UGI CORP /PA/, 10-Q filed on 2/8/2013
Quarterly Report
Document and Entity Information
3 Months Ended
Dec. 31, 2012
Jan. 31, 2013
Entity Information [Line Items]
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
Entity Central Index Key
0000884614 
 
Document Type
10-Q 
 
Document Period End Date
Dec. 31, 2012 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q1 
 
Current Fiscal Year End Date
--09-30 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
113,177,890 
Condensed Consolidated Balance Sheets (unaudited) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Current assets:
 
 
 
Cash and cash equivalents
$ 348.1 
$ 319.9 
$ 229.0 
Restricted cash
6.9 
3.0 
22.3 
Accounts receivable (less allowances for doubtful accounts of $39.9, $36.1 and $38.4, respectively)
999.2 
632.6 
842.9 
Accrued utility revenues
59.0 
16.9 
53.8 
Inventories
378.5 
356.9 
390.7 
Deferred income taxes
57.6 
56.8 
66.5 
Utility regulatory assets
3.6 
6.5 
8.1 
Derivative financial instruments
9.3 
13.2 
13.4 
Prepaid expenses and other current assets
57.5 
98.7 
41.3 
Total current assets
1,919.7 
1,504.5 
1,668.0 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,359.1, $2,286.0 and $2,113.8, respectively)
4,270.8 
4,233.1 
3,273.8 
Goodwill
2,835.0 
2,818.3 
1,624.7 
Intangible assets, net
646.8 
658.2 
159.7 
Other assets
495.2 
495.6 
427.7 
Total assets
10,167.5 
9,709.7 
7,153.9 
Current liabilities:
 
 
 
Current maturities of long-term debt
164.4 
166.7 
46.8 
Bank loans
333.2 
165.1 
421.9 
Accounts payable
580.7 
411.3 
507.4 
Derivative financial instruments
88.1 
100.9 
77.1 
Other current liabilities
616.8 
643.0 
511.6 
Total current liabilities
1,783.2 
1,487.0 
1,564.8 
Long-term debt
3,358.4 
3,347.6 
2,115.7 
Deferred income taxes
946.1 
935.0 
693.6 
Deferred investment tax credits
4.5 
4.6 
4.9 
Other noncurrent liabilities
629.8 
616.7 
575.2 
Total liabilities
6,722.0 
6,390.9 
4,954.2 
Commitments and contingencies (note 11)
   
   
   
UGI Corporation stockholders' equity
 
 
 
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,623,094, 115,507,094 and 115,507,094 shares, respectively)
1,170.0 
1,157.7 
939.1 
Retained earnings
1,238.1 
1,166.1 
1,143.6 
Accumulated other comprehensive (loss) income
(43.7)
(62.0)
(61.8)
Treasury stock, at cost
(29.4)
(28.7)
(26.7)
Total UGI Corporation stockholders' equity
2,335.0 
2,233.1 
1,994.2 
Noncontrolling interests, principally in AmeriGas Partners
1,110.5 
1,085.7 
205.5 
Total equity
3,445.5 
3,318.8 
2,199.7 
Total liabilities and equity
$ 10,167.5 
$ 9,709.7 
$ 7,153.9 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Accounts receivable, allowances for doubtful accounts
$ 39.9 
$ 36.1 
$ 38.4 
Property, plant and equipment, accumulated depreciation and amortization
$ 2,359.1 
$ 2,286.0 
$ 2,113.8 
UGI Common Stock, without par value (in dollars per share)
   
   
   
UGI Common Stock, without par value, shares authorized (in shares)
300,000,000 
300,000,000 
300,000,000 
UGI Common Stock, without par value, shares issued (in shares)
115,644,794 
115,624,594 
115,507,094 
Condensed Consolidated Statements of Income (unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Revenues
$ 2,023.2 
$ 1,688.8 
Costs and expenses:
 
 
Cost of sales (excluding depreciation shown below)
1,218.8 
1,101.8 
Operating and administrative expenses
426.9 
342.4 
Utility taxes other than income taxes
4.3 
4.1 
Depreciation
71.8 
52.8 
Amortization
15.3 
7.5 
Other Operating Income (Expense), Net
(10.0)
(8.1)
Total costs and expenses
1,727.1 
1,500.5 
Operating income (loss)
296.1 
188.3 
Loss from equity investees
0 
(0.1)
Interest expense
(60.3)
(36.0)
Income before income taxes
235.8 
152.2 
Income taxes
(65.1)
(42.1)
Net income
170.7 
110.1 
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners
(68.1)
(23.1)
Net income attributable to UGI Corporation
$ 102.6 
$ 87.0 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
Basic (in dollars per share)
$ 0.91 
$ 0.78 
Diluted (in dollars per share)
$ 0.90 
$ 0.77 
Average common shares outstanding (thousands):
 
 
Basic (in shares)
113,136 
112,240 
Diluted (in shares)
114,490 
113,152 
Dividends declared per common share (in dollars per share)
$ 0.27 
$ 0.26 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Net income
$ 170.7 
$ 110.1 
Net (losses) gains on derivative instruments (net of tax of $4.3 and $23.1, respectively)
(9.3)
(41.3)
Reclassifications of net losses on derivative instruments (net of tax of $(6.6) and $(8.0), respectively)
(21.8)
(12.5)
Foreign currency adjustments (net of tax of $(4.0) and $6.5, respectively)
16.1 
(22.2)
Benefit plans (net of tax of $(0.2) and $(0.1), respectively
0.3 
0.1 
Other Comprehensive Income (Loss), Net of Tax
28.9 
(50.9)
Comprehensive income
199.6 
59.2 
Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners
(78.7)
(16.3)
Comprehensive income attributable to UGI Corporation
$ 120.9 
$ 42.9 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Tax on (loss) gain on derivative instruments
$ 4.3 
$ 23.1 
Tax on reclassifications on derivative instruments
(6.8)
(8.0)
Tax on foreign currency adjustments
(4.0)
6.5 
Tax on benefit plans
$ (0.2)
$ (0.1)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 170.7 
$ 110.1 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
87.1 
60.3 
Deferred income taxes, net
1.6 
(16.9)
Provision for uncollectible accounts
7.4 
5.9 
Net change in realized gains and losses deferred as cash flow hedges
1.9 
(14.1)
Other, net
(3.8)
8.1 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(408.1)
(283.7)
Inventories
(19.3)
(25.3)
Utility deferred fuel costs, net of changes in unsettled derivatives
4.8 
1.6 
Accounts payable
164.8 
63.7 
Other current assets
31.2 
23.3 
Other current liabilities
(7.2)
44.6 
Net cash provided by operating activities
31.1 
(22.4)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(91.3)
(87.4)
Acquisitions of businesses, net of cash acquired
0 
(152.8)
Decrease in restricted cash
(3.9)
(5.1)
Other
1.8 
1.9 
Net cash used by investing activities
(93.4)
(243.4)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends on UGI Common Stock
(30.6)
(29.2)
Distributions on AmeriGas Partners Common Units
(55.2)
(24.0)
Issuances of debt
0 
25.6 
Repayments of debt
(6.3)
(3.1)
Increase in bank loans
134.7 
265.0 
Receivables Facility net borrowings (repayments)
33.0 
18.9 
Issuances of UGI Common Stock
10.6 
3.1 
Other
1.3 
0.4 
Net cash provided (used) by financing activities
87.5 
256.7 
EFFECT OF EXCHANGE RATE CHANGES ON CASH
3.0 
(0.4)
Cash and cash equivalents increase
28.2 
(9.5)
Cash and cash equivalents:
 
 
End of period
348.1 
229.0 
Beginning of period
319.9 
238.5 
Increase
$ 28.2 
$ (9.5)
Statement of Changes in Equity (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Sep. 30, 2012
Sep. 30, 2011
Stockholders' Equity Attributable to Parent
$ 2,335.0 
$ 1,994.2 
$ 2,233.1 
 
Net losses on derivative instruments, net of tax
(9.3)
(41.3)
 
 
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax
(21.8)
(12.5)
 
 
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax
16.1 
(22.2)
 
 
Net Income Attributable to Parent
102.6 
87.0 
 
 
Stockholders' Equity Attributable to Noncontrolling Interest
1,110.5 
205.5 
1,085.7 
 
Net Income Attributable to Noncontrolling Interest
68.1 
23.1 
 
 
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest
3,445.5 
2,199.7 
3,318.8 
 
Common Stock Including Additional Paid in Capital [Member]
 
 
 
 
Stockholders' Equity Attributable to Parent
1,170.0 
939.1 
1,157.7 
937.4 
Common Stock issued in connection with employee and director plans, net of tax withheld
9.6 
1.5 
 
 
Stock Issued During Period, Value, Dividend Reinvestment Plan
0.5 
0.5 
 
 
Excess tax benefits realized on equity-based compensation
1.3 
0.2 
 
 
Stock-based compensation expense
0.9 
(0.5)
 
 
Retained Earnings [Member]
 
 
 
 
Stockholders' Equity Attributable to Parent
1,238.1 
1,143.6 
1,166.1 
1,085.8 
Net Income Attributable to Parent
102.6 
87.0 
 
 
Dividends, Common Stock, Cash
(30.6)
(29.2)
 
 
Accumulated Other Comprehensive Income (Loss) [Member]
 
 
 
 
Stockholders' Equity Attributable to Parent
(43.7)
(61.8)
(62.0)
(17.7)
Net losses on derivative instruments, net of tax
(7.4)
(33.5)
 
 
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax
9.3 
11.5 
 
 
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax
16.1 
(22.2)
 
 
Treasury Stock [Member]
 
 
 
 
Stockholders' Equity Attributable to Parent
(29.4)
(26.7)
(28.7)
(27.8)
Stock Issued During Period, Value, Other
7.2 
0.8 
 
 
Stock Repurchased During Period, Value
(8.1)
0 
 
 
Stock Issued During Period, Value, Dividend Reinvestment Plan
0.2 
0.3 
 
 
Parent [Member]
 
 
 
 
Stockholders' Equity Attributable to Parent
2,335.0 
1,994.2 
 
 
Noncontrolling Interest [Member]
 
 
 
 
Stockholders' Equity Attributable to Noncontrolling Interest
1,110.5 
205.5 
1,085.7 
213.4 
Net Income Attributable to Noncontrolling Interest
68.1 
23.1 
 
 
Net Gain Loss on Derivative Instruments
(1.9)
(7.8)
 
 
Reclassifications of Net Losses (gains) on Derivative Instruments
12.5 
1.0 
 
 
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders
(55.2)
(24.0)
 
 
Stockholders' Equity, Other
1.3 
(0.2)
 
 
Accumulated Defined Benefit Plans Adjustment [Member] |
Accumulated Other Comprehensive Income (Loss) [Member]
 
 
 
 
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent
$ 0.3 
$ 0.1 
 
 
Nature of Operations
Nature of Operations
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 (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering 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 through AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). AmeriGas OLP and HOLP are collectively referred to herein as the “Operating Partnerships.” AmeriGas Partners, AmeriGas OLP and HOLP 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 December 31, 2012, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners and an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 39,488,173 publicly held Common Units and 29,567,362 Common Units held by a subsidiary of Energy Transfer Partners, L.P. (“ETP”) as a result of the January 12, 2012, acquisition of substantially all of ETP's propane operations (“Heritage Propane”).
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “International Propane.”
Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering 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 electricity generation facilities located in Pennsylvania. These businesses 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 a first-tier subsidiary. 
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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, 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
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 report the public’s and ETP’s limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests.We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have 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 that 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, 2012, condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America (“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, 2012 (“Company’s 2012 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 that are restricted from withdrawal.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders 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 December 31,
 
 
2012
 
2011
Denominator (thousands of shares):
 
 
 
 
Average common shares outstanding for basic computation
 
113,136

 
112,240

Incremental shares issuable for stock options and awards
 
1,354

 
912

Average common shares outstanding for diluted computation
 
114,490

 
113,152


Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) 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 and intracompany transaction adjustments.
Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we concluded that it was more likely than not that a portion of our foreign tax credits would be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $5.5 for the three months ended December 31, 2011.
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
Accounting Changes
New Accounting Standard Not Yet Adopted
Disclosures about Offsetting Assets and Liabilities. In December 2011, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014), and interim periods within those annual periods. We are currently evaluating the impact of the new guidance on our future disclosures.
Partnership Acquisition of Heritage Propane
Partnership Acquisition of Heritage Propane
Partnership Acquisition of Heritage Propane

On January 12, 2012, AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,604.8 comprising $1,472.2 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,132.6 (the “Heritage Acquisition”). The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement, dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. For additional information on the Heritage Acquisition, see Note 4 to the Company’s 2012 Annual Financial Statements and Notes.
The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2011:

 
 
Three Months Ended
December 31,
 
 
2012 (As Reported)
 
2011 (Pro Forma)
Revenues
 
$
2,023.2

 
$
2,111.2

Net income attributable to UGI Corporation
 
$
102.6

 
$
85.4

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic
 
$
0.91

 
$
0.76

Diluted
 
$
0.90

 
$
0.75


The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
Goodwill and Intangible Assets
Goodwill and Intangible Assets
Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:
 
 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Goodwill (not subject to amortization)
 
$
2,835.0

 
$
2,818.3

 
$
1,624.7

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
694.8

 
$
691.9

 
$
248.8

Trademarks and tradenames (not subject to amortization)
 
138.4

 
137.2

 
46.4

     Gross carrying amount
 
833.2

 
829.1

 
295.2

     Accumulated amortization
 
(186.4
)
 
(170.9
)
 
(135.5
)
       Intangible assets, net
 
$
646.8

 
$
658.2

 
$
159.7


The changes in goodwill and intangible assets during the three months ended December 31, 2012, principally reflect the effects of currency translation. Amortization expense of intangible assets was $13.3 and $5.8 for the three months ended December 31, 2012 and 2011, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of December 31, 2012, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2013 and for the next four fiscal years is as follows: remainder of Fiscal 2013 — $39.1; Fiscal 2014 — $50.5; Fiscal 2015 — $47.4; Fiscal 2016 — $41.3; Fiscal 2017 — $35.0.
Segment Information
Segment Information
Segment Information

We have organized our business units into six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “International Propane” and Energy Services and Electric Generation together as “Midstream & Marketing.” For Fiscal 2012, the Company began reporting its Electric Generation operating segment as a separate reportable segment and our former Electric Utility reportable segment was combined with Corporate & Other. Previously, the Electric Generation operating segment was included in the Energy Services’ reportable segment. Segment information for the three months ended December 31, 2011 presented below has been adjusted to conform to the current year presentation.
The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2012 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 other reportable segments principally based upon their income before income taxes.


Three Months Ended December 31, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
 
Total
 
Elims.
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation

 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
2,023.2

 
$
(58.5
)
(c)
 
$
876.6

 
$
248.3

 
$
227.8

 
$
14.9

 
$
419.3

 
$
245.6

 
$
49.2

Cost of sales
 
$
1,218.8

 
$
(57.3
)
(c)
 
$
452.1

 
$
123.6

 
$
187.9

 
$
9.6

 
$
279.9

 
$
194.9

 
$
28.1

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
 
$
296.1

 
$
—

 
 
$
139.9

 
$
69.8

 
$
27.3

 
$
0.2

 
$
47.5

 
$
10.3

 
$
1.1

Interest expense
 
(60.3
)
 
—

 
 
(41.2
)
 
(9.6
)
 
(1.0
)
 
—

 
(6.5
)
 
(1.3
)
 
(0.7
)
Income before income taxes
 
$
235.8

 
$
—

 
 
$
98.7

 
$
60.2

 
$
26.3

 
$
0.2

 
$
41.0

 
$
9.0

 
$
0.4

Partnership EBITDA (a)
 
 
 
 
 
 
$
187.8

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
68.1

 
$
—

 
 
$
68.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
—

Depreciation and amortization
 
$
87.1

 
$
—

 
 
$
49.4

 
$
12.6

 
$
1.6

 
$
2.5

 
$
14.1

 
$
5.5

 
$
1.4

Capital expenditures
 
$
91.3

 
$
—

 
 
$
26.5

 
$
28.5

 
$
13.5

 
$
6.8

 
$
12.2

 
$
2.2

 
$
1.6

Total assets (at period end)
 
$
10,167.5

 
$
(101.5
)
 
 
$
4,695.6

 
$
2,164.4

 
$
396.7

 
$
261.2

 
$
1,828.2

 
$
564.1

 
$
358.8

Bank loans (at period end)
 
$
333.2

 
$
—

 
 
$
177.2

 
$
73.1

 
$
69.0

 
$
—

 
$
—

 
$
13.9

 
$
—

Goodwill (at period end)
 
$
2,835.0

 
$
—

 
 
$
1,919.2

 
$
182.1

 
$
2.8

 
$
—

 
$
628.0

 
$
95.9

 
$
7.0

Three Months Ended December 31, 2011:
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
 
Total
 
Elims.
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation

 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
1,688.8

 
$
(56.0
)
(c)
 
$
683.8

 
$
255.0

 
$
234.1

 
$
7.4

 
$
301.6

 
$
216.7

 
$
46.2

Cost of sales
 
$
1,101.8

 
$
(55.0
)
(c)
 
$
443.8

 
$
141.7

 
$
196.7

 
$
4.8

 
$
175.7

 
$
168.1

 
$
26.0

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
188.3

 
$
—

 
 
$
60.1

 
$
61.2

 
$
27.4

 
$
(3.5
)
 
$
37.3

 
$
4.4

 
$
1.4

Loss from equity investees
 
(0.1
)
 
—

 
 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(36.0
)
 
—

 
 
(16.5
)
 
(10.1
)
 
(1.1
)
 
—

 
(6.5
)
 
(1.0
)
 
(0.8
)
Income (loss) before income taxes
 
$
152.2

 
$
—

 
 
$
43.6

 
$
51.1

 
$
26.3

 
$
(3.5
)
 
$
30.7

 
$
3.4

 
$
0.6

Partnership EBITDA (a)
 
 
 
 
 
 
$
83.7

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
23.1

 
$
—

 
 
$
23.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
—

Depreciation and amortization
 
$
60.3

 
$
—

 
 
$
24.2

 
$
12.1

 
$
0.7

 
$
2.1

 
$
14.1

 
$
5.5

 
$
1.6

Capital expenditures
 
$
88.7

 
$
—

 
 
$
21.6

 
$
21.8

 
$
18.6

 
$
9.5

 
$
11.1

 
$
4.8

 
$
1.3

Total assets (at period end)
 
$
7,153.9

 
$
(85.4
)
 
 
$
1,975.7

 
$
2,088.7

 
$
406.7

 
$
251.6

 
$
1,693.7

 
$
528.9

 
$
294.0

Bank loans (at period end)
 
$
421.9

 
$
—

 
 
$
226.0

 
$
57.7

 
$
118.2

 
$
—

 
$
—

 
$
20.0

 
$
—

Goodwill (at period end)
 
$
1,624.7

 
$
—

 
 
$
696.6

 
$
182.1

 
$
2.8

 
$
—

 
$
641.9

 
$
94.3

 
$
7.0

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
Three Months Ended December 31,
 
2012
 
2011
Partnership EBITDA
 
$
187.8

 
$
83.7

Depreciation and amortization
 
(49.4
)
 
(24.2
)
Noncontrolling interests (i)
 
1.5

 
0.6

Operating income
 
$
139.9

 
$
60.1


(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Corporate & Other results principally comprise Electric Utility, UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (”HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Energy Services Accounts Receivable Securitization Facility
Energy Services Accounts Receivable Securitization Facility
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 2013, 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. 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.
During the three months ended December 31, 2012 and 2011, Energy Services transferred trade receivables to ESFC totaling $224.3 and $251.2, respectively. During the three months ended December 31, 2012 and 2011, ESFC sold an aggregate $79.5 and $94.0, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2012, the balance of ESFC receivables was $69.3 and there was $33.0 sold to the commercial paper conduit. At December 31, 2011, the outstanding balance of ESFC receivables was $78.4 and there was $33.2 sold to the commercial paper conduit.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
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 2012 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:

 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Regulatory assets:
 
 
 
 
 
 
Income taxes recoverable
 
$
103.7

 
$
103.2

 
$
98.7

Underfunded pension and postretirement plans
 
184.8

 
188.2

 
148.7

Environmental costs
 
17.1

 
16.8

 
19.4

Deferred fuel and power costs
 
7.8

 
11.6

 
14.8

Removal costs, net
 
11.5

 
12.7

 
11.9

Other
 
5.7

 
5.9

 
8.0

Total regulatory assets
 
$
330.6

 
$
338.4

 
$
301.5

Regulatory liabilities:
 
 
 
 
 
 
Postretirement benefits
 
$
13.5

 
$
13.1

 
$
11.8

Environmental overcollections
 
3.1

 
2.9

 
4.7

Deferred fuel and power refunds
 
1.9

 
4.4

 
5.0

State tax benefits—distribution system repairs
 
7.7

 
7.4

 
6.5

Other
 
0.6

 
0.5

 
0.4

Total regulatory liabilities
 
$
26.8

 
$
28.3

 
$
28.4


Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s 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 overcollected costs are classified as a regulatory liability.
Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural 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 gains (losses) on such contracts at December 31, 2012, September 30, 2012 and December 31, 2011 were $(0.4), $5.3 and $(2.6), respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not currently qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At December 31, 2012, September 30, 2012, and December 31, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $8.2, $9.2 and $13.5, 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power—costs or refunds. Unrealized gains or losses on FTRs at December 31, 2012, September 30, 2012, and December 31, 2011, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012 (“PUC Staff Complaint”), pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Commissioners adopted a Joint Motion on January 24, 2013 (the “Joint Motion”) to adopt the Joint Settlement, with certain modifications. In addition to the commitments made by UGI Utilities in the Joint Settlement, the Joint Motion would require UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 to $0.5; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program, but would not require UGI Utilities to concede to having violated any regulation or operating procedure. We anticipate that the PUC Staff will issue in the near future a tentative order that incorporates the terms and conditions of the Joint Settlement, as modified. The provisions of the tentative order will become final and effective unless any party to the Joint Settlement objects to any of the terms and conditions included in the tentative order within five business days from the date of the issuance. The Company does not believe that the cost of complying with the requirements of the Joint Motion will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
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 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:
 
 
Pension Benefits
 
Other
Postretirement Benefits
 
 
Three Months Ended December 31,
 
Three Months Ended December 31,
 
 
2012
 
2011
 
2012
 
2011
Service cost
 
$
2.8

 
$
2.1

 
$
0.2

 
$
0.1

Interest cost
 
5.9

 
6.1

 
0.2

 
0.2

Expected return on assets
 
(6.9
)
 
(6.4
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
—

 
0.1

 
(0.1
)
 
(0.1
)
Actuarial loss
 
3.8

 
2.1

 
0.1

 
0.1

Net benefit cost
 
5.6

 
4.0

 
0.3

 
0.2

Change in associated regulatory liabilities
 
—

 
—

 
0.8

 
0.8

Net expense
 
$
5.6

 
$
4.0

 
$
1.1

 
$
1.0


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 Plan benefits equal to at least the minimum contribution set forth in applicable employee benefit laws. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $10.0 to the Pension Plan during the remainder of Fiscal 2013. During the three months ended December 31, 2012 and 2011, the Company made contributions to the Pension Plan of $5.7 and $4.1, respectively. 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. 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 three months ended December 31, 2012 and 2011, nor are they expected to be material for all of Fiscal 2013.
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.8 and $0.7 for the three months ended December 31, 2012 and 2011, respectively.
Debt
Debt
Debt

On December 18, 2012, Energy Services amended and restated its unsecured credit agreement with a group of banks (“Energy Services Credit Agreement”) to, among other things, increase its borrowing capacity and extend its expiration. The Energy Services Credit Agreement provides for borrowings up to $240 (including a $50 sublimit for letters of credit) and expires in June 2016. The Energy Services Credit Agreement also provides an option to increase the borrowing capacity by up to an additional $30, to a total of $270, upon approval from one or more of the banks.

Under the Energy Services Credit Agreement, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than or equal to $250; and a minimum Consolidated Net Worth, as defined, of $200.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies

Environmental Matters
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $15.0 and $17.8, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At December 31, 2012, 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. 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.
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 has indicated that the cost could be as high as $20. There have been no recent developments in this matter.
Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities’ predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska, and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012, and is cooperating with its investigation.
AmeriGas Propane
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 communicated the results of its research to DEC in January 2009 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. 
Claremont, New Hampshire and Chestertown, Maryland. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan Propane LLC (“Titan LLC”), a former subsidiary acquired in the Heritage Acquisition, is purportedly the beneficial holder of title with respect to two former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters
AmeriGas Cylinder Investigation. 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 as a result of the Partnership's decision in 2008 to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds. At that time, the District Attorneys issued an administrative subpoena seeking documents and information relating to those 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 sought additional information and documents regarding AmeriGas OLP's cylinder exchange program and we responded to that subpoena. In connection with this matter, the District Attorneys have alleged potential violations of California's antitrust laws, California's slack-fill law, and California's principal false advertising statute. We believe we have strong defenses to these allegations.
 
Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership that relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.
Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action lawsuit 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 this 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 Court has not certified the class and, in October 2008, stayed the lawsuit pending resolution of a separate, but related, class action lawsuit filed against AmeriGas OLP in Monongalia County, which was settled in Fiscal 2011. 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 OLP 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 have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not have a material impact on our results of operations and financial condition.
 
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.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements

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 December 31, 2012, September 30, 2012 and December 31, 2011:
 
 
 
Asset (Liability)
 
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
December 31, 2012:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
0.7

 
$
6.5

 
$
—

 
$
7.2

Interest rate contracts
 
$
—

 
$
4.2

 
$
—

 
$
4.2

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(9.3
)
 
$
(37.6
)
 
$
—

 
$
(46.9
)
Foreign currency contracts
 
$
—

 
$
(2.4
)
 
$
—

 
$
(2.4
)
Interest rate contracts
 
$
—

 
$
(71.8
)
 
$
—

 
$
(71.8
)
September 30, 2012:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
8.6

 
$
4.5

 
$
—

 
$
13.1

Foreign currency contracts
 
$
—

 
$
1.8

 
$
—

 
$
1.8

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(7.8
)
 
$
(53.2
)
 
$
—

 
$
(61.0
)
Interest rate contracts
 
$
—

 
$
(71.9
)
 
$
—

 
$
(71.9
)
December 31, 2011:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
7.4

 
$
2.0

 
$
—

 
$
9.4

Foreign currency contracts
 
$
—

 
$
7.0

 
$
—

 
$
7.0

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(43.9
)
 
$
(34.6
)
 
$
—

 
$
(78.5
)
Interest rate contracts
 
$
—

 
$
(52.4
)
 
$
—

 
$
(52.4
)

 
The fair values of our Level 1 exchange-traded commodity futures and option 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. There were no transfers between Level 1 and Level 2 during the periods presented.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At December 31, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,522.8 and $3,840.3, respectively. At December 31, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,162.5 and $2,264.9, 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 (Level 2).
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 that extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 13.
Disclosures About Derivative Instruments and Hedging Activities
Disclosures About Derivative Instruments and Hedging Activities
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 reduce short-term commodity price volatility and to provide market price risk support to some of its wholesale customers which are generally not designated as hedges for accounting purposes.
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, including the cost of financial instruments used to hedge purchased gas costs. 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 December 31, 2012 and 2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.0 million dekatherms and 9.1 million dekatherms, respectively. At December 31, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 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 GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At December 31, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $8.2 and $13.5, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2012 and 2011, the volumes of Electric Utility’s forward electricity purchase contracts was 482.3 million kilowatt hours and 816.0 million kilowatt hours, respectively. At December 31, 2012, the maximum period over which these contracts extend is 17 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). At December 31, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 118.2 million kilowatt hours and 130.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At December 31, 2012 and 2011, the volumes associated with Midstream & Marketing’s FTRs totaled 677.5 million kilowatt hours and 882.1 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. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, 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. At December 31, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.4 million dekatherms and 2.0 million gallons, respectively. At December 31, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 3.9 million dekatherms and 3.5 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 December 31, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
 
 
 
Volumes
 
 
December 31,
Commodity
 
2012
 
2011
LPG (millions of gallons)
 
212.1

 
125.4

Natural gas (millions of dekatherms)
 
21.1

 
28.0

Electricity forward purchase contracts (millions of kilowatt-hours)
 
1,180.8

 
1,538.3

Electricity forward sales contracts (millions of kilowatt-hours)
 
195.3

 
175.4


At December 31, 2012, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 23 months with a weighted average of 5 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 41 months with a weighted average of 12 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 33 months for electricity forward purchase contracts, with a weighted average of 9 months, and 12 months for electricity forward sales contracts, with a weighted average of 5 months. At December 31, 2012, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 5 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 December 31, 2012, 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 $42.4.
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 its term loans, in each case through the respective scheduled maturity dates. As of December 31, 2012 and 2011, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €441.2 and €442.6, respectively.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2012 and 2011, the total notional amount of unsettled IRPAs was $173. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2013.
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 December 31, 2012, 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 $1.0.
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 forecasted to occur during the heating-season months of October through March. At December 31, 2012 and 2011, we were hedging a total of $120.0 and $106.0 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2012, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 27 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 on a portion of our International Propane euro-denominated net investments. At December 31, 2012, we had no euro-denominated net investment hedges. At December 31, 2011, we were hedging a total of €14.5 of our euro-denominated net investments. From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.
We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At December 31, 2012, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.1. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.
 
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise 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 form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and options contracts generally require cash deposits in margin accounts. At December 31, 2012 and 2011, restricted cash in brokerage accounts totaled $6.9 and $22.3, 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 December 31, 2012. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2012, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
 
The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of December 31, 2012 and 2011:
 
 
 
Derivative Assets
 
Derivative (Liabilities)
 
 
Balance Sheet
 
Fair Value December 31,
 
Balance Sheet
 
Fair Value December 31,
 
 
Location
 
2012
 
2011
 
Location
 
2012
 
2011
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments and
Other assets
 
$
4.9

 
$
1.7

 
Derivative financial instruments
and Other noncurrent liabilities
 
$
(37.9
)
 
$
(62.4
)
Foreign currency contracts
 
Derivative financial instruments and
Other assets
 
—

 
7.0

 
Derivative financial instruments and
Other noncurrent liabilities
 
(2.4
)
 
—

Interest rate contracts
 
Derivative financial instruments
 
4.2

 
—

 
Derivative financial instruments
and Other noncurrent liabilities
 
(71.8
)
 
(52.4
)
Total Derivatives Designated as Hedging Instruments
 
 
 
$
9.1

 
$
8.7

 
 
 
$
(112.1
)
 
$
(114.8
)
Derivatives Subject to Utility Rate Regulation:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments
 
$
0.4

 
$
—

 
Derivative financial instruments and
Other noncurrent liabilities
 
$
(9.0
)
 
$
(16.1
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments
 
$
1.9

 
$
7.7

 
Derivative financial instruments
 
$
—

 
$
—

Total Derivatives
 
 
 
$
11.4

 
$
16.4

 
 
 
$
(121.1
)
 
$
(130.9
)

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 months ended December 31, 2012 and 2011:

 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
 
 
2012
 
2011
 
2012
 
2011
 
Interests into Income
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(10.8
)
 
$
(57.2
)
 
$
(25.3
)
 
$
(19.5
)
 
Cost of sales
Foreign currency contracts
 
(3.7
)
 
1.9

 
0.5

 
0.9

 
Cost of sales
Interest rate contracts
 
1.0

 
(9.6
)
 
(3.5
)
 
(1.9
)
 
Interest expense / other income, net
Total
 
$
(13.5
)
 
$
(64.9
)
 
$
(28.3
)
 
$
(20.5
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
 
$
—

 
$
0.5

 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
Derivatives Not Designated as Hedging Instruments:
 
2012
 
2011
 
 
Commodity contracts
 
$
1.6

 
$
3.1

 
Cost of sales
Commodity contracts
 
—

 
(0.1
)
 
Operating expenses / other
income, net
Foreign currency contracts
 
—

 
0.5

 
Other income, net
Total
 
$
1.6

 
$
3.5

 
 

 
The amounts of derivative gains or losses representing ineffectiveness were not material for the three months ended December 31, 2012 and 2011.
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 and contracts that 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
Inventories

Inventories comprise the following:
 
 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Non-utility LPG and natural gas
 
$
265.9

 
$
240.7

 
$
249.1

Gas Utility natural gas
 
51.8

 
57.7

 
87.7

Materials, supplies and other
 
60.8

 
58.5

 
53.9

Total inventories
 
$
378.5

 
$
356.9

 
$
390.7


At December 31, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), one of which expires in October 2013 and two of which expire in October 2015. 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.
As of December 31, 2012, all of UGI Utilities’ SCAAs are with Energy Services. The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at September 30, 2012, and December 31, 2011, comprising 3.8 billion cubic feet (“bcf”) and 3.3 bcf of natural gas were $11.4 and $15.7, respectively.
Significant Accounting Policies (Policies)
Restricted Cash 
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts that are restricted from withdrawal.
Earnings Per Common Share 
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders 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 December 31,
 
 
2012
 
2011
Denominator (thousands of shares):
 
 
 
 
Average common shares outstanding for basic computation
 
113,136

 
112,240

Incremental shares issuable for stock options and awards
 
1,354

 
912

Average common shares outstanding for diluted computation
 
114,490

 
113,152

Comprehensive Income 
Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) 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 and intracompany transaction adjustments.
Income Taxes 
Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we concluded that it was more likely than not that a portion of our foreign tax credits would be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $5.5 for the three months ended December 31, 2011.
Use of Estimates 
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.
Significant Accounting Policies (Tables)
Shares used in computing basic and diluted earnings per share
Shares used in computing basic and diluted earnings per share are as follows:
 
 
 
Three Months Ended December 31,
 
 
2012
 
2011
Denominator (thousands of shares):
 
 
 
 
Average common shares outstanding for basic computation
 
113,136

 
112,240

Incremental shares issuable for stock options and awards
 
1,354

 
912

Average common shares outstanding for diluted computation
 
114,490

 
113,152

Partnership Acquisition of Heritage Propane (Tables)
Assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition 
Partnership's unaudited consolidated results of operations 
The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2011:

 
 
Three Months Ended
December 31,
 
 
2012 (As Reported)
 
2011 (Pro Forma)
Revenues
 
$
2,023.2

 
$
2,111.2

Net income attributable to UGI Corporation
 
$
102.6

 
$
85.4

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic
 
$
0.91

 
$
0.76

Diluted
 
$
0.90

 
$
0.75

Goodwill and Intangible Assets (Tables)
Component of company's intangible assets
Goodwill and intangible assets comprise the following:
 
 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Goodwill (not subject to amortization)
 
$
2,835.0

 
$
2,818.3

 
$
1,624.7

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
694.8

 
$
691.9

 
$
248.8

Trademarks and tradenames (not subject to amortization)
 
138.4

 
137.2

 
46.4

     Gross carrying amount
 
833.2

 
829.1

 
295.2

     Accumulated amortization
 
(186.4
)
 
(170.9
)
 
(135.5
)
       Intangible assets, net
 
$
646.8

 
$
658.2

 
$
159.7

Segment Information (Tables)
Segment Information

Three Months Ended December 31, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
 
Total
 
Elims.
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation

 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
2,023.2

 
$
(58.5
)
(c)
 
$
876.6

 
$
248.3

 
$
227.8

 
$
14.9

 
$
419.3

 
$
245.6

 
$
49.2

Cost of sales
 
$
1,218.8

 
$
(57.3
)
(c)
 
$
452.1

 
$
123.6

 
$
187.9

 
$
9.6

 
$
279.9

 
$
194.9

 
$
28.1

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
 
$
296.1

 
$
—

 
 
$
139.9

 
$
69.8

 
$
27.3

 
$
0.2

 
$
47.5

 
$
10.3

 
$
1.1

Interest expense
 
(60.3
)
 
—

 
 
(41.2
)
 
(9.6
)
 
(1.0
)
 
—

 
(6.5
)
 
(1.3
)
 
(0.7
)
Income before income taxes
 
$
235.8

 
$
—

 
 
$
98.7

 
$
60.2

 
$
26.3

 
$
0.2

 
$
41.0

 
$
9.0

 
$
0.4

Partnership EBITDA (a)
 
 
 
 
 
 
$
187.8

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
68.1

 
$
—

 
 
$
68.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
—

Depreciation and amortization
 
$
87.1

 
$
—

 
 
$
49.4

 
$
12.6

 
$
1.6

 
$
2.5

 
$
14.1

 
$
5.5

 
$
1.4

Capital expenditures
 
$
91.3

 
$
—

 
 
$
26.5

 
$
28.5

 
$
13.5

 
$
6.8

 
$
12.2

 
$
2.2

 
$
1.6

Total assets (at period end)
 
$
10,167.5

 
$
(101.5
)
 
 
$
4,695.6

 
$
2,164.4

 
$
396.7

 
$
261.2

 
$
1,828.2

 
$
564.1

 
$
358.8

Bank loans (at period end)
 
$
333.2

 
$
—

 
 
$
177.2

 
$
73.1

 
$
69.0

 
$
—

 
$
—

 
$
13.9

 
$
—

Goodwill (at period end)
 
$
2,835.0

 
$
—

 
 
$
1,919.2

 
$
182.1

 
$
2.8

 
$
—

 
$
628.0

 
$
95.9

 
$
7.0

Three Months Ended December 31, 2011:
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
 
Total
 
Elims.
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation

 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
1,688.8

 
$
(56.0
)
(c)
 
$
683.8

 
$
255.0

 
$
234.1

 
$
7.4

 
$
301.6

 
$
216.7

 
$
46.2

Cost of sales
 
$
1,101.8

 
$
(55.0
)
(c)
 
$
443.8

 
$
141.7

 
$
196.7

 
$
4.8

 
$
175.7

 
$
168.1

 
$
26.0

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
188.3

 
$
—

 
 
$
60.1

 
$
61.2

 
$
27.4

 
$
(3.5
)
 
$
37.3

 
$
4.4

 
$
1.4

Loss from equity investees
 
(0.1
)
 
—

 
 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(36.0
)
 
—

 
 
(16.5
)
 
(10.1
)
 
(1.1
)
 
—

 
(6.5
)
 
(1.0
)
 
(0.8
)
Income (loss) before income taxes
 
$
152.2

 
$
—

 
 
$
43.6

 
$
51.1

 
$
26.3

 
$
(3.5
)
 
$
30.7

 
$
3.4

 
$
0.6

Partnership EBITDA (a)
 
 
 
 
 
 
$
83.7

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
23.1

 
$
—

 
 
$
23.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
—

Depreciation and amortization
 
$
60.3

 
$
—

 
 
$
24.2

 
$
12.1

 
$
0.7

 
$
2.1

 
$
14.1

 
$
5.5

 
$
1.6

Capital expenditures
 
$
88.7

 
$
—

 
 
$
21.6

 
$
21.8

 
$
18.6

 
$
9.5

 
$
11.1

 
$
4.8

 
$
1.3

Total assets (at period end)
 
$
7,153.9

 
$
(85.4
)
 
 
$
1,975.7

 
$
2,088.7

 
$
406.7

 
$
251.6

 
$
1,693.7

 
$
528.9

 
$
294.0

Bank loans (at period end)
 
$
421.9

 
$
—

 
 
$
226.0

 
$
57.7

 
$
118.2

 
$
—

 
$
—

 
$
20.0

 
$
—

Goodwill (at period end)
 
$
1,624.7

 
$
—

 
 
$
696.6

 
$
182.1

 
$
2.8

 
$
—

 
$
641.9

 
$
94.3

 
$
7.0

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
Three Months Ended December 31,
 
2012
 
2011
Partnership EBITDA
 
$
187.8

 
$
83.7

Depreciation and amortization
 
(49.4
)
 
(24.2
)
Noncontrolling interests (i)
 
1.5

 
0.6

Operating income
 
$
139.9

 
$
60.1


(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Corporate & Other results principally comprise Electric Utility, UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (”HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 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
The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Regulatory assets:
 
 
 
 
 
 
Income taxes recoverable
 
$
103.7

 
$
103.2

 
$
98.7

Underfunded pension and postretirement plans
 
184.8

 
188.2

 
148.7

Environmental costs
 
17.1

 
16.8

 
19.4

Deferred fuel and power costs
 
7.8

 
11.6

 
14.8

Removal costs, net
 
11.5

 
12.7

 
11.9

Other
 
5.7

 
5.9

 
8.0

Total regulatory assets
 
$
330.6

 
$
338.4

 
$
301.5

Regulatory liabilities:
 
 
 
 
 
 
Postretirement benefits
 
$
13.5

 
$
13.1

 
$
11.8

Environmental overcollections
 
3.1

 
2.9

 
4.7

Deferred fuel and power refunds
 
1.9

 
4.4

 
5.0

State tax benefits—distribution system repairs
 
7.7

 
7.4

 
6.5

Other
 
0.6

 
0.5

 
0.4

Total regulatory liabilities
 
$
26.8

 
$
28.3

 
$
28.4

Defined Benefit Pension and Other Postretirement Plans (Tables)
Component of net periodic pension expense and other postretirement benefit costs
Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other
Postretirement Benefits
 
 
Three Months Ended December 31,
 
Three Months Ended December 31,
 
 
2012
 
2011
 
2012
 
2011
Service cost
 
$
2.8

 
$
2.1

 
$
0.2

 
$
0.1

Interest cost
 
5.9

 
6.1

 
0.2

 
0.2

Expected return on assets
 
(6.9
)
 
(6.4
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
—

 
0.1

 
(0.1
)
 
(0.1
)
Actuarial loss
 
3.8

 
2.1

 
0.1

 
0.1

Net benefit cost
 
5.6

 
4.0

 
0.3

 
0.2

Change in associated regulatory liabilities
 
—

 
—

 
0.8

 
0.8

Net expense
 
$
5.6

 
$
4.0

 
$
1.1

 
$
1.0

Fair Value Measurement (Tables)
Financial assets and financial liabilities that are measured at fair value on a recurring basis
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 December 31, 2012, September 30, 2012 and December 31, 2011:
 
 
 
Asset (Liability)
 
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
December 31, 2012:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
0.7

 
$
6.5

 
$
—

 
$
7.2

Interest rate contracts
 
$
—

 
$
4.2

 
$
—

 
$
4.2

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(9.3
)
 
$
(37.6
)
 
$
—

 
$
(46.9
)
Foreign currency contracts
 
$
—

 
$
(2.4
)
 
$
—

 
$
(2.4
)
Interest rate contracts
 
$
—

 
$
(71.8
)
 
$
—

 
$
(71.8
)
September 30, 2012:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
8.6

 
$
4.5

 
$
—

 
$
13.1

Foreign currency contracts
 
$
—

 
$
1.8

 
$
—

 
$
1.8

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(7.8
)
 
$
(53.2
)
 
$
—

 
$
(61.0
)
Interest rate contracts
 
$
—

 
$
(71.9
)
 
$
—

 
$
(71.9
)
December 31, 2011:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
7.4

 
$
2.0

 
$
—

 
$
9.4

Foreign currency contracts
 
$
—

 
$
7.0

 
$
—

 
$
7.0

Liabilities:
 
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(43.9
)
 
$
(34.6
)
 
$
—

 
$
(78.5
)
Interest rate contracts
 
$
—

 
$
(52.4
)
 
$
—

 
$
(52.4
)
Disclosures About Derivative Instruments and Hedging Activities (Tables)
Outstanding derivative commodity instruments volumes 
At December 31, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
 
 
 
Volumes
 
 
December 31,
Commodity
 
2012
 
2011
LPG (millions of gallons)
 
212.1

 
125.4

Natural gas (millions of dekatherms)
 
21.1

 
28.0

Electricity forward purchase contracts (millions of kilowatt-hours)
 
1,180.8

 
1,538.3

Electricity forward sales contracts (millions of kilowatt-hours)
 
195.3

 
175.4

Balance sheet location and fair value of derivative assets and liabilities 
The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of December 31, 2012 and 2011:
 
 
 
Derivative Assets
 
Derivative (Liabilities)
 
 
Balance Sheet
 
Fair Value December 31,
 
Balance Sheet
 
Fair Value December 31,
 
 
Location
 
2012
 
2011
 
Location
 
2012
 
2011
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments and
Other assets
 
$
4.9

 
$
1.7

 
Derivative financial instruments
and Other noncurrent liabilities
 
$
(37.9
)
 
$
(62.4
)
Foreign currency contracts
 
Derivative financial instruments and
Other assets
 
—

 
7.0

 
Derivative financial instruments and
Other noncurrent liabilities
 
(2.4
)
 
—

Interest rate contracts
 
Derivative financial instruments
 
4.2

 
—

 
Derivative financial instruments
and Other noncurrent liabilities
 
(71.8
)
 
(52.4
)
Total Derivatives Designated as Hedging Instruments
 
 
 
$
9.1

 
$
8.7

 
 
 
$
(112.1
)
 
$
(114.8
)
Derivatives Subject to Utility Rate Regulation:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments
 
$
0.4

 
$
—

 
Derivative financial instruments and
Other noncurrent liabilities
 
$
(9.0
)
 
$
(16.1
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative financial instruments
 
$
1.9

 
$
7.7

 
Derivative financial instruments
 
$
—

 
$
—

Total Derivatives
 
 
 
$
11.4

 
$
16.4

 
 
 
$
(121.1
)
 
$
(130.9
)

Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest 
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 months ended December 31, 2012 and 2011:

 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
 
 
2012
 
2011
 
2012
 
2011
 
Interests into Income
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(10.8
)
 
$
(57.2
)
 
$
(25.3
)
 
$
(19.5
)
 
Cost of sales
Foreign currency contracts
 
(3.7
)
 
1.9

 
0.5

 
0.9

 
Cost of sales
Interest rate contracts
 
1.0

 
(9.6
)
 
(3.5
)
 
(1.9
)
 
Interest expense / other income, net
Total
 
$
(13.5
)
 
$
(64.9
)
 
$
(28.3
)
 
$
(20.5
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
 
$
—

 
$
0.5

 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
Derivatives Not Designated as Hedging Instruments:
 
2012
 
2011
 
 
Commodity contracts
 
$
1.6

 
$
3.1

 
Cost of sales
Commodity contracts
 
—

 
(0.1
)
 
Operating expenses / other
income, net
Foreign currency contracts
 
—

 
0.5

 
Other income, net
Total
 
$
1.6

 
$
3.5

 
 
Inventories (Tables)
Inventories
Inventories comprise the following:
 
 
 
December 31,
2012
 
September 30,
2012
 
December 31,
2011
Non-utility LPG and natural gas
 
$
265.9

 
$
240.7

 
$
249.1

Gas Utility natural gas
 
51.8

 
57.7

 
87.7

Materials, supplies and other
 
60.8

 
58.5

 
53.9

Total inventories
 
$
378.5

 
$
356.9

 
$
390.7

Nature of Operations (Details)
Dec. 31, 2012
Nature of Operations (Additional Textual) [Abstract]
 
General Partner held a general partner interest in AmeriGas Partners
1.00% 
Percentage of limited partnership interest in AmeriGas Partners
25.30% 
Effective ownership interest in AmeriGas OLP
27.10% 
Limited Partnership Common Units held in AmeriGas Partners (in units)
23,756,882 
General public as limited partner interests in AmeriGas Partners
73.70% 
Common Units Owned by Public (in units)
39,488,173 
Common Units Owned by ETP (in units)
29,567,362 
Significant Accounting Policies (Details)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Denominator (thousands of shares):
 
 
Average common shares outstanding for basic computation (in shares)
113,136 
112,240 
Incremental shares issuable for stock options and awards (in shares)
1,354 
912 
Average common shares outstanding for diluted computation (in shares)
114,490 
113,152 
Significant Accounting Policies (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2011
Significant Accounting Policies (Textual) [Abstract]
 
Decrease in income tax expense
$ 5.5 
Partnership Acquisition of Heritage Propane (Details 1) (Heritage Propane [Member], USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Heritage Propane [Member]
 
 
Partnership unaudited consolidated results of operations
 
 
Revenues
$ 2,023.2 
$ 2,111.2 
Net income attributable to UGI Corporation
$ 102.6 
$ 85.4 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
Basic (in dollars per share)
$ 0.91 
$ 0.76 
Diluted (in dollars per share)
$ 0.90 
$ 0.75 
Partnership Acquisition of Heritage Propane (Details Textual) (Heritage Propane [Member], USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended
Jan. 12, 2012
Heritage Propane [Member]
 
Acquisition (Textual) [Abstract]
 
Purchase price of the acquisition
$ 2,604.8 
Business acquired by parent through subsidiaries for cash
1,472.2 
Common units issued by AmeriGas Partners (in units)
29,567,362 
Consideration in AmeriGas Partners Common Units
$ 1,132.6 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Component of Company's Intangible Assets [Abstract]
 
 
 
Goodwill (not subject to amortization)
$ 2,835.0 
$ 2,818.3 
$ 1,624.7 
Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
694.8 
691.9 
248.8 
Trademarks and tradenames (not subject to amortization)
138.4 
137.2 
46.4 
Intangible Assets Excluding Goodwill
833.2 
829.1 
295.2 
Accumulated amortization
(186.4)
(170.9)
(135.5)
Net carrying amount
$ 646.8 
$ 658.2 
$ 159.7 
Goodwill and Intangible Assets (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Component of Company's Intangible Assets (Textual) [Abstract]
 
 
Amortization expense of intangible assets
$ 13.3 
$ 5.8 
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
 
 
Remainder of fiscal 2013
39.1 
 
Fiscal 2014
50.5 
 
Fiscal 2015
47.4 
 
Fiscal 2016
41.3 
 
Fiscal 2017
$ 35.0 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Sep. 30, 2012
Segment information
 
 
 
Revenues
$ 2,023.2 
$ 1,688.8 
 
Cost of sales
1,218.8 
1,101.8 
 
Segment profit:
 
 
 
Operating income (loss)
296.1 
188.3 
 
Loss from equity investees
0 
(0.1)
 
Interest expense
(60.3)
(36.0)
 
Income before income taxes
235.8 
152.2 
 
Noncontrolling interests' net income
68.1 
23.1 
 
Depreciation and amortization
87.1 
60.3 
 
Capital expenditures
91.3 
88.7 
 
Total assets (at period end)
10,167.5 
7,153.9 
9,709.7 
Bank loans (at period end)
333.2 
421.9 
165.1 
Goodwill (at period end)
2,835.0 
1,624.7 
2,818.3 
Eliminations [Member]
 
 
 
Segment information
 
 
 
Revenues
(58.5)1
(56.0)1
 
Cost of sales
(57.3)1
(55.0)1
 
Segment profit:
 
 
 
Operating income (loss)
 
0 
 
Income before income taxes
 
0 
 
Total assets (at period end)
(101.5)
(85.4)
 
AmeriGas Propane [Member]
 
 
 
Segment information
 
 
 
Revenues
876.6 
683.8 
 
Cost of sales
452.1 
443.8 
 
Segment profit:
 
 
 
Operating income (loss)
139.9 
60.1 
 
Interest expense
(41.2)
(16.5)
 
Income before income taxes
98.7 
43.6 
 
Partnership EBITDA
187.8 2
83.7 2
 
Noncontrolling interests' net income
68.0 
23.0 
 
Depreciation and amortization
49.4 
24.2 
 
Capital expenditures
26.5 
21.6 
 
Total assets (at period end)
4,695.6 
1,975.7 
 
Bank loans (at period end)
177.2 
226.0 
 
Goodwill (at period end)
1,919.2 
696.6 
 
Gas Utility [Member]
 
 
 
Segment information
 
 
 
Revenues
248.3 
255.0 
 
Cost of sales
123.6 
141.7 
 
Segment profit:
 
 
 
Operating income (loss)
69.8 
61.2 
 
Interest expense
(9.6)
(10.1)
 
Income before income taxes
60.2 
51.1 
 
Depreciation and amortization
12.6 
12.1 
 
Capital expenditures
28.5 
21.8 
 
Total assets (at period end)
2,164.4 
2,088.7 
 
Bank loans (at period end)
73.1 
57.7 
 
Goodwill (at period end)
182.1 
182.1 
 
Midstream And Marketing, Energy Services [Member]
 
 
 
Segment information
 
 
 
Revenues
227.8 
234.1 
 
Cost of sales
187.9 
196.7 
 
Segment profit:
 
 
 
Operating income (loss)
27.3 
27.4 
 
Interest expense
(1.0)
(1.1)
 
Income before income taxes
26.3 
26.3 
 
Depreciation and amortization
1.6 
0.7 
 
Capital expenditures
13.5 
18.6 
 
Total assets (at period end)
396.7 
406.7 
 
Bank loans (at period end)
69.0 
118.2 
 
Goodwill (at period end)
2.8 
2.8 
 
Midstream & Marketing [Member]
 
 
 
Segment information
 
 
 
Revenues
14.9 
7.4 
 
Cost of sales
9.6 
4.8 
 
Segment profit:
 
 
 
Operating income (loss)
0.2 
(3.5)
 
Interest expense
0 
0 
 
Income before income taxes
0.2 
(3.5)
 
Depreciation and amortization
2.5 
2.1 
 
Capital expenditures
6.8 
9.5 
 
Total assets (at period end)
261.2 
251.6 
 
Bank loans (at period end)
0 
 
 
Goodwill (at period end)
0 
0 
 
International Propane, Antargaz [Member]
 
 
 
Segment information
 
 
 
Revenues
419.3 
301.6 
 
Cost of sales
279.9 
175.7 
 
Segment profit:
 
 
 
Operating income (loss)
47.5 
37.3 
 
Loss from equity investees
 
(0.1)
 
Interest expense
(6.5)
(6.5)
 
Income before income taxes
41.0 
30.7 
 
Noncontrolling interests' net income
0.1 
0.1 
 
Depreciation and amortization
14.1 
14.1 
 
Capital expenditures
12.2 
11.1 
 
Total assets (at period end)
1,828.2 
1,693.7 
 
Goodwill (at period end)
628.0 
641.9 
 
International Propane, Flaga & Other [Member]
 
 
 
Segment information
 
 
 
Revenues
245.6 
216.7 
 
Cost of sales
194.9 
168.1 
 
Segment profit:
 
 
 
Operating income (loss)
10.3 
4.4 
 
Interest expense
(1.3)
(1.0)
 
Income before income taxes
9.0 
3.4 
 
Depreciation and amortization
5.5 
5.5 
 
Capital expenditures
2.2 
4.8 
 
Total assets (at period end)
564.1 
528.9 
 
Bank loans (at period end)
13.9 
20.0 
 
Goodwill (at period end)
95.9 
94.3 
 
Corporate & Other [Member]
 
 
 
Segment information
 
 
 
Revenues
49.2 3
46.2 3
 
Cost of sales
28.1 3
26.0 3
 
Segment profit:
 
 
 
Operating income (loss)
1.1 3
1.4 3
 
Interest expense
(0.7)3
(0.8)3
 
Income before income taxes
0.4 3
0.6 3
 
Depreciation and amortization
1.4 3
1.6 3
 
Capital expenditures
1.6 3
1.3 3
 
Total assets (at period end)
358.8 3
294.0 3
 
Goodwill (at period end)
$ 7.0 3
$ 7.0 3
 
Segment Information (Details 1) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Reconciliation of partnership EBITDA
 
 
Depreciation and amortization
$ (87.1)
$ (60.3)
Operating income (loss)
296.1 
188.3 
AmeriGas Propane [Member]
 
 
Reconciliation of partnership EBITDA
 
 
Partnership EBITDA
187.8 1
83.7 1
Depreciation and amortization
(49.4)
(24.2)
Noncontrolling interests
1.5 2
0.6 2
Operating income (loss)
$ 139.9 
$ 60.1 
Segment Information (Details Textual)
3 Months Ended
Dec. 31, 2012
Reportable_Segments
Segment Reporting Information [Line Items]
 
Number of reportable segments (in reportable segments)
6 
Segment Information (Textual) [Abstract]
 
General Partner's interest in AmeriGas OLP (as a percent)
1.01% 
Energy Services Accounts Receivable Securitization Facility (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Energy services accounts receivable securitization facility (Additional Textual) [Abstract]
 
 
Receivables facility
$ 200 
 
Energy Services Funding Corporation [Member]
 
 
Energy services accounts receivable securitization facility (Textual) [Abstract]
 
 
Sale of undivided interests in its trade receivables to the commercial paper conduit
79.5 
94.0 
Outstanding balance of trade receivables
69.3 
78.4 
Outstanding balance of trade receivables sold
33.0 
33.2 
Energy Services [Member]
 
 
Energy services accounts receivable securitization facility (Textual) [Abstract]
 
 
Sale of trade receivables
$ 224.3 
$ 251.2 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
$ 330.6 
$ 338.4 
$ 301.5 
Regulatory Liabilities
26.8 
28.3 
28.4 
Postretirement benefits [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Liabilities
13.5 
13.1 
11.8 
Environmental overcollections [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Liabilities
3.1 
2.9 
4.7 
Deferred fuel and power refunds [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Liabilities
1.9 
4.4 
5.0 
State tax benefits - distribution system repairs [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Liabilities
7.7 
7.4 
6.5 
Other [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Liabilities
0.6 
0.5 
0.4 
Income taxes recoverable [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
103.7 
103.2 
98.7 
Underfunded pension and postretirement plans [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
184.8 
188.2 
148.7 
Environmental costs [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
17.1 
16.8 
19.4 
Deferred fuel and power costs [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
7.8 
11.6 
14.8 
Removal costs, net [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
11.5 
12.7 
11.9 
Other [Member]
 
 
 
Regulatory Assets and Liabilities Disclosure [Abstract]
 
 
 
Regulatory Assets
$ 5.7 
$ 5.9 
$ 8.0 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textual) (USD $)
In Millions, unless otherwise specified
0 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Oct. 3, 2012
Allentown, Pennsylvania Natural Gas Explosion [Member]
UGI Utilities [Member]
Feb. 9, 2011
Allentown, Pennsylvania Natural Gas Explosion [Member]
UGI Utilities [Member]
Person
Dec. 31, 2012
Allentown Incident [Member]
UGI Utilities [Member]
Dec. 31, 2012
Revised Penalty [Member]
Allentown Incident [Member]
UGI Utilities [Member]
Regulatory Assets [Line Items]
 
 
 
 
 
 
 
Gas utility unrealized gains or losses on derivative financial instruments contracts
$ (0.4)
$ 5.3 
$ (2.6)
 
 
 
 
Fair Value of Electric Utility Electricity Supply Contracts
8.2 
9.2 
13.5 
 
 
 
 
Loss Contingency, Deaths From Natural Gas Explosion
 
 
 
 
5 
 
 
Penalty assessed
 
 
 
 
 
$ 0.4 
$ 0.5 
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains
 
 
 
14 years 
 
 
 
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains
 
 
 
30 years 
 
 
 
Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Pension Benefits [Member]
 
 
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
 
 
Service cost
$ 2.8 
$ 2.1 
Interest cost
5.9 
6.1 
Expected return on assets
(6.9)
(6.4)
Amortization of:
 
 
Prior service cost (benefit)
0 
0.1 
Actuarial loss
3.8 
2.1 
Net benefit cost
5.6 
4.0 
Change in associated regulatory liabilities
0 
0 
Net expense
5.6 
4.0 
Other Postretirement Benefits [Member]
 
 
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
 
 
Service cost
0.2 
0.1 
Interest cost
0.2 
0.2 
Expected return on assets
(0.1)
(0.1)
Amortization of:
 
 
Prior service cost (benefit)
(0.1)
(0.1)
Actuarial loss
0.1 
0.1 
Net benefit cost
0.3 
0.2 
Change in associated regulatory liabilities
0.8 
0.8 
Net expense
$ 1.1 
$ 1.0 
Defined Benefit Pension and Other Postretirement Plans (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Defined Benefit Pension and Other Postretirement Plans (Textual) [Abstract]
 
 
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans
$ 0.8 
$ 0.7 
Pension Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Contribution made to Pension Plan
5.7 
4.1 
Expected contribution to pensions plans during remainder of fiscal year
$ 10.0 
 
Debt (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Debt Instrument [Line Items]
 
Potential Increase to borrowing capacity
$ 30 
Borrowing capacity potential increase
270 
Energy Services Credit Agreement [Member]
 
Debt Instrument [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
240 
Ratio of Consolidated Indebtedness to EBITDA
2.25 
Minimum Consolidated Indebtedness
250 
Minimum Consolidated Net Worth
200 
Energy Services Credit Agreement [Member] |
Letter of Credit [Member]
 
Debt Instrument [Line Items]
 
Revolving Credit Agreement Sublimit for Letters of Credit
$ 50 
Commitments and Contingencies (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Jun. 6, 2006
Key Span [Member]
Jun. 24, 2004
Key Span [Member]
Dec. 31, 2012
Environmental matters [Member]
Dec. 31, 2012
Environmental matters [Member]
CPG MGP [Member]
Dec. 31, 2012
Environmental matters [Member]
PNG MGP [Member]
Dec. 31, 2012
CPG and PNG COAs [Member]
UGI Utilities [Member]
Dec. 31, 2011
CPG and PNG COAs [Member]
UGI Utilities [Member]
Sep. 30, 2008
CA cylinder investigation [Member]
Partnership [Member]
lb
Sep. 30, 2008
FTC Investigation [Member]
Partnership [Member]
lb
Dec. 31, 2012
BP Matter [Member]
Partnership [Member]
Customer
Commitments and Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
Environmental expenditures cap during calendar year
 
 
 
$ 1.8 
$ 1.1 
 
 
 
 
 
Accrual for environmental loss contingencies
 
 
 
 
 
15.0 
17.8 
 
 
 
Base year for determination of investigation and remediation cost (in years)
 
 
5 years 
 
 
 
 
 
 
 
Percentage of costs associated with sites (as a percent)
 
50.00% 
 
 
 
 
 
 
 
 
Approximate remediation cost spent by claimant
 
2.3 
 
 
 
 
 
 
 
 
Environmental exit cost anticipated by claimant
 
11 
 
 
 
 
 
 
 
 
Environmental exit cost based on third party estimate
10 
 
 
 
 
 
 
 
 
 
Additional environment exit cost based on claimant estimate
$ 20 
 
 
 
 
 
 
 
 
 
Amount of propane in cylinders before reduction (in pounds)
 
 
 
 
 
 
 
17 
17 
 
Amount of propane in cylinders after reduction (in pounds)
 
 
 
 
 
 
 
15 
15 
 
Alleged number of residential customers (in customers)
 
 
 
 
 
 
 
 
 
400 
Fair Value Measurement (Details) (Fair Value, Measurements, Recurring [Member], USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Commodity contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
$ 7.2 
$ 13.1 
$ 9.4 
Derivative financial instruments, liabilities
(46.9)
(61.0)
(78.5)
Foreign currency contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
 
1.8 
7.0 
Derivative financial instruments, liabilities
(2.4)
 
 
Interest rate contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
4.2 
 
 
Derivative financial instruments, liabilities
(71.8)
(71.9)
(52.4)
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] |
Commodity contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
0.7 
8.6 
7.4 
Derivative financial instruments, liabilities
(9.3)
(7.8)
(43.9)
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] |
Foreign currency contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
 
   
   
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] |
Interest rate contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, liabilities
   
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Commodity contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
6.5 
4.5 
2.0 
Derivative financial instruments, liabilities
(37.6)
(53.2)
(34.6)
Significant Other Observable Inputs (Level 2) [Member] |
Foreign currency contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
 
1.8 
7.0 
Derivative financial instruments, liabilities
(2.4)
 
 
Significant Other Observable Inputs (Level 2) [Member] |
Interest rate contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
4.2 
 
 
Derivative financial instruments, liabilities
(71.8)
(71.9)
(52.4)
Unobservable Inputs (Level 3) [Member] |
Commodity contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
   
   
   
Derivative financial instruments, liabilities
   
   
   
Unobservable Inputs (Level 3) [Member] |
Foreign currency contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, assets
 
   
   
Unobservable Inputs (Level 3) [Member] |
Interest rate contracts [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Derivative financial instruments, liabilities
   
   
   
Fair Value Measurement (Details Textual) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Fair Value Disclosures [Abstract]
 
 
Carrying value long-term debt
$ 3,522.8 
$ 2,162.5 
Estimated fair value long-term debt
$ 3,840.3 
$ 2,264.9 
Disclosures About Derivative Instruments and Hedging Activities (Details) (Designated as Hedging Instrument [Member])
Dec. 31, 2012
gal
Dec. 31, 2011
gal
LPG (millions of gallons) [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
212,100,000 
125,400,000 
Natural gas (millions of dekatherms) [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
21,100,000 
28,000,000 
Electricity (millions of kilowatt-hours) [Member] |
Forward Purchase Contracts [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
1,180,800,000 
1,538,300,000 
Electricity (millions of kilowatt-hours) [Member] |
Forward Sales Contracts [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
195,300,000 
175,400,000 
Disclosures About Derivative Instruments and Hedging Activities (Details 1) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
$ 11.4 
$ 16.4 
Total Derivatives Liability
(121.1)
(130.9)
Designated as Hedging Instrument [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
9.1 
8.7 
Total Derivatives Liability
(112.1)
(114.8)
Derivative Financial Instruments and Other Assets [Member] |
Designated as Hedging Instrument [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
4.9 
1.7 
Derivative Financial Instruments and Other Assets [Member] |
Designated as Hedging Instrument [Member] |
Foreign Currency Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
   
7.0 
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] |
Designated as Hedging Instrument [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(37.9)
(62.4)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] |
Designated as Hedging Instrument [Member] |
Foreign Currency Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(2.4)
   
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] |
Designated as Hedging Instrument [Member] |
Interest Rate Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(71.8)
(52.4)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] |
Derivatives Subject to Utility Rate Regulation [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(9.0)
(16.1)
Derivative Financial Instruments [Member] |
Designated as Hedging Instrument [Member] |
Interest Rate Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
4.2 
   
Derivative Financial Instruments [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
1.9 
7.7 
Derivative Financial Instruments [Member] |
Derivatives Subject to Utility Rate Regulation [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
0.4 
   
Derivative Financial Instruments, Liabilities [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
 
$ 0 
Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
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
 
 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
$ 1.6 
$ 3.5 
Cash Flow Hedges [Member]
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
Gain (loss) recognized in AOCI and noncontrolling interests
(13.5)
(64.9)
Gain (loss) reclassified from AOCI and noncontrolling interest into income
(28.3)
(20.5)
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
 
 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
1.6 
3.1 
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
 
 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
0 
(0.1)
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
 
 
Gain (loss) recognized in AOCI and noncontrolling interests
(10.8)
(57.2)
Gain (loss) reclassified from AOCI and noncontrolling interest into income
(25.3)
(19.5)
Foreign Currency Contracts [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Other Income [Member]
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
0 
0.5 
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
 
 
Gain (loss) recognized in AOCI and noncontrolling interests
(3.7)
1.9 
Gain (loss) reclassified from AOCI and noncontrolling interest into income
0.5 
0.9 
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
 
 
Gain (loss) recognized in AOCI and noncontrolling interests
0 
0.5 
Interest Rate Contracts [Member] |
Cash Flow Hedges [Member] |
Interest Expense/Other Income [Member]
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
Gain (loss) recognized in AOCI and noncontrolling interests
1.0 
(9.6)
Gain (loss) reclassified from AOCI and noncontrolling interest into income
$ (3.5)
$ (1.9)
Disclosures About Derivative Instruments and Hedging Activities (Details Textual)
In Millions, unless otherwise specified
3 Months Ended
Dec. 31, 2012
USD ($)
Sep. 30, 2012
USD ($)
Dec. 31, 2011
USD ($)
Dec. 31, 2012
Foreign Currency [Member]
USD ($)
Jun. 30, 2011
Foreign Currency [Member]
USD ($)
Dec. 31, 2012
Interest Rate Swaps [Member]
EUR (€)
Dec. 31, 2011
Interest Rate Swaps [Member]
EUR (€)
Dec. 31, 2012
Interest Rate Protection Agreements [Member]
USD ($)
Dec. 31, 2011
Interest Rate Protection Agreements [Member]
USD ($)
Dec. 31, 2011
Net Investment Hedges [Member]
EUR (€)
Dec. 31, 2012
LPG (millions of gallons) [Member]
Dec. 31, 2012
Natural Gas (millions of dekatherms) [Member]
Dec. 31, 2012
Electricity (millions of kilowatt-hours) [Member]
Forward Purchase Contracts [Member]
Dec. 31, 2012
Electricity (millions of kilowatt-hours) [Member]
Forward Sales Contracts [Member]
Dec. 31, 2012
Electric transmission congestion - Electric Utility [Member]
kWh
Dec. 31, 2011
Electric transmission congestion - Electric Utility [Member]
kWh
Dec. 31, 2012
Gas Utility [Member]
DTH
Dec. 31, 2011
Gas Utility [Member]
DTH
Dec. 31, 2012
Midstream & Marketing [Member]
Electric transmission congestion (excluding Electric Utility) [Member]
kWh
Dec. 31, 2011
Midstream & Marketing [Member]
Electric transmission congestion (excluding Electric Utility) [Member]
kWh
Dec. 31, 2012
Electric Utility - Forward Contract [Member]
USD ($)
kWh
Dec. 31, 2011
Electric Utility - Forward Contract [Member]
USD ($)
kWh
Dec. 31, 2012
Midstream and Marketing Natural Gas [Member]
DTH
Dec. 31, 2011
Midstream and Marketing Natural Gas [Member]
DTH
Dec. 31, 2012
Midstream and Marketing Propane Storage [Member]
gal
Dec. 31, 2011
Midstream and Marketing Propane Storage [Member]
gal
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (in units)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
118,200,000 
130,000,000 
13,000,000 
9,100,000 
677,500,000 
882,100,000 
482,300,000 
816,000,000 
2,400,000 
3,900,000 
2,000,000 
3,500,000 
Maximum length of time hedged in price risk cash flow hedges (in months)
 
 
 
27 months 
 
 
 
 
 
 
23 months 
41 months 
33 months 
12 months 
 
 
9 months 
 
5 months 
 
17 months 
 
 
 
 
 
Derivative Liability, Fair Value, Gross Liability
$ 121.1 
 
$ 130.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 8.2 
$ 13.5 
 
 
 
 
Underlying variable rate debt
 
 
 
120.0 
106.0 
441.2 
442.6 
173.0 
173.0 
14.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Length if Time Hedged (in months)
 
 
 
12 months 
 
 
 
 
 
 
5 months 
12 months 
9 months 
5 months 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum approximate range of estimated dollar-denominated purchases of LPG (as a percent)
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum approximate range of estimated dollar-denominated purchases of LPG (as a percent)
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disclosures About Derivative Instruments Hedging Activities (Additional Textual) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months
42.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months
1.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months
1.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash in brokerage accounts
$ 6.9 
$ 3.0 
$ 22.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inventories (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Sep. 30, 2012
Dec. 31, 2011
Inventories
 
 
 
Total inventories
$ 378.5 
$ 356.9 
$ 390.7 
Non-utility LPG and natural gas [Member]
 
 
 
Inventories
 
 
 
Total inventories
265.9 
240.7 
249.1 
Gas Utility Natural Gas [Member]
 
 
 
Inventories
 
 
 
Total inventories
51.8 
57.7 
87.7 
Materials, Supplies and Other [Member]
 
 
 
Inventories
 
 
 
Total inventories
$ 60.8 
$ 58.5 
$ 53.9 
Inventories (Details Textual) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
ft3
Dec. 31, 2011
ft3
Inventories (Textual) [Abstract]
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)
3,800,000,000 
3,300,000,000 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 11.4 
$ 15.7