operate (1) a retail propane distribution business; (2) natural gas and
electric distribution utilities; (3) electricity generation facilities; and (4) energy
marketing and related businesses. Internationally, we distribute liquefied petroleum gases
(“LPG”) in France, central and eastern Europe and China. We refer to UGI and its
consolidated subsidiaries collectively as “the Company” or “we.” |
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, 2009,
the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”)
collectively held a 1% general partner interest and 42.9% limited partner interest in
AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP and Eagle OLP.
Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners
Common Units (“Common Units”). The remaining 56.1% interest in AmeriGas Partners comprises
32,355,179 publicly held Common Units representing limited partner interests. |
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1)
conducts an LPG distribution business in France; (2) conducts a wholly owned LPG
distribution business and, prior to the purchase of the 50% equity interest it did not
already own on January 29, 2009 (see Note 8), participated in an LPG joint-venture business
(Zentraleuropa LPG Holding, “ZLH”) in central and eastern Europe (collectively, “Flaga”);
and (3) participates in an LPG joint-venture business in the Nantong region of China. Our
LPG distribution business in France is conducted through Antargaz, a subsidiary of AGZ
Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). 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”) and its subsidiaries UGI Penn
Natural Gas, Inc. (“UGIPNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, UGIPNG and CPG own
and operate natural gas distribution utilities in eastern, northeastern and central
Pennsylvania. UGI Utilities also owns and operates an electric distribution utility in
northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution
utility is referred to herein as “UGI Gas;” UGIPNG’s natural gas distribution utility is
referred to herein as “PNG Gas;” and CPG’s natural gas distribution utility, which was
acquired on October 1, 2008 (see Note 8), is referred to herein as “CPG Gas.” UGI Gas, PNG
Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to
regulation by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public
Service Commission, and Electric Utility is subject to regulation by the PUC. |
- 4 -
Through other subsidiaries, Enterprises also conducts an energy marketing business primarily
in the eastern United States (collectively, “Energy Services”). Energy Services’ wholly
owned subsidiary, UGI Development Company (“UGID”), owns and operates a 48-megawatt
coal-fired electric generation station located in northeastern Pennsylvania and owns an
approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located
in western Pennsylvania. In early Fiscal 2009, UGID completed construction of and began
operation of an 11-megawatt landfill gas powered electricity generation facility in eastern
Pennsylvania. 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 Enterprises
subsidiaries, we own and operate heating, ventilation, air-conditioning, refrigeration and
electrical contracting services businesses 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. 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, 2008 condensed
consolidated balance sheet data were derived from audited financial statements but do not
include all disclosures required by accounting principles generally accepted in the United
States of America (“GAAP”). 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, 2008 (“Company’s 2008 Annual Report”). Due to the seasonal
nature of our businesses, the results of operations for interim periods are not necessarily
indicative of the results to be expected for a full year. |
Restricted Cash. Restricted cash represents those cash balances in our commodity futures
brokerage accounts which are restricted from withdrawal. |
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. |
- 5 -
Shares used in computing basic and diluted earnings per share are as follows: |
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Denominator (millions of shares): |
||||||||||||||||
Average common shares
outstanding for basic computation |
108.592 | 107.421 | 108.407 | 107.172 | ||||||||||||
Incremental shares issuable for stock
options and awards |
— | 1.169 | 0.800 | 1.196 | ||||||||||||
Average common shares outstanding for
diluted computation |
108.592 | 108.590 | 109.207 | 108.368 | ||||||||||||
Comprehensive Income. The following table presents the components of comprehensive
income for the three and nine months ended June 30, 2009 and 2008: |
| Three Months Ended June 30, | Nine Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Net (loss) income |
$ | (3.6 | ) | $ | 15.7 | $ | 269.5 | $ | 221.8 | |||||||
Other comprehensive income (loss) |
58.4 | 21.4 | (56.6 | ) | 72.5 | |||||||||||
Comprehensive income |
$ | 54.8 | $ | 37.1 | $ | 212.9 | $ | 294.3 | ||||||||
Other comprehensive income (loss) principally comprises (1) gains and losses on
derivative instruments qualifying as cash flow hedges principally commodity instruments,
interest rate protection agreements, interest rate swaps and foreign currency derivatives,
net of reclassifications to net income; (2) actuarial gains and losses on postretirement
benefit plans; and (3) foreign currency translation adjustments. In addition, effective
December 31, 2008, UGI Utilities merged two of the defined benefit pension plans that it
sponsors. In accordance with the provisions of Statement of Financial Accounting Standards
(“SFAS”) No. 87, “Employers’ Accounting for Pensions” (“SFAS 87”), we were required to remeasure the merged plan’s assets and
obligations and, in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit
Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106 and
132(R)” (“SFAS 158”), record the funded status at December 31, 2008 (the “Remeasurement
Date”) in our Condensed Consolidated Balance Sheet. The remeasurement resulted in an
increase in other comprehensive loss of $38.7 during the three months ended December 31,
2008 (see Note 6). |
Reclassifications. We have reclassified certain prior-year period balances to conform to the
current-period presentation. |
Use of Estimates. We make estimates and assumptions when preparing financial statements in
conformity with GAAP. 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. |
Income Taxes. As a result of settlements with tax authorities during the three months ended
December 31, 2008, the Company adjusted its unrecognized tax benefits which reduced income
tax expense and increased net income by $2.0 for the nine months ended June 30, 2009. The
effective tax rate for the three and nine months ended June 30, 2009 reflects the effects of
a $10.0 nondeductible charge related to the Antargaz Competition Authority Matter (see Note
7). |
- 6 -
Subsequent Events. The Company’s management has evaluated the impact of subsequent events
through August 7, 2009, the date the financial statements were filed with the SEC, and the
effects of such evaluation have been reflected in the financial statements and related
disclosures. |
Newly Adopted Accounting Standards. Effective with the quarter ended June 30, 2009, we
adopted Financial Accounting Standards Boards (“FASB”) Staff Position (“FSP”) FAS 107-1 and
APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP 107-1 and
APB 28-1”). FSP 107-1 and APB 28-1 expands the fair value disclosures required for all
financial instruments by SFAS 107, “Disclosures about Fair Value of Financial Instruments,”
to interim periods for public companies. It also requires disclosures regarding significant
fair value assumptions used. See Note 10 for further information on interim period fair
value disclosures in accordance with FSP 107-1 and APB 28-1. |
Effective with the quarter ended June 30, 2009, we adopted SFAS No. 165, “Subsequent Events”
(“SFAS 165”). SFAS 165 provides guidance on management’s accounting for and disclosure of
events that occur after the balance sheet date but before the financial statements are
issued including the date through which subsequent events are evaluated. The adoption of
SFAS 165 did not have a significant impact on the Company’s financial statements. |
Also effective with the quarter ended June 30, 2009, we adopted FSP FAS 115-2 and 124-2,
“Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP 115-2 and 124-2”).
FSP 115-2 and 124-2 amends other-than-temporary impairment guidance in GAAP for debt
securities to make the guidance more operational and to improve the presentation and
disclosure of other-than-temporary impairments on debt and equity securities in the
financial statements. The FSP does not amend existing recognition and measurement guidance
related to other-than-temporary impairments of equity securities. The adoption of FSP 115-2 and 124-2 did not
impact the Company’s financial statements. |
Effective March 31, 2009, we adopted SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities” (“SFAS 161”). SFAS 161 requires enhanced disclosures for all
derivative instruments and hedging activity accounted for under SFAS No. 133, “Accounting
for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 161 provides greater
transparency by requiring disclosure regarding: (1) how and why an entity uses derivatives,
(2) how derivatives and related hedged items are accounted for under SFAS 133 and its
related interpretations, and (3) how derivatives and related hedged items affect an entity’s
financial position, financial performance and cash flows. See Note 10 for disclosures
required by SFAS 161. |
Effective October 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).
SFAS 157 defines fair value, establishes a framework for measuring fair value in generally
accepted accounting principles, and expands disclosures about fair value measurements. In
February 2008, the FASB issued two FSPs amending SFAS 157. FSP FAS 157-1 amends SFAS 157 to
exclude SFAS No. 13, “Accounting for Leases,” and its related interpretive accounting
pronouncements that address leasing transactions. FSP FAS 157-2 delays the effective date of
SFAS 157 until fiscal years beginning after November 15, 2008 (Fiscal 2010) for
non-financial assets and liabilities that are recognized or disclosed at fair value in the
financial statements on a non-recurring basis. The adoption of the initial phase of SFAS 157
did not have a material effect on the Company’s financial statements and the Company does
not anticipate that the adoption of the remainder of SFAS 157 will have a material effect on
the Company’s consolidated financial statements. In October 2008, the FASB issued FSP FAS
157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is
Not Active” (“FSP 157-3”), which clarifies the application of SFAS 157 to financial assets
in a market that is not active. In April 2009, the FASB issued FSP FAS 157-4, “Determining
Fair Value When the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”),
which provides additional guidance for estimating fair value in accordance with SFAS 157
when the volume and level of activity for the asset or liability have significantly
decreased. FSP 157-3 and FSP 157-4 did not have an impact on our results of operations or
financial condition. See Note 9 for further information on fair value measurements in
accordance with SFAS 157. |
- 7 -
Effective October 1, 2008, we adopted FSP FIN 39-1, “Amendment of FASB Interpretation
No. 39” (“FSP 39-1”). FSP 39-1 permits companies to offset fair value amounts recognized for
the right to reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative instruments
executed with the same counterparty under a master netting agreement. In addition, upon the
adoption, companies are permitted to change their accounting policy to offset or not offset
fair value amounts recognized for derivative instruments under master netting arrangements.
FSP 39-1 requires retrospective application for all periods presented. We have elected to
continue our policy of reflecting derivative asset or liability positions, as well as cash
collateral, on a gross basis in our Condensed Consolidated Balance Sheets. Accordingly, the
adoption of FSP 39-1 did not impact our financial statements. |
Also effective October 1, 2008, we adopted SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, we may elect to
report individual financial instruments and certain items at fair value with changes in fair
value reported in earnings. Once made, this election is irrevocable for those items. The
adoption of SFAS 159 did not impact our financial statements. |
Recently Issued Accounting Standards Not Yet Adopted. In June 2009, the FASB issued SFAS No.
168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles” (“SFAS 168”). SFAS 168 identifies the sources of accounting
principles and the framework for selecting accounting principles used in the preparation of
financial statements presented in conformity with GAAP. SFAS 168 establishes the FASB
Accounting Standards Codification as the source of authoritative accounting principles
recognized by the FASB. The issuance of SFAS 168 will not change existing GAAP. SFAS 168 is
effective for all financial statements issued after September 15, 2009. |
Also in June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial
Assets — an amendment of FASB Statement No. 140” (“SFAS 166”). Among other things, SFAS 166
eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). SFAS 166 also amends
the derecognition guidance as stated in SFAS No. 140, “Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities — a replacement of FASB
Statement No. 125.” SFAS 166 is effective for financial asset transfers occurring after the
beginning of an entity’s fiscal year that begins after November 15, 2009 (Fiscal 2011). We
are currently evaluating the provisions of SFAS 166. |
- 8 -
In December 2008, the FASB issued FSP 132(R)-1, “Employers’ Disclosures about Postretirement
Benefit Plan Assets,” which amends Statement 132(R) to require more detailed disclosures
about employers’ plan assets, including employers’ investment strategies, major categories
of plan assets, concentrations of risk within plan assets, and valuation techniques used to
measure the fair value of plan assets. The provisions of this FSP are effective for
reporting periods ending after December 15, 2009. We are currently evaluating the provisions
of FSP 132(R)-1. |
In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of
Intangible Assets” (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of a
recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”
(“SFAS 142”). The intent of FSP 142-3 is to improve the consistency between the useful life
of a recognized intangible asset under SFAS 142 and the period of expected cash flows used
to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business
Combinations” (“SFAS 141R”), and other applicable accounting literature. FSP 142-3 is
effective for financial statements issued for fiscal years beginning after December 15, 2008
(Fiscal 2010) and must be applied prospectively to intangible assets acquired after the
effective date. We are currently evaluating the provisions of FSP 142-3. |
In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R applies to
all transactions or other events in which an entity obtains control of one or more
businesses. SFAS 141R establishes, among other things, principles and requirements for how
the acquirer (1) recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2)
recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and
(3) determines what information with respect to a business combination should be disclosed.
SFAS 141R applies prospectively to business combinations for which the acquisition date is
on or after the first annual reporting period beginning on or after December 15, 2008
(Fiscal 2010). Among the more significant changes in accounting for acquisitions are
(1) transaction costs will generally be expensed (rather than being included as costs of the
acquisition); (2) contingencies, including contingent consideration, will generally be
recorded at fair value with subsequent adjustments recognized in operations (rather than as
adjustments to the purchase price); and (3) decreases in valuation allowances on acquired
deferred tax assets will be recognized in operations (rather than decreases in goodwill).
Generally, the effects of SFAS 141R will depend on future acquisitions. |
Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 is
effective for us on October 1, 2009 (Fiscal 2010). This standard will significantly change
the accounting and reporting relating to noncontrolling interests in a consolidated
subsidiary. After adoption, noncontrolling interests ($258.7, $159.2 and $243.7 at June 30,
2009, September 30, 2008 and June 30, 2008, respectively) will be classified as
stockholders’ equity, a change from its current classification as minority interests between
liabilities and stockholders’ equity. Earnings (loss) attributable to minority interests
($(8.6) and $144.0 in the three and nine months ended June 30, 2009 and ($4.9) and $101.4 in
the three and nine months ended June 30, 2008, respectively) will be included in net income,
although such income will continue to be deducted to measure earnings per share. In
addition, changes in a parent’s ownership interest while retaining control will be accounted
for as equity transactions and any retained noncontrolling equity investments in a former
subsidiary will be initially measured at fair value. |
- 9 -
| 2. | Intangible Assets |
The Company’s intangible assets comprise the following: |
| June 30, | September 30, | June 30, | ||||||||||
| 2009 | 2008 | 2008 | ||||||||||
Goodwill (not subject to amortization) |
$ | 1,545.5 | $ | 1,489.7 | $ | 1,569.1 | ||||||
Other intangible assets: |
||||||||||||
Customer relationships, noncompete
agreements and other |
$ | 217.7 | $ | 197.3 | $ | 224.6 | ||||||
Trademark (not subject to amortization) |
47.7 | 47.8 | 53.5 | |||||||||
Gross carrying amount |
265.4 | 245.1 | 278.1 | |||||||||
Accumulated amortization |
(103.8 | ) | (90.1 | ) | (104.3 | ) | ||||||
Net carrying amount |
$ | 161.6 | $ | 155.0 | $ | 173.8 | ||||||
The increase in goodwill and other intangible assets during the nine months ended June
30, 2009 principally reflects the effects of acquisitions and capital project expenditures.
Amortization expense of intangible assets was $4.7 and $13.6 for the three and nine months
ended June 30, 2009, respectively, and $4.8 and $14.2 for the three and nine months ended
June 30, 2008. No amortization is included in cost of sales in the Condensed Consolidated
Statements of Income. Our expected aggregate amortization expense of intangible assets for
the next five fiscal years is as follows: Fiscal 2009 — $17.2; Fiscal 2010 — $15.4; Fiscal
2011 — $15.0; Fiscal 2012 — $14.9; Fiscal 2013 — $14.3. |
| 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 and our international
propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy
Services. We refer to both international segments collectively as “International Propane.” |
- 10 -
| 3. | Segment Information (continued) |
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 962.2 | $ | (28.6 | ) | $ | 372.7 | $ | 176.9 | $ | 30.8 | $ | 223.4 | $ | 133.5 | $ | 31.4 | $ | 22.1 | |||||||||||||||||
Cost of sales |
$ | 591.6 | $ | (27.4 | ) | $ | 210.3 | $ | 109.8 | $ | 19.7 | $ | 200.4 | $ | 49.3 | $ | 18.1 | $ | 11.4 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 28.8 | $ | 0.1 | $ | 4.4 | $ | 12.9 | $ | 3.3 | $ | 8.6 | $ | (0.5 | ) | $ | 0.8 | $ | (0.8 | ) | ||||||||||||||||
Loss from equity investees |
— | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Interest expense |
(34.6 | ) | — | (17.2 | ) | (10.3 | ) | (0.5 | ) | — | (5.8 | ) | (0.7 | ) | (0.1 | ) | ||||||||||||||||||||
Minority interests |
8.6 | (0.1 | ) | 8.3 | — | — | — | 0.4 | — | — | ||||||||||||||||||||||||||
Income (loss) before income taxes |
$ | 2.8 | $ | — | $ | (4.5 | ) | $ | 2.6 | $ | 2.8 | $ | 8.6 | $ | (5.9 | ) | $ | 0.1 | $ | (0.9 | ) | |||||||||||||||
Depreciation and amortization |
$ | 51.3 | $ | (0.1 | ) | $ | 21.1 | $ | 11.8 | $ | 1.1 | $ | 2.2 | $ | 12.4 | $ | 2.5 | $ | 0.3 | |||||||||||||||||
Partnership EBITDA (c) |
$ | 25.4 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) |
$ | 5,901.3 | $ | (383.3 | ) | $ | 1,619.3 | $ | 1,902.6 | $ | 116.2 | $ | 328.2 | $ | 1,640.3 | $ | 247.7 | $ | 430.3 | |||||||||||||||||
Investments in equity investees (at period end) |
$ | 2.9 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2.9 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,545.5 | $ | (3.9 | ) | $ | 666.1 | $ | 176.9 | $ | — | $ | 11.8 | $ | 620.2 | $ | 67.5 | $ | 6.9 | |||||||||||||||||
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 1,332.8 | $ | (82.3 | ) | $ | 535.2 | $ | 202.2 | $ | 32.8 | $ | 388.9 | $ | 218.7 | $ | 14.1 | $ | 23.2 | |||||||||||||||||
Cost of sales |
$ | 948.6 | $ | (81.7 | ) | $ | 363.0 | $ | 147.4 | $ | 17.7 | $ | 360.9 | $ | 121.5 | $ | 7.7 | $ | 12.1 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 58.2 | $ | 0.1 | $ | 9.6 | $ | 12.5 | $ | 7.5 | $ | 16.0 | $ | 11.2 | $ | 0.6 | $ | 0.7 | ||||||||||||||||||
Loss from equity investees |
(0.7 | ) | — | — | — | — | — | (0.6 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
Interest expense |
(35.4 | ) | — | (18.2 | ) | (8.4 | ) | (0.4 | ) | — | (6.9 | ) | (0.5 | ) | (1.0 | ) | ||||||||||||||||||||
Minority interests |
4.9 | (0.2 | ) | 5.2 | — | — | — | (0.1 | ) | — | — | |||||||||||||||||||||||||
Income (loss) before income taxes |
$ | 27.0 | $ | (0.1 | ) | $ | (3.4 | ) | $ | 4.1 | $ | 7.1 | $ | 16.0 | $ | 3.6 | $ | — | $ | (0.3 | ) | |||||||||||||||
Depreciation and amortization |
$ | 46.8 | — | $ | 20.1 | $ | 9.3 | $ | 0.9 | $ | 1.8 | $ | 13.2 | $ | 1.1 | $ | 0.4 | |||||||||||||||||||
Partnership EBITDA (c) |
$ | 29.7 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) |
$ | 5,967.3 | $ | (370.6 | ) | $ | 1,730.1 | $ | 1,538.3 | $ | 115.8 | $ | 399.9 | $ | 1,876.6 | $ | 218.2 | $ | 459.0 | |||||||||||||||||
Investments in equity investees (at period end) |
$ | 70.8 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 70.8 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,569.1 | $ | (3.9 | ) | $ | 644.8 | $ | 162.3 | $ | — | $ | 11.8 | $ | 696.0 | $ | 51.1 | $ | 7.0 | |||||||||||||||||
| (a) | International Propane-Other principally comprises Flaga, including its central and
eastern European joint-venture business ZLH and our joint-venture business in China. In January
2009, Flaga purchased the 50% interest in ZLH it did not already own. |
|
| (b) | Corporate & Other results principally comprise UGI Enterprises’ HVAC/R operations, net
expenses of UGI’s captive general liability insurance company, UGI Corporation’s unallocated
corporate and general expenses, and interest income. Corporate & Other assets principally
comprise cash, short-term investments and an intercompany loan. The intercompany interest
associated with the intercompany loan is removed in the segment presentation. |
|
| (c) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane
operating income: |
| Three months ended June 30, | 2009 | 2008 | ||||||
Partnership EBITDA |
$ | 25.4 | $ | 29.7 | ||||
Depreciation and amortization |
(21.1 | ) | (20.1 | ) | ||||
Minority interests (i) |
0.1 | — | ||||||
Operating income |
$ | 4.4 | $ | 9.6 | ||||
| (i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
- 11 -
| 3. | Segment Information (continued) |
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 4,878.5 | $ | (135.4 | ) | $ | 1,923.1 | $ | 1,130.1 | $ | 104.8 | $ | 1,007.1 | $ | 699.3 | $ | 81.3 | $ | 68.2 | |||||||||||||||||
Cost of sales |
$ | 3,142.8 | $ | (131.7 | ) | $ | 1,129.8 | $ | 795.7 | $ | 67.1 | $ | 902.3 | $ | 297.4 | $ | 44.9 | $ | 37.3 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 693.0 | $ | 0.2 | $ | 317.2 | $ | 149.8 | $ | 13.8 | $ | 60.0 | $ | 147.5 | $ | 6.6 | $ | (2.1 | ) | |||||||||||||||||
Loss from equity investees |
(0.8 | ) | — | — | — | — | — | (0.7 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
Interest expense |
(106.7 | ) | — | (53.7 | ) | (31.7 | ) | (1.3 | ) | — | (17.9 | ) | (1.8 | ) | (0.3 | ) | ||||||||||||||||||||
Minority interests |
(144.0 | ) | (0.1 | ) | (144.0 | ) | — | — | — | 0.1 | — | — | ||||||||||||||||||||||||
Income (loss) before income taxes |
$ | 441.5 | $ | 0.1 | $ | 119.5 | $ | 118.1 | $ | 12.5 | $ | 60.0 | $ | 129.0 | $ | 4.7 | $ | (2.4 | ) | |||||||||||||||||
Depreciation and amortization |
$ | 148.8 | $ | (0.3 | ) | $ | 62.8 | $ | 34.9 | $ | 3.0 | $ | 6.1 | $ | 35.3 | $ | 6.0 | $ | 1.0 | |||||||||||||||||
Partnership EBITDA (c) |
$ | 376.7 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) |
$ | 5,901.3 | $ | (383.3 | ) | $ | 1,619.3 | $ | 1,902.6 | $ | 116.2 | $ | 328.2 | $ | 1,640.3 | $ | 247.7 | $ | 430.3 | |||||||||||||||||
Investments in equity investees (at period end) |
$ | 2.9 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2.9 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,545.5 | $ | (3.9 | ) | $ | 666.1 | $ | 176.9 | $ | — | $ | 11.8 | $ | 620.2 | $ | 67.5 | $ | 6.9 | |||||||||||||||||
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 5,459.0 | $ | (207.6 | ) | $ | 2,290.0 | $ | 1,005.6 | $ | 103.3 | $ | 1,261.4 | $ | 888.5 | $ | 47.7 | $ | 70.1 | |||||||||||||||||
Cost of sales |
$ | 3,881.2 | $ | (202.0 | ) | $ | 1,545.3 | $ | 739.3 | $ | 59.6 | $ | 1,160.2 | $ | 513.6 | $ | 27.5 | $ | 37.7 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 571.8 | $ | — | $ | 236.8 | $ | 138.1 | $ | 21.4 | $ | 67.3 | $ | 101.7 | $ | 4.0 | $ | 2.5 | ||||||||||||||||||
Loss from equity investees |
(2.1 | ) | — | — | — | — | — | (1.1 | ) | (1.0 | ) | — | ||||||||||||||||||||||||
Interest expense |
(107.6 | ) | — | (55.1 | ) | (28.3 | ) | (1.5 | ) | — | (19.9 | ) | (1.8 | ) | (1.0 | ) | ||||||||||||||||||||
Minority interests |
(101.4 | ) | (0.2 | ) | (100.0 | ) | — | — | — | (1.2 | ) | — | — | |||||||||||||||||||||||
Income (loss) before income taxes |
$ | 360.7 | $ | (0.2 | ) | $ | 81.7 | $ | 109.8 | $ | 19.9 | $ | 67.3 | $ | 79.5 | $ | 1.2 | $ | 1.5 | |||||||||||||||||
Depreciation and amortization |
$ | 137.5 | $ | — | $ | 60.0 | $ | 28.1 | $ | 2.7 | $ | 5.3 | $ | 37.5 | $ | 3.1 | $ | 0.8 | ||||||||||||||||||
Partnership EBITDA (c) |
$ | 294.5 | ||||||||||||||||||||||||||||||||||
Segment assets (at period end) |
$ | 5,967.3 | $ | (370.6 | ) | $ | 1,730.1 | $ | 1,538.3 | $ | 115.8 | $ | 399.9 | $ | 1,876.6 | $ | 218.2 | $ | 459.0 | |||||||||||||||||
Investments in equity investees (at period end) |
$ | 70.8 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 70.8 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,569.1 | $ | (3.9 | ) | $ | 644.8 | $ | 162.3 | $ | — | $ | 11.8 | $ | 696.0 | $ | 51.1 | $ | 7.0 | |||||||||||||||||
| (a) | International Propane-Other principally comprises Flaga, including its central and
eastern European joint-venture business ZLH and our joint-venture business in China. In January
2009, Flaga purchased the 50% interest in ZLH it did not already own. |
|
| (b) | Corporate & Other results principally comprise UGI Enterprises’ HVAC/R operations, net
expenses of UGI’s captive general liability insurance company, UGI Corporation’s unallocated
corporate and general expenses, and interest income. Corporate & Other assets principally
comprise cash, short-term investments and an intercompany loan. The intercompany interest
associated with the intercompany loan is removed in the segment presentation. |
|
| (c) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane
operating income: |
| Nine months ended June 30, | 2009 | 2008 | ||||||
Partnership EBITDA |
$ | 376.7 | $ | 294.5 | ||||
Depreciation and amortization |
(62.8 | ) | (60.0 | ) | ||||
Minority interests (i) |
3.3 | 2.3 | ||||||
Operating income |
$ | 317.2 | $ | 236.8 | ||||
| (i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
- 12 -
| 4. | Energy Services Accounts Receivable Securitization Facility |
In April 2009, Energy Services renewed its $200 receivables purchase facility (“Receivables
Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility
is currently scheduled to expire in April 2010, although the Receivables Facility may
terminate prior to such date due to the termination of commitments of the Receivables
Facility back-up purchasers. |
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without
recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary,
Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement
purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time
sell, an undivided interest in some or all of the receivables to a commercial paper conduit
of a major bank. ESFC was created and has been structured to isolate its assets from
creditors of Energy Services and its affiliates, including UGI. This two-step transaction is
accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Energy
Services continues to service, administer and collect trade receivables on behalf of the
commercial paper issuer and ESFC. |
During the nine months ended June 30, 2009 and 2008, Energy Services sold trade receivables
totaling $1,029.5 and $1,145.2, respectively, to ESFC. During the nine months ended June 30,
2009 and 2008, ESFC sold an aggregate $508.9 and $95.5, respectively, of undivided interests
in its trade receivables to the commercial paper conduit. At June 30, 2009, the outstanding
balance of ESFC trade receivables was $24.1 which is net of $44.4 that was sold to the
commercial paper conduit and removed from the balance sheet. At June 30, 2008, the
outstanding balance of ESFC trade receivables was $132.1 and there was no amount sold to the
commercial paper conduit. |
- 13 -
| 5. | Utility Regulatory Assets and Liabilities and Regulatory Matters |
For a description of the Company’s regulatory assets and liabilities other than those
described below, see Note 6 to the Company’s 2008 Annual Report. UGI Utilities does not
recover a rate of return on its regulatory assets. The following regulatory assets and
liabilities associated with Gas Utility and Electric Utility are included in our
accompanying Condensed Consolidated Balance Sheets: |
| June 30, | September 30, | June 30, | ||||||||||
| 2009 | 2008 | 2008 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 76.6 | $ | 73.7 | $ | 73.8 | ||||||
Postretirement benefits |
3.0 | 4.3 | 4.5 | |||||||||
Recoverable costs — CPG Gas
postretirement benefit plans |
5.6 | — | — | |||||||||
Environmental costs |
20.6 | 9.0 | 9.0 | |||||||||
Deferred fuel costs |
28.8 | 16.0 | — | |||||||||
Other |
6.9 | 4.4 | 4.5 | |||||||||
Total regulatory assets |
$ | 141.5 | $ | 107.4 | $ | 91.8 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 10.0 | $ | 8.9 | $ | 8.6 | ||||||
Environmental overcollections |
9.7 | — | — | |||||||||
Deferred fuel refunds |
13.5 | — | 87.9 | |||||||||
Total regulatory liabilities |
$ | 33.2 | $ | 8.9 | $ | 96.5 | ||||||
Deferred fuel costs and refunds. Gas Utility’s tariffs contain clauses which permit
recovery of certain purchased gas costs through the application of purchased gas cost
(“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for differences
between the total amount of purchased gas costs collected from customers and recoverable
costs incurred. Net undercollected gas costs are classified as a regulatory asset and net
overcollections are classified as a regulatory liability. Gas Utility uses derivative
financial instruments to reduce volatility in the cost of gas it purchases for firm-
residential, commercial and industrial (“retail core-market”) customers. Realized and
unrealized gains or losses on natural gas derivative financial instruments are included in
deferred fuel refunds or costs. Unrealized (losses) gains on such contracts at June 30,
2009, September 30, 2008 and June 30, 2008 were $(42.5), $(23.3) and $49.3, respectively. |
Recoverable costs — CPG Gas postretirement benefit plans. This regulatory asset represents
the portion of prior service cost and net actuarial losses that will be recovered through
future rates based upon established regulatory practices. These regulatory assets are
adjusted annually or more frequently under certain circumstances when the funded status of
the plans is recorded in accordance with SFAS 158. These costs are amortized over the
average remaining life expectancy of the plan participants. |
Environmental overcollections. Environmental overcollections represents the difference
between the amounts recovered in rates and actual costs incurred (net of insurance proceeds)
associated with the terms of a consent order agreement between CPG Gas and the Pennsylvania
Department of Environmental Protection to remediate certain gas plant sites. |
Other Regulatory Matters |
UGIPNG and CPG Base Rate Filings. On January 28, 2009, UGIPNG and CPG filed separate
requests with the PUC to increase base operating revenues by $38.1 annually for UGIPNG and
$19.6 annually for CPG to fund system improvements and operations necessary to maintain safe
and reliable natural gas service and energy assistance for low income customers as well as
energy conservation programs for all customers. On March 26, 2009, the PUC suspended the
effective date for the base operating revenue rate increases to allow for investigation and
public hearings. On May 5, 2009, UGIPNG and CPG received testimony submitted by various
state and special interest parties opposing the level of the proposed rate increases. On
July 2, 2009, UGIPNG and CPG each filed joint settlement petitions with the PUC based on
agreements with the opposing parties regarding the requested base
operating revenue increases. The settlement agreements were approved by an administrative law judge
on July 29, 2009 in substantially the form submitted. The recommended decision of the administrative
law judge is subject to PUC approval. It is anticipated that this
process will conclude by the end of Fiscal 2009. |
- 14 -
Electric Utility. As a result of Pennsylvania’s Electricity Generation Customer Choice and
Competition Act that became effective January 1, 1997, all of Electric Utility’s customers
are permitted to acquire their electricity from entities other than Electric Utility.
Electric Utility remains the provider of last resort (“POLR”) for its customers that are not
served by an alternate electric generation provider. The terms and conditions under which
Electric Utility provides POLR service, and rules governing the rates that may be charged
for such service through December 31, 2009, were established in a series of PUC approved
settlements (collectively, the “POLR Settlement”), the latest of which became effective June
23, 2006. |
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to
certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement,
Electric Utility increased its POLR rates effective January 1, 2008, which increased the
average cost to a residential heating customer by approximately 5.5% over such costs in
effect during calendar year 2007. Effective January 1, 2009, the average cost to a
residential heating customer increased by 1.5% over such costs in effect during calendar
year 2008. |
On July 17, 2008, the PUC approved Electric Utility’s default service procurement,
implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement,
filed in accordance with the PUC’s default service regulations. These plans do not affect
Electric Utility’s existing POLR settlement effective through December 31, 2009. The
approved plans specify how Electric Utility will solicit and acquire default service
supplies for residential customers for the period January 1, 2010 through May 31, 2014, and
for commercial and industrial customers for the period January 1, 2010 through May 31, 2011
(collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008
for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate
filing that provides for Electric Utility to fully recover its default service costs. Under
applicable statutory standards, Electric Utility is entitled to fully recover its default
service costs. |
| 6. | Defined Benefit Pension and Other Postretirement Plans |
We sponsor defined benefit pension plans for employees of UGI, UGI Utilities, CPG, UGIPNG,
and certain of UGI’s other wholly owned domestic subsidiaries (“Pension Plans”). We also
provide postretirement health care benefits to certain retirees and a limited number of
active employees, and postretirement life insurance benefits to nearly all domestic active
and retired employees. In addition, Antargaz employees are covered by certain defined
benefit pension and postretirement plans. |
- 15 -
Net periodic pension expense and other postretirement benefit costs include the following
components: |
| Other | ||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||
| Three Months Ended | Three Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Service cost |
$ | 1.9 | $ | 1.5 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost |
5.8 | 5.0 | 0.2 | 0.3 | ||||||||||||
Expected return on assets |
(6.3 | ) | (6.1 | ) | (0.1 | ) | (0.2 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service benefit |
— | — | (0.1 | ) | (0.1 | ) | ||||||||||
Actuarial loss |
1.2 | — | — | — | ||||||||||||
Net benefit cost |
2.6 | 0.4 | 0.1 | 0.1 | ||||||||||||
Change in associated regulatory liabilities |
— | — | 0.8 | 0.8 | ||||||||||||
Net expense |
$ | 2.6 | $ | 0.4 | $ | 0.9 | $ | 0.9 | ||||||||
| Other | ||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||
| Nine Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Service cost |
$ | 5.3 | $ | 4.5 | $ | 0.2 | $ | 0.3 | ||||||||
Interest cost |
17.6 | 14.8 | 0.7 | 0.8 | ||||||||||||
Expected return on assets |
(19.3 | ) | (18.4 | ) | (0.4 | ) | (0.5 | ) | ||||||||
Amortization of: |
||||||||||||||||
Transition obligation |
— | — | 0.1 | — | ||||||||||||
Prior service benefit |
— | — | (0.2 | ) | (0.3 | ) | ||||||||||
Actuarial loss |
2.7 | 0.1 | — | — | ||||||||||||
Net benefit cost |
6.3 | 1.0 | 0.4 | 0.3 | ||||||||||||
Change in associated regulatory liabilities |
— | — | 2.4 | 2.5 | ||||||||||||
Net expense |
$ | 6.3 | $ | 1.0 | $ | 2.8 | $ | 2.8 | ||||||||
Pension Plans 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 material
contributions to the Pension Plans during Fiscal 2009 for ERISA funding purposes. |
During the nine months ended
June 30, 2009, Antargaz made a €4.1 contribution to one of
its defined benefit pension plans. Antargaz does not expect to make any additional material
contributions to fund its pension or other postretirement benefits during Fiscal 2009. |
Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary
Employees’ Beneficiary Association (“VEBA”) trust to fund and pay UGI Gas and Electric
Utility’s postretirement health care and life insurance benefits referred to above by
depositing into the VEBA the annual amount of postretirement benefit costs determined under
SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” The
difference between the annual amount calculated and the amount included in UGI Gas’ and
Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers.
Amounts contributed to the VEBA by UGI Utilities were not material during the nine months
ended June 30, 2009, nor are they expected to be material for all of Fiscal 2009. |
- 16 -
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement
income plans. We recorded pre-tax expense associated with these plans of $0.6 and $2.2 for
the three and nine months ended June 30, 2009, respectively. We recorded pre-tax expense for
these plans of $0.6 and $2.4 for the three and nine months ended June 30, 2008,
respectively. |
Effective December 31, 2008, the Company merged two of its domestic defined benefit pension
plans. The merged plan will maintain separate benefit formulas and specific rights and
features of each predecessor plan. As a result of the merger, in accordance with SFAS 87 the
Company remeasured the combined plan’s assets and benefit obligations as of December 31,
2008 and in accordance with SFAS 158 recorded an after-tax charge to accumulated other
comprehensive loss of $38.7. |
The following table provides a reconciliation of the projected benefit obligation (“PBO”),
plan assets and the funded status of the merged pension plan as of the Remeasurement Date: |
| Three Months | ||||
| Ended | ||||
| December 31, 2008 | ||||
Change in benefit obligations: |
||||
Benefit obligations — October 1, 2008 |
$ | 300.6 | ||
Service cost |
1.3 | |||
Interest cost |
5.1 | |||
Actuarial loss |
35.4 | |||
Benefits paid |
(3.7 | ) | ||
Benefit obligations — December 31, 2008 |
$ | 338.7 | ||
Change in plan assets: |
||||
Fair value of plan assets — October 1, 2008 |
$ | 241.0 | ||
Actual loss on assets |
(27.3 | ) | ||
Benefits paid |
(3.7 | ) | ||
Fair value of plan assets — December 31, 2008 |
$ | 210.0 | ||
Funded status of the merged plan — December 31, 2008 |
$ | (128.7 | ) | |
Liabilities recorded in the balance sheet: |
||||
Unfunded liabilities (included in other noncurrent liabilities) |
$ | (128.7 | ) | |
Amounts recorded in stockholders’ equity — December 31, 2008: |
||||
Prior service cost |
$ | 0.3 | ||
Net actuarial loss |
132.9 | |||
Total |
$ | 133.2 | ||
The accumulated benefit obligation (“ABO”) of the merged plan at the Remeasurement Date
is $301.5. Actuarial assumptions for the merged plan as of the Remeasurement Date are as
follows: discount rate — 5.9%; expected return on plan assets — 8.5%; rate of increase in
salary levels — 3.8%. |
- 17 -
| 7. | Commitments and Contingencies |
On May 27, 2009, the General Partner was named as a defendant in a purported class action
lawsuit in the Superior Court of the State of California in which plaintiffs are challenging
the General Partner’s weight disclosure with regard to its portable propane grill cylinders.
The complaint purports to be brought on behalf of a class of all AmeriGas consumers in the
state of California during the four years prior to the date of the California complaint, who
exchanged an empty cylinder and were provided with what is alleged to be only a
partially-filled cylinder. The plaintiffs seek restitution, injunctive relief, interest,
costs, attorneys’ fees and other appropriate relief. |
On June 4, 2009, the General Partner, AmeriGas OLP and AmeriGas Partners were each named in
a purported class action lawsuit filed in federal district court in San Francisco,
California. This complaint purports to be brought on behalf of a nationwide class defined
as to include all purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas
and another unaffiliated entity nationwide from January 1, 2008 to the present. This
complaint claims that defendants’ conduct constituted an unfair and deceptive practice that
injured consumers and violated the consumer protection statutes of thirty-seven states and
the District of Columbia, thereby entitling the class to damages, restitution, disgorgement,
injunctive relief, costs and attorneys fees. The complaint also alleges that defendants were
unjustly enriched by their conduct and seeks restitution of any unjust benefits received.
In addition, these plaintiffs are seeking punitive or treble damages, and pre-judgment and
post-judgment interest. |
In addition, five other purported class actions have been filed against us in the following
federal courts: Northern District of California (two lawsuits), Central District of
California, Middle District of Florida and Eastern District of Pennsylvania. These suits,
in essence, reiterate the claims made in the above-described complaints. In addition, some of
the suits filed in federal court allege violation of state “slack filling” laws, as well as
state consumer protection statutes, some of which contain penalty provisions if violations
are proven. |
A motion to consolidate all of the purported class action lawsuits is pending in the United
States District Court for the District of Kansas. In the interim, defendants have filed
motions to stay discovery pending the resolution of the motion to consolidate and no
discovery has yet taken place. We are investigating these claims and intend to vigorously
defend the lawsuits. We are currently not able to predict the outcome of the class action
lawsuits and consequently no amounts have been recorded in the financial statements. It is
possible that any judgment or settlement of the claims could be material to our results of
operations. |
- 18 -
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, 2009, the potential amount payable under this indemnity by the Company
Parties was approximately $58.0. These indemnity obligations expired on July 20, 2009 when
CPLP, now known as Eagle OLP, redeemed an approximate 0.1% limited partner interest held by
an unrelated third party. |
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, resulting
from the defendants’ alleged failure to install underground propane lines at depths required
by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury
and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion
to include customers acquired from Columbia Propane in August 2001 as additional potential
class members and the plaintiffs amended their complaint to name additional parties pursuant
to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG,
former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia
Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is
seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and
attorneys’ fees. |
In 2005, the Swigers filed what purports to be a class action in the Circuit Court of
Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers
of UGI and the General Partner, and their insurance carriers and insurance adjusters. In the
Harrison County lawsuit, the Swigers are seeking compensatory and punitive damages on behalf
of the putative class for violations of the West Virginia
Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil
conspiracy. The Swigers have also requested that the Court rule that insurance coverage
exists under the policies issued by the defendant insurance companies for damages sustained
by the members of the class in the Monongalia County lawsuit. The Circuit Court of Harrison
County has not certified the class in the Harrison County lawsuit at this time and, in
October 2008, stayed that lawsuit pending resolution of the class action lawsuit in
Monongalia County. We believe we have good defenses to the claims in both actions. |
- 19 -
By letter dated March 6, 2008, the New York State Department of Environmental Conservation
(“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in
Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site
characterization study performed by DEC disclosed contamination related to former
manufactured gas plant (“MGP”) operations on the site. DEC has classified the site as a
significant threat to public health or environment with further action required. The
Partnership has researched the history of the site and its ownership interest in the site.
The Partnership has reviewed the preliminary site characterization study prepared by the DEC
and the possible existence of other potentially responsible parties. The Partnership
continues to seek additional information about the site. Because of the preliminary nature
of available environmental information, the ultimate amount of expected clean up costs
cannot be reasonably estimated. It is possible that such amount could be material to the
Partnership’s results of operations. |
||
French tax authorities levy various 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
the entity’s tangible fixed assets. Antargaz has recorded liabilities for business taxes
related to various classes of equipment. 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. |
||
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, by the early 1950s UGI Utilities divested all of its utility
operations other than certain Pennsylvania operations, including those which now constitute
UGI Gas 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 UGI
Gas is currently permitted to include in rates, through future base rate proceedings, a
five-year average of such prudently incurred remediation costs. In accordance with the terms
of the PNG Gas base rate case order which became effective December 2, 2006,
site-specific environmental investigation and remediation costs associated with PNG Gas
incurred prior to December 2, 2006 are amortized as removal costs over five-year periods.
Such costs incurred after December 1, 2006 are expensed as incurred. |
- 20 -
CPG is party to a Consent Order and Agreement with the Pennsylvania Department of
Environmental Protection dated February 15, 2005 (“CPG-COA”), requiring CPG to perform a
specified level of activities associated with environmental investigation and remediation
work at certain properties in Pennsylvania on which MGP-related facilities were operated
(“MGP Properties”) and to plug a minimum of 16 non-producing natural gas wells per year. CPG
has closed all but 8 of the MGP Properties and has plugged all but approximately 78 wells.
Under the CPG-COA, environmental expenditures relating to the MGP Properties are capped at
$1.8 in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties
and at the end of 2013 for well plugging activities. In addition, CPG is responsible for
remediation of an MGP Property in Georgetown, Delaware. The costs associated with
remediation of the Georgetown MGP Property are not expected to be material. At June 30,
2009, our accrued liability for environmental investigation and remediation costs related to
the CPG-COA was $11.6. |
||
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. |
||
Management believes that under applicable law UGI Utilities should not be liable in those
instances in which a former subsidiary owned or operated an MGP. There could be, however,
significant future costs of an uncertain amount associated with environmental damage caused
by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or
operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the
subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be
considered to have been an operator because of its conduct with respect to its subsidiary’s
MGP. |
||
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI
Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22 in remediation costs and paid $26 in third-party claims relating to the
site and estimates that future response costs, including a claim by the United States
Justice Department for natural resource damages, could be as high as $14. Trial took place
in March 2009 and the court’s decision is pending. |
- 21 -
City of Bangor, Maine v. Frontier Communications Corporation, f/k/a Citizens Communications
Company. In April 2003, Citizens Communications Company, now known as Frontier
Communications Corporation (“Frontier”), 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
Frontier to recover environmental response costs associated with MGP wastes generated at a
plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River.
Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging
that the third-party defendants are responsible for an equitable share of costs Frontier may
be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier
alleges that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI
Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies
conducted by the City and Frontier suggest that it could cost up to $18 to clean up the
river. Frontier’s third-party claims were stayed pending trial of the City’s suit against
Frontier, which took place in September 2005. On June 27, 2006, the court issued an order
finding Frontier responsible for 60% of the cleanup costs. On February 14, 2007, Frontier
and the City entered into a settlement agreement pursuant to which Frontier agreed to pay
$7.6 in exchange for a release of its and all predecessors’ liabilities. Separately, the
Maine Department of Environmental Protection has disclaimed its previously announced
intention to pursue third-party defendants, including UGI Utilities, for costs incurred by
the State of Maine related to contaminants at this site. UGI Utilities believes that it has
good defenses to all of Frontier’s claims. |
||
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”)
informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean
up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is
responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged
direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006,
KeySpan reported that the New York Department of Environmental Conservation has approved a
remedy for the site that is estimated to cost approximately $10. KeySpan believes that the
cost could be as high as $20. UGI Utilities is in the process of reviewing the information
provided by KeySpan and is investigating this claim. |
||
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities
(together the “Northeast Companies”), in the United States District Court for the District
of Connecticut seeking contribution from UGI Utilities for past and future remediation costs
related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities
in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941 through control of former subsidiaries that owned
the MGPs. The Northeast Companies estimated that remediation costs for all of the sites
could total approximately $215 and asserted that UGI Utilities is responsible for
approximately $103 of this amount. The Northeast Companies subsequently withdrew their
claims with respect to three of the sites and UGI
Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a
lease. In April 2009, the court conducted a trial to determine whether UGI Utilities
operated any of the nine remaining sites that were owned and operated by former
subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with
respect to all nine sites. In a second phase of the trial scheduled for early 2010, the
court will determine what, if any, contamination at Waterbury North is related to UGI
Utilities’ period of operation. The Northeast Companies estimate that remediation costs at
Waterbury North could total $25. |
- 22 -
Antargaz Competition Authority Matter. In June 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.
Antargaz did not have any further contact with the DGCCRF regarding this matter until
February 2007, when it received a letter from the DGCCRF requesting documents and
information relating to Antargaz’ pricing policies and practices. In March 2007, and again
in August 2007, the DGCCRF requested additional information from Antargaz and three joint
ventures in which it participates. In July 2008, the Competition Authority interviewed Mr.
Varagne, as President of Antargaz and President of the industry association, Comite Francais
du Butane et du Propane, about competitive practices in the LPG cylinder market in France. |
On July 21, 2009, Antargaz received a Statement of Objections from France’s Autorité de la
concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the
DGCCRF. A Statement of Objections (“Statement”) is part of French competition proceedings
and generally follows an investigation under French competition laws. The Statement sets
forth the Competition Authority’s findings; it is not a judgment or final decision. The
Statement alleges that Antargaz engaged in certain anti-competitive practices in violation
of French and European Union civil competition laws related to the cylinder market during
the period from 1999 through 2004. The alleged violations occurred principally during
periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz. |
Antargaz is reviewing the evidence supporting the allegations contained in the Statement and
intends to vigorously defend itself. Based on an assessment of the information contained in
the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0
(€7.1) related to this matter which amount is reflected in Other expense (income) on the
Condensed Consolidated Statements of Income. The final resolution could result in payment of
an amount significantly different from the amount we have recorded. We are unable to predict
the timing of the final resolution of this matter. |
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
any of our environmental or 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. |
- 23 -
| 8. | Acquisitions and Divestitures |
On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL
Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas
distribution utility of PPL Corporation (the “CPG Acquisition”), for cash consideration of
$267.6 plus estimated working capital of $35.4. Immediately after the closing of the CPG
Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central
Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP
for cash consideration of $32 plus estimated working capital of $1.6. CPG distributes
natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also
distributes natural gas to several hundred customers in portions of one Maryland county. CPP
sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG
Acquisition at closing with a combination of $120 cash contributed by UGI on September 25,
2008, proceeds from the issuance on October 1, 2008 of $108 principal amount of 6.375%
Senior Notes due 2013 and approximately $75.0 of borrowings under UGI Utilities’ Revolving
Credit Agreement. AmeriGas OLP funded its acquisition of the assets of CPP with borrowings
under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 of cash proceeds from
the sale of the assets of CPP to reduce its revolving credit agreement borrowings. |
The assets and liabilities resulting from the CPG Acquisition are included in our Condensed
Consolidated Balance Sheet at June 30, 2009. The purchase price allocation has been
finalized except for the fair values of utility regulatory assets which are subject to a
pending base rate proceeding of CPG (see Note 5). Pursuant to the CPG Acquisition purchase
agreement, the purchase price was subject to adjustment for the difference between the
estimated $35.4 and the actual working capital as of the closing date agreed to by both UGI
Utilities and PPL Corporation (“PPL”). In February 2009, UGI Utilities and PPL reached an
agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $3.7 in
cash plus interest. UGI Utilities will receive an additional approximately $7.5 in cash from
PPL associated with certain income tax assets later in Fiscal 2009. Also during the three
months ended March 31, 2009, UGI Utilities and AmeriGas OLP reached an agreement on the
working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to
AmeriGas OLP pursuant to which UGI Utilities paid AmeriGas OLP $1.4. |
- 24 -
The purchase price of the CPG Acquisition, including transaction fees and expenses and
incurred liabilities totaling approximately $2.9, has been allocated to the assets acquired
and liabilities assumed as follows: |
Working capital |
$ | 22.2 | ||
Property, plant and equipment |
236.1 | |||
Goodwill |
33.6 | |||
Utility regulatory assets |
22.5 | |||
Other assets |
12.5 | |||
Noncurrent liabilities |
(32.1 | ) | ||
Total |
$ | 294.8 | ||
Substantially all of the goodwill is deductible for income tax purposes over a
fifteen-year period. |
The operating results of CPG and CPP are included in our consolidated results beginning
October 1, 2008. The following table presents pro forma income statement and basic and
diluted per share data for the three and nine months ended June 30, 2008 as if the CPG
Acquisition had occurred as of October 1, 2007: |
| Three Months Ended | Nine Months Ended | |||||||
| June 30, 2008 | June 30, 2008 | |||||||
| (pro forma) | (pro forma) | |||||||
Revenues |
$ | 1,375.2 | $ | 5,652.2 | ||||
Net income |
$ | 16.3 | $ | 233.5 | ||||
Earnings per share: |
||||||||
Basic |
$ | 0.15 | $ | 2.18 | ||||
Diluted |
$ | 0.15 | $ | 2.15 | ||||
The pro forma results of operations reflect CPG’s and CPP’s historical operating
results after giving effect to adjustments directly attributable to the transaction that are
expected to have a continuing effect. The pro forma amounts are not necessarily indicative
of the operating results that would have occurred had the CPG Acquisition been completed as
of the date indicated, nor are they necessarily indicative of future operating results. |
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground
LPG storage facility located on leased property in California for net cash proceeds of
$42.4. The Partnership recorded a $39.9 pre-tax gain on the sale which amount is included in
“other income” on the Condensed Consolidated Statement of Income for the nine months ended
June 30, 2009. The sale increased net income by $10.4 or $0.10 per diluted share. |
On January 29, 2009, Flaga purchased for cash consideration the 50% equity interest in ZLH
it did not already own from its joint-venture partner, Progas GmbH & Co. KG (“Progas”),
pursuant to a purchase agreement dated December 18, 2008. ZLH distributes LPG in the Czech
Republic, Hungary, Poland, Slovakia and Romania. The purchase price for the 50% equity
interest in ZLH was not material. |
- 25 -
| 9. | Fair Value Measurement |
The Company adopted SFAS 157 effective October 1, 2008. SFAS 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands disclosures about fair
value measurements. SFAS 157 defines fair value as the price that would be received to sell
an asset or paid to transfer a liability (an exit price) in an orderly transaction between
market participants at the measurement date. SFAS 157 clarifies that the fair value should
be based upon assumptions that market participants would use when pricing an asset or
liability, including assumptions about risk and risks inherent in valuation techniques and
inputs to valuations. This includes not only the credit standing of counterparties and
credit enhancements but also the impact of our own nonperformance risk on our liabilities.
SFAS 157 requires fair value measurements to assume that the transaction occurs in the
principal market for the asset or liability or in the absence of a principal market, the
most advantageous market for the asset or liability (the market for which the reporting
entity would be able to maximize the amount received or minimize the amount paid). We apply
fair value measurements to certain assets and liabilities principally commodity, foreign
currency and interest rate derivative instruments. We evaluate the need for credit
adjustments to our derivative instrument fair values in accordance with the requirements
noted above. Such adjustments were not material to the fair values of our derivative
instruments. |
We use the following fair value hierarchy, which prioritizes the inputs to valuation
techniques used to measure fair value into three broad levels: |
| • | Level 1 — Quoted prices (unadjusted) in active markets for identical
assets and liabilities that we have the ability to access at the
measurement date. Instruments categorized in Level 1 consist of our
exchange-traded commodity futures contracts. |
| • | Level 2 — Inputs other than quoted prices included within Level 1 that
are either directly or indirectly observable for the asset or liability,
including quoted prices for similar assets or liabilities in active
markets, quoted prices for identical or similar assets or liabilities in
inactive markets, inputs other than quoted prices that are observable for
the asset or liability, and
inputs that are derived from observable market data by correlation or other
means. Instruments categorized in Level 2 include non-exchange traded
derivatives such as over the counter commodity price swap and option
contracts, interest rate swaps and interest rate protection agreements,
foreign currency forward contracts and financial transmission rights
(“FTRs”). |
| • | Level 3 — Unobservable inputs for the asset or liability including
situations where there is little, if any, market activity for the asset or
liability. The Company did not have any derivative financial instruments
categorized as Level 3 at June 30, 2009. |
- 26 -
The fair value hierarchy gives the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs
to measure fair value might fall into different levels of the fair value hierarchy. The
lowest level input that is significant to a fair value measurement in its entirety
determines the applicable level in the fair value hierarchy. Assessing the significance of a
particular input to the fair value measurement in its entirety requires judgment,
considering factors specific to the asset or liability. |
SFAS 157 requires fair value measurements to be separately disclosed by level within the
fair value hierarchy. The following table presents our assets and liabilities that are
measured at fair value on a recurring basis for each hierarchy level, including both current
and noncurrent portions, as of June 30, 2009: |
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Derivative financial instruments: |
||||||||||||||||
Assets |
$ | — | $ | 14.2 | $ | — | $ | 14.2 | ||||||||
Liabilities |
$ | (59.8 | ) | $ | (48.1 | ) | $ | — | $ | (107.9 | ) | |||||
| 10. | Disclosures About Derivative Instruments, Hedging Activities and Financial Instruments |
Derivative Instruments and Hedging Activities |
The Company is exposed to certain market risks related to its ongoing business operations.
Management uses derivative financial and commodity instruments, among other things, to
manage these risks. The primary risks managed by derivative instruments are (1) commodity
price risk, (2) interest rate risk and (3) foreign currency exchange rate risk. Although we
use derivative financial and commodity instruments to reduce market risk associated with
forecasted transactions, we do not use derivative financial and commodity instruments for
speculative or trading purposes. The use of derivative instruments is controlled by our
derivative, hedging and credit policies which govern,
among other things, the derivative instruments we can use, counterparty credit limits and
contract authorization limits. Because our derivative instruments, other than FTRs and
gasoline futures and swap contracts, generally qualify as hedges under SFAS 133, we expect
that changes in the fair value of derivative instruments used to manage commodity, interest
rate or currency exchange rate risk would be substantially offset by gains or losses on the
associated anticipated transactions. |
Commodity Price Risk |
In order to manage market price risk associated with the Partnership’s fixed-price programs
which permit customers to lock in the prices they pay for propane principally during the
heating season months of October through March, the Partnership uses over-the-counter
derivative commodity instruments, principally price swap contracts. Certain other domestic
business units and our International Propane operations also use over-the-counter price swap
and option contracts to reduce commodity price volatility associated with a portion of their
forecasted LPG purchases. |
- 27 -
Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the
prudently incurred costs of natural gas it sells to retail core-market customers. As
permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility
currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures contracts to
reduce commodity price volatility associated with a portion of the natural gas it purchases
for its retail core-market customers. At June 30, 2009, the volumes of natural gas
associated with Gas Utility’s unsettled NYMEX natural gas futures contracts totaled 8.2
million dekatherms and the maximum period over which Gas Utility is hedging natural gas
market risk is 15 months. |
In order to reduce volatility associated with a substantial portion of its electricity
transmission congestion costs, Electric Utility obtains FTRs through an annual PJM
Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions.
Energy Services purchases FTRs to economically hedge electricity transmission congestion
costs associated with its fixed-price electricity sales contracts. FTRs are derivative
financial instruments that entitle the holder to receive compensation for electricity
transmission congestion charges that result when there is insufficient electricity
transmission capacity on the electric transmission grid. PJM is a regional transmission
organization that coordinates the movement of wholesale electricity in all or parts of 14
eastern and midwestern states. |
In order to reduce operating expense volatility, UGI Utilities from time to time enters into
NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be
used in the operation of their vehicles and equipment. The volumes of gasoline under these
contracts, the associated fair values and the effect on net income were not material for all
periods presented. |
In order to manage market price risk relating to fixed-price sales contracts for natural gas
and electricity, Energy Services enters into NYMEX and over-the-counter natural gas and
electricity futures contracts. |
At June 30, 2009, the Company had the following outstanding derivative commodity instruments
volumes that qualify for hedge accounting treatment: |
| Commodity | Volumes | |||
LPG (millions of gallons) |
163.1 | |||
Natural gas (millions of dekatherms) |
33.3 | |||
Electricity (millions of kilowatt-hours) |
418.0 | |||
The maximum period over which we are currently hedging our exposure to the variability
in cash flows associated with commodity price risk is 22 months. The volume of electricity
congestion that is subject to FTRs at June 30, 2009 totaled 2,226.9 million kilowatt-hours
and the maximum period over which we are currently hedging electricity congestion with FTRs
is 23 months. |
- 28 -
We account for commodity price risk contracts (other than our Gas Utility natural gas
futures contracts, FTRs and gasoline futures contracts) as cash flow hedges. Changes in the
fair values of contracts qualifying for cash flow hedge accounting are recorded in
accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership,
minority interest, to the extent effective in offsetting changes in the underlying commodity
price risk, until earnings are affected by the hedged item. With respect to natural gas
futures contracts associated with our Gas Utility, gains and losses on unsettled natural gas
futures contracts are recorded in deferred fuel costs on the Condensed Consolidated Balance
Sheet in accordance with SFAS No. 71 and reflected in cost of sales through the PGC
mechanism. At June 30, 2009, Gas Utility had recorded a current liability of $42.5,
representing the fair value of unsettled natural gas futures contracts as of that date, and
an associated regulatory asset of $42.5 within deferred fuel costs. Because Electric Utility
is entitled to fully recover its default service costs commencing January 1, 2010 pursuant
to a January 22, 2009 settlement of its default service rate filing with the PUC (see Note
5), changes in the fair value of Electric Utility FTRs associated with periods after January
1, 2010 will not affect net income. Electric Utility FTRs associated with periods prior to
January 2010 are recorded at fair value with changes in fair value reflected in cost of
sales. Energy Services’ FTRs are recorded at fair value with changes in fair value reflected
in cost of sales. |
Interest Rate Risk |
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As
these long-term debt issues mature, we typically refinance such debt with new debt having
interest rates reflecting then-current market conditions. In order to reduce market rate
risk on the underlying benchmark rate of interest associated with near- to medium-term
forecasted issuances of fixed-rate debt, from time to time we enter into interest rate
protection agreements (“IRPAs”). As of June 30, 2009, the total notional amount of the
Company’s unsettled IRPAs was $150. Our current unsettled IRPA contracts hedge
forecasted interest payments associated with the issuance of debt forecasted to occur in
June 2010. |
Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally
indexed to short-term market interest rates. Antargaz has effectively fixed the underlying
euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the
underlying euribor interest rate on a substantial portion of its term loan through September
2011 through the use of pay-fixed, receive-variable interest rate swap agreements. As of
June 30, 2009, the total notional amount of our interest rate swaps was €406.6. |
We account for IRPAs and interest rate swaps as cash flow hedges. Changes in the fair values
of IRPAs and interest rate swaps are recorded in AOCI and, with respect to the Partnership,
minority interest, to the extent effective in offsetting changes in the underlying interest
rate risk, until earnings are affected by the hedged interest expense. |
- 29 -
Foreign Currency Exchange Rate Risk |
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S.
dollar-denominated LPG product purchases through the use of forward foreign currency
exchange contracts. The volume of such contracts are equal to approximately 15% to 20% of
dollar-denominated purchases of LPG estimated to occur during the heating-season months of
October through March. At June 30, 2009, we were hedging a total of $121.4 of U.S. dollar
denominated LPG purchases. The Company also enters into forward foreign currency exchange
contracts to reduce the volatility of the U.S. dollar value on a portion of its
International Propane euro-denominated net investment. At June 30, 2009, we were hedging a
total of €30.8 of our euro-denominated net investments. As of June 30, 2009, our foreign
currency contracts extend through December 2011. |
We account for foreign currency exchange contracts associated with anticipated purchases of
U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign
currency exchange contracts are recorded in AOCI, to the extent effective in offsetting
changes in the underlying currency exchange rate risk, until earnings are affected by the
hedged LPG purchase. Gains and losses on net investment hedges are included in AOCI until
such foreign operations are liquidated. |
Credit Risk Concentration |
We are exposed to credit loss in the event of nonperformance by counterparties to derivative
financial and commodity instruments. Our counterparties principally consist of major energy
companies and major U.S. and international financial institutions. We maintain credit
policies with regard to our counterparties that we believe reduce overall credit risk. These
policies include evaluating and monitoring our counterparties’ financial condition,
including their credit ratings, and entering into agreements with counterparties that govern
credit limits. Certain of these agreements call for the posting of collateral by
the counterparty or by the Company in the form of letters of credit, parental guarantees or
cash. We generally do not have credit-risk-related contingent features in our derivative
contracts. |
- 30 -
The following table provides information regarding the balance sheet location and fair value
of derivative assets and liabilities existing as of June 30, 2009: |
| Derivative Assets | Derivative (Liabilities) | |||||||||||
| Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
| As of June 30, 2009 | Location | Value | Location | Value | ||||||||
Derivatives Designated as
Hedging Instruments: |
||||||||||||
Commodity contracts: |
||||||||||||
LPG
|
Derivative financial instruments and Other assets | $ | 2.0 | Derivative financial instruments | $ | (13.6 | ) | |||||
Natural gas
|
Derivative financial instruments and Other noncurrent liabilities | (54.5 | ) | |||||||||
Electricity
|
Derivative financial instruments | 0.9 | Derivative financial instruments and Other noncurrent liabilities | (6.2 | ) | |||||||
Foreign currrency contracts
|
Derivative financial instruments and Other assets | 3.1 | Other noncurrent liabilities | (2.0 | ) | |||||||
Interest rate contracts
|
Derivative financial instruments | 3.7 | Derivative financial instruments and Other noncurrent liabilities | (31.6 | ) | |||||||
Total Derivatives Designated
as Hedging Instruments
|
$ | 9.7 | $ | (107.9 | ) | |||||||
Derivatives Not Designated as
Hedging Instruments: |
||||||||||||
Financial transmission rights
|
Derivative financial instruments and Other assets | $ | 4.5 | |||||||||
Gasoline contracts
|
Derivative financial instruments | — | ||||||||||
Total Derivatives Not Designated
as Hedging instruments
|
$ | 4.5 | ||||||||||
Total Derivatives
|
$ | 14.2 | $ | (107.9 | ) | |||||||
- 31 -
The following tables provide information on the effects of derivative instruments on the
consolidated statement of income and changes in AOCI and minority interest for the three and
nine months ended June 30, 2009: |
| Location of | Gain or (Loss) | |||||||||
| Gain or (Loss) | Gain or (Loss) | Reclassified | ||||||||
| Recognized in | Reclassified from | from | ||||||||
| AOCI and | AOCI and Minority | AOCI and Minority | ||||||||
| Three Months Ended June 30, 2009 | Minority Interest | Interest into Income | Interest into Income | |||||||
Cash Flow Hedges: |
||||||||||
Commodity contracts: |
||||||||||
LPG |
$ | 20.0 | Cost of sales | $ | (36.2 | ) | ||||
Natural gas |
(4.0 | ) | Cost of sales | (26.0 | ) | |||||
Electricity |
0.3 | Cost of sales | (2.4 | ) | ||||||
Foreign currency contracts |
(6.1 | ) | Cost of sales | 0.2 | ||||||
Interest rate contracts |
10.4 | Interest expense /other income | (2.9 | ) | ||||||
Total |
$ | 20.6 | $ | (67.3 | ) | |||||
Net Investment Hedges: |
||||||||||
Foreign currency contracts |
$ | (2.3 | ) | |||||||
| Location of Gain | Gain | |||||
| Recognized in | Recognized in | |||||
| Income | Income | |||||
Derivatives Not Designated as Hedging Instruments: |
||||||
FTRs |
Cost of sales | $ | 1.0 | |||
Gasoline contracts |
Operating expenses/ other income | 0.2 | ||||
Total |
$ | 1.2 | ||||
- 32 -
| Location of | Gain or (Loss) | |||||||||
| Gain or (Loss) | Gain or (Loss) | Reclassified | ||||||||
| Recognized in | Reclassified from | from | ||||||||
| AOCI and | AOCI and Minority | AOCI and Minority | ||||||||
| Nine Months Ended June 30, 2009 | Minority Interest | Interest into Income | Interest into Income | |||||||
Cash Flow Hedges: |
||||||||||
Commodity contracts |
||||||||||
LPG |
$ | (154.1 | ) | Cost of sales | $ | (188.5 | ) | |||
Natural gas |
(92.6 | ) | Cost of sales | (77.0 | ) | |||||
Electricity |
(4.6 | ) | Cost of sales | (3.6 | ) | |||||
Foreign currency contracts |
3.0 | Cost of sales | 5.0 | |||||||
Interest rate contracts |
(37.2 | ) | Interest expense / other income | (3.9 | ) | |||||
Total |
$ | (285.5 | ) | $ | (268.0 | ) | ||||
Net Investment
Hedges: |
||||||||||
Foreign exchange contracts |
$ | (0.2 | ) | |||||||
| Location of Gain (Loss) | Gain (Loss) | |||||
| Recognized in | Recognized in | |||||
| Income | Income | |||||
Derivatives Not Designated as Hedging Instruments: |
||||||
FTRs |
Cost of sales | $ | 0.9 | |||
Gasoline |
Operating expenses/ other income | (0.6 | ) | |||
Total |
$ | 0.3 | ||||
The amounts of derivative gains or losses representing ineffectiveness and the amounts
of gains or losses recognized in income as a result of excluding from ineffectiveness
testing were not material for the three and nine months ended June 30, 2009, respectively.
The Company reclassified losses of $1.7 into income during the nine months ended June 30,
2009 as a result of the discontinuance of cash flow hedges. The amount of net losses
associated with cash flow hedges expected to be reclassified into earnings during the next
twelve months based upon current fair values is $83.7. |
- 33 -
Financial Instruments |
||
The carrying amounts of financial instruments included in current assets and current
liabilities (excluding unsettled derivative instruments and current maturities of long-term
debt) approximate their fair values because of their short-term nature. The carrying amount
and estimated fair values of our remaining financial instruments assets and (liabilities) at
June 30, 2009 (including unsettled derivative instruments) are as follows: |
| Asset (Liability) | ||||||||
| Carrying | Estimated Fair | |||||||
| Amount | Value | |||||||
Derivative Instruments |
$ | (93.7 | ) | $ | (93.7 | ) | ||
Long-term debt |
$ | (2,099.5 | ) | $ | (2,063.1 | ) | ||
We estimate the fair value of long-term debt by using current market rates and by
discounting future cash flows using rates available for similar type debt. Fair values of
derivative instruments are determined in accordance with the provisions of SFAS 157 as
described in Footnote 9. |
| 11. | Financing Activities |
|
As a result of greater cash needed to fund counterparty collateral requirements resulting
from rapid and precipitous declines in propane commodity prices during the three months
ended December 31, 2008, on November 14, 2008, AmeriGas OLP entered into a revolving credit
agreement with two major banks (“Supplemental Credit Agreement”). The Supplemental Credit
Agreement was scheduled to expire on May 14, 2009 but was voluntarily terminated on April
17, 2009 concurrent with the signing of a new $75 revolving credit facility (as further
described below). The Supplemental Credit Agreement permitted AmeriGas OLP to borrow up to
$50 for working capital and general purposes. |
In order to maintain increased liquidity, on April 17, 2009, AmeriGas OLP entered into a new
$75 unsecured revolving credit facility (“2009 Supplemental Credit Agreement”) with three
major banks. The 2009 Supplemental Credit Agreement expires on July 1, 2010 and permits
AmeriGas OLP to borrow up to $75 for working capital and general purposes. Except for more
restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP,
the 2009 Supplemental Credit Agreement has restrictive covenants substantially similar to
AmeriGas OLP’s $200 Credit Agreement expiring October 15, 2011. |
On October 1, 2008, UGI Utilities issued $108 face value of 6.375% Senior Notes due October
2013. The proceeds from the issuance of the Notes were used by UGI Utilities to fund a
portion of the CPG Acquisition. |
- 34 -
| ITEM 2: | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
- 35 -
- 36 -
| Three Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (Millions of dollars) | (Millions of dollars) | |||||||||||||||
Net income (loss): |
||||||||||||||||
AmeriGas Propane (a) |
$ | (2.9 | ) | $ | (2.5 | ) | $ | 71.6 | (b) | $ | 48.5 | |||||
International Propane |
(8.0 | ) | 2.6 | 86.7 | 57.7 | |||||||||||
Gas Utility |
1.3 | 2.1 | 71.4 | 65.9 | ||||||||||||
Electric Utility |
1.7 | 4.1 | 7.3 | 11.6 | ||||||||||||
Energy Services |
5.1 | 9.4 | 35.4 | 39.7 | ||||||||||||
Corporate & Other |
(0.8 | ) | — | (2.9 | ) | (1.6 | ) | |||||||||
Total net (loss) income |
$ | (3.6 | ) | $ | 15.7 | $ | 269.5 | $ | 221.8 | |||||||
| (a) | Amounts are net of minority interests in AmeriGas Partners, L.P. |
|
| (b) | Includes net income of $10.4 million from sale of the Partnership’s California LPG
storage facility. |
| For the three months ended June 30, | 2009 | 2008 | Decrease | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 372.7 | $ | 535.2 | $ | (162.5 | ) | (30.4 | )% | |||||||
Total margin (a) |
$ | 162.4 | $ | 172.2 | $ | (9.8 | ) | (5.7 | )% | |||||||
Partnership EBITDA (b) |
$ | 25.4 | $ | 29.7 | $ | (4.3 | ) | (14.5 | )% | |||||||
Operating income |
$ | 4.4 | $ | 9.6 | $ | (5.2 | ) | (54.2 | )% | |||||||
Retail gallons sold (millions) |
160.0 | 180.7 | (20.7 | ) | (11.5 | )% | ||||||||||
Degree days — % (warmer) colder
than normal (c) |
(3.1 | )% | 8.1 | % | — | — | ||||||||||
| (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) 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 condensed consolidated financial statements). |
|
| (c) | Deviation from average heating degree-days for the 30-year period 1971-2000 based upon
national weather statistics provided by the National Oceanic and Atmospheric Administration
(“NOAA”) for 335 airports in the United States, excluding Alaska. Prior-year data has been
adjusted to correct a NOAA error. |
- 37 -
- 38 -
| Increase | ||||||||||||||||
| For the three months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of euros) |
||||||||||||||||
Revenues |
€ | 121.0 | € | 148.7 | € | (27.7 | ) | (18.6 | )% | |||||||
Total margin (a) |
€ | 71.6 | € | 66.2 | € | 5.4 | 8.2 | % | ||||||||
Operating income |
€ | 1.2 | € | 7.2 | € | (6.0 | ) | (83.3 | )% | |||||||
Income (loss) before income taxes |
€ | (3.3 | ) | € | 2.0 | € | (5.3 | ) | (265.0 | )% | ||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 164.9 | $ | 232.8 | $ | (67.9 | ) | (29.2 | )% | |||||||
Total margin (a) |
$ | 97.5 | $ | 103.6 | $ | (6.1 | ) | (5.9 | )% | |||||||
Operating income |
$ | 0.3 | $ | 11.8 | $ | (11.5 | ) | (97.5 | )% | |||||||
Income (loss) before income taxes |
$ | (5.8 | ) | $ | 3.6 | $ | (9.4 | ) | (261.1 | )% | ||||||
Antargaz retail gallons sold |
48.1 | 55.2 | (7.1 | ) | (12.9 | )% | ||||||||||
Degree days — % (warmer) than normal (b) |
(29.3 | )% | (14.8 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
- 39 -
| Increase | ||||||||||||||||
| For the three months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 176.9 | $ | 202.2 | $ | (25.3 | ) | (12.5 | )% | |||||||
Total margin (a) |
$ | 67.1 | $ | 54.8 | $ | 12.3 | 22.4 | % | ||||||||
Operating income |
$ | 12.9 | $ | 12.5 | $ | 0.4 | 3.2 | % | ||||||||
Income before income taxes |
$ | 2.6 | $ | 4.1 | $ | (1.5 | ) | (36.6 | )% | |||||||
System throughput —
billions of cubic feet (“bcf”) |
25.8 | 23.4 | 2.4 | 10.3 | % | |||||||||||
Degree days — % (warmer) than normal (b) |
(6.5 | )% | (2.7 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”)
for airports located within Gas Utility’s service territory. |
- 40 -
| For the three months ended June 30, | 2009 | 2008 | Decrease | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 30.8 | $ | 32.8 | $ | (2.0 | ) | (6.1 | )% | |||||||
Total margin (a) |
$ | 9.4 | $ | 13.2 | $ | (3.8 | ) | (28.8 | )% | |||||||
Operating income |
$ | 3.3 | $ | 7.5 | $ | (4.2 | ) | (56.0 | )% | |||||||
Income before income taxes |
$ | 2.8 | $ | 7.1 | $ | (4.3 | ) | (60.6 | )% | |||||||
Distribution sales — millions of
kilowatt hours (“gwh”) |
209.8 | 224.9 | (15.1 | ) | (6.7 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $1.7 million and $1.9 million during the
three-month periods ended June 30, 2009 and 2008, respectively. For financial statement
purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the
Condensed Consolidated Statements of Income. |
- 41 -
| For the three months ended June 30, | 2009 | 2008 | Decrease | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 223.4 | $ | 388.9 | $ | (165.5 | ) | (42.6 | )% | |||||||
Total margin (a) |
$ | 23.0 | $ | 28.0 | $ | (5.0 | ) | (17.9 | )% | |||||||
Operating income |
$ | 8.6 | $ | 16.0 | $ | (7.4 | ) | (46.3 | )% | |||||||
Income before income taxes |
$ | 8.6 | $ | 16.0 | $ | (7.4 | ) | (46.3 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
- 42 -
| Increase | ||||||||||||||||
| For the nine months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,923.1 | $ | 2,290.0 | $ | (366.9 | ) | (16.0 | )% | |||||||
Total margin (a) |
$ | 793.3 | $ | 744.7 | $ | 48.6 | 6.5 | % | ||||||||
Partnership EBITDA (b) |
$ | 376.7 | $ | 294.5 | $ | 82.2 | 27.9 | % | ||||||||
Operating income |
$ | 317.2 | $ | 236.8 | $ | 80.4 | 34.0 | % | ||||||||
Retail gallons sold (millions) |
781.1 | 828.2 | (47.1 | ) | (5.7 | )% | ||||||||||
Degree days — % (warmer)
than normal (c) |
(1.9 | )% | (2.2 | )% | — | — | ||||||||||
| (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) 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 condensed consolidated financial statements). |
|
| (c) | Deviation from average heating degree-days for the 30-year period 1971-2000 based upon
national weather statistics provided by the National Oceanic and Atmospheric Administration
(“NOAA”) for 335 airports in the United States, excluding Alaska. Prior year data has been
adjusted to correct a NOAA error. |
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| Increase | ||||||||||||||||
| For the nine months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of euros) |
||||||||||||||||
Revenues |
€ | 590.7 | € | 624.2 | € | (33.5 | ) | (5.4 | )% | |||||||
Total margin (a) |
€ | 331.6 | € | 263.1 | € | 68.5 | 26.0 | % | ||||||||
Operating income |
€ | 117.6 | € | 70.9 | € | 46.7 | 65.9 | % | ||||||||
Income before income taxes |
€ | 102.7 | € | 54.9 | € | 47.8 | 87.1 | % | ||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 780.6 | $ | 936.2 | $ | (155.6 | ) | (16.6 | )% | |||||||
Total margin (a) |
$ | 438.3 | $ | 395.1 | $ | 43.2 | 10.9 | % | ||||||||
Operating income |
$ | 154.1 | $ | 105.7 | $ | 48.4 | 45.8 | % | ||||||||
Income before income taxes |
$ | 133.7 | $ | 80.7 | $ | 53.0 | 65.7 | % | ||||||||
Antargaz retail gallons sold |
247.4 | 250.2 | (2.8 | ) | (1.1 | )% | ||||||||||
Degree days — % (warmer) than normal (b) |
(1.0 | )% | (5.1 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
- 44 -
| For the nine months ended June 30, | 2009 | 2008 | Increase | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,130.1 | $ | 1,005.6 | $ | 124.5 | 12.4 | % | ||||||||
Total margin (a) |
$ | 334.4 | $ | 266.3 | $ | 68.1 | 25.6 | % | ||||||||
Operating income |
$ | 149.8 | $ | 138.1 | $ | 11.7 | 8.5 | % | ||||||||
Income before income taxes |
$ | 118.1 | $ | 109.8 | $ | 8.3 | 7.6 | % | ||||||||
System throughput —
billions of cubic feet (“bcf”) |
126.4 | 112.4 | 14.0 | 12.5 | % | |||||||||||
Degree days — % colder (warmer) than normal (b) |
3.9 | % | (2.2 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”)
for airports located within Gas Utility’s service territory. |
- 45 -
| Increase | ||||||||||||||||
| For the nine months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 104.8 | $ | 103.3 | $ | 1.5 | 1.5 | % | ||||||||
Total margin (a) |
$ | 32.0 | $ | 37.8 | $ | (5.8 | ) | (15.3 | )% | |||||||
Operating income |
$ | 13.8 | $ | 21.4 | $ | (7.6 | ) | (35.5 | )% | |||||||
Income before income taxes |
$ | 12.5 | $ | 19.9 | $ | (7.4 | ) | (37.2 | )% | |||||||
Distribution sales — millions of
kilowatt hours (“gwh”) |
735.8 | 758.4 | (22.6 | ) | (3.0 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $5.7 million and $5.9 million during the
nine-month periods ended June 30, 2009 and 2008, respectively. For financial statement
purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on
the Condensed Consolidated Statements of Income. |
- 46 -
| Increase | ||||||||||||||||
| For the nine months ended June 30, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,007.1 | $ | 1,261.4 | $ | (254.3 | ) | (20.2 | )% | |||||||
Total margin (a) |
$ | 104.8 | $ | 101.2 | $ | 3.6 | 3.6 | % | ||||||||
Operating income |
$ | 60.0 | $ | 67.3 | $ | (7.3 | ) | (10.8 | )% | |||||||
Income before income taxes |
$ | 60.0 | $ | 67.3 | $ | (7.3 | ) | (10.8 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
- 47 -
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- 50 -
- 51 -
- 52 -
- 53 -
- 54 -
| ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
- 55 -
- 56 -
- 57 -
| Asset (Liability) | ||||||||
| Change in | ||||||||
| Fair Value | Fair Value | |||||||
(Millions of dollars) |
||||||||
June 30, 2009: |
||||||||
LPG commodity price risk |
$ | (11.6 | ) | $ | (13.6 | ) | ||
FTRs |
4.5 | (0.4 | ) | |||||
Natural gas commodity price risk |
(12.1 | ) | (14.2 | ) | ||||
Gasoline |
— | (0.2 | ) | |||||
Electricity commodity price risk |
(5.3 | ) | (1.7 | ) | ||||
Interest rate risk |
(27.9 | ) | (7.0 | ) | ||||
Foreign currency exchange rate risk |
1.2 | (16.5 | ) | |||||
- 58 -
| ITEM 4. | CONTROLS AND PROCEDURES |
| (a) | Evaluation of Disclosure Controls and Procedures |
|
The Company’s management, with the participation of the Company’s Chief Executive Officer
and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure
controls and procedures as of the end of the period covered by this report. Based on that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the
Company’s disclosure controls and procedures as of the end of the period covered by this
report were designed and functioning effectively to provide reasonable assurance that the
information required to be disclosed by the Company in reports filed under the Securities
Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and forms, and
(ii) accumulated and communicated to our management, including the Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. |
||
| (b) | Change in Internal Control over Financial Reporting |
|
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. |
- 59 -
| ITEM 1. | LEGAL PROCEEDINGS |
- 60 -
| ITEM 1A. | RISK FACTORS |
- 61 -
| ITEM 6. | EXHIBITS |
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.1 | Form of Joinder No.
2 to Restricted
Subsidiary
Guarantee, dated as
of July 20, 2009,
by AmeriGas Eagle
Propane, L.P. and
AmeriGas Eagle
Parts & Service
Inc. for the
benefit of Wachovia
Bank, National
Associations, as
agent for the Banks
(as defined)
|
AmeriGas Partners, L.P. | Form 8-K (7/20/09) | 10.1 | ||||||||
| 10.2 | Form of Joinder No.
1 to Restricted
Subsidiary
Guarantee, dated as
of July 20, 2009,
by AmeriGas Eagle
Propane, L.P. and
AmeriGas Eagle
Parts & Service
Inc. for the
benefit of Wachovia
Bank, National
Association and the
Banks (as defined)
|
AmeriGas Partners, L.P. | Form 8-K (7/20/09) | 10.2 | ||||||||
| 10.3 | Restricted Security
Guarantee, dated
April 17, 2009, by
the Restricted
Subsidiaries of
AmeriGas Propane,
L.P. as Guarantors,
for the benefit of
Wachovia Bank,
National
Association and the
Banks (as defined)
|
AmeriGas Partners, L.P. | Form 8-K (7/20/09) | 10.3 | ||||||||
| 10.4 | Fourth Amended and
Restated Agreement
of Limited
Partnership of
AmeriGas Partners,
L.P. dated as of
July 27, 2009
|
AmeriGas Partners, L.P. | Form 10-Q (6/30/09) | 3.1 | ||||||||
| 31.1 | Certification by
the Chief Executive
Officer relating to
the Registrant’s
Report on Form 10-Q
for the quarter
ended June 30,
2009, 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,
2009, 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,
2009, pursuant to
Section 906 of the
Sarbanes-Oxley Act
of 2002 |
|||||||||||
- 62 -
| UGI Corporation (Registrant) |
||||
| Date: August 7, 2009 | By: | /s/ Peter Kelly | ||
| Peter Kelly | ||||
| Vice President — Finance and Chief Financial Officer | ||||
| Date: August 7, 2009 | By: | /s/ Davinder Athwal | ||
| Davinder Athwal | ||||
| Vice President — Accounting and Financial Control and Chief Risk Officer | ||||
- 63 -
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q
for the quarter ended June 30, 2009, 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, 2009, 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, 2009, pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |