| 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 | ||||||||
| 1 | ||||||||
| 2 | ||||||||
| 3 | ||||||||
| 4-30 | ||||||||
| 31-49 | ||||||||
| 50-53 | ||||||||
| 53 | ||||||||
| 54-56 | ||||||||
| 56 | ||||||||
| 57 | ||||||||
| 58 | ||||||||
| Exhibit 10.1 | ||||||||
| Exhibit 31.1 | ||||||||
| Exhibit 31.2 | ||||||||
| Exhibit 32 | ||||||||
| EX-101 INSTANCE DOCUMENT | ||||||||
| EX-101 SCHEMA DOCUMENT | ||||||||
| EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
| EX-101 LABELS LINKBASE DOCUMENT | ||||||||
| EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
-i-
| June 30, | September 30, | June 30, | ||||||||||
| 2010 | 2009 | 2009 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 241.8 | $ | 280.1 | $ | 240.1 | ||||||
Restricted cash |
22.9 | 7.0 | 64.8 | |||||||||
Accounts receivable (less allowances for doubtful accounts of
$44.5, $38.3 and $58.2, respectively) |
503.4 | 405.9 | 454.5 | |||||||||
Accrued utility revenues |
9.7 | 21.0 | 21.2 | |||||||||
Inventories |
249.2 | 363.2 | 269.1 | |||||||||
Deferred income taxes |
26.7 | 34.5 | 49.3 | |||||||||
Utility regulatory assets |
6.3 | 19.6 | 28.8 | |||||||||
Derivative financial instruments |
17.5 | 20.3 | 12.4 | |||||||||
Prepaid expenses and other current assets |
34.1 | 33.5 | 21.0 | |||||||||
Total current assets |
1,111.6 | 1,185.1 | 1,161.2 | |||||||||
Property, plant and equipment (less accumulated depreciation and
amortization of $1,866.2, $1,788.8 and $1,750.5 respectively) |
2,875.5 | 2,903.6 | 2,823.3 | |||||||||
Goodwill |
1,475.9 | 1,582.3 | 1,545.5 | |||||||||
Intangible assets, net |
138.1 | 165.5 | 161.6 | |||||||||
Other assets |
230.5 | 206.1 | 209.7 | |||||||||
Total assets |
$ | 5,831.6 | $ | 6,042.6 | $ | 5,901.3 | ||||||
LIABILITIES AND EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Current maturities of long-term debt |
$ | 572.9 | $ | 94.5 | $ | 11.6 | ||||||
Bank loans |
35.2 | 163.1 | 125.5 | |||||||||
Accounts payable |
297.9 | 334.9 | 276.4 | |||||||||
Derivative financial instruments |
48.0 | 37.5 | 95.1 | |||||||||
Other current liabilities |
379.5 | 467.3 | 437.7 | |||||||||
Total current liabilities |
1,333.5 | 1,097.3 | 946.3 | |||||||||
Long-term debt |
1,456.8 | 2,038.6 | 2,087.9 | |||||||||
Deferred income taxes |
510.9 | 504.9 | 464.7 | |||||||||
Deferred investment tax credits |
5.4 | 5.7 | 5.8 | |||||||||
Other noncurrent liabilities |
531.0 | 579.3 | 554.5 | |||||||||
Total liabilities |
3,837.6 | 4,225.8 | 4,059.2 | |||||||||
Commitments and contingencies (note 9) |
||||||||||||
Equity: |
||||||||||||
UGI Corporation stockholders’ equity: |
||||||||||||
UGI Common Stock, without par value (authorized - 300,000,000 shares;
issued - 115,375,794, 115,261,294 and 115,261,294 shares, respectively) |
896.1 | 875.6 | 870.4 | |||||||||
Retained earnings |
992.1 | 804.3 | 837.0 | |||||||||
Accumulated other comprehensive loss |
(115.8 | ) | (38.9 | ) | (71.7 | ) | ||||||
Treasury stock, at cost |
(42.4 | ) | (49.6 | ) | (52.4 | ) | ||||||
Total UGI Corporation stockholders’ equity |
1,730.0 | 1,591.4 | 1,583.3 | |||||||||
Noncontrolling interests |
264.0 | 225.4 | (1) | 258.8 | (1) | |||||||
Total equity |
1,994.0 | 1,816.8 | (1) | 1,842.1 | (1) | |||||||
Total liabilities and equity |
$ | 5,831.6 | $ | 6,042.6 | $ | 5,901.3 | ||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for
noncontrolling interests in consolidated subsidiaries (Note 3). |
- 1 -
| Three Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues |
$ | 961.9 | $ | 962.2 | $ | 4,701.0 | $ | 4,878.5 | ||||||||
Costs and expenses: |
||||||||||||||||
Cost of sales (excluding depreciation shown below) |
615.5 | 591.6 | 3,009.2 | 3,142.8 | ||||||||||||
Operating and administrative expenses |
267.6 | 281.0 | 892.7 | 929.6 | ||||||||||||
Utility taxes other than income taxes |
4.2 | 4.2 | 13.6 | 13.8 | ||||||||||||
Depreciation |
46.1 | 46.0 | 140.4 | 133.6 | ||||||||||||
Amortization |
5.6 | 5.3 | 16.9 | 15.2 | ||||||||||||
Other (income) expense, net |
(8.3 | ) | 5.3 | (12.2 | ) | (49.5 | ) | |||||||||
| 930.7 | 933.4 | 4,060.6 | 4,185.5 | |||||||||||||
Operating income |
31.2 | 28.8 | 640.4 | 693.0 | ||||||||||||
Loss from equity investees |
(1.9 | ) | — | (1.9 | ) | (0.8 | ) | |||||||||
Interest expense |
(33.6 | ) | (34.6 | ) | (101.9 | ) | (106.7 | ) | ||||||||
(Loss) income before income taxes |
(4.3 | ) | (5.8 | ) | 536.6 | 585.5 | ||||||||||
Income taxes |
0.1 | (6.4 | ) | (162.5 | ) | (172.0 | ) | |||||||||
Net (loss) income |
(4.2 | ) | (12.2 | )(1) | 374.1 | 413.5 | (1) | |||||||||
Less: net loss (income) attributable to noncontrolling interests,
principally AmeriGas Partners |
7.6 | 8.6 | (1) | (115.2 | ) | (144.0 | )(1) | |||||||||
Net income (loss) attributable to UGI Corporation |
$ | 3.4 | $ | (3.6 | )(1) | $ | 258.9 | $ | 269.5 | (1) | ||||||
Earnings (loss) per common share attributable to UGI stockholders: |
||||||||||||||||
Basic |
$ | 0.03 | $ | (0.03 | ) | $ | 2.37 | $ | 2.49 | |||||||
Diluted |
$ | 0.03 | $ | (0.03 | ) | $ | 2.35 | $ | 2.47 | |||||||
Average common shares outstanding (thousands): |
||||||||||||||||
Basic |
109,683 | 108,592 | 109,331 | 108,407 | ||||||||||||
Diluted |
110,699 | 108,592 | 110,188 | 109,207 | ||||||||||||
Dividends declared per common share |
$ | 0.25 | $ | 0.20 | $ | 0.65 | $ | 0.585 | ||||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in
consolidated subsidiaries (Note 3). |
- 2 -
| Nine Months Ended | ||||||||
| June 30, | ||||||||
| 2010 | 2009 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income |
$ | 374.1 | $ | 413.5 | (1) | |||
Reconcile to net cash from operating activities: |
||||||||
Depreciation and amortization |
157.3 | 148.8 | ||||||
Gain on sale of Partnership California storage facility |
— | (39.9 | ) | |||||
Deferred income taxes, net |
46.9 | (8.3 | ) | |||||
Provision for uncollectible accounts |
26.2 | 35.8 | ||||||
Net change in settled accumulated other comprehensive income (loss) |
31.4 | (33.2 | ) | |||||
Other, net |
20.7 | 10.4 | ||||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(147.3 | ) | 68.3 | |||||
Inventories |
106.9 | 159.0 | ||||||
Utility deferred fuel costs |
(1.0 | ) | 40.2 | |||||
Accounts payable |
(10.0 | ) | (238.7 | ) | ||||
Other current assets |
(6.2 | ) | 42.0 | |||||
Other current liabilities |
(82.3 | ) | (4.6 | ) | ||||
Net cash provided by operating activities |
516.7 | 593.3 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Expenditures for property, plant and equipment |
(228.8 | ) | (213.4 | ) | ||||
Acquisitions of businesses, net of cash acquired |
(25.4 | ) | (319.5 | ) | ||||
Net proceeds from sale of Partnership California storage facility |
— | 42.4 | ||||||
(Increase) decrease in restricted cash |
(15.9 | ) | 5.5 | |||||
Other, net |
(14.7 | ) | 1.2 | |||||
Net cash used by investing activities |
(284.8 | ) | (483.8 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Dividends on UGI Common Stock |
(71.1 | ) | (63.3 | ) | ||||
Distributions on AmeriGas Partners publicly held Common Units |
(66.2 | ) | (63.2 | ) | ||||
Issuance of debt |
— | 108.1 | ||||||
Repayments of debt |
(9.5 | ) | (76.5 | ) | ||||
Decrease in bank loans |
(123.3 | ) | (24.0 | ) | ||||
Other |
18.3 | 5.3 | ||||||
Net cash used by financing activities |
(251.8 | ) | (113.6 | ) | ||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
(18.4 | ) | (1.0 | ) | ||||
Cash and cash equivalents decrease |
$ | (38.3 | ) | $ | (5.1 | ) | ||
Cash and cash equivalents: |
||||||||
End of period |
$ | 241.8 | $ | 240.1 | ||||
Beginning of period |
280.1 | 245.2 | ||||||
Decrease |
$ | (38.3 | ) | $ | (5.1 | ) | ||
| (1) | As adjusted in accordance with the transition provisions for accounting for
noncontrolling interests in consolidated
subsidiaries (Note 3). |
- 3 -
| 1. | Nature of Operations |
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates,
distributes and markets energy products and related services. In the United States, we own
and operate (1) a retail propane marketing and distribution business; (2) natural gas and
electric distribution utilities; (3) electricity generation facilities; and (4) energy
marketing and services businesses. Internationally, we market and distribute propane and
other 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 domestic propane marketing and distribution business through AmeriGas Partners,
L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal
operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s
subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating
Partnerships”). AmeriGas Partners and the Operating Partnerships 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. 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, 2010,
the General Partner held a 1% general partner interest and 42.8% limited partner interest in
AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP. Our limited
partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common
Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises
32,397,300 Common Units held by the general public as limited partner interests. |
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1)
conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG
distribution business in central and eastern Europe (“Flaga”); and (3) conducts an LPG
business in the Nantong region of China. We refer to our foreign operations collectively as
“International Propane.” Through other subsidiaries, Enterprises also conducts an energy
marketing and services business primarily in the Mid-Atlantic region of the United States
(collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development
Company (“UGID”), owns interests in electricity generation facilities located in
Pennsylvania. |
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. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG
own and operate natural gas distribution utilities principally located 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 as “UGI Gas;” PNG’s natural gas distribution
utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred
to 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. Gas Utility and Electric Utility are collectively referred to as “Utilities.” |
- 4 -
| 2. | Significant Accounting Policies |
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
interests in certain subsidiaries of Antargaz and Flaga as noncontrolling 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, 2009 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 Current Report on Form 8-K dated
May 26, 2010 (“Company’s 2009 Annual Financial Statements and Notes”) which supersede the
financial statements and related notes included in our Form 10-K for the year ended
September 30, 2009 in order to retrospectively reflect the adoption of the new guidance
relating to noncontrolling interests discussed in Note 3. 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. |
As discussed below, certain prior-period amounts have been adjusted to comply with recently
adopted Financial Accounting Standards Board (“FASB”) accounting guidance for the
presentation of noncontrolling interests in consolidated financial statements. |
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 | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Denominator (thousands of shares): |
||||||||||||||||
Average common shares
outstanding for basic computation |
109,683 | 108,592 | 109,331 | 108,407 | ||||||||||||
Incremental shares issuable for stock
options and awards |
1,016 | — | 857 | 800 | ||||||||||||
Average common shares outstanding for
diluted computation |
110,699 | 108,592 | 110,188 | 109,207 | ||||||||||||
Comprehensive Income (Loss). The following table presents the components of
comprehensive income (loss) for the three and nine months ended June 30, 2010 and 2009: |
| Three Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2010 | 2009 (1) | 2010 | 2009 (1) | |||||||||||||
Net (loss) income |
$ | (4.2 | ) | $ | (12.2 | ) | $ | 374.1 | $ | 413.5 | ||||||
Other comprehensive (loss) income |
(58.2 | ) | 98.1 | (84.4 | ) | (38.0 | ) | |||||||||
Comprehensive (loss) income (including
noncontrolling interests) |
(62.4 | ) | 85.9 | 289.7 | 375.5 | |||||||||||
Less: comprehensive income (loss)
attributable
to noncontrolling interests |
21.4 | (31.1 | ) | (107.7 | ) | (162.5 | ) | |||||||||
Comprehensive (loss) income attributable
to UGI Corporation |
$ | (41.0 | ) | $ | 54.8 | $ | 182.0 | $ | 213.0 | |||||||
| (1) | As adjusted in accordance with the transition provisions for accounting
for noncontrolling interests in consolidated subsidiaries (see Note 3). |
Other comprehensive (loss) income 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, net of associated amortization; and (3) foreign currency translation
adjustments. |
On December 31, 2008, we merged two of our domestic defined benefit pension plans. As a
result of the merger, at December 31, 2008, the Company was required under GAAP to remeasure
the combined plan’s assets and obligations and record the funded status in our Condensed
Consolidated Balance Sheet. The associated after-tax charge to other comprehensive loss of
$38.7 is included in the table above for the nine months ended June 30, 2009. |
Reclassifications. In addition to the previously mentioned prior-period adjustments
resulting from the adoption of accounting guidance relating to the presentation of
noncontrolling interests, we have reclassified certain other prior-period balances to
conform to the current-period presentation. |
- 6 -
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, 2009 and 2008, the Company adjusted its unrecognized tax benefits which reduced
income tax expense and increased net income by $0.9 and $2.0 for the nine months ended June
30, 2010 and 2009, respectively. |
The Company received Internal Revenue Service (“IRS”) consent to change its tax method of
accounting for capitalizing certain repairs and maintenance costs associated with its Gas
Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The
filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal
and state income tax benefits totaling approximately $30.2 which has been, or will be, used
to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’
Fiscal 2009 stand alone Pennsylvania income tax return also produced an approximate $43.4
state net operating loss (“NOL”) carryforward, resulting in a net deferred tax benefit of
approximately $2.8. |
Under current Pennsylvania state income tax law, the NOL stated above can be carried forward
by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because
the Company believes that it is more likely than not that it will fully utilize this state
NOL prior to its expiration, no valuation allowance has been recorded. |
The Company’s determination of what constitutes a capital cost versus ordinary expense as it
relates to the new tax method will likely be reviewed upon audit by the IRS and may be
subject to subsequent adjustment. Accordingly, the status of this tax return position is
uncertain at this time. In accordance with accounting guidance regarding uncertain tax
positions, the Company has added $3.9 to its liability for unrecognized tax benefits related
to this tax method. However, because this tax matter relates only to the timing of tax
deductibility, we have recorded an offsetting deferred tax asset of an equal amount. |
The previously discussed change in tax method did not affect the Company’s net income (loss) for any periods
presented. For further information regarding the regulatory impact of this change, see Note 7. |
| 3. | Accounting Changes |
|
Adoption of New Accounting Standards |
Noncontrolling Interests. Effective October 1, 2009, we adopted new guidance regarding the
accounting for and presentation of noncontrolling interests in consolidated financial
statements. The new guidance changed the accounting and reporting relating to
noncontrolling interests in a consolidated subsidiary. Noncontrolling interests are now
classified within equity on the Condensed Consolidated Balance Sheets, a change from their
prior classification between liabilities and stockholders’ equity. Earnings (losses)
attributable to noncontrolling interests are now included in net income (loss) and deducted
from net income (loss) to determine net income (loss) attributable to UGI Corporation. In
addition, changes in a parent’s ownership interest while retaining control are accounted for
as equity transactions and any retained noncontrolling equity
investments in a former subsidiary are initially measured at fair value. In accordance with
the new guidance, previous periods have been adjusted to conform with the new presentation. |
- 7 -
Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for
business combinations. The new guidance applies to all transactions or other events in which
an entity obtains control of one or more businesses. The new guidance 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. The new guidance
applies prospectively to business combinations for which the acquisition date is on or after
October 1, 2009. Among the more significant changes in accounting for acquisitions are (1)
transaction costs are generally expensed (rather than being included as costs of the
acquisition); (2) contingencies, including contingent consideration, are generally 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 are recognized in operations (rather than as decreases in goodwill). The
new guidance did not have a material impact on our financial statements for the three and
nine months ended June 30, 2010. |
Intangible Asset Useful Lives. Effective October 1, 2009, we adopted new accounting
guidance which 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 GAAP. The intent of the new guidance is to improve the consistency between the useful
life of a recognized intangible asset under GAAP relating to intangible asset accounting and
the period of expected cash flows used to measure the fair value of the asset under GAAP
relating to business combinations and other applicable accounting literature. The new
guidance must be applied prospectively to intangible assets acquired after the effective
date. The adoption of the new guidance did not impact our financial statements. |
Fair Value Measurements. In January 2010, the FASB issued new guidance with respect to fair
value measurements disclosures. The new guidance requires additional disclosure related to
transfers between Levels 1 and 2 and separate disclosures about purchases, sales, issuances,
and settlements related to Level 3. The new guidance clarifies existing disclosure guidance
about inputs and valuation techniques for fair value measurements and levels of
disaggregation. We apply fair value measurements to certain assets and liabilities,
principally commodity, foreign currency and interest rate derivative instruments. The new
disclosures and clarifications of existing disclosures are effective for interim and annual
reporting periods beginning after December 15, 2009 except for the disclosures about
purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair
value measurements. Those disclosures are effective for fiscal years beginning after
December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption of the new
guidance that became effective during Fiscal 2010 did not have a material effect on our
disclosures. |
||
New Accounting Standards Not Yet Adopted |
Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new
guidance requiring more detailed disclosures about employers’ postretirement 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 annual disclosure guidance are effective for fiscal years
ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to
disclosures only, it will not impact the financial statements. |
- 8 -
Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding
accounting for transfers of financial assets. Among other things, the new guidance
eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends
previous derecognition guidance. The new guidance is effective for financial asset transfers
occurring after the beginning of an entity’s fiscal year that begins after November 15, 2009
(Fiscal 2011). The adoption of the new accounting guidance will change the accounting for
transfers of accounts receivable to a commercial paper conduit of a major bank under the
Energy Services Receivables Facility (see Note 6). Beginning October 1, 2010, trade
receivables transferred to the commercial paper conduit will remain on the Company’s balance
sheet and the Company will reflect a liability equal to the amount advanced by the
commercial paper conduit. Under current accounting guidance, trade accounts receivable sold
to the commercial paper conduit are removed from the balance sheet. Additionally, the
Company will record interest expense on amounts owed to the commercial paper conduit.
Currently, losses on sales of accounts receivable are reflected in other income, net. |
| 4. | Intangible Assets |
The Company’s intangible assets comprise the following: |
| June 30, | September 30, | June 30, | ||||||||||
| 2010 | 2009 | 2009 | ||||||||||
Goodwill (not subject to amortization) |
$ | 1,475.9 | $ | 1,582.3 | $ | 1,545.5 | ||||||
Other intangible assets: |
||||||||||||
Customer relationships, noncompete
agreements and other |
$ | 202.9 | $ | 219.1 | $ | 217.7 | ||||||
Trademark (not subject to amortization) |
41.5 | 49.7 | 47.7 | |||||||||
Gross carrying amount |
244.4 | 268.8 | 265.4 | |||||||||
Accumulated amortization |
(106.3 | ) | (103.3 | ) | (103.8 | ) | ||||||
Net carrying amount |
$ | 138.1 | $ | 165.5 | $ | 161.6 | ||||||
The decrease in goodwill and other intangible assets during the nine months ended June
30, 2010 principally reflects the effects of currency translation partially offset by the
effects of acquisitions. Amortization expense of intangible assets was $4.9 and $14.8 for
the three and nine months ended June 30, 2010, respectively, and $4.7 and $13.6 for the
three and nine months ended June 30, 2009, respectively. 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 2010 — $17.8; Fiscal 2011 — $16.8; Fiscal 2012 — $16.7; Fiscal 2013 — $16.0; Fiscal
2014 — $14.0. |
| 5. | 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 retail
propane business in China (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy
Services. We refer to both international segments collectively as “International Propane.” |
The accounting policies of our reportable segments are the same as those described in Note
2, “Significant Accounting Policies” in the Company’s 2009 Annual Financial Statements and
Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s
earnings before interest expense, income taxes, depreciation and amortization (“Partnership
EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability,
it should not be considered as an alternative to net income (as an indicator of operating
performance) or as an alternative to cash flow (as a measure of liquidity or ability to
service debt obligations) and is not a measure of performance or financial condition under
GAAP. Our definition of Partnership EBITDA may be different from that used by other
companies. We evaluate the performance of our International Propane, Gas Utility, Electric
Utility and Energy Services segments principally based upon their income before income
taxes. |
- 9 -
| 5. | Segment Information
(continued) |
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 961.9 | $ | (22.2 | ) | $ | 396.6 | $ | 149.1 | $ | 25.3 | $ | 198.6 | $ | 150.8 | $ | 41.0 | $ | 22.7 | |||||||||||||||||
Cost of sales |
$ | 615.5 | $ | (20.7 | ) | $ | 235.8 | $ | 83.0 | $ | 15.8 | $ | 177.3 | $ | 81.9 | $ | 30.0 | $ | 12.4 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 31.2 | $ | (0.4 | ) | $ | 5.3 | $ | 13.8 | $ | 2.6 | $ | 6.9 | $ | 4.3 | $ | (1.4 | ) | $ | 0.1 | ||||||||||||||||
Loss from equity investees |
(1.9 | ) | — | — | — | — | — | (1.9 | ) | — | — | |||||||||||||||||||||||||
Interest expense |
(33.6 | ) | — | (17.0 | ) | (10.0 | ) | (0.4 | ) | — | (5.3 | ) | (0.7 | ) | (0.2 | ) | ||||||||||||||||||||
(Loss) income before
income taxes |
$ | (4.3 | ) | $ | (0.4 | ) | $ | (11.7 | ) | $ | 3.8 | $ | 2.2 | $ | 6.9 | $ | (2.9 | ) | $ | (2.1 | ) | $ | (0.1 | ) | ||||||||||||
Partnership EBITDA (d) |
$ | 27.2 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net (loss) income |
$ | (7.6 | ) | $ | 0.1 | $ | (7.5 | ) | $ | — | $ | — | $ | — | $ | (0.2 | ) | $ | — | $ | — | |||||||||||||||
Depreciation and amortization |
$ | 51.7 | $ | — | $ | 21.8 | $ | 12.5 | $ | 1.0 | $ | 2.0 | $ | 11.5 | $ | 2.6 | $ | 0.3 | ||||||||||||||||||
Capital expenditures |
$ | 83.1 | $ | — | $ | 14.4 | $ | 16.1 | $ | 2.3 | $ | 34.3 | $ | 12.8 | $ | 2.0 | $ | 1.2 | ||||||||||||||||||
Total assets (at period end) |
$ | 5,831.6 | $ | (69.3 | ) | $ | 1,658.4 | $ | 1,829.4 | $ | 120.4 | $ | 463.3 | $ | 1,446.4 | $ | 231.2 | $ | 151.8 | |||||||||||||||||
Bank loans (at period end) |
$ | 35.2 | $ | — | $ | 15.0 | $ | — | $ | — | $ | — | $ | — | $ | 20.2 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,475.9 | $ | (3.9 | ) | $ | 674.8 | $ | 180.1 | $ | — | $ | 11.8 | $ | 540.6 | $ | 65.6 | $ | 6.9 | |||||||||||||||||
| 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 | )(c) | $ | 0.8 | $ | (0.8 | ) | ||||||||||||||||
Income (loss) from
equity investees |
— | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Interest expense |
(34.6 | ) | — | (17.2 | ) | (10.3 | ) | (0.5 | ) | — | (5.8 | ) | (0.7 | ) | (0.1 | ) | ||||||||||||||||||||
(Loss) income before
income taxes |
$ | (5.8 | ) | $ | 0.1 | $ | (12.8 | ) | $ | 2.6 | $ | 2.8 | $ | 8.6 | $ | (6.3 | )(c) | $ | 0.1 | $ | (0.9 | ) | ||||||||||||||
Partnership EBITDA (d) |
$ | 25.4 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net (loss) income |
$ | (8.6 | ) | $ | 0.1 | $ | (8.3 | ) | $ | — | $ | — | $ | — | $ | (0.4 | ) | $ | — | $ | — | |||||||||||||||
Depreciation and amortization |
$ | 51.3 | $ | (0.1 | ) | $ | 21.1 | $ | 11.8 | $ | 1.1 | $ | 2.2 | $ | 12.4 | $ | 2.5 | $ | 0.3 | |||||||||||||||||
Capital expenditures |
$ | 74.6 | $ | — | $ | 19.5 | $ | 18.2 | $ | 1.1 | $ | 18.1 | $ | 15.5 | $ | 2.0 | $ | 0.2 | ||||||||||||||||||
Total assets (at period end) |
$ | 5,901.3 | $ | (119.7 | ) | $ | 1,619.3 | $ | 1,902.6 | $ | 116.2 | $ | 328.2 | $ | 1,640.3 | $ | 247.7 | $ | 166.7 | |||||||||||||||||
Bank loans (at period end) |
$ | 125.5 | $ | — | $ | — | $ | 103.1 | $ | 6.9 | $ | — | $ | — | $ | 15.5 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,545.5 | $ | (3.9 | ) | $ | 666.1 | $ | 176.9 | $ | — | $ | 11.8 | $ | 620.2 | $ | 67.5 | $ | 6.9 | |||||||||||||||||
| (a) | International Propane — Other principally comprises Flaga and, to a much lesser extent, our
retail propane business in China. |
|
| (b) | Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation,
air-conditioning, refrigeration and electrical contracting business (“HVAC/R”), 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, assets of HVAC/R and an intercompany loan. The intercompany loan and
associated interest is removed in the segment information. |
|
| (c) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane
operating income: |
| Three months ended June 30, | 2010 | 2009 | ||||||
Partnership EBITDA |
$ | 27.2 | $ | 25.4 | ||||
Depreciation and amortization |
(21.8 | ) | (21.1 | ) | ||||
Noncontrolling interests (i) |
(0.1 | ) | 0.1 | |||||
Operating income |
$ | 5.3 | $ | 4.4 | ||||
| (i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
|
| (d) | Includes $(10.0) provision for Antargaz Competition Authority Matter. |
- 10 -
| 5. | Segment Information
(continued) |
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
| Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 4,701.0 | $ | (146.9 | ) | $ | 1,939.3 | $ | 922.3 | $ | 90.9 | $ | 949.5 | $ | 755.3 | $ | 129.8 | $ | 60.8 | |||||||||||||||||
Cost of sales |
$ | 3,009.2 | $ | (142.3 | ) | $ | 1,165.1 | $ | 584.2 | $ | 58.0 | $ | 830.9 | $ | 394.4 | $ | 86.8 | $ | 32.1 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income (loss) |
$ | 640.4 | $ | (0.7 | ) | $ | 261.2 | $ | 168.6 | $ | 11.1 | $ | 75.4 | $ | 123.4 | $ | 4.2 | $ | (2.8 | ) | ||||||||||||||||
Loss from equity investees |
(1.9 | ) | — | — | — | — | — | (1.8 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
Interest expense |
(101.9 | ) | — | (50.2 | ) | (30.5 | ) | (1.3 | ) | — | (17.1 | ) | (2.3 | ) | (0.5 | ) | ||||||||||||||||||||
Income (loss) before
income taxes |
$ | 536.6 | $ | (0.7 | ) | $ | 211.0 | $ | 138.1 | $ | 9.8 | $ | 75.4 | $ | 104.5 | $ | 1.8 | $ | (3.3 | ) | ||||||||||||||||
Partnership EBITDA (c) |
$ | 323.7 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income |
$ | 115.2 | $ | 0.1 | $ | 114.5 | $ | — | $ | — | $ | — | $ | 0.6 | $ | — | $ | — | ||||||||||||||||||
Depreciation and amortization |
$ | 157.3 | $ | (0.1 | ) | $ | 65.0 | $ | 37.0 | $ | 3.0 | $ | 6.0 | $ | 37.2 | $ | 8.2 | $ | 1.0 | |||||||||||||||||
Capital expenditures |
$ | 229.4 | $ | — | $ | 59.8 | $ | 40.6 | $ | 3.9 | $ | 84.7 | $ | 32.1 | $ | 5.7 | $ | 2.6 | ||||||||||||||||||
Total assets (at period end) |
$ | 5,831.6 | $ | (69.3 | ) | $ | 1,658.4 | $ | 1,829.4 | $ | 120.4 | $ | 463.3 | $ | 1,446.4 | $ | 231.2 | $ | 151.8 | |||||||||||||||||
Bank loans (at period end) |
$ | 35.2 | $ | — | $ | 15.0 | $ | — | $ | — | $ | — | $ | — | $ | 20.2 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,475.9 | $ | (3.9 | ) | $ | 674.8 | $ | 180.1 | $ | — | $ | 11.8 | $ | 540.6 | $ | 65.6 | $ | 6.9 | |||||||||||||||||
| 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 | (d) | $ | 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 | ) | ||||||||||||||||||||
Income (loss) before income taxes |
$ | 585.5 | $ | 0.2 | $ | 263.5 | $ | 118.1 | $ | 12.5 | $ | 60.0 | $ | 128.9 | (d) | $ | 4.7 | $ | (2.4 | ) | ||||||||||||||||
Partnership EBITDA (c) |
$ | 376.7 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income (loss) |
$ | 144.0 | $ | 0.1 | $ | 144.0 | $ | — | $ | — | $ | — | $ | (0.1 | ) | $ | — | $ | — | |||||||||||||||||
Depreciation and amortization |
$ | 148.8 | $ | (0.3 | ) | $ | 62.8 | $ | 34.9 | $ | 3.0 | $ | 6.1 | $ | 35.3 | $ | 6.0 | $ | 1.0 | |||||||||||||||||
Capital expenditures |
$ | 213.4 | $ | — | $ | 57.4 | $ | 52.6 | $ | 3.5 | $ | 44.9 | $ | 49.7 | $ | 4.2 | $ | 1.1 | ||||||||||||||||||
Total assets (at period end) |
$ | 5,901.3 | $ | (119.7 | ) | $ | 1,619.3 | $ | 1,902.6 | $ | 116.2 | $ | 328.2 | $ | 1,640.3 | $ | 247.7 | $ | 166.7 | |||||||||||||||||
Bank loans (at period end) |
$ | 125.5 | $ | — | $ | — | $ | 103.1 | $ | 6.9 | $ | — | $ | — | $ | 15.5 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,545.5 | $ | (3.9 | ) | $ | 666.1 | $ | 176.9 | $ | — | $ | 11.8 | $ | 620.2 | $ | 67.5 | $ | 6.9 | |||||||||||||||||
| (a) | International Propane — Other principally comprises Flaga, including, prior to the January 29,
2009 purchase of the 50% equity interest it did not already own, its central and eastern European
joint venture ZLH, and, to a much lesser extent, our retail propane business in China. |
|
| (b) | Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation,
air-conditioning, refrigeration and electrical contracting business (“HVAC/R”), 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, assets of HVAC/R and an intercompany loan. The intercompany loan and
associated interest 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, | 2010 | 2009 | ||||||
Partnership EBITDA |
$ | 323.7 | (ii) | $ | 376.7 | (iii) | ||
Depreciation and amortization |
(65.0 | ) | (62.8 | ) | ||||
Noncontrolling interests (i) |
2.5 | 3.3 | ||||||
Operating income |
$ | 261.2 | $ | 317.2 | ||||
| (i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
|
| (ii) | Includes $12.2 loss associated with the discontinuance of Partnership interest rate
protection agreements. |
|
| (iii) | Includes $39.9 gain on sale of Partnership California storage facility. |
|
| (d) | Includes $(10.0) million provision for Antargaz Competition Authority Matter. |
- 11 -
| 6. | Energy Services Accounts Receivable Securitization Facility |
Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an
issuer of receivables-backed commercial paper currently scheduled to expire in April 2011,
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 FASB’s guidance for 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, 2010 and 2009, Energy Services sold trade receivables
totaling $933.3 and $1,029.5, respectively, to ESFC. During the nine months ended June 30,
2010 and 2009, ESFC sold an aggregate $233.6 and $508.9, respectively, of undivided
interests in its trade receivables to the commercial paper conduit. At June 30, 2010, the
outstanding balance of ESFC trade receivables was $61.8 and there was no amount sold to the
commercial paper conduit and removed from the balance sheet. 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. |
- 12 -
| 7. | 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 8 to the Company’s 2009 Annual Financial Statements and Notes. 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, | ||||||||||
| 2010 | 2009 | 2009 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 95.3 | $ | 79.5 | $ | 76.6 | ||||||
Postretirement benefits |
1.7 | 2.5 | 3.0 | |||||||||
CPG Gas pension and postretirement plans |
8.6 | 8.5 | 5.6 | |||||||||
Environmental costs |
24.3 | 26.9 | 20.6 | |||||||||
Deferred fuel and power costs |
6.3 | 19.6 | 28.8 | |||||||||
Other |
5.5 | 4.5 | 6.9 | |||||||||
Total regulatory assets |
$ | 141.7 | $ | 141.5 | $ | 141.5 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 10.3 | $ | 9.3 | $ | 10.0 | ||||||
Environmental overcollections |
8.3 | 8.7 | 9.7 | |||||||||
Deferred fuel refunds |
16.6 | 30.8 | 13.5 | |||||||||
State tax benefits — distribution
system repairs |
11.0 | — | — | |||||||||
Total regulatory liabilities |
$ | 46.2 | $ | 48.8 | $ | 33.2 | ||||||
Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing
January 1, 2010, Electric Utility’s default service tariffs, contain clauses which permit
recovery of all prudently incurred purchased gas and power costs through the application of
purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates
in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS
rates for differences between the total amount of purchased gas and electric generation
supply costs collected from customers and recoverable costs incurred. Net undercollected
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 costs or refunds. Unrealized losses on such contracts at June 30,
2010 and June 30, 2009 were $(0.6) and $(42.5), respectively. There were no such unrealized
gains or losses at September 30, 2009. |
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs, Electric Utility obtains financial transmission rights
(“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive
compensation for electricity transmission congestion charges when there is insufficient
electricity transmission capacity on the electric transmission grid. Because Electric
Utility is entitled to fully recover its default service costs commencing January 1, 2010
through DS rates, realized and unrealized gains or losses on FTRs associated with periods
beginning January 1, 2010 are included in deferred fuel and power — costs or refunds.
Unrealized gains on FTRs at June 30, 2010 were not material. |
- 13 -
State Income Tax Benefits – Distribution System Repairs. As previously mentioned in Note 2
to condensed consolidated financial statements, the Company received IRS consent to change
its tax method of accounting for capitalizing certain repairs and maintenance costs
associated with its Gas Utility and Electric Utility assets beginning with the tax year
ended September 30, 2009. This regulatory liability represents Pennsylvania state income
tax benefits, net of federal income tax expense, resulting from the deduction for income tax
purposes of these repairs and maintenance expenses which expenses are capitalized for
regulatory and GAAP reporting. The state tax benefits associated with these repairs and
maintenance deductions will be reflected as a reduction to income tax expense over the
remaining tax lives of the related book assets. |
| 8. | Defined Benefit Pension and Other Postretirement Plans |
We sponsor defined benefit pension plans for employees hired prior to January 1, 2009 of
UGI, UGI Utilities, CPG, PNG 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. |
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, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost |
$ | 2.2 | $ | 1.9 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost |
5.8 | 5.8 | 0.3 | 0.2 | ||||||||||||
Expected return on assets |
(6.5 | ) | (6.3 | ) | (0.1 | ) | (0.1 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service benefit |
— | — | (0.1 | ) | (0.1 | ) | ||||||||||
Actuarial loss |
1.5 | 1.2 | 0.1 | — | ||||||||||||
Net benefit cost |
3.0 | 2.6 | 0.3 | 0.1 | ||||||||||||
Change in associated
regulatory liabilities |
— | — | 0.7 | 0.8 | ||||||||||||
Net expense |
$ | 3.0 | $ | 2.6 | $ | 1.0 | $ | 0.9 | ||||||||
| Other | ||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||
| Nine Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost |
$ | 6.5 | $ | 5.3 | $ | 0.3 | $ | 0.2 | ||||||||
Interest cost |
17.6 | 17.6 | 0.9 | 0.7 | ||||||||||||
Expected return on assets |
(19.4 | ) | (19.3 | ) | (0.3 | ) | (0.4 | ) | ||||||||
Amortization of: |
||||||||||||||||
Transition obligation |
— | — | — | 0.1 | ||||||||||||
Prior service benefit |
— | — | (0.3 | ) | (0.2 | ) | ||||||||||
Actuarial loss |
4.4 | 2.7 | 0.2 | — | ||||||||||||
Net benefit cost |
9.1 | 6.3 | 0.8 | 0.4 | ||||||||||||
Change in associated
regulatory liabilities |
— | — | 2.2 | 2.4 | ||||||||||||
Net expense |
$ | 9.1 | $ | 6.3 | $ | 3.0 | $ | 2.8 | ||||||||
- 14 -
Pension Plans’ assets are held in trust and consist principally of equity and fixed
income mutual funds. It is our general policy to fund amounts for pension benefits equal to
at least the minimum contribution required by ERISA. Based upon current assumptions, the
Company estimates that it will be required to contribute approximately $9.5 to the Pension
Plans during the next twelve months. 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 GAAP relating to 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, 2010, nor are they expected to be material for all of Fiscal 2010. |
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement
plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.8 for the
three and nine months ended June 30, 2010, respectively. We recorded pre-tax expense for
these plans of $0.6 and $2.2 for the three and nine months ended June 30, 2009,
respectively. |
| 9. | Commitments and Contingencies |
Environmental Matters |
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. At June 30, 2010, neither
the undiscounted nor the accrued liability for environmental investigation and cleanup costs
for UGI Gas was material for UGI Utilities. |
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. |
- 15 -
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. |
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (“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 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 any costs Frontier would be required to pay to the City for cleaning up tar deposits in
the Penobscot River. Frontier alleged 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. Frontier made similar allegations of control against another third-party
defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned
the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a
resolution of the City’s suit against Frontier, which was tried in September 2005. On June
27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup
costs, which were estimated at $18. On February 14, 2007, Frontier and the City entered into
a settlement agreement pursuant to which Frontier agreed to pay $7.6. Frontier subsequently
filed the current action against the original third-party defendants, repeating its claims
for contribution. On September 22, 2009, the court granted summary judgment in favor of
co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has
filed a motion for summary judgment with respect to 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. |
- 16 -
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. The Northeast Companies are expected to complete additional
environmental investigations at Waterbury North by the end of 2010, after which there will
be a second phase of the trial to determine what, if any, contamination at Waterbury North
is related to UGI Utilities’ period of operation. The Northeast Companies previously
estimated that remediation costs at Waterbury North could total $25. |
AmeriGas OLP Saranac Lake. 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 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, the extent of
contamination and the possible existence of other potentially responsible parties. The
Partnership has communicated the results of its research to DEC and is awaiting a response
before doing any additional investigation. Because of the preliminary nature of available
environmental information, the ultimate amount of expected clean up costs cannot be
reasonably estimated. |
- 17 -
Other Matters |
Purported AmeriGas Class Action Lawsuits. 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 AmeriGas OLP’s weight disclosure with regard
to its portable propane grill cylinders. The complaint purports to be brought on behalf of a
class of all 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. |
Since that initial suit, various AmeriGas entities have been named in more than a dozen
similar suits that have been filed in various courts throughout the United States. These
complaints purport to be brought on behalf of nationwide classes, which are loosely defined
as including all
purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas OLP and another
unaffiliated entity nationwide. The complaints claim that defendants’ conduct constituted
unfair and deceptive practices that injured consumers and violated the consumer protection
statutes of at least thirty-seven states and the District of Columbia, thereby entitling the
class to damages, restitution, disgorgement, injunctive relief, costs and attorneys’ fees.
Some of the complaints also allege violation of state “slack filling” laws. Additionally,
the complaints allege that defendants were unjustly enriched by their conduct and they seek
restitution of any unjust benefits received, punitive or treble damages, and pre-judgment
and post-judgment interest. A motion to consolidate the purported class action lawsuits was
heard by the Multidistrict Litigation Panel (“MDL Panel”) on September 24, 2009 in the
United States District Court for the District of Kansas. By Order, dated October 6, 2009,
the MDL Panel transferred the pending cases to the United States District Court for the
Western District of Missouri. The AmeriGas entities named in the consolidated class action
lawsuits have entered into a settlement agreement with the class. On May 19, 2010, the
United States District Court for the District of Kansas granted the classes’ motion seeking
preliminary approval of the settlement and scheduled a final settlement fairness hearing for
October 2010. |
AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received
a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San
Joaquin and Fresno Counties and the City Attorney of San Diego have commenced an
investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and
issued an administrative subpoena seeking documents and information relating to these
practices. We are cooperating with these California governmental investigations. |
- 18 -
Swiger, et al. v. UGI/AmeriGas, Inc. et al. 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 Corporation 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 Columbia Energy Group,
former owner of Columbia Propane Corporation, seeking indemnification for conduct undertaken
by Columbia Propane Corporation prior to AmeriGas OLP’s acquisition. In June 2010, Columbia
Energy Group filed a complaint in the Delaware Court of Chancery seeking to enjoin AmeriGas
OLP from pursuing its cross-claims in the West Virginia litigation and asking the court to
find that AmeriGas OLP’s cross-claims are without merit and barred. Class counsel has
indicated that the class is seeking compensatory damages in excess of $12 plus punitive
damages, civil penalties and attorneys’ fees. The Circuit Court of Monongalia County has
tentatively scheduled a trial for the class action for the Spring of 2011. |
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. |
French Business Tax. 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. |
Antargaz Competition Authority Matter. 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 General Division of Competition, Consumption and
Fraud Punishment (“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. |
- 19 -
We filed our written response to the Statement of Objections with the Competition Authority
on October 21, 2009. The Competition Authority completed its review of Antargaz’ response
and issued its report on April 26, 2010. Antargaz filed its response to this report on June
28, 2010. A hearing date has not yet been scheduled by the Competition Authority. Based on
our assessment of the information contained in the report, we believe that we have good
defenses to the objections and that the reserve established by management for this matter is
adequate. However, 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. |
We cannot predict with certainty the final results of any of the environmental or other
pending claims or legal actions described above. 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. In addition to the
matters described above, there are other pending claims and legal actions arising in the
normal course of our businesses. While the results of these other pending claims and legal
actions cannot be predicted with certainty, we believe, after consultation with counsel, the
final outcome of such other matters will not have a significant effect on our consolidated
financial position, results of operations or cash flows. |
- 20 -
| 10. | Equity |
The following table sets forth changes in UGI’s equity and the equity of the noncontrolling
interests for the nine months ended June 30, 2010 and 2009: |
| UGI Shareholders | ||||||||||||||||||||||||
| Accumulated | ||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||
| Non- | Comprehensive | |||||||||||||||||||||||
| controlling | Common | Retained | Income | Treasury | Total | |||||||||||||||||||
| Interests | Stock | Earnings | (Loss) | Stock | Equity | |||||||||||||||||||
Nine Months Ended June 30, 2010: |
||||||||||||||||||||||||
Balance September 30, 2009 |
$ | 225.4 | $ | 875.6 | $ | 804.3 | $ | (38.9 | ) | $ | (49.6 | ) | $ | 1,816.8 | (1) | |||||||||
Net income |
115.2 | 258.9 | 374.1 | |||||||||||||||||||||
Net gains (losses) on derivative
instruments |
6.9 | (11.0 | ) | (4.1 | ) | |||||||||||||||||||
Reclassifications of net (gains)
losses on derivative instruments |
(14.4 | ) | 30.9 | 16.5 | ||||||||||||||||||||
Benefit plans |
2.3 | 2.3 | ||||||||||||||||||||||
Foreign currency translation
adjustments |
(99.1 | ) | (99.1 | ) | ||||||||||||||||||||
Comprehensive income |
107.7 | 258.9 | (76.9 | ) | 289.7 | |||||||||||||||||||
Dividends and distributions |
(66.2 | ) | (71.1 | ) | (137.3 | ) | ||||||||||||||||||
Transactions with owners |
0.7 | 20.5 | 7.2 | 28.4 | ||||||||||||||||||||
Other |
(3.6 | ) | (3.6 | ) | ||||||||||||||||||||
Balance June 30, 2010 |
$ | 264.0 | $ | 896.1 | $ | 992.1 | $ | (115.8 | ) | $ | (42.4 | ) | $ | 1,994.0 | ||||||||||
Nine Months Ended June 30, 2009: |
||||||||||||||||||||||||
Balance September 30, 2008 |
$ | 159.2 | (1) | $ | 858.3 | $ | 630.9 | $ | (15.2 | ) | $ | (56.3 | ) | $ | 1,576.9 | (1) | ||||||||
Net income |
144.0 | (1) | 269.5 | 413.5 | (1) | |||||||||||||||||||
Net losses on derivative instruments |
(84.0 | )(1) | (121.2 | ) | (205.2 | )(1) | ||||||||||||||||||
Reclassifications of net losses on
derivative
instruments |
102.5 | (1) | 99.0 | 201.5 | (1) | |||||||||||||||||||
Benefit plans |
(38.8 | ) | (38.8 | )(1) | ||||||||||||||||||||
Foreign currency translation
adjustments |
4.5 | 4.5 | (1) | |||||||||||||||||||||
Comprehensive income |
162.5 | (1) | 269.5 | (56.5 | ) | 375.5 | (1) | |||||||||||||||||
Dividends and distributions |
(63.2 | )(1) | (63.4 | ) | (126.6 | )(1) | ||||||||||||||||||
Transactions with owners |
0.5 | (1) | 12.1 | 3.9 | 16.5 | (1) | ||||||||||||||||||
Other |
(0.2 | )(1) | (0.2 | )(1) | ||||||||||||||||||||
Balance June 30, 2009 |
$ | 258.8 | (1) | $ | 870.4 | $ | 837.0 | $ | (71.7 | ) | $ | (52.4 | ) | $ | 1,842.1 | (1) | ||||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for
noncontrolling interests in consolidated subsidiaries (see Note 3). |
- 21 -
| 11. | Fair Value Measurement |
Derivative Financial Instruments |
The following table presents our financial assets and financial liabilities that are
measured at fair value on a recurring basis for each of the fair value hierarchy levels,
including both current and noncurrent portions, as of June 30, 2010, September 30, 2009 and
June 30, 2009: |
| Asset (Liability) | ||||||||||||||||
| Quoted Prices | ||||||||||||||||
| in Active | Significant | |||||||||||||||
| Markets for | Other | |||||||||||||||
| Identical Assets | Observable | Unobservable | ||||||||||||||
| and Liabilities | Inputs | Inputs | ||||||||||||||
| (Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
June 30, 2010: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (25.1 | ) | $ | (14.8 | ) | $ | — | $ | (39.9 | ) | |||||
Foreign currency contracts |
$ | — | $ | 16.9 | $ | — | $ | 16.9 | ||||||||
Interest rate contracts |
$ | — | $ | (16.4 | ) | $ | — | $ | (16.4 | ) | ||||||
September 30, 2009: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (3.8 | ) | $ | 15.1 | $ | — | $ | 11.3 | |||||||
Foreign currency contracts |
$ | — | $ | (5.7 | ) | $ | — | $ | (5.7 | ) | ||||||
Interest rate contracts |
$ | — | $ | (34.3 | ) | $ | — | $ | (34.3 | ) | ||||||
June 30, 2009: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (59.8 | ) | $ | (7.2 | ) | $ | — | $ | (67.0 | ) | |||||
Foreign currency contracts |
$ | — | $ | 1.2 | $ | — | $ | 1.2 | ||||||||
Interest rate contracts |
$ | — | $ | (27.9 | ) | $ | — | $ | (27.9 | ) | ||||||
The fair values of our Level 1 exchange-traded derivative contracts are based upon
actively-quoted market prices for identical assets and liabilities. The remainder of our
derivative financial instruments are designated as Level 2. The fair values of certain
non-exchange traded commodity derivatives are based upon indicative price quotations
available through brokers, industry price publications or recent market transactions and
related market indicators. For commodity option contracts not traded on an exchange, we use
a Black Scholes option pricing model that considers time value and volatility of the
underlying commodity. The fair values of interest rate contracts and foreign currency
contracts are based upon third-party quotes or indicative values based on recent market
transactions. |
Other 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 value of our long-term debt at June 30, 2010 were $2,029.7 and $2,122.7,
respectively. The carrying amount and estimated fair value of our long-term debt at June
30, 2009 were $2,099.5 and $2,063.1, respectively. 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. |
- 22 -
Financial instruments other than derivative financial instruments, such as our short-term
investments and trade accounts receivable, could expose us to concentrations of credit risk.
We limit our credit risk from short-term investments by investing only in investment-grade
commercial paper, money market mutual funds and securities guaranteed by the U.S. Government
or its agencies. The credit risk from trade accounts receivable is limited because we have a
large customer base which extends across many different U.S. markets and several foreign
countries. |
| 12. | Disclosures About Derivative Instruments, Hedging Activities and Financial
Instruments |
We are exposed to certain market risks related to our 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 risk
management 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 (as further
described below), generally qualify as hedges under GAAP or are subject to regulatory rate
recovery mechanisms, 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
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. |
Gas Utility’s tariffs contain clauses that permit recovery of 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 and option 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, 2010 and 2009, the volumes of natural gas associated with
Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.3 million
dekatherms and 8.2 million dekatherms, respectively. Gains and losses on natural gas
futures contracts and gains on natural gas option contracts are recorded in regulatory
assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB’s
guidance in Accounting Standards Codification (“ASC”) 980 related to rate-regulated entities
and reflected in cost of sales through the PGC mechanism (see Note 7). |
- 23 -
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. 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 filing with the PUC, gains and losses on Electric Utility
FTRs associated with periods beginning on or after January 1, 2010 are recorded in
regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales
through the DS recovery mechanism (see Note 7). Gains and losses associated with periods
prior to January 2010 were reflected in cost of sales. At June 30, 2010 and 2009, the
volumes of Electric Utility electric transmission congestion subject to FTRs totaled 739.3
million kilowatt hours and 1,277.0 million kilowatt hours, respectively. Energy Services’
FTRs are recorded at fair value with changes in fair value reflected in cost of sales. |
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 its vehicles and equipment. Associated volumes, fair values and
effects 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, 2010 and 2009, we had the following outstanding derivative commodity instruments
volumes that qualify for hedge accounting treatment: |
| Volumes | ||||||||
| Commodity | 2010 | 2009 | ||||||
LPG (millions of gallons) |
150.5 | 163.1 | ||||||
Natural gas (millions of dekatherms) |
33.3 | 25.1 | ||||||
Electricity (millions of kilowatt-hours) |
928.0 | 378.2 | ||||||
The maximum period over which we are currently hedging our exposure to the variability
in cash flows associated with LPG commodity price risk is 21 months with a weighted average
of 7 months. The maximum period over which we are currently hedging our exposure to the
variability in cash flows associated with natural gas commodity price risk (excluding Gas
Utility) is 31 months with a weighted average of 8 months. The maximum period over which we
are currently hedging our exposure to the variability in cash flows associated with
electricity price risk is 30 months with a weighted average of 9 months. The volume of
electric transmission congestion that is subject to FTRs (excluding Electric Utility) at
June 30, 2010 and 2009 totaled 1,415.0 million kilowatt hours and 1,005.0 million kilowatt
hours, respectively. The maximum period over which we are economically hedging such
electricity congestion with FTRs is 11 months with a weighted average of 6 months. |
- 24 -
We account for commodity price risk contracts (other than our Gas Utility natural gas
futures and option contracts, gasoline futures and swap contracts, and Electric Utility
FTRs) 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, noncontrolling interests, to the extent effective in offsetting
changes in the
underlying commodity price risk. When earnings are affected by the hedged commodity, gains
or losses are recorded in cost of sales on the Consolidated Statements of Income. At June
30, 2010, the amount of net losses associated with commodity price risk hedges expected to
be reclassified into earnings during the next twelve months based upon current fair values
is $45.7. |
||
Interest Rate Risk |
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 €380 variable-rate debt through its March 2011 maturity date
through the use of pay-fixed, receive-variable interest rate swap agreements. Antargaz
intends to refinance its €380 variable-rate term loan, subject to market conditions, on a
long-term basis by March 2011. In anticipation of such refinancing, Antargaz has entered
into forward-starting interest rate swap agreements to hedge the underlying euribor rate of
interest relating to 4 1/2 years of quarterly interest payments on €300 notional amount of
long-term debt commencing March 31, 2011. Flaga has also fixed the underlying euribor
interest rate on a substantial portion of its two term loans through their scheduled
maturity dates ending in 2014 through the use of pay-fixed, receive-variable interest rate
swap agreements. As of June 30, 2010 and 2009, the total notional amounts of our existing
and anticipated variable rate debt subject to interest rate swap agreements were €706.2 and
€406.6, respectively. |
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”). There were no unsettled IRPAs outstanding at June 30, 2010. |
We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values
of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership,
noncontrolling interests, to the extent effective in offsetting changes in the underlying
interest rate risk, until earnings are affected by the hedged interest expense. At such
time, gains and losses are recorded in interest expense. At June 30, 2010, the amount of net
losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest
rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7. |
- 25 -
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 amount of dollar-denominated purchases of LPG associated with such
contracts generally represents approximately 20% — 30% of estimated dollar-denominated
purchases of LPG to occur during the heating-season months of October through March. At June
30, 2010 and 2009, we were hedging a total of $72.8 and $121.4 of U.S. dollar-denominated
LPG purchases, respectively. The maximum period over which we are currently hedging our
exposure to the variability in cash flows associated with dollar-denominated purchases of
LPG is 18 months with a weighted average of 7 months. We also enter into forward foreign
currency exchange contracts
to reduce the volatility of the U.S. dollar value on a portion of our International Propane
euro-denominated net investments. At June 30, 2010 and 2009, we were hedging a total of
€48.3 and €30.8, respectively, of our euro-denominated net investments. As of June 30, 2010,
such 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, at which time gains and losses are recorded in cost of sales. At June
30, 2010, the amount of net gains associated with currency rate risk (other than net
investment hedges) expected to be reclassified into earnings during the next twelve months
based upon current fair values is $5.1. Gains and losses on net investment hedges are
included in AOCI until such foreign operations are liquidated. |
||
Derivative Financial Instrument Credit Risk |
We are exposed to risk of loss in the event of nonperformance by our derivative financial
instrument counterparties. Our derivative financial instrument counterparties principally
comprise 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. Additionally, our natural gas and electricity exchange-traded futures contracts which
are guaranteed by the NYMEX generally require cash deposits in margin accounts. At June 30,
2010 and 2009, restricted cash in brokerage accounts totaled $22.9 and $64.8, respectively.
Although we have concentrations of credit risk associated with derivative financial
instruments, the maximum amount of loss, based upon the gross fair values of the derivative
financial instruments, we would incur if these counterparties failed to perform according to
the terms of their contracts was not material at June 30, 2010. We generally do not have
credit-risk-related contingent features in our derivative contracts. |
- 26 -
The following table provides information regarding the balance sheet location and fair value
of derivative assets and liabilities existing as of June 30, 2010 and 2009: |
| Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||
| Fair Value | Fair Value | |||||||||||||||||||
| Balance Sheet | June 30, | Balance Sheet | June 30, | |||||||||||||||||
| Location | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||
Derivatives Designated
as
Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | Derivative financial instruments | ||||||||||||||||||
and Other assets |
$ | 0.3 | $ | 2.9 | and Other noncurrent liabilities |
$ | (42.8 | ) | $ | (74.3 | ) | |||||||||
Foreign currency contracts |
Derivative financial instruments | |||||||||||||||||||
and Other assets |
16.9 | 3.1 | Other noncurrent liabilities | — | (2.0 | ) | ||||||||||||||
| Derivative financial instruments | ||||||||||||||||||||
Interest rate contracts |
Derivative financial instruments | — | 3.7 | and Other noncurrent liabilities |
(16.4 | ) | (31.6 | ) | ||||||||||||
Total Derivatives Designated
as Hedging
Instruments |
$ | 17.2 | $ | 9.7 | (59.2 | ) | (107.9 | ) | ||||||||||||
Derivatives Accounted
for
under ASC 980: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | $ | 0.6 | $ | — | Derivative financial instruments | $ | (0.8 | ) | $ | — | |||||||||
Derivatives Not Designated as
Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | |||||||||||||||||||
and Other assets |
$ | 2.8 | $ | 4.5 | ||||||||||||||||
Total Derivatives |
$ | 20.6 | $ | 14.2 | $ | (60.0 | ) | $ | (107.9 | ) | ||||||||||
- 27 -
The following tables provide information on the effects of derivative instruments on
the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling
interest for the three and nine months ended June 30, 2010 and 2009: |
| Gain or (Loss) | Gain or (Loss) | Location of | ||||||||||||||||
| Recognized in | Reclassified from | Gain or (Loss) | ||||||||||||||||
| AOCI and | AOCI and Noncontrolling | Reclassified from | ||||||||||||||||
| Noncontrolling Interests | Interests into Income | AOCI and Noncontrolling | ||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | Interests into Income | ||||||||||||||
Cash Flow Hedges: |
||||||||||||||||||
Commodity contracts |
$ | (14.6 | ) | $ | 17.9 | $ | (7.7 | ) | $ | (64.6 | ) | Cost of sales | ||||||
Foreign currency contracts |
5.3 | (6.1 | ) | 0.1 | 0.2 | Cost of sales | ||||||||||||
Interest rate contracts |
(6.3 | ) | 10.4 | (3.9 | ) | (2.9 | ) | Interest expense /other income | ||||||||||
Total |
$ | (15.6 | ) | $ | 22.2 | $ | (11.5 | ) | $ | (67.3 | ) | |||||||
Net
Investment Hedges: |
||||||||||||||||||
Foreign currency contracts |
$ | 6.1 | $ | (2.3 | ) | |||||||||||||
| Gain or (Loss) | ||||||||||
| Recognized in Income | Location of Gain or (Loss) | |||||||||
| 2010 | 2009 | Recognized in Income | ||||||||
Derivatives
Not Designated
as Hedging Instruments: |
||||||||||
Commodity contracts |
$ | (0.1 | ) | $ | 1.0 | Cost of sales | ||||
Commodity contracts |
1.0 | 0.2 | Operating expenses / other income | |||||||
Total |
$ | 0.9 | $ | 1.2 | ||||||
- 28 -
| Gain or (Loss) | Gain or (Loss) | Location of | ||||||||||||||||
| Recognized in | Reclassified from | Gain or (Loss) | ||||||||||||||||
| AOCI and | AOCI and Noncontrolling | Reclassified from | ||||||||||||||||
| Noncontrolling Interests | Interests into Income | AOCI and Noncontrolling | ||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | Interests into Income | ||||||||||||||
Cash Flow Hedges: |
||||||||||||||||||
Commodity contracts |
$ | (30.1 | ) | $ | (249.7 | ) | $ | (14.1 | ) | $ | (269.1 | ) | Cost of sales | |||||
Foreign currency contracts |
12.2 | 3.0 | 0.7 | 5.0 | Cost of sales | |||||||||||||
Interest rate contracts |
(7.2 | ) | (37.2 | ) | (24.4 | ) | (3.9 | ) | Interest expense/other income | |||||||||
Total |
$ | (25.1 | ) | $ | (283.9 | ) | $ | (37.8 | ) | $ | (268.0 | ) | ||||||
Net
Investment Hedges: |
||||||||||||||||||
Foreign currency contracts |
$ | 11.2 | $ | (0.2 | ) | |||||||||||||
| Gain or (Loss) | ||||||||||
| Recognized in Income | Location of Gain or (Loss) | |||||||||
| 2010 | 2009 | Recognized in Income | ||||||||
Derivatives Not Designated as Hedging Instruments: |
||||||||||
Commodity contracts |
$ | 0.1 | $ | 0.9 | Cost of sales | |||||
Commodity contracts |
1.4 | (0.6 | ) | Operating expenses / other income | ||||||
Total |
$ | 1.5 | $ | 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 derivatives from
ineffectiveness testing, were not material for the three and nine months ended June 30, 2010
and 2009. During the three months ended March 31, 2010, the Partnership’s management
determined that it was likely that the Partnership would not issue $150 of long-term debt
during the summer of 2010 due to the Partnership’s strong cash flow and anticipated
extension of all or a portion of AmeriGas OLP’s $75 unsecured revolving credit agreement
(“2009 AmeriGas Supplemental Credit Agreement”). As a result, the Partnership discontinued
cash flow hedge accounting treatment for IRPAs associated with this previously anticipated
Fiscal 2010 $150 long-term debt issuance and recorded a $12.2 loss which is reflected in
other (income) expense, net on the Condensed Consolidated Statement of Income for nine
months ended June 30, 2010. In March 2009, the Partnership recorded losses of $1.7 as a
result of the discontinuance of cash flow hedge accounting associated with IRPAs. |
We are also a party to a number of contracts that have elements of a derivative instrument.
These contracts include, among others, binding purchase orders, contracts which provide for
the purchase and delivery, or sale, of natural gas, LPG and electricity, and service
contracts that require the counterparty to provide commodity storage, transportation or
capacity service to meet our normal sales commitments. Although many of these contracts have
the requisite elements of a derivative instrument, these contracts qualify for normal
purchase and normal sale exception accounting under GAAP because they provide for the
delivery of products or services in quantities that are expected to be used in the normal
course of operating our business and the price in the contract is based on an underlying
that is directly associated with the price of the product or service being purchased or
sold. |
- 29 -
| 13. | Inventories |
Inventories comprise the following: |
| June 30, | September 30, | June 30, | ||||||||||
| 2010 | 2009 | 2009 | ||||||||||
Non-utility LPG and natural gas |
$ | 138.2 | $ | 118.0 | $ | 112.0 | ||||||
Gas Utility natural gas |
60.3 | 189.7 | 99.0 | |||||||||
Materials, supplies and other |
50.7 | 55.5 | 58.1 | |||||||||
Total inventories |
$ | 249.2 | $ | 363.2 | $ | 269.1 | ||||||
At June 30, 2010, UGI Utilities is a party to three storage contract administrative
agreements (“SCAAs”). Pursuant to the SCAAs, UGI Utilities has, among other things, released
certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also
transferred certain associated storage inventories upon commencement of the SCAAs, will
receive a transfer of storage inventories at the end of the SCAAs, and makes payments
associated with refilling
storage inventories during the term of the SCAAs. The historical cost of natural gas storage
inventories released under the SCAAs, which represent a portion of Gas Utility’s total
natural gas storage inventories, and any exchange receivable (representing amounts of
natural gas inventories used by the other parties to the agreement but not yet replenished),
are included in the caption “Gas Utility natural gas” in the table above. The carrying value
of gas storage inventories released under SCAAs with non-affiliates at June 30, 2010,
September 30, 2009 and June 30, 2009 comprising 4.2 billion cubic feet (“bcf”), 1.3 bcf and
0.8 bcf of natural gas was $23.2, $10.5 and $6.7, respectively. |
| 14. | Subsequent Event — Sale of Atlantic Energy |
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned
subsidiary Atlantic Energy, Inc. (“Atlantic Energy”) to DCP Midstream Partners, L.P. for
$49.0 cash plus an amount for inventory and other working capital. Atlantic Energy owns and
operates a 20 million gallon marine import and transshipment facility located in the port of
Chesapeake, Virginia. The Company expects to record an after-tax gain of approximately $16.0
which will be reflected in results for the quarter ending September 30, 2010. |
- 30 -
- 31 -
- 32 -
| Three Months Ended | Nine Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| Net income (loss) attributable to UGI Corporation by business unit: | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (Millions of dollars) | (Millions of dollars) | |||||||||||||||
Net income (loss) attributable to UGI Corporation: |
||||||||||||||||
AmeriGas Propane |
$ | (2.9 | ) | $ | (2.9 | ) | $ | 56.5 | (a) | $ | 71.6 | (b) | ||||
International Propane |
(3.5 | ) | (8.0 | ) | 70.5 | 86.7 | ||||||||||
Gas Utility |
2.4 | 1.3 | 83.5 | 71.4 | ||||||||||||
Electric Utility |
1.2 | 1.7 | 5.7 | 7.3 | ||||||||||||
Energy Services |
5.5 | 5.1 | 46.1 | 35.4 | ||||||||||||
Corporate & Other |
0.7 | (0.8 | ) | (3.4 | ) | (2.9 | ) | |||||||||
Net income (loss) attributable to UGI Corporation |
$ | 3.4 | $ | (3.6 | ) | $ | 258.9 | $ | 269.5 | |||||||
| (a) | Includes net loss of $3.3 million associated with discontinuance of Partnership interest rate
hedges. |
|
| (b) | Includes net income of $10.4 million from sale of the Partnership’s California LPG storage
facility. |
- 33 -
| AmeriGas Propane: | Increase | |||||||||||||||
| For the three months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 396.6 | $ | 372.7 | $ | 23.9 | 6.4 | % | ||||||||
Total margin (a) |
$ | 160.8 | $ | 162.4 | $ | (1.6 | ) | (1.0 | )% | |||||||
Partnership EBITDA (b) |
$ | 27.2 | $ | 25.4 | $ | 1.8 | 7.1 | % | ||||||||
Operating income |
$ | 5.3 | $ | 4.4 | $ | 0.9 | 20.5 | % | ||||||||
Retail gallons sold (millions) |
150.1 | 160.0 | (9.9 | ) | (6.2 | )% | ||||||||||
Degree days — % (warmer) than normal (c) |
(17.0 | )% | (2.8 | )% | — | — | ||||||||||
| (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 5 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. |
- 34 -
| International Propane: | Increase | |||||||||||||||
| For the three months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of euros) (a) | ||||||||||||||||
Revenues |
€ | 144.5 | € | 121.0 | € | 23.5 | 19.4 | % | ||||||||
Total margin (b) |
€ | 61.5 | € | 71.6 | € | (10.1 | ) | (14.1 | )% | |||||||
Operating income |
€ | 1.3 | € | 1.2 | € | 0.1 | 8.3 | % | ||||||||
Loss before income taxes |
€ | (4.9 | ) | € | (3.3 | ) | € | 1.6 | 48.5 | % | ||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 191.8 | $ | 164.9 | $ | 26.9 | 16.3 | % | ||||||||
Total margin (b) |
$ | 79.9 | $ | 97.5 | $ | (17.6 | ) | (18.1 | )% | |||||||
Operating income |
$ | 2.9 | $ | 0.3 | $ | 2.6 | 866.7 | % | ||||||||
Loss before income taxes |
$ | (5.0 | ) | $ | (6.2 | ) | € | (1.2 | ) | (19.4 | )% | |||||
Antargaz retail gallons sold |
49.3 | 48.1 | 1.2 | 2.5 | % | |||||||||||
Degree days — % (warmer) than normal (c) |
(9.6 | )% | (29.3 | )% | — | — | ||||||||||
| (a) | Euro amounts exclude amounts associated with the Company’s propane operation in China
which amounts are not material. |
|
| (b) | Total margin represents total revenues less total cost of sales. |
|
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
- 35 -
| Gas Utility: | Increase | |||||||||||||||
| For the three months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 149.1 | $ | 176.9 | $ | (27.8 | ) | (15.7 | )% | |||||||
Total margin (a) |
$ | 66.1 | $ | 67.1 | $ | (1.0 | ) | (1.5 | )% | |||||||
Operating income |
$ | 13.8 | $ | 12.9 | $ | 0.9 | 7.0 | % | ||||||||
Income before income taxes |
$ | 3.8 | $ | 2.6 | $ | 1.2 | 46.2 | % | ||||||||
System throughput —
billions of cubic feet (“bcf”) |
28.0 | 25.8 | 2.2 | 8.5 | % | |||||||||||
Degree days — % (warmer) than normal (b) |
(26.4 | )% | (6.5 | )% | — | — | ||||||||||
| (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. |
- 36 -
| Electric Utility: | Increase | |||||||||||||||
| For the three months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 25.3 | $ | 30.8 | $ | (5.5 | ) | (17.9 | )% | |||||||
Total margin (a) |
$ | 8.1 | $ | 9.4 | $ | (1.3 | ) | (13.8 | )% | |||||||
Operating income |
$ | 2.6 | $ | 3.3 | $ | (0.7 | ) | (21.2 | )% | |||||||
Income before income taxes |
$ | 2.2 | $ | 2.8 | $ | (0.6 | ) | (21.4 | )% | |||||||
Distribution sales — millions of
kilowatt hours (“gwh”) |
218.6 | 209.8 | 8.8 | 4.2 | % | |||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $1.4 million and $1.7 million during the
three-month periods ended June 30, 2010 and 2009, respectively. For financial statement
purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the
Condensed Consolidated Statements of Income. |
- 37 -
| Energy Services: | ||||||||||||||||
| For the three months ended June 30, | 2010 | 2009 | Decrease | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 198.6 | $ | 223.4 | $ | (24.8 | ) | (11.1 | )% | |||||||
Total margin (a) |
$ | 21.3 | $ | 23.0 | $ | (1.7 | ) | (7.4 | )% | |||||||
Operating income |
$ | 6.9 | $ | 8.6 | $ | (1.7 | ) | (19.8 | )% | |||||||
Income before income taxes |
$ | 6.9 | $ | 8.6 | $ | (1.7 | ) | (19.8 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
- 38 -
| AmeriGas Propane: | Increase | |||||||||||||||
| For the nine months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 1,939.3 | $ | 1,923.1 | $ | 16.2 | 0.8 | % | ||||||||
Total margin (a) |
$ | 774.2 | $ | 793.3 | $ | (19.1 | ) | (2.4 | )% | |||||||
Partnership EBITDA (b) |
$ | 323.7 | $ | 376.7 | $ | (53.0 | ) | (14.1 | )% | |||||||
Operating income |
$ | 261.2 | $ | 317.2 | $ | (56.0 | ) | (17.7 | )% | |||||||
Retail gallons sold (millions) |
746.7 | 781.1 | (34.4 | ) | (4.4 | )% | ||||||||||
Degree days — % (warmer) than
normal (c) |
(1.5 | )% | (2.5 | )% | — | — | ||||||||||
| (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 5 to condensed consolidated financial statements). Partnership EBITDA (and
operating income) in the 2010 nine-month period include a pre-tax loss of $12.2 million
associated with the discontinuance of interest rate hedges. Partnership EBITDA (and
operating income) in the 2009 nine-month period includes a pre-tax gain of $39.9 million
associated with the sale of the Partnership’s California LPG storage facility. |
|
| (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. |
- 39 -
- 40 -
| International Propane: | Increase | |||||||||||||||
| For the nine months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of euros) (a) | ||||||||||||||||
Revenues |
€ | 631.7 | € | 590.7 | € | 41.0 | 6.9 | % | ||||||||
Total margin (b) |
€ | 289.5 | € | 331.6 | € | (42.1 | ) | (12.7 | )% | |||||||
Operating income |
€ | 89.4 | € | 117.6 | € | (28.2 | ) | (24.0 | )% | |||||||
Income before income taxes |
€ | 74.1 | € | 102.7 | € | (28.6 | ) | (27.8 | )% | |||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 885.1 | $ | 780.6 | $ | 104.5 | 13.4 | % | ||||||||
Total margin (b) |
$ | 403.9 | $ | 438.3 | $ | (34.4 | ) | (7.8 | )% | |||||||
Operating income |
$ | 127.6 | $ | 154.1 | $ | (26.5 | ) | (17.2 | )% | |||||||
Income before income taxes |
$ | 106.3 | $ | 133.6 | $ | (27.3 | ) | (20.4 | )% | |||||||
Antargaz retail gallons sold |
237.9 | 247.4 | (9.5 | ) | (3.8 | )% | ||||||||||
Degree days — % (warmer) than
normal (c) |
(0.1 | )% | (1.0 | )% | — | — | ||||||||||
| (a) | Euro amounts exclude amounts associated with the Company’s propane operation in China
which amounts are not material. |
|
| (b) | Total margin represents total revenues less total cost of sales. |
|
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
- 41 -
| Gas Utility: | Increase | |||||||||||||||
| For the nine months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 922.3 | $ | 1,130.1 | $ | (207.8 | ) | (18.4 | )% | |||||||
Total margin (a) |
$ | 338.1 | $ | 334.4 | $ | 3.7 | 1.1 | % | ||||||||
Operating income |
$ | 168.6 | $ | 149.8 | $ | 18.8 | 12.6 | % | ||||||||
Income before income taxes |
$ | 138.1 | $ | 118.1 | $ | 20.0 | 16.9 | % | ||||||||
System throughput —
billions of cubic feet (“bcf”) |
124.9 | 126.4 | (1.5 | ) | (1.2 | )% | ||||||||||
Degree days — % (warmer) colder than normal (b) |
(4.5 | )% | 3.9 | % | — | — | ||||||||||
| (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. |
- 42 -
| Electric Utility: | ||||||||||||||||
| For the nine months ended June 30, | 2010 | 2009 | Decrease | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 90.9 | $ | 104.8 | $ | (13.9 | ) | (13.3 | )% | |||||||
Total margin (a) |
$ | 27.9 | $ | 32.0 | $ | (4.1 | ) | (12.8 | )% | |||||||
Operating income |
$ | 11.1 | $ | 13.8 | $ | (2.7 | ) | (19.6 | )% | |||||||
Income before income taxes |
$ | 9.8 | $ | 12.5 | $ | (2.7 | ) | (21.6 | )% | |||||||
Distribution sales — millions of kilowatt hours (“gwh”) |
723.8 | 735.8 | (12.0 | ) | (1.6 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $5.0 million and $5.7 million during the
nine-month periods ended June 30, 2010 and 2009, respectively. For financial statement
purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the
Condensed Consolidated Statements of Income. |
- 43 -
| Energy Services: | Increase | |||||||||||||||
| For the nine months ended June 30, | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 949.5 | $ | 1,007.1 | $ | (57.6 | ) | (5.7 | )% | |||||||
Total margin (a) |
$ | 118.6 | $ | 104.8 | $ | 13.8 | 13.2 | % | ||||||||
Operating income |
$ | 75.4 | $ | 60.0 | $ | 15.4 | 25.7 | % | ||||||||
Income before income taxes |
$ | 75.4 | $ | 60.0 | $ | 15.4 | 25.7 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
- 44 -
- 45 -
- 46 -
- 47 -
- 48 -
- 49 -
- 50 -
- 51 -
- 52 -
| (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. |
- 53 -
- 54 -
- 55 -
- 56 -
| Incorporation by Reference | ||||||||||||
| Exhibit No. |
Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.1 | UGI Corporation
2009 Deferral Plan
as Amended and
Restated Effective
June 1, 2010. |
|||||||||||
| 10.2 | AmeriGas Propane,
Inc. 2010 Long-Term
Incentive Plan on
behalf of AmeriGas
Partners, L.P.
Effective July 30,
2010.
|
AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.1 | ||||||||
| 10.3 | Amendment No. 1 to
Credit Agreement,
dated as of July 1,
2010, among the
Partnership, as
Borrower, AmeriGas
Propane, Inc., as
Guarantor,
Petrolane
Incorporated, as
Guarantor, Citizens
Bank of
Pennsylvania, as
Syndication Agent,
JPMorgan Chase
Bank, N.A., as
Documentation Agent
and Wells Fargo
Bank, N.A., as
Administrative
Agent.
|
AmeriGas Partners, L.P. | Form 8-K (7/1/10) | 10.1 | ||||||||
| 10.4 | Gas Supply and
Delivery Service
Agreement between
UGI Utilities, Inc.
and UGI Energy
Services, Inc.
effective as of May
1, 2007.
|
UGI Utilities | Form 10-Q (6/30/10) | 10.1 | ||||||||
| 10.5 | SST Service
Agreement dated
November 1, 2004
between Columbia
Gas Transmission
Corporation and UGI
Utilities, Inc.
|
UGI Utilities | Form 10-Q (6/30/10) | 10.2 | ||||||||
| 31.1 | Certification by
the Chief Executive
Officer relating to
the Registrant’s
Report on Form 10-Q
for the quarter
ended June 30,
2010, 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,
2010, 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,
2010, pursuant to
Section 906 of the
Sarbanes-Oxley Act
of 2002. |
|||||||||||
| 101 | The
following financial statements from UGI Corporation and
Subsidiaries’ Quarterly Report on Form 10-Q for the quarter and
nine months ended June 30, 2010, formatted in XBRL (Extensible
Business Reporting Language): (i) the Condensed Consolidated Balance
Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the
Condensed Consolidated Statements of Cash Flows; and (iv) Notes to
Condensed Financial Statements, tagged as blocks of text. |
|||||||||||
- 57 -
| UGI Corporation | ||||
| (Registrant) |
||||
| Date: August 6, 2010 | By: | /s/ Peter Kelly | ||
| Peter Kelly | ||||
| Vice President - Finance and Chief Financial Officer |
||||
| Date: August 6, 2010 | By: | /s/ Davinder Athwal | ||
| Davinder Athwal | ||||
| Vice President - Accounting and Financial Control and Chief Risk Officer |
||||
- 58 -
| 10.1 | UGI Corporation 2009 Deferral Plan as Amended and Restated Effective June 1, 2010. |
|||
| 31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on
Form 10-Q for the quarter ended June 30, 2010, 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, 2010, 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, 2010, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
|||
| 101 | The
following financial statements from UGI Corporation and
Subsidiaries’ Quarterly Report on Form 10-Q for the quarter and
nine months ended June 30, 2010, formatted in XBRL (Extensible
Business Reporting Language): (i) the Condensed Consolidated Balance
Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the
Condensed Consolidated Statements of Cash Flows; and (iv) Notes to
Condensed Financial Statements, tagged as blocks of text. |