UGI CORP /PA/, 10-Q filed on 8/5/2011
Quarterly Report
Document and Entity Information
9 Months Ended
Jun. 30, 2011
Jul. 29, 2011
Document and Entity Information [Abstract]
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
Entity Central Index Key
0000884614 
 
Document Type
10-Q 
 
Document Period End Date
Jun. 30, 2011 
 
Amendment Flag
FALSE 
 
Document Fiscal Year Focus
2011 
 
Document Fiscal Period Focus
Q3 
 
Current Fiscal Year End Date
--09-30 
 
Entity Well-known Seasoned Issuer
Yes 
 
Entity Voluntary Filers
No 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
111,804,420 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Millions
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
Current assets
 
 
 
Cash and cash equivalents
$ 317.8 
$ 260.7 
$ 241.8 
Restricted cash
10.2 
34.8 
22.9 
Accounts receivable (less allowances for doubtful accounts of $45.0, $34.6 and $44.5, respectively)
595.7 
467.8 
503.4 
Accrued utility revenues
7.4 
14.0 
9.7 
Inventories
271.6 
314.0 
249.2 
Deferred income taxes
26.8 
32.6 
26.7 
Derivative financial instruments
10.5 
11.3 
17.5 
Prepaid expenses and other current assets
50.2 
84.9 
40.4 
Total current assets
1,290.2 
1,220.1 
1,111.6 
Property, plant and equipment (less accumulated depreciation and amortization of $2,065.9, $1,916.5 and $1,866.2, respectively)
3,228.0 
3,053.2 
2,875.5 
Goodwill
1,612.0 
1,562.7 
1,475.9 
Intangible assets, net
159.5 
150.1 
138.1 
Other assets
384.0 
388.2 
230.5 
Total assets
6,673.7 
6,374.3 
5,831.6 
Current liabilities:
 
 
 
Current maturities of long-term debt
38.5 
573.6 
572.9 
Bank loans
206.1 
200.4 
35.2 
Accounts payable
338.7 
372.6 
297.9 
Derivative financial instruments
21.2 
58.0 
48.0 
Other current liabilities
430.4 
470.1 
379.5 
Total current liabilities
1,034.9 
1,674.7 
1,333.5 
Long-term debt
2,039.5 
1,432.2 
1,456.8 
Deferred income taxes
678.3 
601.4 
510.9 
Deferred investment tax credits
5.0 
5.3 
5.4 
Other noncurrent liabilities
535.1 
599.1 
531.0 
Total liabilities
4,292.8 
4,312.7 
3,837.6 
Commitments and contingencies (note 10)
 
 
 
UGI Corporation stockholders' equity:
 
 
 
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,507,094, 115,400,294 and 115,375,794 shares, respectively)
934.9 
906.1 
896.1 
Retained earnings
1,137.3 
966.7 
992.1 
Accumulated other comprehensive income (loss)
67.6 
(10.1)
(115.8)
Treasury stock, at cost
(28.6)
(38.2)
(42.4)
Total UGI Corporation stockholders' equity
2,111.2 
1,824.5 
1,730.0 
Noncontrolling interests
269.7 
237.1 
264.0 
Total equity
2,380.9 
2,061.6 
1,994.0 
Total liabilities and equity
$ 6,673.7 
$ 6,374.3 
$ 5,831.6 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
ASSETS
 
 
 
Accounts receivable, allowances for doubtful accounts
$ 45.0 
$ 34.6 
$ 44.5 
Property, plant and equipment, accumulated depreciation and amortization
$ 2,065.9 
$ 1,916.5 
$ 1,866.2 
UGI Corporation stockholders' equity:
 
 
 
UGI Common Stock, without par value
 
 
 
UGI Common Stock, without par value authorized
300,000,000 
300,000,000 
300,000,000 
UGI Common Stock, without par value, issued
115,507,094 
115,400,294 
115,375,794 
Condensed Consolidated Statements of Income (Unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Revenues
 
 
 
 
Revenues
$ 1,105.4 
$ 961.9 
$ 5,052.0 
$ 4,701.0 
Costs and expenses:
 
 
 
 
Cost of sales (excluding depreciation shown below)
731.0 
615.5 
3,317.5 
3,009.2 
Operating and administrative expenses
304.3 
267.6 
966.4 
892.7 
Utility taxes other than income taxes
3.6 
4.2 
13.4 
13.6 
Depreciation
50.8 
46.1 
149.0 
140.4 
Amortization
7.0 
5.6 
19.6 
16.9 
Other income, net
(8.5)
(8.3)
(40.4)
(12.2)
Total costs and expenses
1,088.2 
930.7 
4,425.5 
4,060.6 
Operating income
17.2 
31.2 
626.5 
640.4 
Loss from equity investees
(0.2)
(1.9)
(0.8)
(1.9)
Loss on extinguishment of debt
 
 
(18.8)
 
Interest expense
(35.0)
(33.6)
(102.6)
(101.9)
(Loss) income before income taxes
(18.0)
(4.3)
504.3 
536.6 
Income tax benefit (expense)
4.5 
0.1 
(147.2)
(162.5)
Net (loss) income
(13.5)
(4.2)
357.1 
374.1 
Less: net income (loss) attributable to noncontrolling interests, principally AmeriGas Partners
6.3 
7.6 
(101.8)
(115.2)
Net (loss) income attributable to UGI Corporation
$ (7.2)
$ 3.4 
$ 255.3 
$ 258.9 
(Loss) earnings per common share attributable to UGI stockholders:
 
 
 
 
Basic
$ (0.06)
$ 0.03 
$ 2.29 
$ 2.37 
Diluted
$ (0.06)
$ 0.03 
$ 2.26 
$ 2.35 
Average common shares outstanding (thousands):
 
 
 
 
Basic
112,020 
109,683 
111,515 
109,331 
Diluted
112,020 
110,699 
113,046 
110,188 
Dividends declared per common share
$ 0.26 
$ 0.25 
$ 0.76 
$ 0.65 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Millions
9 Months Ended
Jun. 30,
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 357.1 
$ 374.1 
Reconcile to net cash from operating activities:
 
 
Depreciation and amortization
168.6 
157.3 
Deferred income taxes, net
24.8 
46.9 
Provision for uncollectible accounts
19.8 
26.2 
Net change in realized gains and losses deferred as cash flow hedges
13.8 
31.4 
Loss on extinguishment of debt
18.8 
 
Other, net
18.4 
20.7 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(93.1)
(147.3)
Inventories
56.7 
106.9 
Utility deferred fuel costs
33.0 
(1.0)
Accounts payable
(51.3)
(10.0)
Other current assets
(6.8)
(6.2)
Other current liabilities
(92.6)
(82.3)
Net cash provided by operating activities
467.2 
516.7 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(245.3)
(228.8)
Acquisitions of businesses, net of cash acquired
(49.6)
(25.4)
Decrease (increase) in restricted cash
24.6 
(15.9)
Other, net
(1.7)
(14.7)
Net cash used by investing activities
(272.0)
(284.8)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends on UGI Common Stock
(84.7)
(71.1)
Distributions on AmeriGas Partners publicly held Common Units
(69.7)
(66.2)
Issuances of debt
981.5 
 
Repayments of debt
(987.3)
(9.5)
Increase (decrease) in bank loans
5.4 
(123.3)
Receivables Facility net repayments
(12.1)
 
Issuances of UGI Common Stock
24.9 
16.6 
Other
3.4 
1.7 
Net cash used by financing activities
(138.6)
(251.8)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
0.5 
(18.4)
Cash and cash equivalents increase (decrease)
57.1 
(38.3)
Cash and cash equivalents:
 
 
End of period
317.8 
241.8 
Beginning of period
260.7 
280.1 
Increase (decrease)
$ 57.1 
$ (38.3)
Nature of Operations
Nature of Operations
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) an energy marketing, midstream infrastructure, storage and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in 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 subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prior to its October 1, 2010 merger with AmeriGas OLP, AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnership”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. 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, 2011, 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 32,433,087 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 distribution business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage and energy services business primarily in the Mid-Atlantic region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
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 in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. 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.”
Significant Accounting Policies
Significant Accounting Policies
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, 2010 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Denominator (thousands of shares):
                               
Average common shares outstanding for basic computation
    112,020       109,683       111,515       109,331  
Incremental shares issuable for stock options and awards
          1,016       1,531       857  
 
                       
Average common shares outstanding for diluted computation
    112,020       110,699       113,046       110,188  
 
                       
Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2011 and 2010:
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Net (loss) income
  $ (13.5 )   $ (4.2 )   $ 357.1     $ 374.1  
Other comprehensive (loss) income
    (0.5 )     (58.2 )     76.5       (84.4 )
 
                       
Comprehensive (loss) income (including noncontrolling interests)
    (14.0 )     (62.4 )     433.6       289.7  
Less: comprehensive income (loss) attributable to noncontrolling interests
    10.8       21.4       (100.6 )     (107.7 )
 
                       
Comprehensive (loss) income attributable to UGI Corporation
  $ (3.2 )   $ (41.0 )   $ 333.0     $ 182.0  
 
                       
Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, 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.
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets (see Note 7) and an after-tax increase in other comprehensive income of $2.1 which is reflected in other comprehensive income in the nine months ended June 30, 2011.
Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.
Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Accounting Changes
Accounting Changes
3.  
Accounting Changes
Adoption of New Accounting Standard
Transfers of Financial Assets. Effective October 1, 2010, the Company adopted 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 adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.
New Accounting Standards Not Yet Adopted
Fair Value Measurements. In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.
Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 and the guidance is required to be applied retrospectively. Early adoption is permitted.
Intangible Assets
Intangible Assets
4.  
Intangible Assets
The Company’s intangible assets comprise the following:
                         
    June 30,     September 30,     June 30,  
    2011     2010     2010  
Goodwill (not subject to amortization)
  $ 1,612.0     $ 1,562.7     $ 1,475.9  
 
                 
 
                       
Other intangible assets:
                       
Customer relationships, noncompete agreements and other
  $ 240.6     $ 215.4     $ 202.9  
Trademarks (not subject to amortization)
    51.9       46.3       41.5  
 
                 
Gross carrying amount
    292.5       261.7       244.4  
Accumulated amortization
    (133.0 )     (111.6 )     (106.3 )
 
                 
Net carrying amount
  $ 159.5     $ 150.1     $ 138.1  
 
                 
The increases in goodwill and other intangible assets during the nine months ended June 30, 2011 principally reflects the effects of acquisitions and currency translation. Amortization expense of intangible assets was $5.4 and $15.1 for the three and nine months ended June 30, 2011, respectively, and $4.9 and $14.8 for the three and nine months ended June 30, 2010, 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 remainder of Fiscal 2011 and the next four fiscal years is as follows: remainder of Fiscal 2011 — $5.0; Fiscal 2012 — $20.7; Fiscal 2013 — $20.1; Fiscal 2014 — $19.2; Fiscal 2015 — $16.2.
Segment Information
Segment Information
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, our propane distribution business in China and certain International Propane nonoperating entities (“Flaga & Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. 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 2010 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 Midstream & Marketing segments principally based upon their income before income taxes.
Three Months Ended June 30, 2011:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 1,105.4     $ (40.0 ) (c)   $ 470.8     $ 148.1     $ 24.1     $ 217.1     $ 161.0     $ 102.3     $ 22.0  
 
                                                                       
Cost of sales
  $ 731.0     $ (39.1 ) (c)   $ 300.8     $ 78.8     $ 14.6     $ 193.1     $ 95.3     $ 74.6     $ 12.9  
 
                                                                       
Segment profit:
                                                                       
Operating income (loss)
  $ 17.2     $     $ 6.7     $ 17.2     $ 2.4     $ 8.4     $ (11.4 )   $ (3.6 )   $ (2.5 )
Loss from equity investees
    (0.2 )                                   (0.2 )            
Interest expense
    (35.0 )           (15.7 )     (9.9 )     (0.7 )     (0.6 )     (7.1 )     (0.8 )     (0.2 )
 
                                                     
(Loss) income before income taxes
  $ (18.0 )   $     $ (9.0 )   $ 7.3     $ 1.7     $ 7.8     $ (18.7 )   $ (4.4 )   $ (2.7 )
 
                                                     
 
                                                                       
Partnership EBITDA (a)
                  $ 31.1                                                  
Noncontrolling interests’ net loss
  $ (6.3 )   $     $ (6.1 )   $     $     $     $ (0.2 )   $     $  
Depreciation and amortization
  $ 57.8     $     $ 24.5     $ 11.6     $ 1.1     $ 1.8     $ 13.5     $ 4.7     $ 0.6  
 
                                                                       
Capital expenditures
  $ 78.5     $     $ 18.6     $ 20.9     $ 1.0     $ 18.7     $ 12.0     $ 6.6     $ 0.7  
 
                                                                       
Total assets (at period end)
  $ 6,673.7     $ (81.0 )   $ 1,772.1     $ 2,002.0     $ 156.5     $ 572.2     $ 1,678.2     $ 407.3     $ 166.4  
 
                                                                       
Bank loans (at period end)
  $ 206.1     $     $ 176.0     $     $     $     $     $ 30.1     $  
 
Goodwill (at period end)
  $ 1,612.0     $     $ 695.8     $ 180.1     $     $ 2.8     $ 641.1     $ 85.3     $ 6.9  
Three Months Ended June 30, 2010:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 961.9     $ (22.2 ) (c)   $ 396.6     $ 149.1     $ 25.3     $ 198.6     $ 150.8     $ 41.0     $ 22.7  
 
                                                                       
Cost of sales
  $ 615.5     $ (20.7 ) (c)   $ 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 (a)
                  $ 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  
(a)  
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
                 
Three months ended June 30,   2011     2010  
 
Partnership EBITDA
  $ 31.1     $ 27.2  
Depreciation and amortization
    (24.5 )     (21.8 )
Noncontrolling interest (i)
    0.1       (0.1 )
 
           
Operating income
  $ 6.7     $ 5.3  
 
           
(i)  
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
 
(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)  
Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Nine Months Ended June 30, 2011:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 5,052.0     $ (172.9 ) (c)   $ 2,077.8     $ 921.7     $ 84.7     $ 857.0     $ 889.7     $ 332.4     $ 61.6  
 
                                                                       
Cost of sales
  $ 3,317.5     $ (170.3 ) (c)   $ 1,300.9     $ 562.3     $ 53.4     $ 738.6     $ 554.0     $ 243.8     $ 34.8  
 
                                                                       
Segment profit:
                                                                       
Operating income (loss)
  $ 626.5     $ 0.2     $ 252.9     $ 193.2     $ 9.0     $ 76.7     $ 101.0     $ (0.2 )   $ (6.3 )
Loss from equity investees
    (0.8 )                                   (0.8 )            
Loss on extinguishment of debt
    (18.8 )           (18.8 )                                    
Interest expense
    (102.6 )           (47.4 )     (30.2 )     (1.8 )     (2.0 )     (18.5 )     (2.1 )     (0.6 )
 
                                                     
Income (loss) before income taxes
  $ 504.3     $ 0.2     $ 186.7     $ 163.0     $ 7.2     $ 74.7     $ 81.7     $ (2.3 )   $ (6.9 )
 
                                                     
 
                                                                       
Partnership EBITDA (a)
                  $ 301.9                                                  
Noncontrolling interests’ net income
  $ 101.8     $     $ 101.2     $     $     $     $ 0.6     $     $  
Depreciation and amortization
  $ 168.6     $     $ 70.4     $ 36.1     $ 3.1     $ 5.4     $ 38.4     $ 13.7     $ 1.5  
 
                                                                       
Capital expenditures
  $ 246.1     $     $ 59.2     $ 54.5     $ 5.1     $ 81.5     $ 31.8     $ 12.6     $ 1.4  
 
                                                                       
Total assets (at period end)
  $ 6,673.7     $ (81.0 )   $ 1,772.1     $ 2,002.0     $ 156.5     $ 572.2     $ 1,678.2     $ 407.3     $ 166.4  
 
                                                                       
Bank loans (at period end)
  $ 206.1     $     $ 176.0     $     $     $     $     $ 30.1     $  
 
                                                                       
Goodwill (at period end)
  $ 1,612.0     $     $ 695.8     $ 180.1     $     $ 2.8     $ 641.1     $ 85.3     $ 6.9  
Nine Months Ended June 30, 2010:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 4,701.0     $ (146.9 ) (c)   $ 1,939.3     $ 922.3     $ 90.9     $ 949.5     $ 755.3     $ 129.8     $ 60.8  
 
                                                                       
Cost of sales
  $ 3,009.2     $ (142.3 ) (c)   $ 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 (a)
                  $ 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  
(a)  
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
                 
Nine months ended June 30,   2011     2010  
 
Partnership EBITDA
  $ 301.9 (ii)   $ 323.7 (iii)
Depreciation and amortization
    (70.4 )     (65.0 )
Loss on extinguishment of debt
    18.8        
Noncontrolling interest (i)
    2.6       2.5  
 
           
Operating income
  $ 252.9     $ 261.2  
 
           
(i)  
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
 
(ii)  
Includes $18.8 loss associated with the extinguishment of Partnership debt.
 
(iii)  
Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
 
(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)  
Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Energy Services Accounts Receivable Securitization Facility
Energy Services Accounts Receivable Securitization Facility
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 2012, 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. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
Effective October 1, 2010, the Company adopted a new accounting standard that changes the accounting for the Receivables Facility on a prospective basis (see Note 3). Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet; the Company reflects a liability equal to the amount advanced by the commercial paper conduit; and the Company records interest expense on amounts sold to the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet and any losses on sales of accounts receivable were reflected in other income, net.
During the nine months ended June 30, 2011 and 2010, Energy Services transferred trade receivables to ESFC totaling $923.5 and $933.3, respectively. During the nine months ended June 30, 2011 and 2010, ESFC sold an aggregate $68.0 and $233.6, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2011, the balance of ESFC receivables was $50.9 and there was no amount sold to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC receivables was $61.8 and there was no amount sold to the commercial paper conduit.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
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 2010 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,  
    2011     2010     2010  
Regulatory assets:
                       
Income taxes recoverable
  $ 92.7     $ 82.5     $ 95.3  
Underfunded pension and postretirement plans
    116.0       159.2       10.3  
Environmental costs
    20.7       22.6       24.3  
Deferred fuel and power costs
    7.8       36.6       6.3  
Other
    8.9       5.8       5.5  
 
                 
Total regulatory assets
  $ 246.1     $ 306.7     $ 141.7  
 
                 
 
                       
Regulatory liabilities:
                       
Postretirement benefits
  $ 11.6     $ 10.5     $ 10.3  
Environmental overcollections
    6.2       7.2       8.3  
Deferred fuel and power refunds
    22.4       8.3       16.6  
State tax benefits — distribution system repairs
    6.2       6.7       11.0  
 
                 
Total regulatory liabilities
  $ 46.4     $ 32.7     $ 46.2  
 
                 
Underfunded pension and postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP relating to accounting for retirement benefits. These costs are amortized over the average remaining future service lives of the plan participants.
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43.1 (see Note 8).
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, 2011, September 30, 2010 and June 30, 2010 were $1.1, $1.4 and $0.6, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 13, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At June 30, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10.1 and $19.7, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.
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 DS 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, 2011, September 30, 2010 and June 30, 2010 were not material.
Other Regulatory Matters
Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.
CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 in additional base rate revenue as well as $0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.
Defined Benefit Pension And Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
8.  
Defined Benefit Pension and Other Postretirement Plans
In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). 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,  
    2011     2010     2011     2010  
Service cost
  $ 2.1     $ 2.2     $ 0.1     $ 0.1  
Interest cost
    6.1       5.8       0.3       0.3  
Expected return on assets
    (6.4 )     (6.5 )     (0.1 )     (0.1 )
Amortization of:
                               
Prior service cost (benefit)
    0.1             (0.2 )     (0.1 )
Actuarial loss
    1.7       1.5       0.1       0.1  
 
                       
Net benefit cost
    3.6       3.0       0.2       0.3  
Change in associated regulatory liabilities
                0.8       0.7  
 
                       
Net expense
  $ 3.6     $ 3.0     $ 1.0     $ 1.0  
 
                       
                                 
                    Other  
    Pension Benefits     Postretirement Benefits  
    Nine Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Service cost
  $ 6.6     $ 6.5     $ 0.4     $ 0.3  
Interest cost
    18.1       17.6       0.8       0.9  
Expected return on assets
    (19.4 )     (19.4 )     (0.4 )     (0.3 )
Amortization of:
                               
Prior service cost (benefit)
    0.2             (0.5 )     (0.3 )
Actuarial loss
    5.7       4.4       0.3       0.2  
 
                       
Net benefit cost
    11.2       9.1       0.6       0.8  
Change in associated regulatory liabilities
                2.4       2.2  
 
                       
Net expense
  $ 11.2     $ 9.1     $ 3.0     $ 3.0  
 
                       
Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. 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 $16.0 to the Pension Plan during the next twelve months. During the nine months ended June 30, 2011, the Company made contributions to the Pension Plan of $16.7. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to 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 for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts 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, 2011, nor are they expected to be material for all of Fiscal 2011.
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.9 and $2.2 for the three and nine months ended June 30, 2011, respectively. 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.
Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.1; and increased pre-tax other comprehensive income by $3.6 (see Notes 2 and 7).
The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:
         
    Three Months  
    Ended  
    December 31,  
    2010  
Change in benefit obligations:
       
Benefit obligations — October 1, 2010
  $ 465.0  
Service cost
    2.2  
Interest cost
    5.8  
Actuarial gain
    (30.6 )
Benefits paid
    (4.7 )
 
     
Benefit obligations — December 31, 2010
  $ 437.7  
 
     
 
       
Change in plan assets:
       
Fair value of plan assets — October 1, 2010
  $ 287.9  
Actual gain on assets
    19.3  
Employer contributions
    1.8  
Benefits paid
    (4.7 )
 
     
Fair value of plan assets — December 31, 2010
  $ 304.3  
 
     
 
       
Funded status of the merged plan — December 31, 2010
  $ (133.4 )
 
     
At December 31, 2010:
       
Liabilities recorded in the balance sheet:
       
Unfunded liabilities — included in other current liabilities
  $ (20.3 )
Unfunded liabilities — included in other noncurrent liabilities
    (113.1 )
 
     
Net amount recognized
  $ (133.4 )
 
     
Amounts recorded in regulatory assets and liabilities:
       
Prior service cost
  $ 0.3  
Net actuarial loss
    112.7  
 
     
Total
  $ 113.0  
 
     
Amounts recorded in stockholders’ equity:
       
Prior service cost
  $ 0.1  
Net actuarial loss
    9.8  
 
     
Total
  $ 9.9  
 
     
The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391.2. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.
Debt
Debt
9.  
Debt
AmeriGas Partners. On January 20, 2011, AmeriGas Partners issued $470 principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used in February 2011 to repay AmeriGas Partners’ $415 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent notice of redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of AmeriGas Partners 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these extinguishments of debt which amount is reflected on the Consolidated Statements of Income under the caption “Loss on extinguishment of debt.” The loss reduced net income attributable to UGI Corporation by $5.2 during the nine months ended June 30, 2011. The 6.50% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets.
In addition, on June 21, 2011, AmeriGas OLP entered into an unsecured revolving credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325 (including a $100 sublimit for letters of credit). Concurrently with entering into the AmeriGas 2011 Credit Agreement, AmeriGas OLP terminated its then-existing $200 revolving credit agreement dated as of November 6, 2006 and its $75 credit agreement dated as of April 17, 2009. The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement. The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that AmeriGas OLP and AmeriGas Partners not exceed ratios of total indebtedness to EBITDA, as defined for each of those entities, and that AmeriGas Partners maintains a minimum ratio of EBITDA to interest expense, as defined.
Antargaz Refinancing. In March 2011, Antargaz entered into a new five-year variable rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used on March 16, 2011 to repay Antargaz’ existing Senior Facilities Agreement that was due March 31, 2011.
The new agreement consists of (1) a €380 variable-rate term loan and (2) a €40 revolving credit facility. Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At June 30, 2011, the effective interest rate on Antargaz’ term loan was 4.66%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. In addition, UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement. The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00.
UGI Utilities 2011 Credit Agreement. On May 25, 2011, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. The UGI Utilities 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking such regulatory approval.
Flaga Working Capital Facility Extensions. During the three months ended June 30, 2011, Flaga extended the expiration dates of its two multi-currency working capital facilities, which provide for combined borrowings of €24, to September 2011. Also during the three months ended June 30, 2011, Flaga extended the expiration dates of its two euro-denominated working capital facilities, which provide for combined borrowings of €12, to March 2012.
Commitments and Contingencies
Commitments and Contingencies
10.  
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, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
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 two claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. Trial took place in March 2009 and the court’s decision is pending.
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 they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. 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 in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s decision in favor of UGI Utilities. A second phase of the trial is scheduled for August 2011 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.
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 challenged AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. After that initial suit, various AmeriGas entities were named in more than a dozen similar suits that were filed in various courts throughout the United States. All of those cases were consolidated and transferred to the United States District Court for the Western District of Missouri. On May 19, 2010, the Court granted the class’ motion seeking preliminary approval of the parties’ settlement. On October 4, 2010, the Court ruled that the settlement was fair, reasonable and adequate to the class and granted final approval of the settlement.
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 (the “District Attorneys”) 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 have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena seeks information and documents regarding AmeriGas OLP’s cylinder exchange program and alleges potential violations of California’s Unfair Competition Law. We are reviewing the subpoena and will continue to cooperate with the District Attorneys.
Swiger, et al. v. UGI/AmeriGas, Inc. et al. In 1996, a fire occurred at the residence of Samuel and Brenda Swiger (the “Swigers”) 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. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class, which was preliminarily approved by the Circuit Court of Monongalia County on January 13, 2011.
In 2005, the Swigers also 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 alleged 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 this action.
BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We recently commenced an investigation into these allegations. Because of the preliminary nature of this investigation, which is ongoing, the amount of loss, if any, cannot be reasonably estimated.
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. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010 the Company reversed its previously recorded nontaxable accrual for this matter which increased net income by $9.4. This amount is reflected in other income, net, on the Condensed Consolidated Statement of Income.
We cannot predict 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. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
Equity
Equity
11.  
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, 2011 and 2010:
                                                 
            UGI Shareholders        
                            Accumulated              
                            Other              
    Non-                     Comprehensive              
    controlling     Common     Retained     Income     Treasury     Total  
    Interests     Stock     Earnings     (Loss)     Stock     Equity  
 
                                               
Nine Months Ended June 30, 2011:
                                               
Balance September 30, 2010
  $ 237.1     $ 906.1     $ 966.7     $ (10.1 )   $ (38.2 )   $ 2,061.6  
Net income
    101.8               255.3                       357.1  
Net gains on derivative instruments
    14.8                       10.8               25.6  
Reclassifications of net (gains) losses on derivative instruments
    (16.0 )                     27.0               11.0  
Benefit plans
                            2.1               2.1  
Foreign currency translation adjustments
                            37.8               37.8  
 
                                       
Comprehensive income
    100.6               255.3       77.7               433.6  
Dividends and distributions
    (69.7 )             (84.7 )                     (154.4 )
Equity transactions
    0.5       28.8                       9.6       38.9  
Other
    1.2                                       1.2  
 
                                   
Balance June 30, 2011
  $ 269.7     $ 934.9     $ 1,137.3     $ 67.6     $ (28.6 )   $ 2,380.9  
 
                                   
 
                                               
Nine Months Ended June 30, 2010:
                                               
Balance September 30, 2009
  $ 225.4     $ 875.6     $ 804.3     $ (38.9 )   $ (49.6 )   $ 1,816.8  
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 )
Equity transactions
    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  
 
                                   
Fair Value Measurement
Fair Value Measurement
12.  
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, 2011, September 30, 2010 and June 30, 2010:
                                 
    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, 2011:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 0.6     $ 10.1     $     $ 10.7  
Interest rate contracts
  $     $ 5.0     $     $ 5.0  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (12.2 )   $ (11.6 )   $     $ (23.8 )
Foreign currency contracts
  $     $ (6.1 )   $     $ (6.1 )
Interest rate contracts
  $     $ (3.6 )   $     $ (3.6 )
 
                               
September 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 1.1     $ 10.7     $     $ 11.8  
Foreign currency contracts
  $     $ 0.8     $     $ 0.8  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (49.4 )   $ (20.3 )   $     $ (69.7 )
Foreign currency contracts
  $     $ (2.9 )   $     $ (2.9 )
Interest rate contracts
  $     $ (18.5 )   $     $ (18.5 )
 
                               
June 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 0.4     $ 3.2     $     $ 3.6  
Foreign currency contracts
  $     $ 16.9     $     $ 16.9  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (25.4 )   $ (18.1 )   $     $ (43.5 )
Interest rate contracts
  $     $ (16.4 )   $     $ (16.4 )
The fair values of our Level 1 exchange-traded commodity futures and options contracts and non exchange-traded commodity futures and forward 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, 2011 were $2,078.0 and $2,170.4, respectively. 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. 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.
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, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. 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.
Disclosures About Derivative Instruments and Hedging Activities
Disclosures About Derivative Instruments and Hedging Activities
13.  
Disclosures About Derivative Instruments and Hedging Activities
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 most of our derivative instruments 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. In addition, the Partnership, 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. In addition, from time to time, the Partnership enters into price swap agreements to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.
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, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and 11.3 million dekatherms, respectively. At June 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).
Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10.1 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying June 30, 2011 Condensed Consolidated Balance Sheet. In accordance with ASC 980, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet. At June 30, 2011, volumes under Electric Utility’s forward electricity purchase contracts were 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing 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 DS costs commencing January 1, 2010, 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 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 1,955.2 million kilowatt hours and 1,415.0 million kilowatt hours, respectively.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during the three months ended June 30, 2011 were not material. At June 30, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.3 million dekatherms and 0.9 million gallons, respectively.
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.
At June 30, 2011 and 2010, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
                 
    Volumes  
    June 30,  
Commodity   2011     2010  
 
               
LPG (millions of gallons)
    145.0       150.5  
Natural gas (millions of dekatherms)
    21.2       33.3  
Electricity (millions of kilowatt-hours)
    1,200.8       928.0  
At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 15 months with a weighted average of 7 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 30 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 21 months with a weighted average of 7 months. At June 30, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 11 months.
We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) 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 Condensed Consolidated Statements of Income. At June 30, 2011, 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 $8.7.
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 entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2011 and 2010, the total notional amounts of existing or anticipated variable-rate debt subject to interest rate swap agreements were €398.8 and €706.2, 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”). At June 30, 2011, the total notional amount of unsettled IRPAs was $173.0. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.
As previously disclosed, during the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 of long-term debt during the summer of 2010. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net, on the Condensed Consolidated Statements of Income for the nine months ended 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, 2011, 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 (which excludes the impact of AmeriGas Partners’ debt refinancing described in Note 15).
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 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At June 30, 2011 and 2010, we were hedging a total of $141.4 and $72.8 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 32 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. At June 30, 2011 and 2010, we were hedging a total of €14.5 and €48.3, respectively, of our euro-denominated net investments. As of June 30, 2011, our foreign currency contracts extend through March 2014.
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 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, 2011, the amount of net losses 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 $4.0. Gains and losses on net investment hedges remain in AOCI until such foreign net investment is sold or 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 large 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 or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in these accounts totaled $10.2 and $22.9, 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, 2011. We generally do not have credit-risk-related contingent features in our derivative contracts.
The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:
                                         
    Derivative Assets     Derivative (Liabilities)  
        Fair Value         Fair Value  
    Balance Sheet   June 30,     Balance Sheet   June 30,  
    Location   2011     2010     Location   2011     2010  
Derivatives Designated as
Hedging Instruments:
                                       
 
                                       
Commodity contracts
  Derivative financial instruments and Other assets   $ 6.0     $ 0.3     Derivative financial instruments and Other noncurrent liabilities   $ (12.6 )   $ (42.8 )
Foreign currency contracts
                                       
 
  Derivative financial instruments and Other assets           16.9     Derivative financial instruments and Other noncurrent liabilities     (6.1 )      
Interest rate contracts
                                       
 
  Other assets     5.0           Derivative financial instruments and Other noncurrent liabilities     (3.6 )     (16.4 )
 
                               
Total Derivatives Designated
as Hedging Instruments
      $ 11.0     $ 17.2         $ (22.3 )   $ (59.2 )
 
                               
 
                                       
Derivatives Accounted for
under ASC 980:
                                       
Commodity contracts
  Derivative financial instruments   $ 0.2     $ 0.6     Derivative financial instruments and Other noncurrent liabilities   $ (11.2 )   $ (0.8 )
 
                                       
Derivatives Not Designated as
Hedging Instruments:
                                       
Commodity contracts
  Derivative financial instruments   $ 4.5     $ 2.8                      
 
                               
 
                                       
Total Derivatives
      $ 15.7     $ 20.6         $ (33.5 )   $ (60.0 )
 
                               
The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2011 and 2010:
Three Months Ended June 30,:
                                     
    Gain (Loss)     Gain (Loss)     Location of
    Recognized in     Reclassified from     Gain (Loss)
    AOCI and     AOCI and Noncontrolling     Reclassified from
    Noncontrolling Interests     Interests into Income     AOCI and Noncontrolling
    2011     2010     2011     2010     Interests into Income
 
                                   
Cash Flow
                                   
Hedges:
                                   
Commodity contracts
  $ (1.4 )   $ (14.6 )   $ 3.9     $ (7.7 )   Cost of sales
Foreign currency contracts
    (1.9 )     5.3             0.1     Cost of sales
Interest rate contracts
    (13.2 )     (6.3 )     (2.4 )     (3.9 )   Interest expense / other income
 
                           
Total
  $ (16.5 )   $ (15.6 )   $ 1.5     $ (11.5 )    
 
                           
 
                                   
Net Investment
                                   
Hedges:
                                   
 
                                   
Foreign currency contracts
  $ (0.5 )   $ 6.1                      
 
                               
 
                                   
    Gain (Loss)                      
    Recognized in Income                     Location of Gain (Loss)
 
  2011     2010                     Recognized in Income
Derivatives Not Designated as Hedging Instruments:
                                   
Commodity contracts
  $     $ (0.1 )                   Operating expenses / other income
Commodity contracts
    0.2       1.0                     Cost of sales
 
                               
Total
  $ 0.2     $ 0.9                      
 
                               
Nine Months Ended June 30,:
                                         
    Gain (Loss)     Gain (Loss)     Location of
    Recognized in     Reclassified from     Gain (Loss)
    AOCI and     AOCI and Noncontrolling     Reclassified from
    Noncontrolling Interests     Interests into Income     AOCI and Noncontrolling
    2011     2010     2011     2010     Interests into Income
 
                                       
Cash Flow
                                       
Hedges:
                                       
Commodity contracts
  $ 25.4     $ (30.1 )   $ (19.1 )   $ (14.1 )   Cost of sales
Foreign currency contracts
    (3.4 )     12.2       (0.7 )     0.7     Cost of sales
Interest rate contracts
    11.6       (7.2 )     (9.6 )     (24.4 )   Interest expense /other income
 
                               
Total
  $ 33.6     $ (25.1 )   $ (29.4 )   $ (37.8 )        
 
                               
 
                                       
Net Investment
                                       
Hedges:
                                       
 
                                       
Foreign currency contracts
  $ (1.1 )   $ 11.2                          
 
                                   
 
                                       
 
  Gain (Loss)                      
 
  Recognized in Income                     Location of Gain (Loss)
 
  2011     2010                     Recognized in Income
Derivatives Not Designated as Hedging Instruments:
                                       
Commodity contracts
  $ 0.3     $ 0.1                     Operating expenses / other income
Commodity contracts
    (0.4 )     1.4                     Cost of sales
 
                                   
Total
  $ (0.1 )   $ 1.5                          
 
                                   
The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine months ended June 30, 2011 and 2010.
We are also a party to a number of other 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 purchases and normal sales 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.
Inventories
Inventories
14.  
Inventories
Inventories comprise the following:
                         
    June 30,     September 30,     June 30,  
    2011     2010     2010  
Non-utility LPG and natural gas
  $ 170.5     $ 157.9     $ 145.6  
Gas Utility natural gas
    50.1       111.5       60.3  
Materials, supplies and other
    51.0       44.6       43.3  
 
                 
Total inventories
  $ 271.6     $ 314.0     $ 249.2  
 
                 
At June 30, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor 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 represents 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 values of natural gas storage inventories released under SCAAs with non-affiliates at June 30, 2011, September 30, 2010 and June 30, 2010 comprising 2.0 billion cubic feet (“bcf”), 8.0 bcf and 4.2 bcf of natural gas was $9.6, $41.9 and $23.2, respectively.
Subsequent Event - AmeriGas Refinancing
Subsequent Event - AmeriGas Refinancing
15.  
Subsequent Event — AmeriGas Refinancing
On July 27, 2011, AmeriGas Partners announced an offer to purchase for cash any and all of its $350 aggregate principal amount of outstanding 7 1/8% Senior Notes (“the 2016 Notes”) due May 2016 (the “Tender Offer”), subject to receipt of the proceeds of the issuance of $450 of 6.25% Senior Notes due 2019 (the “6.25% Notes”). The 6.25% Notes are expected to be issued on August 10, 2011. The proceeds from the offering will be used to finance the Tender Offer and for general corporate purposes, including to repay borrowings outstanding under the AmeriGas 2011 Credit Agreement. The Partnership intends to redeem any 2016 Notes that are not tendered in the Tender Offer. The Partnership expects to record a loss of approximately $20.0 associated with these transactions during the fourth quarter of Fiscal 2011 which is expected to reduce net income attributable to UGI Corporation by approximately $6.0.
Significant Accounting Policies (Policies)
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Denominator (thousands of shares):
                               
Average common shares outstanding for basic computation
    112,020       109,683       111,515       109,331  
Incremental shares issuable for stock options and awards
          1,016       1,531       857  
 
                       
Average common shares outstanding for diluted computation
    112,020       110,699       113,046       110,188  
 
                       
Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2011 and 2010:
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Net (loss) income
  $ (13.5 )   $ (4.2 )   $ 357.1     $ 374.1  
Other comprehensive (loss) income
    (0.5 )     (58.2 )     76.5       (84.4 )
 
                       
Comprehensive (loss) income (including noncontrolling interests)
    (14.0 )     (62.4 )     433.6       289.7  
Less: comprehensive income (loss) attributable to noncontrolling interests
    10.8       21.4       (100.6 )     (107.7 )
 
                       
Comprehensive (loss) income attributable to UGI Corporation
  $ (3.2 )   $ (41.0 )   $ 333.0     $ 182.0  
 
                       
Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, 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.
Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.
Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
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, 2010 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). 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.
Adoption of New Accounting Standard
Transfers of Financial Assets. Effective October 1, 2010, the Company adopted 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 adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.
New Accounting Standards Not Yet Adopted
Fair Value Measurements. In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.
Significant Accounting Policies (Tables)
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Denominator (thousands of shares):
                               
Average common shares outstanding for basic computation
    112,020       109,683       111,515       109,331  
Incremental shares issuable for stock options and awards
          1,016       1,531       857  
 
                       
Average common shares outstanding for diluted computation
    112,020       110,699       113,046       110,188  
 
                       
                                 
    Three Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Net (loss) income
  $ (13.5 )   $ (4.2 )   $ 357.1     $ 374.1  
Other comprehensive (loss) income
    (0.5 )     (58.2 )     76.5       (84.4 )
 
                       
Comprehensive (loss) income (including noncontrolling interests)
    (14.0 )     (62.4 )     433.6       289.7  
Less: comprehensive income (loss) attributable to noncontrolling interests
    10.8       21.4       (100.6 )     (107.7 )
 
                       
Comprehensive (loss) income attributable to UGI Corporation
  $ (3.2 )   $ (41.0 )   $ 333.0     $ 182.0  
 
                       
Intangible Assets (Tables)
Component of company's intangible assets
                         
    June 30,     September 30,     June 30,  
    2011     2010     2010  
Goodwill (not subject to amortization)
  $ 1,612.0     $ 1,562.7     $ 1,475.9  
 
                 
 
                       
Other intangible assets:
                       
Customer relationships, noncompete agreements and other
  $ 240.6     $ 215.4     $ 202.9  
Trademarks (not subject to amortization)
    51.9       46.3       41.5  
 
                 
Gross carrying amount
    292.5       261.7       244.4  
Accumulated amortization
    (133.0 )     (111.6 )     (106.3 )
 
                 
Net carrying amount
  $ 159.5     $ 150.1     $ 138.1  
 
                 
Segment Information (Tables)
Segment Information
Three Months Ended June 30, 2011:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 1,105.4     $ (40.0 ) (c)   $ 470.8     $ 148.1     $ 24.1     $ 217.1     $ 161.0     $ 102.3     $ 22.0  
 
                                                                       
Cost of sales
  $ 731.0     $ (39.1 ) (c)   $ 300.8     $ 78.8     $ 14.6     $ 193.1     $ 95.3     $ 74.6     $ 12.9  
 
                                                                       
Segment profit:
                                                                       
Operating income (loss)
  $ 17.2     $     $ 6.7     $ 17.2     $ 2.4     $ 8.4     $ (11.4 )   $ (3.6 )   $ (2.5 )
Loss from equity investees
    (0.2 )                                   (0.2 )            
Interest expense
    (35.0 )           (15.7 )     (9.9 )     (0.7 )     (0.6 )     (7.1 )     (0.8 )     (0.2 )
 
                                                     
(Loss) income before income taxes
  $ (18.0 )   $     $ (9.0 )   $ 7.3     $ 1.7     $ 7.8     $ (18.7 )   $ (4.4 )   $ (2.7 )
 
                                                     
 
                                                                       
Partnership EBITDA (a)
                  $ 31.1                                                  
Noncontrolling interests’ net loss
  $ (6.3 )   $     $ (6.1 )   $     $     $     $ (0.2 )   $     $  
Depreciation and amortization
  $ 57.8     $     $ 24.5     $ 11.6     $ 1.1     $ 1.8     $ 13.5     $ 4.7     $ 0.6  
 
                                                                       
Capital expenditures
  $ 78.5     $     $ 18.6     $ 20.9     $ 1.0     $ 18.7     $ 12.0     $ 6.6     $ 0.7  
 
                                                                       
Total assets (at period end)
  $ 6,673.7     $ (81.0 )   $ 1,772.1     $ 2,002.0     $ 156.5     $ 572.2     $ 1,678.2     $ 407.3     $ 166.4  
 
                                                                       
Bank loans (at period end)
  $ 206.1     $     $ 176.0     $     $     $     $     $ 30.1     $  
 
Goodwill (at period end)
  $ 1,612.0     $     $ 695.8     $ 180.1     $     $ 2.8     $ 641.1     $ 85.3     $ 6.9  
Three Months Ended June 30, 2010:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 961.9     $ (22.2 ) (c)   $ 396.6     $ 149.1     $ 25.3     $ 198.6     $ 150.8     $ 41.0     $ 22.7  
 
                                                                       
Cost of sales
  $ 615.5     $ (20.7 ) (c)   $ 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 (a)
                  $ 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  
(a)  
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
                 
Three months ended June 30,   2011     2010  
 
Partnership EBITDA
  $ 31.1     $ 27.2  
Depreciation and amortization
    (24.5 )     (21.8 )
Noncontrolling interest (i)
    0.1       (0.1 )
 
           
Operating income
  $ 6.7     $ 5.3  
 
           
(i)  
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
 
(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)  
Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Nine Months Ended June 30, 2011:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 5,052.0     $ (172.9 ) (c)   $ 2,077.8     $ 921.7     $ 84.7     $ 857.0     $ 889.7     $ 332.4     $ 61.6  
 
                                                                       
Cost of sales
  $ 3,317.5     $ (170.3 ) (c)   $ 1,300.9     $ 562.3     $ 53.4     $ 738.6     $ 554.0     $ 243.8     $ 34.8  
 
                                                                       
Segment profit:
                                                                       
Operating income (loss)
  $ 626.5     $ 0.2     $ 252.9     $ 193.2     $ 9.0     $ 76.7     $ 101.0     $ (0.2 )   $ (6.3 )
Loss from equity investees
    (0.8 )                                   (0.8 )            
Loss on extinguishment of debt
    (18.8 )           (18.8 )                                    
Interest expense
    (102.6 )           (47.4 )     (30.2 )     (1.8 )     (2.0 )     (18.5 )     (2.1 )     (0.6 )
 
                                                     
Income (loss) before income taxes
  $ 504.3     $ 0.2     $ 186.7     $ 163.0     $ 7.2     $ 74.7     $ 81.7     $ (2.3 )   $ (6.9 )
 
                                                     
 
                                                                       
Partnership EBITDA (a)
                  $ 301.9                                                  
Noncontrolling interests’ net income
  $ 101.8     $     $ 101.2     $     $     $     $ 0.6     $     $  
Depreciation and amortization
  $ 168.6     $     $ 70.4     $ 36.1     $ 3.1     $ 5.4     $ 38.4     $ 13.7     $ 1.5  
 
                                                                       
Capital expenditures
  $ 246.1     $     $ 59.2     $ 54.5     $ 5.1     $ 81.5     $ 31.8     $ 12.6     $ 1.4  
 
                                                                       
Total assets (at period end)
  $ 6,673.7     $ (81.0 )   $ 1,772.1     $ 2,002.0     $ 156.5     $ 572.2     $ 1,678.2     $ 407.3     $ 166.4  
 
                                                                       
Bank loans (at period end)
  $ 206.1     $     $ 176.0     $     $     $     $     $ 30.1     $  
 
                                                                       
Goodwill (at period end)
  $ 1,612.0     $     $ 695.8     $ 180.1     $     $ 2.8     $ 641.1     $ 85.3     $ 6.9  
Nine Months Ended June 30, 2010:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Energy             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Services     Antargaz     Other     & Other (b)  
Revenues
  $ 4,701.0     $ (146.9 ) (c)   $ 1,939.3     $ 922.3     $ 90.9     $ 949.5     $ 755.3     $ 129.8     $ 60.8  
 
                                                                       
Cost of sales
  $ 3,009.2     $ (142.3 ) (c)   $ 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 (a)
                  $ 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  
(a)  
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
                 
Nine months ended June 30,   2011     2010  
 
Partnership EBITDA
  $ 301.9 (ii)   $ 323.7 (iii)
Depreciation and amortization
    (70.4 )     (65.0 )
Loss on extinguishment of debt
    18.8        
Noncontrolling interest (i)
    2.6       2.5  
 
           
Operating income
  $ 252.9     $ 261.2  
 
           
(i)  
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
 
(ii)  
Includes $18.8 loss associated with the extinguishment of Partnership debt.
 
(iii)  
Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
 
(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)  
Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)
Regulatory assets and liabilities associated with Gas Utility and Electric Utility
                         
    June 30,     September 30,     June 30,  
    2011     2010     2010  
Regulatory assets:
                       
Income taxes recoverable
  $ 92.7     $ 82.5     $ 95.3  
Underfunded pension and postretirement plans
    116.0       159.2       10.3  
Environmental costs
    20.7       22.6       24.3  
Deferred fuel and power costs
    7.8       36.6       6.3  
Other
    8.9       5.8       5.5  
 
                 
Total regulatory assets
  $ 246.1     $ 306.7     $ 141.7  
 
                 
 
                       
Regulatory liabilities:
                       
Postretirement benefits
  $ 11.6     $ 10.5     $ 10.3  
Environmental overcollections
    6.2       7.2       8.3  
Deferred fuel and power refunds
    22.4       8.3       16.6  
State tax benefits — distribution system repairs
    6.2       6.7       11.0  
 
                 
Total regulatory liabilities
  $ 46.4     $ 32.7     $ 46.2  
 
                 
Defined Benefit Pension and Other Postretirement Plans (Tables)
                                 
                    Other  
    Pension Benefits     Postretirement Benefits  
    Three Months Ended     Three Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Service cost
  $ 2.1     $ 2.2     $ 0.1     $ 0.1  
Interest cost
    6.1       5.8       0.3       0.3  
Expected return on assets
    (6.4 )     (6.5 )     (0.1 )     (0.1 )
Amortization of:
                               
Prior service cost (benefit)
    0.1             (0.2 )     (0.1 )
Actuarial loss
    1.7       1.5       0.1       0.1  
 
                       
Net benefit cost
    3.6       3.0       0.2       0.3  
Change in associated regulatory liabilities
                0.8       0.7  
 
                       
Net expense
  $ 3.6     $ 3.0     $ 1.0     $ 1.0  
 
                       
                                 
                    Other  
    Pension Benefits     Postretirement Benefits  
    Nine Months Ended     Nine Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Service cost
  $ 6.6     $ 6.5     $ 0.4     $ 0.3  
Interest cost
    18.1       17.6       0.8       0.9  
Expected return on assets
    (19.4 )     (19.4 )     (0.4 )     (0.3 )
Amortization of:
                               
Prior service cost (benefit)
    0.2             (0.5 )     (0.3 )
Actuarial loss
    5.7       4.4       0.3       0.2  
 
                       
Net benefit cost
    11.2       9.1       0.6       0.8  
Change in associated regulatory liabilities
                2.4       2.2  
 
                       
Net expense
  $ 11.2     $ 9.1     $ 3.0     $ 3.0  
 
                       
         
    Three Months  
    Ended  
    December 31,  
    2010  
Change in benefit obligations:
       
Benefit obligations — October 1, 2010
  $ 465.0  
Service cost
    2.2  
Interest cost
    5.8  
Actuarial gain
    (30.6 )
Benefits paid
    (4.7 )
 
     
Benefit obligations — December 31, 2010
  $ 437.7  
 
     
 
       
Change in plan assets:
       
Fair value of plan assets — October 1, 2010
  $ 287.9  
Actual gain on assets
    19.3  
Employer contributions
    1.8  
Benefits paid
    (4.7 )
 
     
Fair value of plan assets — December 31, 2010
  $ 304.3  
 
     
 
       
Funded status of the merged plan — December 31, 2010
  $ (133.4 )
 
     
At December 31, 2010:
       
Liabilities recorded in the balance sheet:
       
Unfunded liabilities — included in other current liabilities
  $ (20.3 )
Unfunded liabilities — included in other noncurrent liabilities
    (113.1 )
 
     
Net amount recognized
  $ (133.4 )
 
     
Amounts recorded in regulatory assets and liabilities:
       
Prior service cost
  $ 0.3  
Net actuarial loss
    112.7  
 
     
Total
  $ 113.0  
 
     
Amounts recorded in stockholders’ equity:
       
Prior service cost
  $ 0.1  
Net actuarial loss
    9.8  
 
     
Total
  $ 9.9  
 
     
Equity (Tables)
Changes in UGI's equity and the equity of the noncontrolling interests
                                                 
            UGI Shareholders        
                            Accumulated              
                            Other              
    Non-                     Comprehensive              
    controlling     Common     Retained     Income     Treasury     Total  
    Interests     Stock     Earnings     (Loss)     Stock     Equity  
 
                                               
Nine Months Ended June 30, 2011:
                                               
Balance September 30, 2010
  $ 237.1     $ 906.1     $ 966.7     $ (10.1 )   $ (38.2 )   $ 2,061.6  
Net income
    101.8               255.3                       357.1  
Net gains on derivative instruments
    14.8                       10.8               25.6  
Reclassifications of net (gains) losses on derivative instruments
    (16.0 )                     27.0               11.0  
Benefit plans
                            2.1               2.1  
Foreign currency translation adjustments
                            37.8               37.8  
 
                                       
Comprehensive income
    100.6               255.3       77.7               433.6  
Dividends and distributions
    (69.7 )             (84.7 )                     (154.4 )
Equity transactions
    0.5       28.8                       9.6       38.9  
Other
    1.2                                       1.2  
 
                                   
Balance June 30, 2011
  $ 269.7     $ 934.9     $ 1,137.3     $ 67.6     $ (28.6 )   $ 2,380.9  
 
                                   
 
                                               
Nine Months Ended June 30, 2010:
                                               
Balance September 30, 2009
  $ 225.4     $ 875.6     $ 804.3     $ (38.9 )   $ (49.6 )   $ 1,816.8  
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 )
Equity transactions
    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  
 
                                   
Fair Value Measurement [Tables]
Financial assets and financial liabilities that are measured at fair value on a recurring basis
                                 
    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, 2011:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 0.6     $ 10.1     $     $ 10.7  
Interest rate contracts
  $     $ 5.0     $     $ 5.0  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (12.2 )   $ (11.6 )   $     $ (23.8 )
Foreign currency contracts
  $     $ (6.1 )   $     $ (6.1 )
Interest rate contracts
  $     $ (3.6 )   $     $ (3.6 )
 
                               
September 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 1.1     $ 10.7     $     $ 11.8  
Foreign currency contracts
  $     $ 0.8     $     $ 0.8  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (49.4 )   $ (20.3 )   $     $ (69.7 )
Foreign currency contracts
  $     $ (2.9 )   $     $ (2.9 )
Interest rate contracts
  $     $ (18.5 )   $     $ (18.5 )
 
                               
June 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 0.4     $ 3.2     $     $ 3.6  
Foreign currency contracts
  $     $ 16.9     $     $ 16.9  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (25.4 )   $ (18.1 )   $     $ (43.5 )
Interest rate contracts
  $     $ (16.4 )   $     $ (16.4 )
Disclosures About Derivative Instruments and Hedging Activities (Tables)
                 
    Volumes  
    June 30,  
Commodity   2011     2010  
 
               
LPG (millions of gallons)
    145.0       150.5  
Natural gas (millions of dekatherms)
    21.2       33.3  
Electricity (millions of kilowatt-hours)
    1,200.8       928.0  
                                         
    Derivative Assets     Derivative (Liabilities)  
        Fair Value         Fair Value  
    Balance Sheet   June 30,     Balance Sheet   June 30,  
    Location   2011     2010     Location   2011     2010  
Derivatives Designated as
Hedging Instruments:
                                       
 
                                       
Commodity contracts
  Derivative financial instruments and Other assets   $ 6.0     $ 0.3     Derivative financial instruments and Other noncurrent liabilities   $ (12.6 )   $ (42.8 )
Foreign currency contracts
                                       
 
  Derivative financial instruments and Other assets           16.9     Derivative financial instruments and Other noncurrent liabilities     (6.1 )      
Interest rate contracts
                                       
 
  Other assets     5.0           Derivative financial instruments and Other noncurrent liabilities     (3.6 )     (16.4 )
 
                               
Total Derivatives Designated
as Hedging Instruments
      $ 11.0     $ 17.2         $ (22.3 )   $ (59.2 )
 
                               
 
                                       
Derivatives Accounted for
under ASC 980:
                                       
Commodity contracts
  Derivative financial instruments   $ 0.2     $ 0.6     Derivative financial instruments and Other noncurrent liabilities   $ (11.2 )   $ (0.8 )
 
                                       
Derivatives Not Designated as
Hedging Instruments:
                                       
Commodity contracts
  Derivative financial instruments   $ 4.5     $ 2.8                      
 
                               
 
                                       
Total Derivatives
      $ 15.7     $ 20.6         $ (33.5 )   $ (60.0 )
 
                               
                                     
    Gain (Loss)     Gain (Loss)     Location of
    Recognized in     Reclassified from     Gain (Loss)
    AOCI and     AOCI and Noncontrolling     Reclassified from
    Noncontrolling Interests     Interests into Income     AOCI and Noncontrolling
    2011     2010     2011     2010     Interests into Income
 
                                   
Cash Flow
                                   
Hedges:
                                   
Commodity contracts
  $ (1.4 )   $ (14.6 )   $ 3.9     $ (7.7 )   Cost of sales
Foreign currency contracts
    (1.9 )     5.3             0.1     Cost of sales
Interest rate contracts
    (13.2 )     (6.3 )     (2.4 )     (3.9 )   Interest expense / other income
 
                           
Total
  $ (16.5 )   $ (15.6 )   $ 1.5     $ (11.5 )    
 
                           
 
                                   
Net Investment
                                   
Hedges:
                                   
 
                                   
Foreign currency contracts
  $ (0.5 )   $ 6.1                      
 
                               
 
                                   
    Gain (Loss)                      
    Recognized in Income                     Location of Gain (Loss)
 
  2011     2010                     Recognized in Income
Derivatives Not Designated as Hedging Instruments:
                                   
Commodity contracts
  $     $ (0.1 )                   Operating expenses / other income
Commodity contracts
    0.2       1.0                     Cost of sales
 
                               
Total
  $ 0.2     $ 0.9                      
 
                               
Nine Months Ended June 30,:
                                         
    Gain (Loss)     Gain (Loss)     Location of
    Recognized in     Reclassified from     Gain (Loss)
    AOCI and     AOCI and Noncontrolling     Reclassified from
    Noncontrolling Interests     Interests into Income     AOCI and Noncontrolling
    2011     2010     2011     2010     Interests into Income
 
                                       
Cash Flow
                                       
Hedges:
                                       
Commodity contracts
  $ 25.4     $ (30.1 )   $ (19.1 )   $ (14.1 )   Cost of sales
Foreign currency contracts
    (3.4 )     12.2       (0.7 )     0.7     Cost of sales
Interest rate contracts
    11.6       (7.2 )     (9.6 )     (24.4 )   Interest expense /other income
 
                               
Total
  $ 33.6     $ (25.1 )   $ (29.4 )   $ (37.8 )        
 
                               
 
                                       
Net Investment
                                       
Hedges:
                                       
 
                                       
Foreign currency contracts
  $ (1.1 )   $ 11.2                          
 
                                   
 
                                       
 
  Gain (Loss)                      
 
  Recognized in Income                     Location of Gain (Loss)
 
  2011     2010                     Recognized in Income
Derivatives Not Designated as Hedging Instruments:
                                       
Commodity contracts
  $ 0.3     $ 0.1                     Operating expenses / other income
Commodity contracts
    (0.4 )     1.4                     Cost of sales
 
                                   
Total
  $ (0.1 )   $ 1.5                          
 
                                   
Inventories (Tables)
Inventories
                         
    June 30,     September 30,     June 30,  
    2011     2010     2010  
Non-utility LPG and natural gas
  $ 170.5     $ 157.9     $ 145.6  
Gas Utility natural gas
    50.1       111.5       60.3  
Materials, supplies and other
    51.0       44.6       43.3  
 
                 
Total inventories
  $ 271.6     $ 314.0     $ 249.2  
 
                 
Nature of Operations (Details)
Jun. 30, 2011
Nature Of Operations (Textuals) [Abstract]
 
General Partner held a general partner interest in AmeriGas Partners
1.00% 
Percentage of our limited partnership interest in AmeriGas Partners
42.80% 
Effective ownership interest in AmeriGas OLP
44.40% 
Limited partnership Common Units Held in AmeriGas Partners
24,691,209 
General public as limited partner interests in AmeriGas Partners
56.20% 
Common Units held by the general public as limited partner interests
32,433,087 
Significant Accounting Policies (Details)
In Thousands
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Denominator (thousands of shares):
 
 
 
 
Average common shares outstanding for basic computation
112,020 
109,683 
111,515 
109,331 
Incremental shares issuable for stock options and awards
1,016 
1,531 
857 
Average common shares outstanding for diluted computation
112,020 
110,699 
113,046 
110,188 
Significant Accounting Policies (Details 1) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Components of comprehensive income (loss)
 
 
 
 
Net (loss) income
$ (13.5)
$ (4.2)
$ 357.1 
$ 374.1 
Other comprehensive (loss) income
(0.5)
(58.2)
76.5 
(84.4)
Comprehensive (loss) income (including noncontrolling interests)
(14.0)
(62.4)
433.6 
289.7 
Less: comprehensive income (loss) attributable to noncontrolling interests
10.8 
21.4 
(100.6)
(107.7)
Comprehensive (loss) income attributable to UGI Corporation
$ (3.2)
$ (41.0)
$ 333.0 
$ 182.0 
Significant Accounting Policies (Details Textuals) (USD $)
In Millions
9 Months Ended
Jun. 30, 2011
Significant Accounting Policies (Textuals) [Abstract]
 
Other comprehensive income including associated after-tax charge
$ 2.1 
Intangible Assets (Details) (USD $)
In Millions
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
Intangible Assets [Abstract]
 
 
 
Goodwill (not subject to amortization)
$ 1,612.0 
$ 1,562.7 
$ 1,475.9 
Other intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
240.6 
215.4 
202.9 
Trademark (not subject to amortization)
51.9 
46.3 
41.5 
Gross carrying amount
292.5 
261.7 
244.4 
Accumulated amortization
(133.0)
(111.6)
(106.3)
Net carrying amount
$ 159.5 
$ 150.1 
$ 138.1 
Intangible Assets (Details Textuals) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Component of Company's Intangible Assets (Textuals) [Abstract]
 
 
 
 
Amortization expense of intangible assets
$ 5.4 
$ 4.9 
$ 15.1 
$ 14.8 
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
 
 
 
 
Fiscal 2011
 
 
5.0 
 
Fiscal 2012
 
 
20.7 
 
Fiscal 2013
 
 
20.1 
 
Fiscal 2014
 
 
19.2 
 
Fiscal 2015
 
 
$ 16.2 
 
Segment Information (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Sep. 30, 2010
Segment Informations [Abstract]
 
 
 
 
 
Revenues
$ 1,105.4 
$ 961.9 
$ 5,052.0 
$ 4,701.0 
 
Cost of sales
731.0 
615.5 
3,317.5 
3,009.2 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
17.2 
31.2 
626.5 
640.4 
 
Loss from equity investees
(0.2)
(1.9)
(0.8)
(1.9)
 
Loss on extinguishment of debt
 
 
(18.8)
 
 
Interest expense
(35.0)
(33.6)
(102.6)
(101.9)
 
(Loss) income before income taxes
(18.0)
(4.3)
504.3 
536.6 
 
Noncontrolling interests' net loss
(6.3)
(7.6)
101.8 
115.2 
 
Depreciation and amortization
57.8 
51.7 
168.6 
157.3 
 
Capital expenditures
78.5 
83.1 
246.1 
229.4 
 
Total assets (at period end)
6,673.7 
5,831.6 
6,673.7 
5,831.6 
6,374.3 
Bank loans (at period end)
206.1 
35.2 
206.1 
35.2 
200.4 
Goodwill (at period end)
1,612.0 
1,475.9 
1,612.0 
1,475.9 
1,562.7 
Elims [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
(40.0)
(22.2)
(172.9)
(146.9)
 
Cost of sales
(39.1)
(20.7)
(170.3)
(142.3)
 
Segment profit:
 
 
 
 
 
Operating income (loss)
 
(0.4)
0.2 
(0.7)
 
(Loss) income before income taxes
 
(0.4)
0.2 
(0.7)
 
Noncontrolling interests' net loss
 
0.1 
 
0.1 
 
Depreciation and amortization
 
 
 
(0.1)
 
Total assets (at period end)
(81.0)
(69.3)
(81.0)
(69.3)
 
Goodwill (at period end)
 
(3.9)
 
(3.9)
 
AmeriGas Propane [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
470.8 
396.6 
2,077.8 
1,939.3 
 
Cost of sales
300.8 
235.8 
1,300.9 
1,165.1 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
6.7 
5.3 
252.9 
261.2 
 
Loss on extinguishment of debt
 
 
(18.8)
 
 
Interest expense
(15.7)
(17.0)
(47.4)
(50.2)
 
(Loss) income before income taxes
(9.0)
(11.7)
186.7 
211.0 
 
Partnership EBITDA
31.1 
27.2 
301.9 
323.7 
 
Noncontrolling interests' net loss
(6.1)
(7.5)
101.2 
114.5 
 
Depreciation and amortization
24.5 
21.8 
70.4 
65.0 
 
Capital expenditures
18.6 
14.4 
59.2 
59.8 
 
Total assets (at period end)
1,772.1 
1,658.4 
1,772.1 
1,658.4 
 
Bank loans (at period end)
176.0 
15.0 
176.0 
15.0 
 
Goodwill (at period end)
695.8 
674.8 
695.8 
674.8 
 
Gas Utility [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
148.1 
149.1 
921.7 
922.3 
 
Cost of sales
78.8 
83.0 
562.3 
584.2 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
17.2 
13.8 
193.2 
168.6 
 
Interest expense
(9.9)
(10.0)
(30.2)
(30.5)
 
(Loss) income before income taxes
7.3 
3.8 
163.0 
138.1 
 
Depreciation and amortization
11.6 
12.5 
36.1 
37.0 
 
Capital expenditures
20.9 
16.1 
54.5 
40.6 
 
Total assets (at period end)
2,002.0 
1,829.4 
2,002.0 
1,829.4 
 
Goodwill (at period end)
180.1 
180.1 
180.1 
180.1 
 
Electric Utility [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
24.1 
25.3 
84.7 
90.9 
 
Cost of sales
14.6 
15.8 
53.4 
58.0 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
2.4 
2.6 
9.0 
11.1 
 
Interest expense
(0.7)
(0.4)
(1.8)
(1.3)
 
(Loss) income before income taxes
1.7 
2.2 
7.2 
9.8 
 
Depreciation and amortization
1.1 
1.0 
3.1 
3.0 
 
Capital expenditures
1.0 
2.3 
5.1 
3.9 
 
Total assets (at period end)
156.5 
120.4 
156.5 
120.4 
 
Energy Services [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
217.1 
198.6 
857.0 
949.5 
 
Cost of sales
193.1 
177.3 
738.6 
830.9 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
8.4 
6.9 
76.7 
75.4 
 
Interest expense
(0.6)
 
(2.0)
 
 
(Loss) income before income taxes
7.8 
6.9 
74.7 
75.4 
 
Depreciation and amortization
1.8 
2.0 
5.4 
6.0 
 
Capital expenditures
18.7 
34.3 
81.5 
84.7 
 
Total assets (at period end)
572.2 
463.3 
572.2 
463.3 
 
Goodwill (at period end)
2.8 
11.8 
2.8 
11.8 
 
International Propane, Antargaz [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
161.0 
150.8 
889.7 
755.3 
 
Cost of sales
95.3 
81.9 
554.0 
394.4 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
(11.4)
4.3 
101.0 
123.4 
 
Loss from equity investees
(0.2)
(1.9)
(0.8)
(1.8)
 
Interest expense
(7.1)
(5.3)
(18.5)
(17.1)
 
(Loss) income before income taxes
(18.7)
(2.9)
81.7 
104.5 
 
Noncontrolling interests' net loss
(0.2)
(0.2)
0.6 
0.6 
 
Depreciation and amortization
13.5 
11.5 
38.4 
37.2 
 
Capital expenditures
12.0 
12.8 
31.8 
32.1 
 
Total assets (at period end)
1,678.2 
1,446.4 
1,678.2 
1,446.4 
 
Goodwill (at period end)
641.1 
540.6 
641.1 
540.6 
 
International Propane, Other [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
102.3 
41.0 
332.4 
129.8 
 
Cost of sales
74.6 
30.0 
243.8 
86.8 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
(3.6)
(1.4)
(0.2)
4.2 
 
Loss from equity investees
 
 
 
(0.1)
 
Interest expense
(0.8)
(0.7)
(2.1)
(2.3)
 
(Loss) income before income taxes
(4.4)
(2.1)
(2.3)
1.8 
 
Depreciation and amortization
4.7 
2.6 
13.7 
8.2 
 
Capital expenditures
6.6 
2.0 
12.6 
5.7 
 
Total assets (at period end)
407.3 
231.2 
407.3 
231.2 
 
Bank loans (at period end)
30.1 
20.2 
30.1 
20.2 
 
Goodwill (at period end)
85.3 
65.6 
85.3 
65.6 
 
Corporate And Other [Member]
 
 
 
 
 
Segment Informations [Abstract]
 
 
 
 
 
Revenues
22.0 
22.7 
61.6 
60.8 
 
Cost of sales
12.9 
12.4 
34.8 
32.1 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
(2.5)
0.1 
(6.3)
(2.8)
 
Interest expense
(0.2)
(0.2)
(0.6)
(0.5)
 
(Loss) income before income taxes
(2.7)
(0.1)
(6.9)
(3.3)
 
Depreciation and amortization
0.6 
0.3 
1.5 
1.0 
 
Capital expenditures
0.7 
1.2 
1.4 
2.6 
 
Total assets (at period end)
166.4 
151.8 
166.4 
151.8 
 
Goodwill (at period end)
$ 6.9 
$ 6.9 
$ 6.9 
$ 6.9 
 
Segment Information (Details 1) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Reconciliation of Partnership EBITDA
 
 
 
 
Depreciation and amortization
$ (57.8)
$ (51.7)
$ (168.6)
$ (157.3)
Loss on extinguishment of debt
 
 
18.8 
 
Operating income
17.2 
31.2 
626.5 
640.4 
AmeriGas Propane [Member]
 
 
 
 
Reconciliation of Partnership EBITDA
 
 
 
 
Partnership EBITDA
31.1 
27.2 
301.9 
323.7 
Depreciation and amortization
(24.5)
(21.8)
(70.4)
(65.0)
Loss on extinguishment of debt
 
 
18.8 
 
Noncontrolling interests
0.1 
(0.1)
2.6 
2.5 
Operating income
$ 6.7 
$ 5.3 
$ 252.9 
$ 261.2 
Segment Information (Details Textuals) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Jun. 30,
2011
2010
Segment Information (Textuals) [Abstract]
 
 
Loss on extinguishment of debt
$ 18.8 
 
AmeriGas Propane [Member]
 
 
Segment Information (Textuals) [Abstract]
 
 
General Partner's interest in AmeriGas OLP
1.01% 
 
Loss on extinguishment of debt
18.8 
 
Loss associated with the discontinuance of Partnership interest rate protection agreements
 
$ 12.2 
Energy Services Accounts Receivable Securitization Facility (Details) (USD $)
In Millions
9 Months Ended
Jun. 30,
2011
2010
Energy services accounts receivable securitization facility (Textuals) [Abstract]
 
 
Outstanding balance of trade receivables sold
$ 0 
 
Energy Services Accounts Receivable Securitization Facility Additional Textuals [Abstract]
 
 
Receivables facility
200 
 
Energy Services Funding Corporation [Member]
 
 
Energy services accounts receivable securitization facility (Textuals) [Abstract]
 
 
Sale of undivided interests in its trade receivables to the commercial paper conduit
68.0 
233.6 
Outstanding balance of trade receivables
50.9 
61.8 
Outstanding balance of trade receivables sold
 
Energy Services [Member]
 
 
Energy services accounts receivable securitization facility (Textuals) [Abstract]
 
 
Sale of trade receivables
$ 923.5 
$ 933.3 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
Regulatory Asset
 
 
 
Regulatory Assets
$ 246.1 
$ 306.7 
$ 141.7 
Regulatory Liability
 
 
 
Regulatory Liabilities
46.4 
32.7 
46.2 
Income taxes recoverable [Member]
 
 
 
Regulatory Asset
 
 
 
Regulatory Assets
92.7 
82.5 
95.3 
Underfunded pension and postretirement plans [Member]
 
 
 
Regulatory Asset
 
 
 
Regulatory Assets
116.0 
159.2 
10.3 
Environmental costs [Member]
 
 
 
Regulatory Asset
 
 
 
Regulatory Assets
20.7 
22.6 
24.3 
Deferred fuel and power costs [Member]
 
 
 
Regulatory Asset
 
 
 
Regulatory Assets
7.8 
36.6 
6.3 
Other [Member]
 
 
 
Regulatory Asset
 
 
 
Regulatory Assets
8.9 
5.8 
5.5 
Postretirement benefits [Member]
 
 
 
Regulatory Liability
 
 
 
Regulatory Liabilities
11.6 
10.5 
10.3 
Environmental overcollections [Member]
 
 
 
Regulatory Liability
 
 
 
Regulatory Liabilities
6.2 
7.2 
8.3 
Deferred fuel and power refunds [Member]
 
 
 
Regulatory Liability
 
 
 
Regulatory Liabilities
22.4 
8.3 
16.6 
State tax benefits - distribution system repairs [Member]
 
 
 
Regulatory Liability
 
 
 
Regulatory Liabilities
$ 6.2 
$ 6.7 
$ 11.0 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textuals) (USD $)
In Millions
3 Months Ended
Dec. 31, 2010
Jun. 30, 2011
Jun. 23, 2011
Mar. 31, 2011
Jan. 14, 2011
Sep. 30, 2010
Jun. 30, 2010
Utility regulatory assets and liabilities and regulatory matters [Textuals Abstract]
 
 
 
 
 
 
 
Gas utility unrealized losses on derivative financial instruments contracts
 
$ 1.1 
 
 
 
$ 1.4 
$ 0.6 
Decrease in regulatory assets on remeasurement of merged plan's assets and benefit obligations
43.1 
 
 
 
 
 
 
Fair values of electric utility's forward purchase power agreements
 
33.5 
 
 
 
 
60.0 
Net book value of storage facility assets
 
 
 
10.9 
 
 
 
Expected Increase in base operating revenues by CPG Base Rate Filing
 
 
 
 
16.5 
 
 
Increase in distribution rates, Base rate revenue
 
 
8.0 
 
 
 
 
Amount included in distribution rates for CPG'S Energy and Efficiency Conservation Program
 
 
0.9 
 
 
 
 
Electric Utility - Forward Contract [Member]
 
 
 
 
 
 
 
Utility regulatory assets and liabilities and regulatory matters [Textuals Abstract]
 
 
 
 
 
 
 
Fair values of electric utility's forward purchase power agreements
 
$ 10.1 
 
 
 
$ 19.7 
 
Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
3 Months Ended
Dec. 31, 2010
2011
Pension Benefit [Member]
2010
Pension Benefit [Member]
2011
Pension Benefit [Member]
2010
Pension Benefit [Member]
2011
Other Postretirement Benefits [Member]
2010
Other Postretirement Benefits [Member]
2011
Other Postretirement Benefits [Member]
2010
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs
 
 
 
 
 
 
 
 
 
Service cost
$ 2.2 
$ 2.1 
$ 2.2 
$ 6.6 
$ 6.5 
$ 0.1 
$ 0.1 
$ 0.4 
$ 0.3 
Interest cost
5.8 
6.1 
5.8 
18.1 
17.6 
0.3 
0.3 
0.8 
0.9 
Expected return on assets
 
(6.4)
(6.5)
(19.4)
(19.4)
(0.1)
(0.1)
(0.4)
(0.3)
Amortization of:
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1 
 
0.2 
 
(0.2)
(0.1)
(0.5)
(0.3)
Actuarial loss
 
1.7 
1.5 
5.7 
4.4 
0.1 
0.1 
0.3 
0.2 
Net benefit cost
 
3.6 
3.0 
11.2 
9.1 
0.2 
0.3 
0.6 
0.8 
Change in associated regulatory liabilities
 
 
 
 
 
0.8 
0.7 
2.4 
2.2 
Net expense
 
$ 3.6 
$ 3.0 
$ 11.2 
$ 9.1 
$ 1.0 
$ 1.0 
$ 3.0 
$ 3.0 
Defined Benefit Pension and Other Postretirement Plans (Details 1) (USD $)
In Millions
3 Months Ended
Dec. 31, 2010
Change in benefit obligations:
 
Benefit obligations - October 1,2010
$ 465.0 
Service cost
2.2 
Interest cost
5.8 
Actuarial gain
(30.6)
Benefits paid
(4.7)
Benefits obligations - December 31, 2010
437.7 
Change in plan assets:
 
Fair value of plan assets - October 1, 2010
287.9 
Actual gain on assets
19.3 
Employer contributions
1.8 
Benefits paid
(4.7)
Fair value of plan assets - December 31, 2010
304.3 
Funded status of the merged plan - December 31,2010
(133.4)
Liabilities recorded in the balance sheet:
 
Unfunded liabilities - included in other current liabilities
(20.3)
Unfunded liabilities - included in other noncurrent liabilities
(113.1)
Net amount recognized
(133.4)
Amounts Recorded In Regulatory Assets And Liabilities Pre Tax Abstract
 
Prior service cost
0.3 
Net actuarial loss
112.7 
Total
113.0 
Amounts recorded in stockholders' equity:
 
Prior service cost
0.1 
Net actuarial loss
9.8 
Total
$ 9.9 
Defined Benefit Pension and Other Postretirement Plans (Details Textuals) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
3 Months Ended
Dec. 31, 2010
1 Months Ended
Dec. 31, 2010
Pension Benefit [Member]
3 Months Ended
Dec. 31, 2010
Pension Benefit [Member]
9 Months Ended
Jun. 30, 2011
Pension Benefit [Member]
2011
Non-qualified Supplemental Executive Retirement Plan [Member]
2010
Non-qualified Supplemental Executive Retirement Plan [Member]
2011
Non-qualified Supplemental Executive Retirement Plan [Member]
2010
Non-qualified Supplemental Executive Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
 
 
 
 
Expected contribution to pensions plans in next twelve months
 
 
 
$ 16.0 
 
 
 
 
Pension and other postretirement plans pretax expense
 
 
 
 
0.9 
0.6 
2.2 
1.8 
Contribution to the Pension Plan
1.8 
 
 
16.7 
 
 
 
 
Decrease in other noncurrent liabilities on remeasurement of merged plan's assets and benefit obligations
 
46.7 
46.7 
 
 
 
 
 
Decrease in regulatory assets on remeasurement of merged plan's assets and benefit obligations
43.1 
 
43.1 
 
 
 
 
 
Increase in pre-tax other comprehensive income on remeasurement of merged plan's assets and benefit obligations
 
 
3.6 
 
 
 
 
 
Discount rate for the merged plan
 
5.50% 
5.50% 
 
 
 
 
 
Accumulated benefit obligation of the merged plan
 
$ 391.2 
$ 391.2 
 
 
 
 
 
Expected rate of return on plan assets
 
8.50% 
 
 
 
 
 
 
Rate of increase in salary levels
 
3.80% 
 
 
 
 
 
 
Debt (Details)
In Millions, unless otherwise specified
9 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
1 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
USD ($)
2011
AmeriGas 2011 Credit Agreement [Member]
USD ($)
Jun. 30, 2011
AmeriGas 2011 Credit Agreement [Member]
Letter of Credit [Member]
USD ($)
2011
AmeriGas 2011 Credit Agreement [Member]
Maximum [Member]
2011
AmeriGas 2011 Credit Agreement [Member]
Minimum [Member]
2011
Existing Revolving Credit Agreement [Member]
USD ($)
2011
Supplemented Credit Agreement Member]
USD ($)
2011
Antargaz 2011 Senior Facilities [Member]
EUR (€)
2011
Antargaz 2011 Senior Facilities [Member]
Variable-rate Term Loan [Member]
EUR (€)
Jun. 30, 2011
Antargaz 2011 Senior Facilities [Member]
Revolving Credit Facility [Member]
EUR (€)
2011
Antargaz 2011 Senior Facilities [Member]
Maximum [Member]
2011
Antargaz 2011 Senior Facilities [Member]
Minimum [Member]
2011
UGI Utilities 2011 Credit Agreement [Member]
May 25, 2011
UGI Utilities 2011 Credit Agreement [Member]
USD ($)
2011
UGI Utilities 2011 Credit Agreement [Member]
Maximum [Member]
2011
UGI Utilities 2011 Credit Agreement [Member]
Minimum [Member]
1 Months Ended
May 31, 2011
UGI Utilities existing revolving credit agreement [Member]
USD ($)
2011
Flaga multi-currency working capital facility [Member]
EUR (€)
2011
Flaga euro-denominated working capital facility [Member]
EUR (€)
2011
6.50% Senior Notes due 2021 [Member]
USD ($)
2011
8.875% Senior Notes due May 2011 [Member]
USD ($)
2011
7.25% Senior Notes [Member]
USD ($)
2011
AmeriGas Propane [Member]
USD ($)
Debt (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from issuance of senior notes
 
 
 
 
 
 
 
 
€ 380 
 
 
 
 
 
 
 
 
 
 
$ 470 
 
 
 
Repayment of Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14.6 
415.0 
 
Interest rate on notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.50% 
8.875% 
7.25% 
 
Loss on extinguishment of debt
18.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18.8 
Borrowing capacity under revolving credit agreement
 
325 
 
 
 
 
 
 
 
40 
 
 
 
300 
 
 
 
24 
12 
 
 
 
 
Debt compliance ratio
 
 
 
 
 
 
 
3.50 
 
 
 
 
0.65 
 
 
 
 
 
 
 
 
 
 
Revolving credit agreement sublimit for letters of credit
 
 
100 
 
 
 
 
 
 
 
 
 
 
100 
 
 
 
 
 
 
 
 
 
Borrowing capacity of credit agreement terminated
 
 
 
 
 
200 
75 
 
 
 
 
 
 
 
 
 
350 
 
 
 
 
 
 
Interest rate for credit agreement
 
base rate plus a margin or at a two-week, one-, two-, three-, or six-month Eurodollar Rate 
 
 
 
 
 
one-, two-, three- or six-month euribor, plus a margin. 
 
 
 
 
LIBOR and the banks’ prime rate, plus a margin 
 
 
 
 
 
 
 
 
 
 
Base rate for revolving credit agreement
 
higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Margin on credit agreement base rate borrowings
 
 
 
1.75% 
0.75% 
 
 
 
 
 
2.50% 
1.75% 
 
 
2.00% 
0.00% 
 
 
 
 
 
 
 
Margin on credit agreement Eurodollar rate borrowings
 
 
 
2.75% 
1.75% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit agreement facility fee rate
 
 
 
0.50% 
0.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturities under term loan, May 2014
 
 
 
 
 
 
 
 
38 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturities under term loan, May 2015
 
 
 
 
 
 
 
 
34.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturities under term loan, March 2016
 
 
 
 
 
 
 
 
307.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective underlying euribor rate of interest on term loan through September 2015
 
 
 
 
 
 
 
 
2.45% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective underlying euribor rate of interest on term loan after September 2015
 
 
 
 
 
 
 
 
3.71% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective interest rate on term loan
 
 
 
 
 
 
 
 
4.66% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments guaranteed by UGI
 
 
 
 
 
 
 
100 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Date of expiration extension
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 2011 
March 2012 
 
 
 
 
Reduction in net income attributable to UGI Corporation due to extinguishment loss
$ 5.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2010
Antargaz Competition Authority [Member]
Jun. 30, 2011
Environmental matters [Member]
Jun. 30, 2011
SCE&G [Member]
9 Months Ended
Jun. 30, 2011
KeySpan [Member]
Jun. 30, 2011
Northeast Companies [Member]
Commitments and Contingencies (Textuals) [Abstract]
 
 
 
 
 
Litigating claims relating to sites
 
 
 
 
Alleged percentage of liability for MGP site
 
 
25.00% 
 
 
Approximate remediation cost spent by claimant
 
 
$ 22.0 
$ 2.3 
 
Approximate third party claim paid by claimant
 
 
26 
 
 
Environmental Exit Cost Anticipated by Claimant
 
 
14 
11 
25 
Alleged percentage of responsibility for cost by claimant
 
 
 
50.00% 
 
Environmental Exit Cost Based on Third Party Estimate
 
 
 
10 
 
Additional Environment Exit Cost Based On Claimant Estimate
 
 
 
20 
 
Reversal of Competition Authority Matter Accrual
$ 9.4 
 
 
 
 
Equity (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
$ 2,061.6 
$ 1,816.8 
Net income
(13.5)
(4.2)
357.1 
374.1 
Net gains (losses) on derivative instruments
 
 
25.6 
(4.1)
Reclassifications of net losses (gains) on derivative instruments (net of taxes)
 
 
11.0 
16.5 
Benefit plans
 
 
2.1 
2.3 
Foreign currency translation adjustments
 
 
37.8 
(99.1)
Comprehensive (loss) income (including noncontrolling interests)
(14.0)
(62.4)
433.6 
289.7 
Dividends and distributions
 
 
(154.4)
(137.3)
Equity transactions
 
 
38.9 
28.4 
Other
 
 
1.2 
(3.6)
Ending Balance
2,380.9 
1,994.0 
2,380.9 
1,994.0 
Noncontrolling interests [Member]
 
 
 
 
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
237.1 
225.4 
Net income
 
 
101.8 
115.2 
Net gains (losses) on derivative instruments
 
 
14.8 
6.9 
Reclassifications of net losses (gains) on derivative instruments (net of taxes)
 
 
(16.0)
(14.4)
Comprehensive (loss) income (including noncontrolling interests)
 
 
100.6 
107.7 
Dividends and distributions
 
 
(69.7)
(66.2)
Equity transactions
 
 
0.5 
0.7 
Other
 
 
1.2 
(3.6)
Ending Balance
269.7 
264.0 
269.7 
264.0 
Common Stock [Member]
 
 
 
 
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
906.1 
875.6 
Equity transactions
 
 
28.8 
20.5 
Ending Balance
934.9 
896.1 
934.9 
896.1 
Retained earnings [Member]
 
 
 
 
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
966.7 
804.3 
Net income
 
 
255.3 
258.9 
Comprehensive (loss) income (including noncontrolling interests)
 
 
255.3 
258.9 
Dividends and distributions
 
 
(84.7)
(71.1)
Ending Balance
1,137.3 
992.1 
1,137.3 
992.1 
Accumulated other comprehensive income (loss) [Member]
 
 
 
 
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
(10.1)
(38.9)
Net gains (losses) on derivative instruments
 
 
10.8 
(11.0)
Reclassifications of net losses (gains) on derivative instruments (net of taxes)
 
 
27.0 
30.9 
Benefit plans
 
 
2.1 
2.3 
Foreign currency translation adjustments
 
 
37.8 
(99.1)
Comprehensive (loss) income (including noncontrolling interests)
 
 
77.7 
(76.9)
Ending Balance
67.6 
(115.8)
67.6 
(115.8)
Treasury stock [Member]
 
 
 
 
Changes in UGI's equity and the equity of the noncontrolling interests
 
 
 
 
Beginning Balance
 
 
(38.2)
(49.6)
Equity transactions
 
 
9.6 
7.2 
Ending Balance
$ (28.6)
$ (42.4)
$ (28.6)
$ (42.4)
Fair Value Measurement (Details) (Fair Value, Measurements, Recurring [Member], USD $)
In Millions
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
Fair Value Inputs Level-1 [Member] |
Commodity Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
$ 0.6 
$ 1.1 
$ 0.4 
Derivative financial instruments, liabilities
(12.2)
(49.4)
(25.4)
Fair Value Inputs Level-1 [Member] |
Foreign currency contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Fair Value Inputs Level-1 [Member] |
Interest Rate Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
 
 
Derivative financial instruments, liabilities
Fair Value Inputs Level-2 [Member] |
Commodity Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
10.1 
10.7 
3.2 
Derivative financial instruments, liabilities
(11.6)
(20.3)
(18.1)
Fair Value Inputs Level-2 [Member] |
Foreign currency contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
0.8 
16.9 
Derivative financial instruments, liabilities
(6.1)
(2.9)
Fair Value Inputs Level-2 [Member] |
Interest Rate Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
5.0 
 
 
Derivative financial instruments, liabilities
(3.6)
(18.5)
(16.4)
Fair Value, Inputs, Level 3 [Member] |
Commodity Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Fair Value, Inputs, Level 3 [Member] |
Foreign currency contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Fair Value, Inputs, Level 3 [Member] |
Interest Rate Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
 
 
Derivative financial instruments, liabilities
Commodity Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
10.7 
11.8 
3.6 
Derivative financial instruments, liabilities
(23.8)
(69.7)
(43.5)
Foreign currency contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
0.8 
16.9 
Derivative financial instruments, liabilities
(6.1)
(2.9)
Interest Rate Contracts [Member]
 
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
 
Derivative financial instruments, assets
5.0 
 
 
Derivative financial instruments, liabilities
$ (3.6)
$ (18.5)
$ (16.4)
Fair Value Measurement (Details Textuals) (USD $)
In Millions
Jun. 30, 2011
Jun. 30, 2010
Fair Value Measurement [Abstract]
 
 
Carrying value long-term debt
$ 2,078.0 
$ 2,029.7 
Estimated fair value of long-term debt
$ 2,170.4 
$ 2,122.7 
Disclosures About Derivative Instruments and Hedging Activities (Details)
Jun. 30, 2011
Gallons
Jun. 30, 2010
Gallons
LPG [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
145,000,000 
150,500,000 
Natural Gas [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
21,200,000 
33,300,000 
Electricity (millions of kilowatt-hours)
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
1,200,800,000 
928,000,000 
Disclosures About Derivative Instruments and Hedging Activities (Details 1) (USD $)
In Millions
Jun. 30, 2011
Jun. 30, 2010
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
$ 15.7 
$ 20.6 
Total Derivatives Liability
(33.5)
(60.0)
Commodity Contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments and Other Assets [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
6.0 
0.3 
Commodity Contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(12.6)
(42.8)
Foreign currency contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments and Other Assets [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
16.9 
Foreign currency contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments Other Noncurrent Liabilities [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(6.1)
Interest Rate Contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments and Other Assets [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
5.0 
Interest Rate Contracts [Member] |
Designated as Hedging Instrument [Member] |
Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(3.6)
(16.4)
Designated as Hedging Instrument [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
11.0 
17.2 
Total Derivatives Liability
(22.3)
(59.2)
Commodity Contracts [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Derivative Financial Instruments [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
4.5 
2.8 
Commodity Contracts [Member] |
Accounted For Under ASC 980 [Member] |
Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(11.2)
(0.8)
Commodity Contracts [Member] |
Accounted For Under ASC 980 [Member] |
Derivative Financial Instruments [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
$ 0.2 
$ 0.6 
Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $)
In Millions
3 Months Ended
Jun. 30,
9 Months Ended
Jun. 30,
2011
2010
2011
2010
Commodity Contracts [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Cost of Sales [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Gain or (Loss) Recognized in Income
$ 0.2 
$ 1.0 
$ (0.4)
$ 1.4 
Commodity Contracts [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Operating Expenses/Other Income [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Gain or (Loss) Recognized in Income
 
(0.1)
0.3 
0.1 
Derivatives Not Designated as Hedging Instruments [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Gain or (Loss) Recognized in Income
0.2 
0.9 
(0.1)
1.5 
Commodity Contracts [Member] |
Cash Flow Hedges [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(1.4)
(14.6)
25.4 
(30.1)
Commodity Contracts [Member] |
Cash Flow Hedges [Member] |
Cost of Sales [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
3.9 
(7.7)
(19.1)
(14.1)
Foreign currency contracts [Member] |
Cash Flow Hedges [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(1.9)
5.3 
(3.4)
12.2 
Foreign currency contracts [Member] |
Cash Flow Hedges [Member] |
Cost of Sales [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
 
0.1 
(0.7)
0.7 
Interest Rate Contracts [Member] |
Cash Flow Hedges [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(13.2)
(6.3)
11.6 
(7.2)
Interest Rate Contracts [Member] |
Cash Flow Hedges [Member] |
Interest Expense And Other Income
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
(2.4)
(3.9)
(9.6)
(24.4)
Cash Flow Hedges [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(16.5)
(15.6)
33.6 
(25.1)
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
1.5 
(11.5)
(29.4)
(37.8)
Foreign currency contracts [Member] |
Net Investment Hedges [Member]
 
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
$ (0.5)
$ 6.1 
$ (1.1)
$ 11.2 
Disclosures About Derivative Instruments and Hedging Activities (Details Textual)
In Millions, unless otherwise specified
9 Months Ended
Jun. 30, 2011
USD ($)
Sep. 30, 2010
USD ($)
Jun. 30, 2010
USD ($)
Jun. 30, 2011
Gas Utility [Member]
Dekatherm
Jun. 30, 2010
Gas Utility [Member]
Dekatherm
9 Months Ended
Jun. 30, 2010
AmeriGas Propane [Member]
USD ($)
Jun. 30, 2011
Electric Utility - Forward Contract [Member]
USD ($)
Kilowatt-hour
Sep. 30, 2010
Electric Utility - Forward Contract [Member]
USD ($)
Jun. 30, 2011
Midstream And Marketing's Natural Gas Member
Dekatherm
Jun. 30, 2011
Midstream And Marketing's Propane Storage [Member]
Gallons
Jun. 30, 2011
Electric transmission congestion - Electric Utility [Member]
Kilowatt-hour
Jun. 30, 2010
Electric transmission congestion - Electric Utility [Member]
Kilowatt-hour
Jun. 30, 2011
Electric transmission congestion (excluding Electric Utility) [Member]
Kilowatt-hour
Jun. 30, 2010
Electric transmission congestion (excluding Electric Utility) [Member]
Kilowatt-hour
Jun. 30, 2011
LPG [Member]
Gallons
Jun. 30, 2010
LPG [Member]
Gallons
Jun. 30, 2011
Natural Gas [Member]
Dekatherm
Jun. 30, 2010
Natural Gas [Member]
Dekatherm
Jun. 30, 2011
Electricity (millions of kilowatt-hours)
Kilowatt-hour
Jun. 30, 2010
Electricity (millions of kilowatt-hours)
Kilowatt-hour
9 Months Ended
Jun. 30, 2011
Antargaz [Member]
EUR (€)
Jun. 30, 2011
Net Investment Hedges [Member]
EUR (€)
Jun. 30, 2010
Net Investment Hedges [Member]
EUR (€)
Jun. 30, 2011
Interest Rate Swaps [Member]
EUR (€)
Jun. 30, 2010
Interest Rate Swaps [Member]
EUR (€)
9 Months Ended
Jun. 30, 2011
Foreign Currency [Member]
USD ($)
Jun. 30, 2010
Foreign Currency [Member]
USD ($)
9 Months Ended
Jun. 30, 2011
IRPAs [Member]
USD ($)
Mar. 31, 2010
IRPAs [Member]
USD ($)
Derivative (Textual) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (in units)
 
 
 
18,600,000 
11,300,000 
 
874,400,000 
 
2,300,000 
900,000 
287,300,000 
739,300,000 
1,955,200,000 
1,415,000,000 
145,000,000 
150,500,000 
21,200,000 
33,300,000 
1,200,800,000 
928,000,000 
 
 
 
 
 
 
 
 
 
Maximum length of time hedged in price risk cash flow hedges
 
 
 
16 months 
 
 
35 months 
 
 
 
 
 
11 months 
 
15 months 
 
30 months 
 
21 months 
 
 
 
 
 
 
32 months 
 
 
 
Maximum length of time hedged in price risk cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
March 2014 
 
 
 
 
 
 
 
Maximum period of hedging exposure to variability in cash flows associated with price risk, weighted average
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7 months 
 
9 months 
 
7 months 
 
 
 
 
 
 
12 months 
 
 
 
Underlying variable rate debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
€ 0 
€ 14.5 
€ 48.3 
€ 398.8 
€ 706.2 
$ 141.4 
$ 72.8 
$ 173.0 
 
Debt Instrument Maturity Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mar. 01, 2011 
 
 
 
 
 
 
 
 
Loss as a result of the discontinuance of cash flow hedge accounting
 
 
 
 
 
12.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12.2 
 
Minimum approximate range of estimated dollar-denominated purchases of LPG
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15.00% 
 
 
 
Maximum approximate range of estimated dollar-denominated purchases of LPG
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30.00% 
 
 
 
Long term debt not issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150 
Fair values of electric utility's forward purchase power agreements
33.5 
 
60.0 
 
 
 
10.1 
19.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disclosures About Derivative Instruments and Hedging Activities (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months
8.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months
1.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months
4.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash in brokerage accounts
$ 10.2 
$ 34.8 
$ 22.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission organization that movements of wholesale electricity in number of states
14 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inventories (Details) (USD $)
In Millions
Jun. 30, 2011
Sep. 30, 2010
Jun. 30, 2010
Inventories
 
 
 
Total inventories
$ 271.6 
$ 314.0 
$ 249.2 
Non-utility LPG and natural gas [Member]
 
 
 
Inventories
 
 
 
Total inventories
170.5 
157.9 
145.6 
Gas Utility natural gas [Member]
 
 
 
Inventories
 
 
 
Total inventories
50.1 
111.5 
60.3 
Materials, supplies and other [Member]
 
 
 
Inventories
 
 
 
Total inventories
$ 51.0 
$ 44.6 
$ 43.3 
Inventories (Details Textual) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2011
Billion-cubic-feet
Sep. 30, 2010
Billion-cubic-feet
Jun. 30, 2010
Billion-cubic-feet
Inventories (Textuals) [Abstract]
 
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)
2,000,000,000 
8,000,000,000 
4,200,000,000 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 9.6 
$ 41.9 
$ 23.2 
Subsequent Event - AmeriGas Refinancing (Details Textuals) (Refinancing of Debt [Member], USD $)
In Millions, unless otherwise specified
9 Months Ended
Jun. 30, 2011
Jul. 27, 2011
Subsequent Event [Line Items]
 
 
Subsequent event date
Jul. 27, 2011 
 
Expected Loss on extinguishment of debt
 
$ 20.0 
Expected reduction of net income
 
6.0 
7 1/8% Senior Notes Due 2016 [Member]
 
 
Subsequent Event [Line Items]
 
 
Aggregate prinicipal amount outstanding 7 1/8% senior notes
 
350.0 
Interest rate on notes
 
7.125% 
% Senior Notes Due 2019 [Member]
 
 
Subsequent Event [Line Items]
 
 
Proceeds of the issuance of senior notes due 2019
 
$ 450.0 
Interest rate on notes
 
6.25%