UGI CORP /PA/, 10-K filed on 11/21/2012
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Sep. 30, 2012
Nov. 13, 2012
Mar. 31, 2012
Entity Information [Line Items]
 
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
 
Entity Central Index Key
0000884614 
 
 
Document Type
10-K 
 
 
Document Period End Date
Sep. 30, 2012 
 
 
Amendment Flag
false 
 
 
Document Fiscal Year Focus
2012 
 
 
Document Fiscal Period Focus
FY 
 
 
Current Fiscal Year End Date
--09-30 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
$ 3,057,059,971 
Entity Common Stock, Shares Outstanding
 
112,704,763 
 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Current assets
 
 
Cash and cash equivalents
$ 319.9 
$ 238.5 
Restricted cash
3.0 
17.2 
Accounts receivable (less allowances for doubtful accounts of $36.1 and $36.8, respectively)
632.6 
546.7 
Accrued utility revenues
16.9 
14.8 
Inventories
356.9 
363.0 
Deferred income taxes
56.8 
44.9 
Income taxes recoverable
32.2 
19.2 
Utility regulatory assets
6.5 
8.6 
Derivative financial instruments
13.2 
10.2 
Prepaid expenses and other current assets
66.5 
43.0 
Total current assets
1,504.5 
1,306.1 
Property, plant and equipment
 
 
Utilities
2,295.7 
2,201.0 
Non-utility
4,223.4 
3,083.5 
Total property, plant and equipment
6,519.1 
5,284.5 
Accumulated depreciation and amortization
(2,286.0)
(2,080.0)
Net property, plant, and equipment
4,233.1 
3,204.5 
Goodwill
2,818.3 
1,562.2 
Intangible assets, net
658.2 
147.8 
Other assets
495.6 
442.7 
Total assets
9,709.7 
6,663.3 
Current liabilities
 
 
Current maturities of long-term debt
166.7 
47.4 
Bank loans
165.1 
138.7 
Accounts payable
411.3 
399.6 
Employee compensation and benefits accrued
91.1 
73.9 
Deposits and advances
252.8 
161.5 
Derivative financial instruments
100.9 
49.7 
Accrued interest
72.7 
27.9 
Other current liabilities
226.4 
179.2 
Total current liabilities
1,487.0 
1,077.9 
Debt and other liabilities
 
 
Long-term debt
3,347.6 
2,110.3 
Deferred income taxes
935.0 
709.2 
Deferred investment tax credits
4.6 
5.0 
Other noncurrent liabilities
616.7 
569.8 
Total liabilities
6,390.9 
4,472.2 
Commitments and contingencies (Note 15)
   
   
UGI Corporation stockholders' equity:
 
 
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,624,594 and 115,507,094 shares, respectively)
1,157.7 
937.4 
Retained earnings
1,166.1 
1,085.8 
Accumulated other comprehensive loss
(62.0)
(17.7)
Treasury stock, at cost
(28.7)
(27.8)
Total UGI Corporation stockholders' equity
2,233.1 
1,977.7 
Noncontrolling interests, principally in AmeriGas Partners
1,085.7 
213.4 
Total equity
3,318.8 
2,191.1 
Total liabilities and equity
$ 9,709.7 
$ 6,663.3 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Current assets
 
 
Accounts receivable, allowances for doubtful accounts
$ 36.1 
$ 36.8 
UGI Corporation stockholders' equity:
 
 
UGI Common Stock, without par value
$ 0 
$ 0 
UGI Common Stock, without par value authorized
300,000,000 
300,000,000 
UGI Common Stock, without par value, issued
115,624,594 
115,507,094 
Consolidated Statements of Income (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Revenues
 
 
 
Utilities
$ 882.5 
$ 1,135.5 
$ 1,167.7 
Non-utility
5,636.7 
4,955.8 
4,423.7 
Revenue, Net
6,519.2 
6,091.3 
5,591.4 
Cost of sales (excluding depreciation shown below):
 
 
 
Utilities
459.1 
678.5 
730.5 
Non-utility
3,652.1 
3,332.4 
2,853.5 
Operating and administrative expenses
1,591.7 
1,266.4 
1,177.4 
Utility taxes other than income taxes
17.3 
16.6 
18.6 
Depreciation
264.2 
201.2 
187.6 
Amortization
51.8 
26.7 
22.6 
Other income, net
(38.3)
(46.5)
(58.0)
Total costs and expenses
5,997.9 
5,475.3 
4,932.2 
Operating income
521.3 
616.0 
659.2 
Loss from equity investees
(0.3)
(0.9)
(2.1)
Loss on extinguishments of debt
(13.3)
(38.1)
   
Interest expense
(221.5)
(138.0)
(133.8)
Income before income taxes
286.2 
439.0 
523.3 
Income taxes
(99.6)
(130.8)
(167.6)
Net income
186.6 
308.2 
355.7 
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners
12.8 
(75.3)
(94.7)
Net income attributable to UGI Corporation
$ 199.4 
$ 232.9 
$ 261.0 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
Basic (in dollars per share)
$ 1.77 
$ 2.09 
$ 2.38 
Diluted (in dollars per share)
$ 1.76 
$ 2.06 
$ 2.36 
Average common shares outstanding (thousands):
 
 
 
Basic (in shares)
112,581 1
111,674 1
109,588 
Diluted (in shares)
113,432 1
112,944 1
110,511 
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Net income
$ 186.6 
$ 308.2 
$ 355.7 
Net losses on derivative instruments (net of tax of $44.8, $(15.4) and $(29.2), respectively)
(127.1)
(10.8)
(16.8)
Reclassifications of net losses on derivative instruments (net of tax of $(36.9), $(20.4) and $(25.3), respectively)
87.9 
11.8 
22.9 
Foreign currency translation adjustments (net of tax of $3.6, $4.5 and $7.9, respectively)
(20.6)
(14.0)
(39.4)
Foreign currency gains and losses on long-term intra-company transactions (net of tax of $0.7, $0.4 and $0.0, respectively)
(1.7)
(0.8)
0 
Benefit plans (net of tax of $6.0, $(0.1) and $12.7, respectively)
(11.5)
0.1 
(18.7)
Reclassification of benefit plans actuarial losses and prior service costs to net income (net of tax of $(0.5), $(0.4) and $(2.9), respectively)
0.7 
0.6 
4.2 
Reclassification of pension plans actuarial losses and prior service costs to regulatory assets (net of tax of $(59.1))
0 
0 
83.3 
Comprehensive income
114.3 
295.1 
391.2 
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners
38.9 
(69.8)
(101.4)
Comprehensive income attributable to UGI Corporation
$ 153.2 
$ 225.3 
$ 289.8 
Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Tax on (loss) gain on derivative instruments
$ 44.8 
$ (15.4)
$ (29.2)
Tax on reclassifications on derivative instruments
(36.9)
(20.4)
(25.3)
Tax on foreign currency translation
2.8 
4.5 
7.9 
Tax on foreign currency gain and losses on long-term intra-company transactions
0.7 
0.4 
0 
Tax on benefit plans
6.0 
(0.1)
12.7 
Tax on reclassification of benefit plans and prior service costs
(0.5)
(0.4)
(2.9)
Reclassification of pension plans actuarial losses and prior service costs to regulatory assets, tax
$ 0 
$ 0 
$ (59.1)
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 186.6 
$ 308.2 
$ 355.7 
Adjustments to reconcile net income to net cash provided by operating
 
 
 
Depreciation and amortization
316.0 
227.9 
210.2 
Gains on sales of Atlantic Energy, LLC
   
   
(36.5)
Deferred income taxes, net
82.9 
82.7 
62.6 
Provision for uncollectible accounts
26.5 
20.0 
27.1 
Stock-based compensation expense
14.5 
15.6 
13.2 
Net change in realized gains and losses deferred as cash flow hedges
(6.6)
12.2 
23.8 
Loss on extinguishments of debt
13.3 
38.1 
   
Other, net
(10.7)
(7.1)
7.7 
Net change in:
 
 
 
Accounts receivable and accrued utility revenues
65.5 
(66.0)
(94.6)
Inventories
89.2 
(40.7)
34.3 
Utility deferred fuel costs, net of changes in unsettled derivatives
(1.7)
12.8 
(18.5)
Accounts payable
(78.7)
19.2 
47.1 
Increase (Decrease) in Other Current Assets
12.5 
1.9 
9.4 
Other current liabilities
23.4 
(66.3)
(23.9)
Net cash provided by operating activities
707.7 
554.7 
598.8 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(339.4)
(360.7)
(347.3)
Acquisitions of businesses, net of cash acquired
(1,580.5)
(52.5)
(83.0)
Net proceeds from sale of Atlantic Energy, LLC
   
   
66.6 
Decrease (increase) in restricted cash
14.2 
17.6 
(27.8)
Other, net
1.2 
(19.8)
(7.8)
Net cash used by investing activities
(1,904.5)
(415.4)
(399.3)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Dividends on UGI Common Stock
(119.1)
(113.8)
(98.6)
Distributions on AmeriGas Partners publicly held Common Units
(181.7)
(93.7)
(89.1)
Issuances of debt
1,550.2 
1,480.6 
   
Repayments of debt
(299.9)
(1,383.6)
(94.8)
Receivables Facility net (repayments) borrowings
(14.3)
2.2 
   
Increase (decrease) in bank loans
41.7 
(74.6)
37.9 
Issuances of UGI Common Stock
23.2 
27.3 
27.5 
Issuances of AmeriGas Partners Common Units
276.6 
0 
0 
Other
1.8 
3.5 
3.5 
Net cash provided (used) by financing activities
1,278.5 
(152.1)
(213.6)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
(0.3)
(9.4)
(5.3)
Cash and cash equivalents increase (decrease)
81.4 
(22.2)
(19.4)
Cash and cash equivalents:
 
 
 
End of year
319.9 
238.5 
260.7 
Beginning of year
238.5 
260.7 
280.1 
Increase (decrease)
81.4 
(22.2)
(19.4)
Cash paid for:
 
 
 
Interest
168.8 
135.0 
130.5 
Income taxes
$ 33.3 
$ 48.6 
$ 128.5 
Consolidated Statements of Changes In Equity (USD $)
In Millions, unless otherwise specified
Total
Total UGI Corporation Stockholder's Equity
Common stock, without par value
Retained earnings
Accumulated other comprehensive income (loss)
Treasury stock
Noncontrolling interests
Beginning Balance at Sep. 30, 2009
 
 
 
 
 
 
$ 225.4 
Beginning Balance at Sep. 30, 2009
 
 
875.6 
804.3 
(38.9)
(49.6)
 
Common stock issued:
 
 
 
 
 
 
 
Employee and director plans
 
 
 
 
 
10.6 
 
Employee and director plans
 
 
14.4 
 
 
 
 
Dividend reinvestment plan
 
 
1.7 
 
 
0.8 
 
Reacquired common stock - employee and director plans
 
 
 
 
 
0 
 
Excess tax benefits realized on equity-based compensation
 
 
4.2 
 
 
 
 
Stock-based compensation expense
 
 
10.2 
 
 
 
 
Net losses on derivative instruments, net of tax
(16.8)
 
 
 
(37.8)
 
 
Reclassifications of net losses on derivative instruments, net of tax
(22.9)
 
 
 
37.2 
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
(18.7)
 
 
 
(18.7)
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
4.2 
 
 
 
4.2 
 
 
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets
83.3 
 
 
 
83.3 
 
 
Adjustments to reflect change in ownership of Amerigas Partners, net of tax
 
 
0 
 
0 
 
0 
Net income attributable to UGI Corporation
261.0 
 
 
261.0 
 
 
 
Cash dividends on Common Stock ($1.06, $1.02 and $0.90 per share, respectively)
 
 
 
(98.6)
 
 
 
Foreign currency losses on long-term intra-company transactions, net of tax
0 
 
 
 
 
 
 
Foreign currency translation adjustments, net of tax
(39.4)
 
 
 
(39.4)
 
 
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners
94.7 
 
 
 
 
 
94.7 
Net (losses) gainson derivative instruments
 
 
 
 
 
 
21.0 
Reclassification of net losses (gains) on derivative instruments
 
 
 
 
 
 
(14.3)
Dividends and distributions
 
 
 
 
 
 
(89.1)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
0 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
0 
Other
 
 
 
 
 
 
(0.6)
Ending Balance at Sep. 30, 2010
 
1,824.5 
906.1 
966.7 
(10.1)
(38.2)
 
Ending Balance at Sep. 30, 2010
2,061.6 
 
 
 
 
 
237.1 
Common stock issued:
 
 
 
 
 
 
 
Employee and director plans
 
 
 
 
 
9.7 
 
Employee and director plans
 
 
14.7 
 
 
 
 
Dividend reinvestment plan
 
 
2.2 
 
 
0.7 
 
Reacquired common stock - employee and director plans
 
 
 
 
 
0 
 
Excess tax benefits realized on equity-based compensation
 
 
3.8 
 
 
 
 
Stock-based compensation expense
 
 
10.6 
 
 
 
 
Net losses on derivative instruments, net of tax
(10.8)
 
 
 
(23.4)
 
 
Reclassifications of net losses on derivative instruments, net of tax
(11.8)
 
 
 
29.9 
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
0.1 
 
 
 
0.1 
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
0.6 
 
 
 
0.6 
 
 
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets
0 
 
 
 
 
 
 
Adjustments to reflect change in ownership of Amerigas Partners, net of tax
 
 
0 
 
0 
 
0 
Net income attributable to UGI Corporation
232.9 
 
 
232.9 
 
 
 
Cash dividends on Common Stock ($1.06, $1.02 and $0.90 per share, respectively)
 
 
 
(113.8)
 
 
 
Foreign currency losses on long-term intra-company transactions, net of tax
(0.8)
 
 
 
(0.8)
 
 
Foreign currency translation adjustments, net of tax
(14.0)
 
 
 
(14.0)
 
 
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners
75.3 
 
 
 
 
 
75.3 
Net (losses) gainson derivative instruments
 
 
 
 
 
 
12.6 
Reclassification of net losses (gains) on derivative instruments
 
 
 
 
 
 
(18.1)
Dividends and distributions
 
 
 
 
 
 
(94.0)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
0 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
0 
Other
 
 
 
 
 
 
0.5 
Ending Balance at Sep. 30, 2011
1,977.7 
1,977.7 
937.4 
1,085.8 
(17.7)
(27.8)
 
Ending Balance at Sep. 30, 2011
2,191.1 
 
 
 
 
 
213.4 
Common stock issued:
 
 
 
 
 
 
 
Employee and director plans
 
 
 
 
 
6.4 
 
Employee and director plans
 
 
13.6 
 
 
 
 
Dividend reinvestment plan
 
 
2.2 
 
 
0.9 
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(8.2)
 
Excess tax benefits realized on equity-based compensation
 
 
1.8 
 
 
 
 
Stock-based compensation expense
 
 
8.3 
 
 
 
 
Net losses on derivative instruments, net of tax
(127.1)
 
 
 
(67.3)
 
 
Reclassifications of net losses on derivative instruments, net of tax
(87.9)
 
 
 
54.2 
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
(11.5)
 
 
 
(11.5)
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
0.7 
 
 
 
0.7 
 
 
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets
0 
 
 
 
 
 
 
Adjustments to reflect change in ownership of Amerigas Partners, net of tax
 
 
194.4 
 
1.9 
 
(321.4)
Net income attributable to UGI Corporation
199.4 
 
 
199.4 
 
 
 
Cash dividends on Common Stock ($1.06, $1.02 and $0.90 per share, respectively)
 
 
 
(119.1)
 
 
 
Foreign currency losses on long-term intra-company transactions, net of tax
(1.7)
 
 
 
(1.7)
 
 
Foreign currency translation adjustments, net of tax
(20.6)
 
 
 
(20.6)
 
 
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners
(12.8)
 
 
 
 
 
(12.8)
Net (losses) gainson derivative instruments
 
 
 
 
 
 
(59.8)
Reclassification of net losses (gains) on derivative instruments
 
 
 
 
 
 
33.7 
Dividends and distributions
 
 
 
 
 
 
(182.1)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
276.6 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
1,132.6 
Other
 
 
 
 
 
 
5.5 
Ending Balance at Sep. 30, 2012
2,233.1 
2,233.1 
1,157.7 
1,166.1 
(62.0)
(28.7)
 
Ending Balance at Sep. 30, 2012
$ 3,318.8 
 
 
 
 
 
$ 1,085.7 
Consolidated Statements of Changes In Equity (Parenthetical) (Retained earnings, USD $)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Retained earnings
 
 
 
Cash dividends on Common Stock per share
$ 1.06 
$ 1.02 
$ 0.90 
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 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, its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, as a result of the January 12, 2012, acquisition of Heritage Propane from Energy Transfer Partners, L.P. ("ETP"), AmeriGas OLP's principal operating subsidiary, Heritage Operating, L.P. ("HOLP"). In addition, from January 12, 2012, through the date of its merger with and into AmeriGas OLP in August 2012, we also conducted business through AmeriGas OLP's operating subsidiary, Titan Propane LLC ("Titan LLC") which was also acquired on January 12, 2012, from ETP (see Note 4 for additional information about the acquisition of Heritage Propane). AmeriGas OLP, HOLP and Titan LLC (prior to its merger with and into AmeriGas OLP), are 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 September 30, 2012, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners, and held 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 39,477,103 Common Units held by the public and 29,567,362 Common Units held by ETP as a result of the acquisition of 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 electric 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 first-tier subsidiaries.
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas." 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
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
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.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the general public’s and ETP's 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. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2012. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $80.0 and $72.4 at September 30, 2012 and 2011, respectively.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.
For additional information regarding the effects of rate regulation on our utility operations, see Note 8.
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
•
Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded contract.
•
Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swap and option contracts, interest rate swaps and interest rate protection agreements, foreign currency forward contracts, financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts that do not qualify for Level 1.
•
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2012 or 2011.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 16 for additional information on fair value measurements.
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
A substantial portion of our derivative financial instruments are designated and qualify as cash flow hedges or net investment hedges. In addition, gains and losses on certain derivative financial instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Certain of our derivative financial instruments, although generally effective as economic hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments, other than net investment hedges, are included in cash flows from operating activities. Cash flows from net investment hedges are included in cash flows from investing activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 17.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our International Propane operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and International Propane delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes
AmeriGas Partners and the Operating Partnerships are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating Partnerships have subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income tax expense when such property is placed in service.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2012, Fiscal 2011 and Fiscal 2010, interest (income) expense of $(0.1), $0.2 and $(0.2), respectively, was recognized in income taxes on the Consolidated Statements of Income.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2012, Fiscal 2011 and Fiscal 2010:
(Thousands of shares)
 
2012 (a)
 
2011(a)
 
2010
Average common shares outstanding for basic computation
 
112,581

 
111,674

 
109,588

Incremental shares issuable for stock options and common stock awards
 
851

 
1,270

 
923

Average common shares outstanding for diluted computation
 
113,432

 
112,944

 
110,511


(a)
For Fiscal 2012 and Fiscal 2011, there were approximately 81 shares and 3,700 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share because their effect was antidilutive.
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges, actuarial gains and losses on postretirement benefit plans and foreign currency translation adjustments and foreign currency long-term intra-company transactions. Other comprehensive income in Fiscal 2010 also includes the reclassification of $83.3 of actuarial losses associated with a UGI Utilities’ pension plan to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of such pension plan’s funded status (see Note 8).
The components of AOCI at September 30, 2012 and 2011 follow:
 
Postretirement
Benefit Plans
 
Derivative
Instruments Net
Losses
 
Foreign
Currency
Translation
Adjustments
 
Total
Balance, September 30, 2012
$
(22.9
)
 
$
(58.8
)
 
$
19.7

 
$
(62.0
)
Balance, September 30, 2011
$
(12.1
)
 
$
(47.6
)
 
$
42.0

 
$
(17.7
)


Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 25 to 35 years for electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.2% in Fiscal 2012, 2.3% in Fiscal 2011 and 2.5% in Fiscal 2010. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2012, 2.6% in Fiscal 2011 and 2.6% in Fiscal 2010. When Utilities retire depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets
In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. We review identifiable intangible assets subject to amortization for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested annually for impairment and written down to fair value as required.
We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit's goodwill exceeds the implied fair value of that goodwill. We determine fair values for each of our reporting units generally using discounted cash flows to establish fair values unless market values are available. The Company adopted new accounting guidance regarding goodwill impairment during Fiscal 2012 which permits us, in certain circumstances, to perform a qualitative approach to determine if it is more likely than not that the carrying value of a reporting unit is greater than its fair value (see Note 3).
No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2012, Fiscal 2011 or Fiscal 2010. No amortization expense is included in cost of sales in the Consolidated Statements of Income (see Note 11).
Impairment of Long-Lived Assets
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2012, Fiscal 2011 or Fiscal 2010.

Deferred Debt Issuance Costs
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $46.6 and $30.7 at September 30, 2012 and 2011, respectively. We are amortizing these costs over the terms of the related debt. The increase in deferred debt issuance costs during Fiscal 2012 largely resulted from the Partnership's issuance of debt to fund the acquisition of Heritage Propane (see Notes 4 and 5).
Refundable Tank and Cylinder Deposits
Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $205.1 and $204.4 at September 30, 2012 and 2011, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. 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 CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 15.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity in our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.
We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).
For additional information on our equity-based compensation plans and related disclosures, see Note 13.
Accounting Changes
Accounting Changes
Accounting Changes

Indefinite-Lived Intangible Asset Impairment. In July 2012, the FASB issued guidance on testing indefinite-lived intangible assets, other than goodwill, for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount. If the entity determines on the basis of qualitative factors that the fair value of the indefinite-lived intangible asset is not more likely than not impaired, the entity would not need to calculate the value of the asset. The new guidance does not revise the requirement to test indefinite-lived intangible assets annually for impairment. In addition, the new guidance does not amend the requirement to test these assets for impairment between annual tests if there is a change in events or circumstances. We adopted the new guidance in the fourth quarter of Fiscal 2012.
Goodwill Impairment. In September 2011, the FASB issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. We adopted the new guidance for Fiscal 2012.
Fair Value Measurements. In May 2011, the FASB issued new guidance on fair value measurements and related disclosure requirements. The new guidance results in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance became effective for our interim period ending March 31, 2012, and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.
New Accounting Standard Not Yet Adopted
Disclosures about Offsetting Assets and Liabilities. In December 2011, the 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.
Acquisitions and Dispositions
Acquisitions and Dispositions
Acquisitions & Dispositions
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,598.2, comprising $1,465.6 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of $1,132.6 (the “Heritage Acquisition”). The Acquisition Date cash consideration for the Heritage Acquisition was subject to purchase price adjustments based on working capital, cash and the amount of indebtedness of Heritage Propane (“Working Capital Adjustment”) and certain excess cash proceeds resulting from ETP's sale of HOLP's former cylinder exchange business (“HPX”). In April 2012, AmeriGas Partners paid $25.5 of additional cash consideration as a result of the Working Capital Adjustment and in June 2012, AmeriGas Partners received $18.9 in cash representing the excess cash proceeds from the sale of HPX. 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 (“ETP GP”), and Heritage ETC, L.P. (the “Contributor”). The acquired business conducted its propane operations in 41 states through HOLP and Titan LLC. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The Heritage Acquisition is consistent with our growth strategies, one of which is to grow our core business through acquisitions.
Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and the sole member of Titan LLC; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. As a result of the Heritage Acquisition, the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, contributed 934,327 Common Units to the Partnership having a fair value of $41.7. These Common Units were subsequently cancelled.
The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes”). For further information on the 6.75% Notes and the 7.00% Notes, see Note 5.

The Consolidated Balance Sheet at September 30, 2012, reflects the final allocation of the purchase price to the assets acquired and liabilities assumed for the Heritage Propane business combination. The purchase price paid comprises AmeriGas Partners Common Units issued having a fair value of $1,132.6, and total cash consideration of $1,472.2 including cash acquired of $60.7. The fair value of the AmeriGas Partners Common Units issued to ETP was based on the closing price on the Acquisition Date subject to a discount to reflect certain contractual transfer restrictions for a period of approximately twelve months. The purchase price allocation is as follows:
Assets acquired:
 
Current assets
$
301.4

Property, plant & equipment
890.2

Customer relationships (estimated useful life of 15 years)
418.9

Trademarks and tradenames
91.1

Goodwill
1,217.7

Other assets
9.9

Total assets acquired
$
2,929.2

 
 
Liabilities assumed:
 
Current liabilities
$
(238.1
)
Long-term debt
(62.9
)
Other noncurrent liabilities
(23.4
)
Total liabilities assumed
$
(324.4
)
Total
$
2,604.8


Goodwill associated with the Heritage Acquisition principally results from synergies expected from combining the operations and from assembled workforce. The tax effects of such goodwill will be realized over a fifteen-year period. We allocated the purchase price of the acquisition to identifiable intangible assets based on estimated fair values.  Tradenames and trademarks were valued using the relief from royalty method and customer relationships were valued using a discounted cash flow method. The relief from royalty method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections and are the assumptions most sensitive and susceptible to change as they require significant management judgment. The key assumptions used in the customer relationship discounted cash flow method include discount rates, growth rates and cash flow projections and are the assumptions most sensitive and susceptible to change as they require significant management judgment. We allocated the purchase price of the acquisition to property, plant and equipment based on estimated fair values primarily using replacement cost and market value methods.
Transaction expenses associated with the Heritage Acquisition, which are included in operating and administrative expenses in the Consolidated Statement of Income, totaled $5.3 for Fiscal 2012. The results of operations of Heritage Propane are included in the Consolidated Statements of Income since the Acquisition Date. As a result of achieving planned strategic operating and marketing milestones, it is impracticable to determine the impact of the Heritage Propane operations on the revenues and earnings of the Company.
The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2010:

 
 
Fiscal 2012
 
Fiscal 2011
Revenues
 
$
7,010.9

 
$
7,522.0

Net income attributable to UGI Corporation
 
$
197.6

 
$
223.5

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic
 
$
1.76

 
$
2.00

Diluted
 
$
1.74

 
$
1.98


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.
In accordance with the Contribution Agreement, ETP and the Partnership entered into a transition services agreement and ETP, HPX and the Partnership also entered into a transition services agreement (collectively, the “TSA”) whereby each party may be a provider and receiver of certain services to the other. The principal services include general business continuity, information technology, accounting, tax and administrative services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed by the parties. Amounts associated with such services were not material.
In October 2011, we acquired Shell’s LPG distribution businesses in (1) Belgium, the Netherlands, Luxembourg through Antargaz; (2) Denmark, Finland, Norway and Sweden through Flaga; and (3) the United Kingdom through UGI Midlands Limited (a second-tier subsidiary of Enterprises), for €133.6 ($179.0) in cash ("Shell Transaction"). Also during Fiscal 2012, AmeriGas OLP acquired a number of smaller domestic retail propane distribution businesses for $13.5 in cash. During Fiscal 2011, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.0 in cash, and Flaga acquired a propane distribution business in Poland for total cash consideration of approximately $19.0. During Fiscal 2010, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.3 in cash, and our International Propane operations acquired propane distribution businesses in Denmark, Hungary and Switzerland, and an additional 46% interest in our retail business in China, for total cash consideration of $48.7.
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, LLC (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 in cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5 pre-tax gain on the sale which amount is included in other income, net in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2. Atlantic Energy’s income from operations was not material in Fiscal 2010.
Debt
Debt
Debt
Long-term debt comprises the following at September 30:

 
2012
 
2011
AmeriGas Propane:
 
 
 
AmeriGas Partners Senior Notes:
 
 
 
   7.00%, due May 2022
$
980.8

 
$
—

   6.75%, due May 2020
550.0

 
—

   6.50%, due May 2021
270.0

 
470.0

   6.25%, due August 2019
450.0

 
450.0

HOLP Senior Secured Notes
55.6

 
—

Other
21.6

 
13.5

Total AmeriGas Propane
2,328.0

 
933.5

International Propane:
 
 
 
Antargaz 2011 Senior Facilities term loan, due through March 2016
488.7

 
508.7

Flaga term loan, due through September 2016
51.4

 
53.5

Flaga term loan, due October 2016
24.6

 
—

Flaga term loan, due through June 2014
3.6

 
5.6

Other
5.6

 
3.5

Total International Propane
573.9

 
571.3

UGI Utilities:
 
 
 
Senior Notes:
 
 
 
6.375%, due September 2013
108.0

 
108.0

5.75%, due September 2016
175.0

 
175.0

6.21%, due September 2036
100.0

 
100.0

Medium- Term Notes:
 
 
 
5.53%, due September 2012
—

 
40.0

5.37%, due August 2013
25.0

 
25.0

5.16%, due May 2015
20.0

 
20.0

7.37%, due October 2015
22.0

 
22.0

5.64%, due December 2015
50.0

 
50.0

6.17%, due June 2017
20.0

 
20.0

7.25%, due November 2017
20.0

 
20.0

5.67%, due January 2018
20.0

 
20.0

6.50%, due August 2033
20.0

 
20.0

6.13%, due October 2034
20.0

 
20.0

Total UGI Utilities
600.0

 
640.0

Other
12.4

 
12.9

Total long-term debt
3,514.3

 
2,157.7

Less: current maturities
(166.7
)
 
(47.4
)
Total long-term debt due after one year
$
3,347.6

 
$
2,110.3



Scheduled principal repayments of long-term debt due in fiscal years 2013 to 2017 follow:

 
2013
 
2014
 
2015
 
2016
 
2017
AmeriGas Propane
$
30.0

 
$
10.9

 
$
8.9

 
$
6.5

 
$
4.6

UGI Utilities
133.0

 
—

 
20.0

 
247.0

 
20.0

International Propane
2.5

 
52.9

 
45.0

 
448.2

 
25.1

Other
0.6

 
0.6

 
0.5

 
0.6

 
0.6

Total
$
166.1

 
$
64.4

 
$
74.4

 
$
702.3

 
$
50.3



AmeriGas Propane
In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, the “Issuers” issued $550 principal amount of 6.75% Notes due May 2020 and $1,000 principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the 6.75% Notes, in whole or in part, at any time on or after May 20, 2016, and to redeem the 7.00% Notes, in whole or in part, at any time on or after May 20, 2017, subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. On or prior to May 20, 2015, the Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of each of the 6.75% Notes and the 7.00% Notes with the proceeds of an AmeriGas Partners registered public equity offering. The 6.75% Notes and the 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners’ existing Senior Notes. In connection with the Heritage Acquisition, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent Residual Support Agreement ("CRSA") with ETP pursuant to which ETP will provide contingent, residual support of $1,500 of debt ("Supported Debt" as defined in the CRSA).
On March 28, 2012, AmeriGas Partners announced that holders of approximately $383.5 in aggregate principal amount of outstanding 6.50% Senior Notes due May 2021 (the “6.50% Notes”), representing approximately 82% of the total $470 principal amount outstanding, had validly tendered their notes in connection with the Partnership’s March 14, 2012, offer to purchase for cash up to $200 of the 6.50% Notes. Tendered 6.50% Notes in the amount of $200 were redeemed on March 28, 2012, at an effective price of 105% using an approximate proration factor of 52.3% of total notes tendered. During June 2012, AmeriGas Partners repurchased approximately $19.2 aggregate principal amount of outstanding 7.00% Notes. The Partnership recorded a net loss of $13.3 on these extinguishments of debt which amount is reflected on the Fiscal 2012 Consolidated Statement of Income under the caption loss on extinguishments of debt. The net loss reduced net income attributable to UGI Corporation by $2.2 during Fiscal 2012.
In January 2011, AmeriGas Partners issued $470 principal amount of 6.50% Notes due May 2021. The proceeds from the issuance of the 6.50% Notes were used in February 2011 to repay AmeriGas Partners’ $415 principal amount of its 7.25% Senior Notes due May 2015 pursuant to a tender offer and subsequent redemption. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these extinguishments of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption loss on extinguishments of debt. This loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.
In August 2011, AmeriGas Partners issued $450 principal amount of 6.25% Senior Notes due August 2019 (the “6.25% Senior Notes”). The proceeds from the issuance of the 6.25% Senior Notes were used to repay $350 principal amount of AmeriGas Partners 7.125% Senior Notes due May 2016 pursuant to a tender offer and subsequent redemption. The Partnership incurred a loss of $19.3 on this extinguishment of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption loss on extinguishments of debt. This loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.
The 6.50% and 6.25% Senior Notes generally may be redeemed at our option (pursuant to a tender offer). A redemption premium applies through May 2019 (with respect to the 6.50% Notes) and through August 2017 (with respect to the 6.25% Notes). In addition, in the event that AmeriGas Partners completes a registered public offering of Common Units, the Partnership may, at its option, redeem up to 35% of the outstanding 6.50% Notes (through May 20, 2014) or 35% of the outstanding 6.25% Notes (through August 20, 2014), each at a premium. AmeriGas Partners may, under certain circumstances involving excess sales proceeds from the disposition of assets not reinvested in the business or a change of control, be required to offer to prepay its 6.50% and 6.25% Senior Notes.
As a result of the Heritage Acquisition, the Partnership's total long-term debt at September 30, 2012, includes $62.5 of Heritage Propane long-term debt including $55.6 of HOLP Senior Secured Notes (including unamortized premium of $4.4). The face interest rates on the HOLP Notes range from 7.26% to 8.87% with an effective interest rate of 6.75%. The HOLP Senior Secured Notes are collateralized by HOLP's receivables, contracts, equipment, inventory, general intangibles, cash and HOLP capital stock.
In June 2011, AmeriGas OLP entered into an unsecured credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325 (including a $100 sublimit for letters of credit). During Fiscal 2012, the AmeriGas 2011 Credit Agreement was amended to, among other things, increase the total amount available to $525, extend its expiration date to October 2016, and amend certain financial covenants as a result of the Heritage Acquisition. The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement.
At September 30, 2012 and 2011, there were $49.9 and $95.5 of borrowings outstanding under the AmeriGas 2011 Credit Agreement, respectively, which amounts are reflected as bank loans on the Consolidated Balance Sheets. The weighted-average interest rates on the AmeriGas 2011 Credit Agreement borrowings at September 30, 2012 and 2011, were 2.72% and 2.29%, respectively. At September 30, 2012 and 2011, issued and outstanding letters of credit, which reduce available borrowings under the AmeriGas 2011 Credit Agreement, totaled $47.9 and $35.7, respectively.
Restrictive Covenants. The AmeriGas Partners Senior Notes restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to Available Cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2012, these restrictions did not limit the amount of Available Cash. See Note 14 for definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”).
The HOLP Senior Secured Notes contain restrictive covenants including the maintenance of financial covenants and limitations on the disposition of assets, changes in ownership, additional indebtedness, restrictive payments and the creation of liens. The financial covenants require HOLP to maintain a ratio of combined Funded Indebtedness to combined EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of combined EBITDA to combined Interest Expense (as defined).
The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that the Partnership and AmeriGas OLP maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined, as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
International Propane
In March 2011, Antargaz entered into a five-year Senior Facilities Agreement with a consortium of banks (“2011 Senior Facilities Agreement”) consisting of a €380 variable-rate term loan and a €40 credit facility. The proceeds from the 2011 Senior Facilities Agreement term loan were used to repay Antargaz’ then-existing Senior Facilities Agreement term loan due March 2011.
Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Borrowings under the 2011 Senior Facilities Agreement bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. There were no amounts outstanding under the 2011 Senior Facilities Agreement at September 30, 2012 or 2011. The margin on the term loan and credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2012, the effective interest rate on Antargaz’ term loan was 4.66%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables.
In December 2011, Flaga entered into a €19.1 euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2012, was 4.35%.
In September 2011, Flaga entered into a €40 euro-based variable-rate term loan of which €26.7 matures in August 2016 and €13.3 matures in September 2016. A portion of the proceeds from the loan were used to repay its €24.0 euro-based variable-rate term loan which matured during Fiscal 2011. The €40 euro-based term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. The margin on such borrowings ranges from 0.23% to 2.55% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rates on Flaga's term loans at September 30, 2012 and 2011, were 5.18% and 4.76%, respectively.
As of September 30, 2012 and 2011, Flaga also has a euro-based variable-rate term loan which had outstanding principal balances of €2.8 ($3.6) and €4.2 ($5.6), respectively. This term loan matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 2.625% to 3.50% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined on a UGI consolidated basis. Semi-annual principal payments of €0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. As of September 30, 2012 and 2011, the effective interest rate on this term loan was 5.04%.
At September 30, 2012, Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 multi-currency working capital facility which includes an uncommitted €6 overdraft facility (the “Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 (the “Euro Working Capital Facility”). The Multi-Currency Working Capital Facility expires in September 2014 and the Euro Working Capital Facility expires in September 2013. At September 30, 2012 and 2011, there were €11.9 ($15.3) and €12.3 ($16.5) of borrowings outstanding under the Flaga Credit Agreements. These amounts are reflected as bank loans on the Consolidated Balance Sheets.
Borrowings under the Flaga Credit Agreements generally bear interest at market rates (a daily euro-based rate or three-month euribor rates) plus a margin. The weighted-average interest rates on Flaga Credit Agreements borrowings at September 30, 2012 and 2011, were 2.31% and 3.39%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the Flaga Credit Agreements, totaled €19.2 ($24.7) and €12.1 ($16.2) at September 30, 2012 and 2011, respectively.
Restrictive Covenants and Guarantees. The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00. Under this agreement, Antargaz is generally permitted to make restricted payments, such as dividends if no event of default exists or would exist upon payment of such restricted payment. UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement.
The Flaga term loans, working capital facilities and interest rate swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
UGI Utilities
UGI Utilities has an unsecured credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit) which expires in October 2015. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had $9.2 of borrowings outstanding under the UGI Utilities 2011 Credit Agreement at September 30, 2012 which amount is reflected in bank loans on the Consolidated Balance Sheet. UGI Utilities had no borrowings outstanding under the UGI Utilities 2011 Credit Agreement at September 30, 2011. The weighted-average interest rate on UGI Utilities 2011 Credit Agreement borrowings at September 30, 2012 was 1.21%. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities 2011 Credit Agreement, totaled $2.0 at September 30, 2012 and 2011.
Restrictive Covenants. UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Energy Services
Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 (including a $50 sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. In addition, 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 2.00 to 1.00. There were $85 and $10 of borrowings outstanding under the Energy Services Credit Agreement at September 30, 2012 and 2011, respectively. These amounts are reflected as bank loans on the Consolidated Balance Sheets.
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 3.0% for each Eurodollar Revolving Loan (as defined in the Energy Services Credit Agreement) or (ii) the Alternate Base Rate plus 2.0%. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%. The weighted-average interest rate on the Energy Services Credit Agreement borrowings at September 30, 2012 and 2011, was 3.25%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.
Restrictive Covenants. The Energy Services Credit Agreement restricts the ability of Energy Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and guaranty obligations, create liens, make acquisitions or investments, make certain dividend or other distributions and make any material changes to the nature of its businesses. 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 $250; and a minimum Consolidated Net Worth, as defined, of $150.
Energy Services also has a $200 receivables securitization facility (see Note 18).
Restricted Net Assets
At September 30, 2012, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,400.
Income Taxes
Income Taxes
Income Taxes
Income before income taxes comprises the following:

 
2012
 
2011
 
2010
Domestic
$
227.3

 
$
388.8

 
$
448.8

Foreign
58.9

 
50.2

 
74.5

Total income before income taxes
$
286.2

 
$
439.0

 
$
523.3



The provisions for income taxes consist of the following:

 
2012
 
2011
 
2010
Current expense (benefit):
 
 
 
 
 
Federal
$
(10.4
)
 
$
24.4

 
$
60.5

State
11.2

 
14.5

 
20.4

Foreign
18.8

 
15.0

 
25.8

Investment tax credit
(2.9
)
 
(5.8
)
 
(1.7
)
Total current expense
16.7

 
48.1

 
105.0

Deferred expense (benefit):
 
 
 
 
 
Federal
76.2

 
79.3

 
54.5

State
5.2

 
2.4

 
6.4

Foreign
1.8

 
1.4

 
2.1

Investment tax credit amortization
(0.3
)
 
(0.4
)
 
(0.4
)
Total deferred expense
82.9

 
82.7

 
62.6

Total income tax expense
$
99.6

 
$
130.8

 
$
167.6



Federal income taxes for Fiscal 2012 and Fiscal 2010 are net of foreign tax credits of $5.2 and $2.1, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

 
2012
 
2011
 
2010
U.S. federal statutory tax rate
35.0
 %
 
35.0
 %
 
35.0
 %
Difference in tax rate due to:
 
 
 
 
 
Noncontrolling interests not subject to tax
1.3

 
(6.0
)
 
(6.4
)
State income taxes, net of federal benefit
3.8

 
2.2

 
3.5

Valuation allowance adjustments
(1.6
)
 
—

 
(0.2
)
Effects of foreign operations
(3.6
)
 
(0.6
)
 
(0.6
)
Other, net
(0.1
)
 
(0.8
)
 
0.7

Effective tax rate
34.8
 %
 
29.8
 %
 
32.0
 %


The effects of foreign operations in the table above for Fiscal 2012 reflects the impact of tax efficient structuring of certain of our international operations and, as a result of the Shell Transaction, also reflects a greater proportion of pretax income in countries in which the statutory income tax rate is less than the U.S. statutory tax rate. The tax restructuring of certain of our international operations also permitted us to reduce our foreign tax credit valuation allowance by $4.6 during Fiscal 2012 which is included as valuation allowance adjustments in the table above.
Earnings of the Company's foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company's tax provision reflects the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2012, Fiscal 2011 and Fiscal 2010, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $3.2, $7.9 and $2.5, respectively. The state tax flow through amounts in Fiscal 2012 and Fiscal 2011 reflect the impact of 2010 U.S. Federal tax legislation that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property is placed in service before 2012. This legislation was also permitted for Pennsylvania state corporate income tax purposes.
Deferred tax liabilities (assets) comprise the following at September 30:
 
2012
 
2011
Excess book basis over tax basis of property, plant and equipment
$
582.0

 
$
490.4

Investment in AmeriGas Partners
293.2

 
172.7

Intangible assets and goodwill
61.2

 
52.1

Utility regulatory assets
140.4

 
124.7

Foreign currency translation adjustment
3.6

 
8.5

Other
6.8

 
7.2

Gross deferred tax liabilities
1,087.2

 
855.6

 
 
 
 
Pension plan liabilities
(72.7
)
 
(62.8
)
Employee-related benefits
(43.0
)
 
(42.7
)
Operating loss carryforwards
(38.0
)
 
(31.8
)
Foreign tax credit carryforwards
(55.5
)
 
(60.1
)
Utility regulatory liabilities
(11.8
)
 
(12.4
)
Derivative financial instruments
(37.7
)
 
(30.5
)
Other
(31.9
)
 
(32.9
)
Gross deferred tax assets
(290.6
)
 
(273.2
)
Deferred tax assets valuation allowance
81.6

 
81.9

Net deferred tax liabilities
$
878.2

 
$
664.3



At September 30, 2012, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $50.2 and $5.3, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $213.3 and expire through 2032. We also have operating loss carryforwards of $18.6 for certain operations of AmeriGas Propane that expire through 2032. At September 30, 2012, deferred tax assets relating to operating loss carryforwards include $12.1 for Flaga, $1.8 for Antargaz, $0.9 for UGI International Holdings BV, $5.2 for AmeriGas Propane and $17.9 for certain other subsidiaries. A valuation allowance of $17.2 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $1.0 was provided for certain acquisition loss carryforwards for certain operations of AmeriGas Propane because it is more likely than not that these assets will expire unused. A valuation allowance of $7.9 was also provided for deferred tax assets related to certain operations of Antargaz, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity.
We have foreign tax credit carryforwards of approximately $55.5 expiring through 2022 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets decreased by $0.3 in Fiscal 2012 due to a decrease in unusable foreign tax credits of $4.6 partially offset by adjustments to unusable net operating losses obtained in connection with overseas acquisitions of $1.7, an increase in unusable state operating losses of $1.6, and unusable net operating losses in connection with an AmeriGas Propane acquisition of $1.0.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European countries. Our U.S. federal income tax returns are settled through the 2009 tax year, our French tax returns are settled through the 2008 tax year, our Belgian tax returns are settled through 2007 and our Netherlands tax returns are settled through 2004. Our Austrian tax returns are settled through 2008 and our other central and eastern European tax returns are effectively settled for various years from 2005 to 2010. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.
As of September 30, 2012, we have unrecognized income tax benefits totaling $3.1 including related accrued interest of $0.2. If these unrecognized tax benefits were subsequently recognized, $1.9 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 2012, are $1.1 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. There are no expected changes in unrecognized tax benefits and related interest in the next twelve months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

Balance at September 30, 2009
$
2.3

Additions for tax positions of the current year
4.3

Reductions as a result of tax positions taken in prior years
(0.2
)
Settlements with tax authorities
(1.0
)
Balance at September 30, 2010
5.4

Additions for tax positions of the current year
0.4

Additions for tax positions of prior years
1.0

Settlements with tax authorities
(0.5
)
Balance at September 30, 2011
6.3

Additions for tax positions of the current year
0.5

Additions for tax positions of prior years
0.6

Settlements with tax authorities
(4.5
)
Balance at September 30, 2012
$
2.9

Employee Retirement Plans
Employee Retirement Plans
Employee Retirement 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. Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans covering these employees ("U.S. Pension Plans Merger"). The Company's two U.S. pension plans prior to the Pension Plans Merger, and the single U.S. pension plan after the Pension Plans Merger, are hereafter referred to as the "U.S. Pension Plan."
We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the Antargaz plans, such amounts are not material.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2012 and 2011. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.

 
Pension
Benefits
 
Other Postretirement
Benefits
 
2012
 
2011
 
2012
 
2011
Change in benefit obligations:
 
 
 
 
 
 
 
Benefit obligations — beginning of year
$
462.9

 
$
471.8

 
$
20.5

 
$
22.9

Service cost
9.3

 
8.8

 
0.4

 
0.4

Interest cost
25.1

 
24.1

 
1.1

 
1.1

Actuarial loss (gain)
82.4

 
(22.0
)
 
3.2

 
(2.4
)
Plan amendments
0.1

 
—

 
1.0

 
(0.1
)
Acquisitions
14.6

 
—

 
—

 
—

Foreign currency
(0.7
)
 
(0.1
)
 
(0.1
)
 
—

Benefits paid
(20.3
)
 
(19.7
)
 
(1.4
)
 
(1.4
)
Benefit obligations — end of year
$
573.4

 
$
462.9

 
$
24.7

 
$
20.5

 
 
 
 
 
 
 
 
Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets — beginning of year
$
290.0

 
$
287.9

 
$
9.8

 
$
10.0

Actual gain on plan assets
51.2

 
2.6

 
1.7

 
0.1

Foreign currency
(0.5
)
 
—

 
—

 
—

Employer contributions
32.2

 
19.2

 
1.1

 
1.1

Acquisitions
17.3

 
—

 
—

 
—

Benefits paid
(20.3
)
 
(19.7
)
 
(1.4
)
 
(1.4
)
Fair value of plan assets — end of year
$
369.9

 
$
290.0

 
$
11.2

 
$
9.8

Funded status of the plans — end of year
$
(203.5
)
 
$
(172.9
)
 
$
(13.5
)
 
$
(10.7
)
 
 
 
 
 
 
 
 
(Liabilities) recorded in the balance sheet:
 
 
 
 
 
 
 
Unfunded liabilities — included in other current liabilities
$
(15.8
)
 
$
(27.6
)
 
$
(0.6
)
 
$
(0.6
)
Unfunded liabilities — included in other noncurrent liabilities
(187.7
)
 
(145.3
)
 
(12.9
)
 
(10.1
)
Net amount recognized
$
(203.5
)
 
$
(172.9
)
 
$
(13.5
)
 
$
(10.7
)
 
 
 
 
 
 
 
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
 
 
 
 
Prior service credit
$
(0.1
)
 
$
(0.2
)
 
$
(0.1
)
 
$
(0.1
)
Net actuarial loss (gain)
25.3

 
13.6

 
0.4

 
(0.8
)
Total
$
25.2

 
$
13.4

 
$
0.3

 
$
(0.9
)
 
 
 
 
 
 
 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
1.5

 
$
1.8

 
$
(2.8
)
 
$
(3.2
)
Net actuarial loss
184.5

 
146.9

 
5.8

 
6.3

Total
$
186.0

 
$
148.7

 
$
3.0

 
$
3.1



In Fiscal 2013, we estimate that we will amortize approximately $15.4 of net actuarial losses and $(0.1) of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our domestic plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

 
Pension Plan
 
Other Postretirement Benefits
 
2012
 
2011 (a)
 
2010
 
2009
 
2012
 
2011
 
2010
 
2009
Weighted-average assumptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.20
%
 
5.30
%
 
5.00
%
 
5.50
%
 
4.20
%
 
5.30
%
 
5.00
%
 
5.50
%
Expected return on plan assets
7.75
%
 
8.00
%
 
8.50
%
 
8.50
%
 
5.20
%
 
5.50
%
 
5.50
%
 
5.50
%
Rate of increase in salary levels
3.25
%
 
3.50
%
 
3.75
%
 
3.75
%
 
3.25
%
 
3.50
%
 
3.75
%
 
3.75
%
______________
(a)
The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the U.S. Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011.
The ABOs for the U.S. Pension Plan were $496.4 and $415.0 as of September 30, 2012 and 2011, respectively.
Net periodic pension expense and other postretirement benefit cost includes the following components:

 
Pension Benefits
 
Other Postretirement Benefits
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Service cost
$
9.3

 
$
8.8

 
$
8.7

 
$
0.4

 
$
0.4

 
$
0.4

Interest cost
25.1

 
24.1

 
23.5

 
1.1

 
1.1

 
1.1

Expected return on assets
(26.2
)
 
(25.8
)
 
(25.8
)
 
(0.5
)
 
(0.5
)
 
(0.5
)
Curtailment gain
—

 
—

 
—

 
—

 
(3.2
)
 
—

Settlement loss
—

 
—

 
1.0

 
—

 
—

 
—

Amortization of:
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
0.2

 
0.2

 
—

 
(0.3
)
 
(0.7
)
 
(0.4
)
Actuarial loss
8.4

 
7.5

 
5.9

 
0.3

 
0.4

 
0.1

Net benefit cost (income)
16.8

 
14.8

 
13.3

 
1.0

 
(2.5
)
 
0.7

Change in associated regulatory liabilities
—

 
—

 
—

 
3.2

 
3.1

 
3.1

Net benefit cost after change in regulatory liabilities
$
16.8

 
$
14.8

 
$
13.3

 
$
4.2

 
$
0.6

 
$
3.8



U.S. Pension Plan's assets are held in trust. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2012, Fiscal 2011 and Fiscal 2010, we made cash contributions to the U.S. Pension Plan of $31.2, $18.7 and $3.4, respectively. We believe that in Fiscal 2013 we will be required to make contributions to the U.S. Pension Plan totaling approximately $16.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under GAAP. The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2013 are not expected to be material.
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
 
Pension
Benefits
 
Other
Postretirement
Benefits
Fiscal 2013
$
22.3

 
$
1.9

Fiscal 2014
23.3

 
1.9

Fiscal 2015
24.6

 
1.9

Fiscal 2016
27.4

 
1.9

Fiscal 2017
28.0

 
1.8

Fiscal 2018 - 2022
158.0

 
8.7



The assumed domestic health care cost trend rates are 7.0% for Fiscal 2013, decreasing to 5.0% in Fiscal 2017. A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2012 other postretirement benefit cost or September 30, 2012, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2012 and 2011, the PBOs of these plans were $29.5 and $25.6, respectively. We recorded net costs for these plans of $3.0 in Fiscal 2012, $3.0 in Fiscal 2011 and $2.6 in Fiscal 2010. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $11.0 and $7.6 at September 30, 2012 and 2011, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.7 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2013.
U.S. Pension Plan and VEBA Assets. The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly-traded diversified equity and fixed income mutual funds and UGI Common Stock.
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan

 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2012
 
2011
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
53.5
%
 
49.4
%
 
52.5
%
 
40.0% - 65.0%
International
10.5
%
 
10.7
%
 
12.5
%
 
7.5% - 17.5%
Total
64.0
%
 
60.1
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
36.0
%
 
39.9
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 

VEBA

 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2012
 
2011
 
 
Domestic equity investments
68.5
%
 
62.2
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
31.5
%
 
37.8
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 


Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.5% and 7.6% of U.S. Pension Plan assets at September 30, 2012 and 2011, respectively. At September 30, 2012, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.
GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee.
The fair values of the U.S. Pension Plan and VEBA trust assets at September 30, 2012 and 2011, by asset class are as follows:

 
U.S. Pension Plan
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2012:
 
 
 
 
 
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
$
188.2

 
$
—

 
$
—

 
$
188.2

International
36.9

 
—

 
—

 
36.9

Fixed income
123.3

 
—

 
—

 
123.3

Cash equivalents
—

 
3.1

 
—

 
3.1

Total
$
348.4

 
$
3.1

 
$
—

 
$
351.5

 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
$
143.1

 
$
—

 
$
—

 
$
143.1

International
31.0

 
—

 
—

 
31.0

Fixed income
113.6

 
—

 
—

 
113.6

Cash equivalents
—

 
2.0

 
—

 
2.0

Total
$
287.7

 
$
2.0

 
$
—

 
$
289.7


 
VEBA
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2012:
 
 
 
 
 
 
 
Domestic equity
$
7.7

 
$
—

 
$
—

 
$
7.7

Fixed income
3.4

 
—

 
—

 
3.4

Cash equivalents
—

 
0.1

 
—

 
0.1

Total
$
11.1

 
$
0.1

 
$
—

 
$
11.2

 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Domestic equity
$
6.1

 
$
—

 
$
—

 
$
6.1

Fixed income
3.3

 
—

 
—

 
3.3

Cash equivalents
—

 
0.4

 
—

 
0.4

Total
$
9.4

 
$
0.4

 
$
—

 
$
9.8



The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $13.7 in Fiscal 2012, $10.4 in Fiscal 2011 and $9.8 in Fiscal 2010.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:
 
2012
 
2011
Regulatory assets:
 
 
 
Income taxes recoverable
$
103.2

 
$
97.9

Underfunded pension and postretirement plans
188.2

 
150.7

Environmental costs
16.8

 
19.5

Deferred fuel and power costs
11.6

 
12.2

Removal costs, net
12.7

 
12.3

Other
5.9

 
7.8

Total regulatory assets
$
338.4

 
$
300.4

 
 
 
 
Regulatory liabilities:
 
 
 
Postretirement benefits
$
13.1

 
$
11.5

Environmental overcollections
2.9

 
4.7

Deferred fuel and power refunds
4.4

 
6.6

State tax benefits — distribution system repairs
7.4

 
6.3

Other
0.5

 
0.7

Total regulatory liabilities
$
28.3

 
$
29.8



Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs. Environmental costs represent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG and PNG expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 15). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2012, the period over which PNG and CPG expect to recover these costs will depend upon future remediation activity.
Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs (as further described below under “Electric Utility DS Rates”) 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 DS rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.
Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at September 30, 2012 and 2011 were $5.3 and $(3.1), respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities. At September 30, 2012 and 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $9.2 and $8.7, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 2012 and 2011, such gains or losses were not material.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2012, UGI Utilities expects to recover these costs over periods of 1 to 5 years.
Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above.
Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.
State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2012, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in other noncurrent liabilities on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.
Other Regulatory Matters

Distribution System Improvement Charge Legislation. On April 14, 2012, legislation enabling gas and electric utilities in Pennsylvania to seek surcharge recovery of eligible capital investment in distribution system infrastructure improvement projects became effective. The surcharge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC surcharge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures, for up to five percent of distribution rates. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff. Filings to implement a DSIC surcharge may be filed no earlier than January 2, 2013.
 
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 Staff Complaint had alleged that UGI Utilities had committed six violations of gas safety regulations and UGI Utilities' operating procedures related to its cast iron main replacement and gas odorant monitoring programs, and its emergency response to the Incident. As part of the Joint Settlement, UGI Utilities has agreed (i) to the assessment of a $0.4 civil penalty; (ii) to accelerate the time frame for UGI Utilities, CPG, and PNG to replace the remainder of its cast iron mains to 14 years, and (iii) to install odorant monitoring and injection equipment in its natural gas system at a number of supply points, but does not concede to having violated any regulation or operating procedure. Under the Joint Settlement, UGI Utilities, CPG and PNG have also agreed to not seek recovery of the related annual cost of capital return requirements through a DSIC for a period of 24 months but are permitted to retain the current 30-year timeframe for replacing the remainder of their bare steel mains. On October 31, 2012, the PUC administrative law judge issued an initial decision approving the settlement. The provisions of the Joint Settlement will become effective if the initial decision becomes final or if the PUC determines to review the initial decision and issues a final order approving the terms and conditions of the Joint Settlement without modification. The Company does not believe that the cost of complying with the requirements of the Joint Settlement will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.
CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8.0 as well as $0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $0.9 increase in revenue associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.
Electric Utility DS Rates. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”). In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009.
Transfers of Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.
On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9-mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1.
Inventories
Inventories
Inventories
Inventories comprise the following at September 30:

 
2012
 
2011
Non-utility LPG and natural gas
$
240.7

 
$
222.2

Gas Utility natural gas
57.7

 
95.6

Materials, supplies and other
58.5

 
45.2

Total inventories
$
356.9

 
$
363.0



At September 30, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying values of gas storage inventories released under the SCAAs to non-affiliates at September 30, 2012 and 2011 comprising 3.8 billion cubic feet (“bcf”) and 3.9 bcf of natural gas was $11.4 and $19.0, respectively. Effective November 1, 2012, UGI Utilities entered into two new SCAAs having terms of three years.
Property, Plant and Equipment
Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:

 
2012
 
2011
Utilities:
 
 
 
Distribution
$
2,047.8

 
$
1,951.9

Transmission
85.4

 
83.4

General and other, including work in process
162.5

 
165.7

Total Utilities
2,295.7

 
2,201.0

 
 
 
 
Non-utility:
 
 
 
Land
175.0

 
98.5

Buildings and improvements
283.3

 
214.8

Transportation equipment
246.5

 
112.6

Equipment, primarily cylinders and tanks
3,041.1

 
2,127.6

Electric generation
254.3

 
230.0

Other, including work in process
223.2

 
300.0

Total non-utility
4,223.4

 
3,083.5

Total property, plant and equipment
$
6,519.1

 
$
5,284.5

Goodwill and Intangible Assets
Goodwill and Intangible Assets
Goodwill and Intangible Assets
Goodwill and intangible assets comprise the following at September 30:

 
2012
 
2011
Goodwill (not subject to amortization)
$
2,818.3

 
$
1,562.2

Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
$
691.9

 
$
232.1

Trademarks and tradenames (not subject to amortization)
137.2

 
47.9

Gross carrying amount
829.1

 
280.0

Accumulated amortization
(170.9
)
 
(132.2
)
Intangible assets, net
$
658.2

 
$
147.8



Changes in the carrying amount of goodwill are as follows:

 
 
 
 
 
 
 
International Propane
 
 
 
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Antargaz
 
Flaga & Other
 
Corporate &
Other
 
Total
Balance September 30, 2010
$
683.1

 
$
180.1

 
$
2.8

 
$
602.7

 
$
87.0

 
$
7.0

 
$
1,562.7

Goodwill acquired
13.1

 
—

 
—

 
—

 
—

 
—

 
13.1

Purchase accounting adjustments
0.1

 
2.0

 
—

 
—

 
(3.2
)
 
—

 
(1.1
)
Foreign currency translation
—

 
—

 
—

 
(10.9
)
 
(1.6
)
 
—

 
(12.5
)
Balance September 30, 2011
696.3

 
182.1

 
2.8

 
591.8

 
82.2

 
7.0

 
1,562.2

Goodwill acquired
1,223.1

 
—

 
—

 
46.4

 
13.7

 
—

 
1,283.2

Purchase accounting adjustments
(0.2
)
 
—

 
—

 
—

 
—

 
—

 
(0.2
)
Foreign currency translation
—

 
—

 
—

 
(26.2
)
 
(0.7
)
 
—

 
(26.9
)
Balance September 30, 2012
$
1,919.2

 
$
182.1

 
$
2.8

 
$
612.0

 
$
95.2

 
$
7.0

 
$
2,818.3



We amortize customer relationships and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $44.5 in Fiscal 2012, $20.4 in Fiscal 2011 and $19.9 in Fiscal 2010. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2013 — $51.8; Fiscal 2014 — $50.5; Fiscal 2015 — $47.4; Fiscal 2016 — $41.3; Fiscal 2017 — $35.0. There were no accumulated impairment losses at September 30, 2012.
Series Preferred Stock
Series Preferred Stock
Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2012 or 2011.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2012 and 2011, there were no shares of UGI Utilities Series Preferred Stock outstanding.
Common Stock and Equity Based Compensation
Common Stock and Equity-Based Compensation
Common Stock and Equity-Based Compensation
UGI Common Stock share activity for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follows:
 
Issued
 
Treasury
 
Outstanding
Balance, September 30, 2009
115,261,294

 
(6,514,587
)
 
108,746,707

Issued:
 
 
 
 
 
Employee and director plans
139,000

 
1,390,207

 
1,529,207

Dividend reinvestment plan
—

 
97,673

 
97,673

Balance, September 30, 2010
115,400,294

 
(5,026,707
)
 
110,373,587

Issued:
 
 
 
 
 
Employee and director plans
106,800

 
1,263,065

 
1,369,865

Dividend reinvestment plan
—

 
92,570

 
92,570

Balance, September 30, 2011
115,507,094

 
(3,671,072
)
 
111,836,022

Issued:
 
 
 
 
 
Employee and director plans
117,500

 
824,925

 
942,425

Dividend reinvestment plan
—

 
104,994

 
104,994

Shares reacquired - employee and director plans
—

 
(263,020
)
 
(263,020
)
Balance, September 30, 2012
115,624,594

 
(3,004,173
)
 
112,620,421


As a result of the January 2012 issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the Heritage Acquisition and related General Partner Common Unit transactions (see Note 4), and the March 2012 issuance of 7,000,000 AmeriGas Partners Common Units pursuant to AmeriGas Partners’ public offering (see Note 14), the Company recorded a $196.3 increase in UGI Corporation stockholders’ equity (which amount is net of deferred income taxes) and an associated $321.4 pre-tax decrease in noncontrolling interests equity.

Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $14.5 ($8.7 after-tax), $15.6 ($10.3 after-tax) and $13.2 ($8.7 after-tax) in Fiscal 2012, Fiscal 2011 and Fiscal 2010, respectively.
UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “OECP”), we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards to key employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the OECP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the OECP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or SARs is 3,200,000. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. We do not expect to repurchase shares on the market for such purposes during Fiscal 2013. Beginning during Fiscal 2012, options granted under the OECP may be net exercised whereby shares equal to the option price and grantee's minimum applicable payroll tax withholding are withheld from the number of shares payable ("net exercise"). We record shares withheld under option net exercises as shares reacquired.
UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follow:
 
Shares
 
Weighted
Average
Option Price
 
Total
Intrinsic
Value
 
Weighted
Average
Contract Term
(Years)
Shares under option — September 30, 2009
7,501,493

 
$
22.74

 
$
23.2

 
6.4
Granted
1,394,300

 
$
24.37

 
 
 
 
Cancelled
(62,501
)
 
$
25.12

 
 
 
 
Exercised
(1,276,247
)
 
$
18.09

 
$
11.7

 
 
Shares under option — September 30, 2010
7,557,045

 
$
23.81

 
$
36.2

 
6.5
Granted
1,443,558

 
$
31.55

 
 
 
 
Cancelled
(235,437
)
 
$
27.79

 
 
 
 
Exercised
(1,091,987
)
 
$
20.95

 
$
11.4

 
 
Shares under option — September 30, 2011
7,673,179

 
$
25.55

 
$
15.1

 
6.2
Granted
1,508,050

 
$
29.26

 
 
 
 
Cancelled
(321,600
)
 
$
27.74

 
 
 
 
Exercised
(801,857
)
 
$
20.93

 
$
7.2

 
 
Shares under option — September 30, 2012
8,057,772

 
$
26.62

 
$
41.4

 
6.1
Options exercisable — September 30, 2010
4,706,376

 
$
22.99

 
 
 
 
Options exercisable — September 30, 2011
4,879,784

 
$
24.15

 
 
 
 
Options exercisable — September 30, 2012
5,317,698

 
$
25.32

 
$
34.2

 
5.0
Non-vested options — September 30, 2012
2,740,074

 
$
29.13

 
$
7.2

 
8.3


Cash received from stock option exercises and associated tax benefits were $16.8 and $2.3, $22.9 and $3.8, and $23.1 and $4.3 in Fiscal 2012, Fiscal 2011 and Fiscal 2010, respectively. As of September 30, 2012, there was $4.2 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2012:

 
Range of exercise prices
 
Under
$20.00
 
$20.00 -
$25.00
 
$25.01 -
$30.00
 
Over
$30.00
Options outstanding at September 30, 2012:
 
 
 
 
 
 
 
Number of options
162,300

 
2,996,470

 
3,529,044

 
1,369,958

Weighted average remaining contractual life (in years)
1.5

 
5.3

 
6.3

 
7.8

Weighted average exercise price
$
16.92

 
$
23.29

 
$
27.99

 
$
31.53

Options exercisable at September 30, 2012:
 
 
 
 
 
 
 
Number of options
162,300

 
2,546,170

 
2,164,909

 
444,319

Weighted average exercise price
$
16.92

 
$
23.12

 
$
27.26

 
$
31.60



UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.31 in Fiscal 2012, $5.40 in Fiscal 2011 and $4.49 in Fiscal 2010. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2012, Fiscal 2011 and Fiscal 2010 are as follows:

 
2012
 
2011
 
2010
Expected life of option
5.75 years
 
5.75 years
 
5.75 years
Weighted average volatility
24.7%
 
24.3%
 
24.0%
Weighted average dividend yield
3.5%
 
3.4%
 
3.3%
Expected volatility
24.7%
 
23.8% - 24.3%
 
24.0%
Expected dividend yield
3.3% - 3.7%
 
3.1% - 3.4%
 
3.3% - 3.4%
Risk free rate
0.8% - 1.1%
 
1.2% - 2.4%
 
1.7% - 3.1%


UGI Unit Awards. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and the Russell Midcap Utility Index (excluding telecommunication companies) for grants on or after January 1, 2011 (“UGI comparator group”). Based on the TSR percentile rank, grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator group is based on historical volatility.
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:

 
Grants Awarded in Fiscal
 
2012
 
2011
 
2010
Risk free rate
0.4
%
 
1.0
%
 
1.7
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
22.2
%
 
27.6
%
 
28.0
%
Dividend yield
3.5
%
 
3.2
%
 
3.3
%


The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $27.25 for Units granted in Fiscal 2012, $35.19 for Units granted in Fiscal 2011 and $22.51 for Units granted in Fiscal 2010.
The following table summarizes UGI Unit award activity for Fiscal 2012:
 
Total
 
Vested
 
Non-Vested
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
September 30, 2011
900,283

 
$
24.13

 
598,955

 
$
21.41

 
301,328

 
$
29.56

UGI Performance Units:
 
 
 
 
 
 
 
 
 
 
 
Granted
197,400

 
$
27.25

 
33,518

 
$
29.16

 
163,882

 
$
26.86

Forfeited
(51,411
)
 
$
27.94

 
—

 
$
—

 
(51,411
)
 
$
27.94

Vested
—

 
$
—

 
110,083

 
$
29.04

 
(110,083
)
 
$
29.04

Performance criteria not met
(170,481
)
 
$
27.82

 
(170,481
)
 
$
27.82

 
—

 
$
—

UGI Stock Units:
 
 
 
 
 
 
 
 
 
 
 
Granted (a)
42,445

 
$
29.69

 
40,945

 
$
29.53

 
1,500

 
$
34.06

Vested
—

 
$
—

 
—

 
$
—

 
—

 
$
—

Unit awards paid
(32,898
)
 
$
26.17

 
(32,898
)
 
$
26.17

 
—

 
$
—

September 30, 2012
885,338

 
$
24.09

 
580,122

 
$
21.72

 
305,216

 
$
28.59

(a)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2011 and Fiscal 2010 were 61,945 and 27,060, respectively.
During Fiscal 2012, Fiscal 2011 and Fiscal 2010, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
 
2012
 
2011
 
2010
UGI Performance Unit awards:
 
 
 
 
 
Number of original awards granted
210,750

 
197,917

 
193,983

Fiscal year granted
2009

 
2008

 
2007

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
—

 
142,494

 
123,169

Cash paid
$
—

 
$
7.5

 
$
2.6

 
 
 
 
 
 
UGI Stock Unit awards:
 
 
 
 
 
Number of original awards granted
32,898

 
22,400

 
—

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
21,757

 
17,545

 
—

Cash paid
$
0.2

 
$
0.2

 
$
—



During Fiscal 2012, Fiscal 2011 and Fiscal 2010, we granted UGI Unit awards representing 239,845, 285,470 and 231,710 shares, respectively, having weighted-average grant date fair values per Unit of $27.68, $34.78 and $22.69, respectively.
As of September 30, 2012, there was a total of approximately $5.2 of unrecognized compensation cost associated with 885,338 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years. The total fair values of UGI Units that vested during Fiscal 2012, Fiscal 2011 and Fiscal 2010 were $3.6, $6.8 and $5.0, respectively. As of September 30, 2012 and 2011, total liabilities of $5.0 and $6.0, respectively, associated with UGI Unit awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets.
At September 30, 2012, 1,436,672 shares of Common Stock were available for future grants under the OECP, of which up to 1,436,672 may be issued pursuant to future grants other than stock options or SARs.
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, unit appreciation rights and other Common Unit-based awards. The 2010 Propane Plan succeeded the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaced the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). The total aggregate number of Common Units that may be issued under the 2010 Propane Plan is 2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.
Recipients of AmeriGas Performance Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years ) may be higher or lower than the target number based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
As a result of the Heritage Acquisition, certain Heritage Propane employees were awarded AmeriGas Performance Units, AmeriGas Stock Units (in the form of phantom units), or a combination of AmeriGas Performance Units and AmeriGas Stock Units. The terms of the Performance Unit awards granted to Heritage Propane employees are generally the same as those described above. The AmeriGas Stock Units awards granted to Heritage employees vest in tranches with certain awards beginning to vest in January 2013 through January 2016. Certain of the AmeriGas Stock Unit awards provide for accelerated vesting under certain conditions. Under certain conditions all or a portion of these awards could be forfeited. The AmeriGas Stock Unit awards granted to Heritage Propane employees provide for the crediting of distribution equivalents to participants' accounts.
Under GAAP, AmeriGas Performance Units are equity awards with a market-based condition which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award and the award above the target, if any, which will be paid in Common Units, is accounted for as equity and the fair value of all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all limited partnerships in the peer group is based on historical volatility.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:

 
Grants Awarded in Fiscal
 
2012
 
2011
 
2010
Risk-free rate
0.4
%
 
1.0
%
 
1.7
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
23.0
%
 
34.6
%
 
35.0
%
Dividend yield
6.4
%
 
5.8
%
 
6.8
%


The General Partner granted awards under the 2010 Propane Plan representing 248,818, 49,287 and 57,750 Common Units in Fiscal 2012, Fiscal 2011 and Fiscal 2010, respectively, having weighted-average grant date fair values per Common Unit subject to award of $43.22, $53.19 and $41.39, respectively. At September 30, 2012, 2,517,419 Common Units were available for future award grants under the 2010 Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2012:
 
Total
 
Vested
 
Non-Vested
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
September 30, 2011
155,356

 
$
41.79

 
62,638

 
$
38.20

 
92,718

 
$
44.22

AmeriGas Performance Units:


 


 


 


 


 


  Granted
55,150

 
$
48.28

 
8,665

 
$
48.28

 
46,485

 
$
48.28

  Forfeited
(15,068
)
 
$
50.37

 
—

 
$
—

 
(15,068
)
 
$
50.37

  Vested
—

 
$
—

 
36,833

 
$
39.28

 
(36,833
)
 
$
39.28

  Performance criteria not met
(48,633
)
 
$
32.17

 
(48,633
)
 
$
32.17

 
—

 
$
—

AmeriGas Stock Units:
 
 
 
 
 
 
 
 
 
 
 
  Granted
193,668

 
$
41.77

 
66,244

 
$
41.81

 
127,424

 
$
41.76

  Forfeited
(10,360
)
 
$
41.42

 
—

 
$
—

 
(10,360
)
 
$
41.42

  Vested
—

 
$
—

 
6,050

 
$
35.05

 
(6,050
)
 
$
35.05

  Awards paid
(66,146
)
 
$
40.72

 
(66,146
)
 
$
40.72

 
—

 
$
—

September 30, 2012
263,967

 
$
44.70

 
65,651

 
$
45.42

 
198,316

 
$
44.47



During Fiscal 2012, Fiscal 2011 and Fiscal 2010, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:

 
2012 (a)
 
2011
 
2010
Number of Common Units subject to original awards granted
60,200

 
41,064

 
49,650

Fiscal year granted
2009

 
2008

 
2007

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued
3,500

 
35,787

 
42,121

Cash paid
$
0.1

 
$
1.2

 
$
1.2


(a) In addition, 40,516 AmeriGas Stock Units, and $0.9 in cash, were paid to Heritage Propane employees associated with awards granted in Fiscal 2012.

As of September 30, 2012, there was a total of approximately $3.0 of unrecognized compensation cost associated with 263,967 Common Units subject to award that is expected to be recognized over a weighted-average period of 2.0 years. The total fair value of Common Unit-based awards that vested during Fiscal 2012, Fiscal 2011 and Fiscal 2010 was $5.1, $2.0 and $2.0, respectively. As of September 30, 2012 and 2011, total liabilities of $1.1 and $1.2 associated with Common Unit-based awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets.
Partnership Distributions and Common Unit Offering
Partnership Distributions and Common Unit Offering
Partnership Distributions and Common Unit Offering
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter. Available Cash generally means:

1.
all cash on hand at the end of such quarter,
2.
plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter,
3.
less the amount of cash reserves established by the General Partner in its reasonable discretion.
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.
During Fiscal 2012, Fiscal 2011 and Fiscal 2010, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. The total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $19.7 in Fiscal 2012, $9.0 in Fiscal 2011 and $6.9 in Fiscal 2010. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2012, Fiscal 2011 and Fiscal 2010 of $13.0, $5.0 and $3.0, respectively.
In March 2012, AmeriGas Partners sold 7,000,000 Common Units in an underwritten public offering at a public offering price of $41.25 per unit. The net proceeds of the public offering totaling $276.6 and the associated capital contributions from the General Partner totaling $2.8 were used to redeem $200 of 6.50% Senior Notes pursuant to a tender offer, to reduce bank loan borrowings and for general partnership purposes.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Commitments
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $77.9 in Fiscal 2012, $69.8 in Fiscal 2011 and $70.6 in Fiscal 2010.
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 2017
AmeriGas Propane
$
62.0

 
$
48.8

 
$
39.4

 
$
30.3

 
$
23.1

 
$
63.9

UGI Utilities
5.4

 
4.3

 
3.4

 
3.1

 
1.8

 
2.3

International Propane
8.0

 
5.6

 
3.4

 
2.6

 
2.4

 
2.3

Other
2.0

 
1.7

 
1.3

 
1.1

 
0.3

 
0.1

Total
$
77.4

 
$
60.4

 
$
47.5

 
$
37.1

 
$
27.6

 
$
68.6



Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2022. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-price contracts to purchase a portion of its supply requirements. These contracts currently have terms that do not exceed four years. International Propane enters into variable-priced contracts to purchase a portion of its supply requirements that currently do not exceed four years.
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2012:
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 2017
UGI Utilities supply, storage and transportation contracts
$
173.9

 
$
95.0

 
$
61.8

 
$
43.3

 
$
26.5

 
$
62.7

Midstream & Marketing supply contracts
171.1

 
51.4

 
4.7

 
—

 
—

 
—

AmeriGas Propane supply contracts
141.4

 
87.0

 
87.7

 
3.2

 
—

 
—

International Propane supply contracts
226.4

 
143.4

 
143.4

 
58.0

 
—

 
—

Total
$
712.8

 
$
376.8

 
$
297.6

 
$
104.5

 
$
26.5

 
$
62.7



The Partnership and International Propane also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual price and quantity adjustments.
Contingencies
Environmental Matters
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 September 30, 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 $17.9, 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 September 30, 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 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.

HOLP San Bernardino. In July 2001, HOLP acquired a company that had previously received a request for information from the EPA regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred prior to the construction of the facility acquired by HOLP, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). No follow-up correspondence has been received from the EPA on the matter since HOLP’s acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.
Titan LLC Claremont, Chestertown and Bennington. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan LLC is purportedly the beneficial holder of title with respect to three former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites.
Claremont, New Hampshire and Chestertown, Maryland. 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.
Bennington, Vermont. In 1996, a predecessor company of Titan LLC performed an environmental assessment of its property in Bennington, Vermont and discovered that the site was a former MGP. At that time, Titan LLC’s predecessor informed the company that previously owned and operated the MGP of potential liability under CERCLA. Titan LLC has not received any requests to remediate or provide costs associated with the site. 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.

Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of Objections (“Statement”) from France's Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period expired without an appeal being filed. As a result of the decision, during the three-month period ended December 31, 2010, the Company reversed its previously recorded nontaxable accrual for this matter which increased Fiscal 2011 net income by $9.4.

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 September 30, 2012 and 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
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
)
 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
3.5

 
$
3.3

 
$
—

 
$
6.8

Foreign currency contracts
$
—

 
$
5.3

 
$
—

 
$
5.3

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(28.1
)
 
$
(16.1
)
 
$
—

 
$
(44.2
)
Foreign currency contracts
$
—

 
$
(3.3
)
 
$
—

 
$
(3.3
)
Interest rate contracts
$
—

 
$
(44.4
)
 
$
—

 
$
(44.4
)


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 September 30, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,514.3 and $3,787.6, respectively. At September 30, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,157.7 and $2,223.4, 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 which 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 17.
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. 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 September 30, 2012 and 2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 19.2 million dekatherms and 15.1 million dekatherms, respectively. At September 30, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 12 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 Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 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. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. Accordingly, the fair value of these contracts are required to be recognized on the balance sheet. At September 30, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $9.2 and $8.7, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2012 and 2011, the volumes of Electric Utility’s forward electricity purchase contracts were 570.4 million kilowatt hours and 788.6 million kilowatt hours, respectively. At September 30, 2012, the maximum period over which these contracts extend is 20 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 commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010, are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 8). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 189.7 million kilowatt hours and 208.6 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At September 30, 2012 and 2011, the volumes associated with Midstream & Marketing’s FTRs totaled 988.8 million kilowatt hours and 1,418.6 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, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. At September 30, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.3 million dekatherms and 3.1 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 September 30, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

 
 
Volumes
Commodity
 
2012
 
2011
LPG (millions of gallons)
 
243.9

 
138.0

Natural gas (millions of dekatherms, net)
 
23.6

 
26.1

Electricity calls (millions of kilowatt hours)
 
1,415.7

 
1,219.8

Electricity puts (millions of kilowatt hours)
 
135.3

 
204.9



At September 30, 2012, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 26 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 39 months with a weighted average of 11 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 36 months for electricity call contracts, with a weighted average of 10 months, and 16 months for electricity put contracts, with a weighted average of 8 months. At September 30, 2012, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 8 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 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 in the Consolidated Statements of Income. At September 30, 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 $53.0.
Interest Rate Risk
Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of September 30, 2012 and 2011, the total notional amounts of variable-rate debt subject to interest rate swap agreements were €441.9 and €424.2, respectively.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At September 30, 2012 and 2011, the total notional amount of unsettled IRPAs was $173.0 and $173.0, respectively. 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.
UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income during Fiscal 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, in the Consolidated Statements of Income.
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 September 30, 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 $0.8.
Foreign Currency Exchange Rate Risk
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2012 and 2011, we were hedging a total of $174.5 and $133.9 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 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 30 months with a weighted average of 11 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 September 30, 2012, we had no euro-dominated net investment hedges. At September 30, 2011, we were hedging a total of €14.5 of our euro-denominated net investments.
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 September 30, 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 $1.8. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.
In September 2011, in order to economically hedge the U.S. dollar amount of a substantial portion of the Shell Transaction's associated euro-denominated purchase price, we entered into foreign currency exchange contracts. These contracts were recorded at fair value with gains or losses recorded in other income, net.
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 brokerage accounts. At September 30, 2012 and 2011, restricted cash in brokerage accounts totaled $3.0 and $17.2, 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 September 30, 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 September 30, 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 balance sheet location and fair value of derivative assets and liabilities existing as of September 30, 2012 and 2011:

 
Derivative Assets
 
Derivative Liabilities
 
 
 
Fair Value
 
 
 
Fair Value
 
 
 
September 30,
 
 
 
September 30,
 
Balance Sheet
Location
 
2012
 
2011
 
Balance Sheet
Location
 
2012
 
2011
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 Commodity contracts
Derivative financial instruments
and Other assets
 
$
6.5

 
$
1.1

 
Derivative financial instruments
and Other noncurrent liabilities
 
$
(50.7
)
 
$
(32.5
)
Foreign currency contracts
Derivative financial instruments
and Other assets
 
1.8

 
5.2

 
Derivative financial instruments
and Other noncurrent liabilities
 
—

 
—

Interest rate contracts
 
 
—

 
—

 
Derivative financial instruments
and Other noncurrent liabilities
 
(71.9
)
 
(44.4
)
Total Derivatives Designated as Hedging Instruments
 
 
$
8.3

 
$
6.3

 
 
 
$
(122.6
)
 
$
(76.9
)
Derivatives Accounted for Under ASC 980:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 
$
5.3

 
$
—

 
Derivative financial instruments and Other noncurrent liabilities
 
$
(9.4
)
 
$
(11.7
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
 
 
$
—

—

$
—

 
Derivative financial instruments
 
$
—

 
$
(3.3
)
Commodity contracts
Derivative financial instruments
and Other assets
 
1.3

 
5.8

 
 
 
(0.9
)
 
—

Total Derivatives Not Designated as Hedging Instruments
 
 
$
1.3

 
$
5.8

 
 
 
$
(0.9
)
 
$
(3.3
)
Total Derivatives
 
 
$
14.9

 
$
12.1

 
 
 
$
(132.9
)
 
$
(91.9
)


The following tables provide information on the effects of derivative instruments in the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2012 and 2011:
 
Gain or (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain or (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain or (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
(135.1
)
 
$
2.2

 
$
(41.7
)
 
$
(115.4
)
 
$
(17.4
)
 
$
(21.0
)
 
Cost of sales
Foreign currency contracts
(0.5
)
 
6.9

 
3.2

 
2.1

 
(0.8
)
 
0.7

 
Cost of sales
Interest rate contracts
(36.8
)
 
(35.8
)
 
(12.6
)
 
(11.5
)
 
(14.1
)
 
(28.2
)
 
Interest expense /other income
Total
$
(172.4
)
 
$
(26.7
)
 
$
(51.1
)
 
$
(124.8
)
 
$
(32.3
)
 
$
(48.5
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
$
0.6

 
$
0.2

 
$
5.0

 
 
 
 
 
 
 
 

Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
Gain or (Loss)
Recognized in Income
Location of
Gain or (Loss)
Recognized in Income
 
 
2012
 
2011
 
2010
Commodity contracts
$
(16.8
)
 
$
2.1

 
$
1.3

Cost of sales
 
Commodity contracts
0.2

 
0.3

 
0.2

Operating expenses / other income
 
Foreign currency contracts
0.5

 
(6.1
)
 
—

Other income
 
Total
$
(16.1
)
 
$
(3.7
)
 
$
1.5

 
 


The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for Fiscal 2012, Fiscal 2011 and Fiscal 2010.
As a result of the Partnership’s refinancing of its 7.125% Senior Notes (see Note 5), during the three months ended September 30, 2011, the Partnership discontinued cash flow hedge accounting for settled but unamortized IRPA losses associated with the Senior Notes and recorded a loss of $2.6 which amount is included in loss on extinguishments of debt on the Fiscal 2011 Consolidated Statement of Income. During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that the Partnership would not issue $150 of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of its then-existing credit agreement. As a result, the Partnership discontinued cash flow hedge accounting treatment for IRPAs associated with this previously anticipated Fiscal 2010 $150 long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net, in the Fiscal 2010 Consolidated Statement of Income.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
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’s 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 the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the FASB’s guidance for accounting for transfers of financial assets and extinguishments of liabilities. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
Effective October 1, 2010, the Company adopted a new accounting standard that changes the accounting for the Receivables Facility on a prospective basis. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet; the Company reflects a liability equal to the amount advanced by the commercial paper conduit; and the Company records interest expense on amounts sold to the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet and any losses on sales of accounts receivable were reflected in other income, net.
During Fiscal 2012, Fiscal 2011 and Fiscal 2010, Energy Services transferred trade receivables totaling $836.0, $1,134.9 and $1,147.3, respectively, to ESFC. During Fiscal 2012, Fiscal 2011 and Fiscal 2010, ESFC sold an aggregate $286.0, $88.0 and $254.6, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2012, the outstanding balance of ESFC trade receivables was $43.5 of which no amount was sold to the commercial paper conduit. At September 30, 2011, the outstanding balance of ESFC trade receivables was $52.1 and there was $14.3 sold to the commercial paper conduit and reflected on the Consolidated Balance Sheet as bank loans. Losses on sales of receivables to the commercial paper conduit during Fiscal 2012 and Fiscal 2011, which amounts are included in interest expense on the Consolidated Statements of Income, totaled $1.0 and $1.2, respectively. Losses on sales of receivables to the commercial paper conduit during Fiscal 2010, which amount is included in other income, net, were $1.5.
Other Income, Net
Other Income, Net
Other Income, Net
Other income, net, comprises the following:

 
2012
 
2011
 
2010
Interest and interest-related income
$
2.4

 
$
2.3

 
$
2.9

Antargaz Competition Authority matter
—

 
9.4

 
—

Utility non-tariff service income
2.7

 
6.4

 
2.4

Foreign currency hedge gain (loss)
0.5

 
(6.1
)
 
—

Gain on sale of Atlantic Energy, LLC
—

 
—

 
36.5

Finance charges
18.8

 
15.1

 
11.3

Partnership interest rate protection agreement loss
—

 
—

 
(12.2
)
Other, net
13.9

 
19.4

 
17.1

Total other income, net
$
38.3

 
$
46.5

 
$
58.0

Quarterly Data (Unaudited)
Quarterly Data (unaudited)
Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.

 
 
December 31,
 
March 31,
 
June 30,
 
September 30,
 
 
2011 (a)
 
2010 (b)
 
2012 (c)
 
2011 (d)
 
2012
 
2011
 
2012
 
2011 (e)
Revenues
 
$
1,688.8

 
$
1,765.6

 
$
2,427.5

 
$
2,181.0

 
$
1,277.2

 
$
1,105.4

 
$
1,125.7

 
$
1,039.3

Operating income (loss)
 
$
188.3

 
$
252.3

 
$
380.8

 
$
357.0

 
$
(19.2
)
 
$
17.2

 
$
(28.6
)
 
$
(10.5
)
Loss from equity investees
 
$
(0.1
)
 
$
(0.2
)
 
$
—

 
$
(0.4
)
 
$
(0.1
)
 
$
(0.2
)
 
$
(0.1
)
 
$
(0.1
)
(Loss) gain on extinguishments of debt
 
$
—

 
$
—

 
$
(13.4
)
 
$
(18.8
)
 
$
0.1

 
$
—

 
$
—

 
$
(19.3
)
Net income (loss)
 
$
110.1

 
$
155.0

 
$
227.0

 
$
215.6

 
$
(76.5
)
 
$
(13.5
)
 
$
(74.0
)
 
$
(48.9
)
Net income (loss) attributable to UGI Corporation
 
$
87.0

 
$
113.1

 
$
133.4

 
$
149.4

 
$
(6.3
)
 
$
(7.2
)
 
$
(14.7
)
 
$
(22.4
)
Earnings (loss) per share attributable to UGI stockholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
$0.78
 
$1.02
 
$1.19
 
$1.34
 
$(0.06)
 
$(0.06)
 
$(0.13)
 
$(0.20)
Diluted
 
$0.77
 
$1.01
 
$1.18
 
$1.32
 
$(0.06)
 
$(0.06)
 
$(0.13)
 
$(0.20)
(a)
Includes adjustment to foreign tax credit valuation allowance which increased net income by $5.5 or $0.05 per diluted share.
(b)
Includes the reversal of previously recorded nontaxable accrual associated with the Antargaz Competition Authority Matter which increased operating income and net income attributable to UGI Corporation by $9.4 or $0.08 per diluted share (see Note 15).
(c)
Includes loss on extinguishment of Partnership long-term debt which decreased net income attributable to UGI Corporation by $2.2 or $0.02 per diluted share (see Note 5).
(d)
Includes loss on extinguishment of Partnership long-term debt which decreased net income attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).
(e)
Includes loss on extinguishment of Partnership long-term debt which increased net loss attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).
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." In Fiscal 2012, the Company is reporting its Electric Generation operating segment as a separate reportable segment and our former Electric Utility reportable segment has been combined with Corporate & Other. Previously, the Electric Generation operating segment was included in the Energy Services' reportable segment. Prior years have been adjusted to conform to the current year presentation.
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. Antargaz' revenues are derived principally from the distribution of LPG to retail customers in France and, to a much lesser extent, Belgium, the Netherlands and Luxembourg. Flaga & Other revenues are derived principally from the distribution of LPG to customers in northern, central and eastern Europe and the United Kingdom. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, LPG, electricity and fuel oil as well as storage and other energy services to customers located primarily in the Mid-Atlantic region of the United States. Electric Generation revenues are derived principally from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S.
The accounting policies of our reportable segments are the same as those described in Note 2. 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.
No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of International Propane, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of International Propane, are located in the United States.

 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,519.2

 
$
(178.8
)
(c)
$
2,921.6

 
$
785.4

 
$
816.4

 
$
43.0

 
$
1,121.3

 
$
824.7

 
$
185.6

Cost of sales
$
4,111.2

 
$
(174.0
)
(c)
$
1,719.7

 
$
402.5

 
$
703.8

 
$
27.1

 
$
685.5

 
$
640.3

 
$
106.3

Operating income (loss)
$
521.3

 
$
—

 
$
170.3

 
$
172.2

 
$
68.9

 
$
(6.5
)
 
$
88.2

 
$
23.6

 
$
4.6

Loss from equity investees
$
(0.3
)
 
—

 
—

 
—

 
—

 
—

 
(0.3
)
 
—

 
—

Loss on extinguishments of debt
$
(13.3
)
 
—

 
(13.3
)
 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(221.5
)
 
—

 
(142.6
)
 
(40.1
)
 
(4.8
)
 
—

 
(26.3
)
 
(4.6
)
 
(3.1
)
Income (loss) before income taxes
$
286.2

 
$
—

 
$
14.4

 
$
132.1

 
$
64.1

 
$
(6.5
)
 
$
61.6

 
$
19.0

 
$
1.5

Net income (loss) attributable to UGI
$
199.4

 
$
—

 
$
15.9

 
$
80.5

 
$
37.6

 
$
(1.2
)
 
$
51.3

 
$
13.8

 
$
1.5

Depreciation and amortization
$
316.0

 
$
—

 
$
169.1

 
$
49.0

 
$
3.7

 
$
9.0

 
$
57.1

 
$
22.1

 
$
6.0

Noncontrolling interests’ net (loss) income
$
(12.8
)
 
$
—

 
$
(13.0
)
 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
324.7

 

 

 

 

 

 

Total assets
$
9,709.7

 
$
(104.1
)
 
$
4,539.6

 
$
2,070.4

 
$
368.5

 
$
258.2

 
$
1,686.5

 
$
531.8

 
$
358.8

Bank loans
$
165.1

 
$
—

 
$
49.9

 
$
9.2

 
$
85.0

 
$
—

 
$
—

 
$
21.0

 
$
—

Capital expenditures
$
343.2

 
$
—

 
$
103.1

 
$
109.0

 
$
36.0

 
$
24.4

 
$
47.3

 
$
16.9

 
$
6.5

Investments in equity investees
$
0.3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

Goodwill
$
2,818.3

 
$
—

 
$
1,919.2

 
$
182.1

 
$
2.8

 
$
—

 
$
612.0

 
$
95.2

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,091.3

 
$
(233.0
)
(c)
$
2,538.0

 
$
1,026.4

 
$
1,023.8

 
$
49.1

 
$
1,050.6

 
$
438.1

 
$
198.3

Cost of sales
$
4,010.9

 
$
(228.6
)
(c)
$
1,605.3

 
$
610.6

 
$
902.2

 
$
31.1

 
$
649.8

 
$
321.0

 
$
119.5

Operating income (loss)
$
616.0

 
$
—

 
$
242.9

 
$
199.6

 
$
84.2

 
$
(1.3
)
 
$
89.2

 
$
(3.1
)
 
$
4.5

Loss from equity investees
$
(0.9
)
 
—

 
—

 
—

 
—

 
—

 
(0.9
)
 
—

 
—

Loss on extinguishments of debt
$
(38.1
)
 
—

 
(38.1
)
 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(138.0
)
 
—

 
(63.5
)
 
(40.4
)
 
(2.0
)
 
(0.7
)
 
(25.5
)
 
(2.7
)
 
(3.2
)
Income (loss) before income taxes
$
439.0

 
$
—

 
$
141.3

 
$
159.2

 
$
82.2

 
$
(2.0
)
 
$
62.8

 
$
(5.8
)
 
$
1.3

Net income (loss) attributable to UGI
$
232.9

 
$
—

 
$
39.9

 
$
99.3

 
$
48.4

 
$
4.1

 
$
44.2

 
$
(3.2
)
 
$
0.2

Depreciation and amortization
$
227.9

 
$
—

 
$
94.7

 
$
48.4

 
$
2.4

 
$
5.6

 
$
52.1

 
$
18.5

 
$
6.2

Noncontrolling interests’ net income
$
75.3

 
$
—

 
$
75.0

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
297.1

 

 

 

 

 

 

Total assets
$
6,663.3

 
$
(93.3
)
 
$
1,800.4

 
$
2,028.7

 
$
338.2

 
$
242.5

 
$
1,636.6

 
$
428.8

 
$
281.4

Bank loans
$
138.7

 
$
—

 
$
95.5

 
$
—

 
$
24.3

 
$
—

 
$
—

 
$
18.9

 
$
—

Capital expenditures
$
355.6

 
$
—

 
$
77.2

 
$
91.3

 
$
63.1

 
$
49.7

 
$
48.9

 
$
16.5

 
$
8.9

Investments in equity investees
$
0.3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

Goodwill
$
1,562.2

 
$
—

 
$
696.3

 
$
182.1

 
$
2.8

 
$
—

 
$
591.8

 
$
82.2

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
5,591.4

 
$
(203.9
)
(c)
$
2,320.3

 
$
1,047.5

 
$
1,105.3

 
$
58.5

 
$
887.1

 
$
172.4

 
$
204.2

Cost of sales
$
3,584.0

 
$
(197.1
)
(c)
$
1,395.1

 
$
653.4

 
$
998.0

 
$
30.6

 
$
465.9

 
$
116.2

 
$
121.9

Operating income (loss)
$
659.2

 
$
—

 
$
235.8

 
$
175.3

 
$
110.8

 
$
9.2

 
$
115.1

 
$
1.9

 
$
11.1

Loss from equity investees
$
(2.1
)
 
—

 
—

 
—

 
—

 
—

 
(2.0
)
 
(0.1
)
 
—

Loss on extinguishments of debt
 
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(133.8
)
 
—

 
(65.1
)
 
(40.5
)
 
(0.1
)
 
(0.1
)
 
(22.4
)
 
(3.0
)
 
(2.6
)
Income (loss) before income taxes
$
523.3

 
$
—

 
$
170.7

 
$
134.8

 
$
110.7

 
$
9.1

 
$
90.7

 
$
(1.2
)
 
$
8.5

Net income attributable to UGI
$
261.0

 
$
—

 
$
47.3

 
$
83.1

 
$
61.2

 
$
7.0

 
$
60.0

 
$
(1.2
)
 
$
3.6

Depreciation and amortization
$
210.2

 
$
—

 
$
87.4

 
$
49.5

 
$
3.3

 
$
4.4

 
$
48.9

 
$
11.5

 
$
5.2

Noncontrolling interests’ net income (loss)
$
94.7

 
$
—

 
$
91.1

 
$
—

 
$
3.3

 
$
—

 
$
0.3

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
321.0

 

 

 

 

 

 

Total assets
$
6,374.0

 
$
(81.1
)
 
$
1,690.6

 
$
1,996.3

 
$
245.8

 
$
205.0

 
$
1,678.3

 
$
320.2

 
$
318.9

Bank loans
$
200.4

 
$
—

 
$
91.0

 
$
17.0

 
$
—

 
$
—

 
$
68.2

 
$
24.2

 
$
—

Capital expenditures
$
352.9

 
$
—

 
$
83.2

 
$
73.5

 
$
48.3

 
$
68.1

 
$
51.4

 
$
7.6

 
$
20.8

Investments in equity investees
$
0.4

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

Goodwill
$
1,562.7

 
$
—

 
$
683.1

 
$
180.1

 
$
2.8

 
$
—

 
$
602.7

 
$
87.0

 
$
7.0

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:

Year ended September 30,
 
2012
 
2011
 
2010
 
 
Partnership EBITDA
 
$
324.7

 
$
297.1

 
$
321.0

 
 
Depreciation and amortization
 
(169.1
)
 
(94.7
)
 
(87.4
)
 
 
Loss on extinguishments of debt
 
13.3

 
38.1

 
—

 
 
Noncontrolling interests (i)
 
1.4

 
2.4

 
2.2

 
 
Operating income
 
$
170.3

 
$
242.9

 
$
235.8

 
 

(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 principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Condensed Financial Information of Registrant (Parent Company)
Condensed Financial Information of Registrant (Parent Company)
BALANCE SHEETS
(Millions of dollars)

 
September 30,
 
2012
 
2011
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1.9

 
$
0.4

Accounts and notes receivable
4.0

 
4.9

Deferred income taxes
0.4

 
0.4

Prepaid expenses and other current assets
0.3

 
1.4

Total current assets
6.6

 
7.1

Investments in subsidiaries
2,244.4

 
1,992.1

Deferred income taxes
28.3

 
22.3

Total assets
$
2,279.3

 
$
2,021.5

 
 
 
 
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
Current liabilities:
 
 
 
Accounts and notes payable
$
11.1

 
$
11.4

Derivative financial instruments
—

 
3.3

Accrued liabilities
2.4

 
1.7

Total current liabilities
13.5

 
16.4

Noncurrent liabilities
32.7

 
27.4

Commitments and contingencies (Note 1)

 

Common stockholders’ equity:
 
 
 
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,624,594 and 115,507,094 shares, respectively)
1,157.7

 
937.4

Retained earnings
1,166.1

 
1,085.8

Accumulated other comprehensive loss
(62.0
)
 
(17.7
)
Treasury stock, at cost
(28.7
)
 
(27.8
)
Total common stockholders’ equity
2,233.1

 
1,977.7

Total liabilities and common stockholders’ equity
$
2,279.3

 
$
2,021.5


Note 1 — Commitments and Contingencies:
In addition to the guarantees of Flaga’s and Antargaz’ debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2012, UGI Corporation had agreed to indemnify the issuers of $42.7 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $425.0 of obligations to suppliers and customers of UGI Energy Services, Inc. and subsidiaries of which $347.6 of such obligations were outstanding as of September 30, 2012. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga which amount totaled $5.6 at September 30, 2012.
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

 
Year Ended
September 30,
 
2012
 
2011
 
2010
Revenues
$
—

 
$
—

 
$
—

Costs and expenses:
 
 
 
 
 
Operating and administrative expenses
27.8

 
31.0

 
31.8

Other income, net (1)
(28.1
)
 
(24.8
)
 
(31.7
)
 
(0.3
)
 
6.2

 
0.1

Operating income (loss)
0.3

 
(6.2
)
 
(0.1
)
Intercompany interest income
0.2

 
0.1

 
—

Income (loss) before income taxes
0.5

 
(6.1
)
 
(0.1
)
Income tax expense (benefit) 
0.3

 
(1.1
)
 
0.7

Income (loss) before equity in income of unconsolidated subsidiaries
0.2

 
(5.0
)
 
(0.8
)
Equity in income of unconsolidated subsidiaries
199.2

 
237.9

 
261.8

Net income
$
199.4

 
$
232.9

 
$
261.0

Earnings per common share:
 
 
 
 
 
Basic
$
1.77

 
$
2.09

 
$
2.38

Diluted
$
1.76

 
$
2.06

 
$
2.36

Average common shares outstanding (thousands):
 
 
 
 
 
Basic
112,581

 
111,674

 
109,588

Diluted
113,432

 
112,944

 
110,511


(1)
UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other income, net” in the Statements of Income above.
STATEMENTS OF CASH FLOWS
(Millions of dollars)

 
Year Ended
September 30,
 
2012
 
2011
 
2010
NET CASH PROVIDED BY OPERATING ACTIVITIES (a)
$
158.3

 
$
201.6

 
$
173.0

 
 
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Net investments in unconsolidated subsidiaries
(54.4
)
 
(119.4
)
 
(106.6
)
Net cash used by investing activities
(54.4
)
 
(119.4
)
 
(106.6
)
 
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Payment of dividends on Common Stock
(119.1
)
 
(113.8
)
 
(98.6
)
Issuance of Common Stock
16.7

 
31.0

 
31.8

Net cash used by financing activities
(102.4
)
 
(82.8
)
 
(66.8
)
Cash and cash equivalents increase (decrease)
$
1.5

 
$
(0.6
)
 
$
(0.4
)
Cash and cash equivalents:
 
 
 
 
 
End of year
$
1.9

 
$
0.4

 
$
1.0

Beginning of year
0.4

 
1.0

 
1.4

Increase (decrease)
$
1.5

 
$
(0.6
)
 
$
(0.4
)

(a)
Includes dividends received from unconsolidated subsidiaries of $156.0, $188.9 and $172.8, for the years ended September 30, 2012, 2011 and 2010, respectively.
Valuation and Qualifying Accounts
Valuation and Qualifying Accounts
 
Balance at
beginning
of year
 
Charged
(credited)
to costs and
expenses
 
Other
 
Balance at
end of
year
 
Year Ended September 30, 2012
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
36.8

 
$
26.5

 
$
(27.2
)
(1)
$
36.1

 
Other reserves:
 
 
 
 
 
 
 
 
Property and casualty liability
$
65.3

 
$
31.5

 
$
(34.0
)
(3)
$
95.3

(5)
 
 
 
 
 
32.5

(4)
 
 
Environmental, litigation and other
$
36.9

 
$
1.2

 
$
(5.0
)
(3)
$
37.6

 
 
 
 
 
 
(0.4
)
(2)
 
 
 
 
 
 
 
4.9

(4)
 
 
Deferred tax assets valuation allowance
$
81.9

 
$
(3.1
)
 
2.8

 
$
81.6

 
 
 
 
 
 
 
 
 
 
Year Ended September 30, 2011
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
34.6

 
$
20.0

 
$
(17.8
)
(1)
$
36.8

 
Other reserves:
 
 
 
 
 
 
 
 
Property and casualty liability
$
65.7

 
$
22.5

 
$
(26.5
)
(3)
$
65.3

(5)
 
 
 
 
 
3.6

(2)
 
 
Environmental, litigation and other
$
65.8

 
$
(5.3
)
 
$
(25.4
)
(3)
$
36.9

 
 
 
 
 
 
1.8

(2)
 
 
Deferred tax assets valuation allowance
$
78.4

 
$
3.5

 
—

 
$
81.9

 
 
 
 
 
 
 
 
 
 
Year Ended September 30, 2010
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
38.3

 
$
27.1

 
$
(30.8
)
(1)
$
34.6

 
Other reserves:
 
 
 
 
 
 
 
 
Property and casualty liability
$
72.3

 
$
15.2

 
$
(27.4
)
(3)
$
65.7

(5)
 
 
 
 
 
5.6

(2)
 
 
Environmental, litigation and other
$
66.3

 
$
5.4

 
$
(4.9
)
(3)
$
65.8

 
 
 
 
 
 
(1.0
)
(2)
 
 
Deferred tax assets valuation allowance
$
87.8

 
$
(9.4
)
 
$
—

 
$
78.4

 

(1)
Uncollectible accounts written off, net of recoveries.
(2)
Other adjustments.
(3)
Payments, net.
(4)
Acquisition.
(5)
At September 30, 2012, 2011 and 2010, the Company had insurance indemnification receivables associated with its property and casualty liabilities totaling $20.9, $11.3 and $7.2, respectively.
Significant Accounting Policies (Policies)
Basis of Presentation 
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
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.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation 
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the general public’s and ETP's 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. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2012. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method.
Effects of Regulation 
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.
For additional information regarding the effects of rate regulation on our utility operations, see Note 8.
Fair Value Measurements 
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
•
Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded contract.
•
Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swap and option contracts, interest rate swaps and interest rate protection agreements, foreign currency forward contracts, financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts that do not qualify for Level 1.
•
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2012 or 2011.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 16 for additional information on fair value measurements.
Derivative Instruments 
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
A substantial portion of our derivative financial instruments are designated and qualify as cash flow hedges or net investment hedges. In addition, gains and losses on certain derivative financial instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Certain of our derivative financial instruments, although generally effective as economic hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments, other than net investment hedges, are included in cash flows from operating activities. Cash flows from net investment hedges are included in cash flows from investing activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 17.
Foreign Currency Translation 
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition 
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
LPG Delivery Expenses 
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our International Propane operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and International Propane delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes 
Income Taxes
AmeriGas Partners and the Operating Partnerships are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating Partnerships have subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income tax expense when such property is placed in service.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.
Earnings Per Common Share 
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards.
Comprehensive Income 
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges, actuarial gains and losses on postretirement benefit plans and foreign currency translation adjustments and foreign currency long-term intra-company transactions.
Cash and Cash Equivalents 
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash 
Restricted Cash
Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Inventories 
Inventories
Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories.
Property, Plant and Equipment and Related Depreciation 
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 25 to 35 years for electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.2% in Fiscal 2012, 2.3% in Fiscal 2011 and 2.5% in Fiscal 2010. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2012, 2.6% in Fiscal 2011 and 2.6% in Fiscal 2010. When Utilities retire depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets 
Goodwill and Intangible Assets
In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. We review identifiable intangible assets subject to amortization for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested annually for impairment and written down to fair value as required.
We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit's goodwill exceeds the implied fair value of that goodwill. We determine fair values for each of our reporting units generally using discounted cash flows to establish fair values unless market values are available. The Company adopted new accounting guidance regarding goodwill impairment during Fiscal 2012 which permits us, in certain circumstances, to perform a qualitative approach to determine if it is more likely than not that the carrying value of a reporting unit is greater than its fair value (see Note 3).
Impairment of Long-Lived Assets 
Impairment of Long-Lived Assets
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.
Deferred Debt Issuance Costs 
We are amortizing these costs over the terms of the related debt.
Refundable Tank and Cylinder Deposits 
Refundable Tank and Cylinder Deposits
Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $205.1 and $204.4 at September 30, 2012 and 2011, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters 
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. 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 CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 15.
Employee Retirement Plans 
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7).
Equity-Based Compensation 
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity in our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.
We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).
For additional information on our equity-based compensation plans and related disclosures, see Note 13.
Significant Accounting Policies (Tables)
Shares used in computing basic and diluted earnings per share 
In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2012, Fiscal 2011 and Fiscal 2010:
(Thousands of shares)
 
2012 (a)
 
2011(a)
 
2010
Average common shares outstanding for basic computation
 
112,581

 
111,674

 
109,588

Incremental shares issuable for stock options and common stock awards
 
851

 
1,270

 
923

Average common shares outstanding for diluted computation
 
113,432

 
112,944

 
110,511


(a)
For Fiscal 2012 and Fiscal 2011, there were approximately 81 shares and 3,700 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share because their effect was antidilutive.
Components of AOCI 
The components of AOCI at September 30, 2012 and 2011 follow:
 
Postretirement
Benefit Plans
 
Derivative
Instruments Net
Losses
 
Foreign
Currency
Translation
Adjustments
 
Total
Balance, September 30, 2012
$
(22.9
)
 
$
(58.8
)
 
$
19.7

 
$
(62.0
)
Balance, September 30, 2011
$
(12.1
)
 
$
(47.6
)
 
$
42.0

 
$
(17.7
)
Acquisitions and Dispositions (Tables)
Assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition 
The purchase price allocation is as follows:
Assets acquired:
 
Current assets
$
301.4

Property, plant & equipment
890.2

Customer relationships (estimated useful life of 15 years)
418.9

Trademarks and tradenames
91.1

Goodwill
1,217.7

Other assets
9.9

Total assets acquired
$
2,929.2

 
 
Liabilities assumed:
 
Current liabilities
$
(238.1
)
Long-term debt
(62.9
)
Other noncurrent liabilities
(23.4
)
Total liabilities assumed
$
(324.4
)
Total
$
2,604.8

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, 2010:

 
 
Fiscal 2012
 
Fiscal 2011
Revenues
 
$
7,010.9

 
$
7,522.0

Net income attributable to UGI Corporation
 
$
197.6

 
$
223.5

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic
 
$
1.76

 
$
2.00

Diluted
 
$
1.74

 
$
1.98

Debt (Tables)
Composition of Long Term Debt 
Long-term debt comprises the following at September 30:

 
2012
 
2011
AmeriGas Propane:
 
 
 
AmeriGas Partners Senior Notes:
 
 
 
   7.00%, due May 2022
$
980.8

 
$
—

   6.75%, due May 2020
550.0

 
—

   6.50%, due May 2021
270.0

 
470.0

   6.25%, due August 2019
450.0

 
450.0

HOLP Senior Secured Notes
55.6

 
—

Other
21.6

 
13.5

Total AmeriGas Propane
2,328.0

 
933.5

International Propane:
 
 
 
Antargaz 2011 Senior Facilities term loan, due through March 2016
488.7

 
508.7

Flaga term loan, due through September 2016
51.4

 
53.5

Flaga term loan, due October 2016
24.6

 
—

Flaga term loan, due through June 2014
3.6

 
5.6

Other
5.6

 
3.5

Total International Propane
573.9

 
571.3

UGI Utilities:
 
 
 
Senior Notes:
 
 
 
6.375%, due September 2013
108.0

 
108.0

5.75%, due September 2016
175.0

 
175.0

6.21%, due September 2036
100.0

 
100.0

Medium- Term Notes:
 
 
 
5.53%, due September 2012
—

 
40.0

5.37%, due August 2013
25.0

 
25.0

5.16%, due May 2015
20.0

 
20.0

7.37%, due October 2015
22.0

 
22.0

5.64%, due December 2015
50.0

 
50.0

6.17%, due June 2017
20.0

 
20.0

7.25%, due November 2017
20.0

 
20.0

5.67%, due January 2018
20.0

 
20.0

6.50%, due August 2033
20.0

 
20.0

6.13%, due October 2034
20.0

 
20.0

Total UGI Utilities
600.0

 
640.0

Other
12.4

 
12.9

Total long-term debt
3,514.3

 
2,157.7

Less: current maturities
(166.7
)
 
(47.4
)
Total long-term debt due after one year
$
3,347.6

 
$
2,110.3

Principal Repayment of long-term debt 
Scheduled principal repayments of long-term debt due in fiscal years 2013 to 2017 follow:

 
2013
 
2014
 
2015
 
2016
 
2017
AmeriGas Propane
$
30.0

 
$
10.9

 
$
8.9

 
$
6.5

 
$
4.6

UGI Utilities
133.0

 
—

 
20.0

 
247.0

 
20.0

International Propane
2.5

 
52.9

 
45.0

 
448.2

 
25.1

Other
0.6

 
0.6

 
0.5

 
0.6

 
0.6

Total
$
166.1

 
$
64.4

 
$
74.4

 
$
702.3

 
$
50.3

Income Taxes (Tables)
Income before income taxes 
Income before income taxes comprises the following:

 
2012
 
2011
 
2010
Domestic
$
227.3

 
$
388.8

 
$
448.8

Foreign
58.9

 
50.2

 
74.5

Total income before income taxes
$
286.2

 
$
439.0

 
$
523.3

Provisions for income taxes 
The provisions for income taxes consist of the following:

 
2012
 
2011
 
2010
Current expense (benefit):
 
 
 
 
 
Federal
$
(10.4
)
 
$
24.4

 
$
60.5

State
11.2

 
14.5

 
20.4

Foreign
18.8

 
15.0

 
25.8

Investment tax credit
(2.9
)
 
(5.8
)
 
(1.7
)
Total current expense
16.7

 
48.1

 
105.0

Deferred expense (benefit):
 
 
 
 
 
Federal
76.2

 
79.3

 
54.5

State
5.2

 
2.4

 
6.4

Foreign
1.8

 
1.4

 
2.1

Investment tax credit amortization
(0.3
)
 
(0.4
)
 
(0.4
)
Total deferred expense
82.9

 
82.7

 
62.6

Total income tax expense
$
99.6

 
$
130.8

 
$
167.6

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate 
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

 
2012
 
2011
 
2010
U.S. federal statutory tax rate
35.0
 %
 
35.0
 %
 
35.0
 %
Difference in tax rate due to:
 
 
 
 
 
Noncontrolling interests not subject to tax
1.3

 
(6.0
)
 
(6.4
)
State income taxes, net of federal benefit
3.8

 
2.2

 
3.5

Valuation allowance adjustments
(1.6
)
 
—

 
(0.2
)
Effects of foreign operations
(3.6
)
 
(0.6
)
 
(0.6
)
Other, net
(0.1
)
 
(0.8
)
 
0.7

Effective tax rate
34.8
 %
 
29.8
 %
 
32.0
 %
Deferred tax liabilities (assets) 
Deferred tax liabilities (assets) comprise the following at September 30:
 
2012
 
2011
Excess book basis over tax basis of property, plant and equipment
$
582.0

 
$
490.4

Investment in AmeriGas Partners
293.2

 
172.7

Intangible assets and goodwill
61.2

 
52.1

Utility regulatory assets
140.4

 
124.7

Foreign currency translation adjustment
3.6

 
8.5

Other
6.8

 
7.2

Gross deferred tax liabilities
1,087.2

 
855.6

 
 
 
 
Pension plan liabilities
(72.7
)
 
(62.8
)
Employee-related benefits
(43.0
)
 
(42.7
)
Operating loss carryforwards
(38.0
)
 
(31.8
)
Foreign tax credit carryforwards
(55.5
)
 
(60.1
)
Utility regulatory liabilities
(11.8
)
 
(12.4
)
Derivative financial instruments
(37.7
)
 
(30.5
)
Other
(31.9
)
 
(32.9
)
Gross deferred tax assets
(290.6
)
 
(273.2
)
Deferred tax assets valuation allowance
81.6

 
81.9

Net deferred tax liabilities
$
878.2

 
$
664.3

Reconciliation of beginning and ending amount of unrecognized tax benefit 
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

Balance at September 30, 2009
$
2.3

Additions for tax positions of the current year
4.3

Reductions as a result of tax positions taken in prior years
(0.2
)
Settlements with tax authorities
(1.0
)
Balance at September 30, 2010
5.4

Additions for tax positions of the current year
0.4

Additions for tax positions of prior years
1.0

Settlements with tax authorities
(0.5
)
Balance at September 30, 2011
6.3

Additions for tax positions of the current year
0.5

Additions for tax positions of prior years
0.6

Settlements with tax authorities
(4.5
)
Balance at September 30, 2012
$
2.9

Employee Retirement Plans (Tables)
Change in Pension Benefits and Other postretirement benefits Obligations, plan assets, and the funded status 
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2012 and 2011. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.

 
Pension
Benefits
 
Other Postretirement
Benefits
 
2012
 
2011
 
2012
 
2011
Change in benefit obligations:
 
 
 
 
 
 
 
Benefit obligations — beginning of year
$
462.9

 
$
471.8

 
$
20.5

 
$
22.9

Service cost
9.3

 
8.8

 
0.4

 
0.4

Interest cost
25.1

 
24.1

 
1.1

 
1.1

Actuarial loss (gain)
82.4

 
(22.0
)
 
3.2

 
(2.4
)
Plan amendments
0.1

 
—

 
1.0

 
(0.1
)
Acquisitions
14.6

 
—

 
—

 
—

Foreign currency
(0.7
)
 
(0.1
)
 
(0.1
)
 
—

Benefits paid
(20.3
)
 
(19.7
)
 
(1.4
)
 
(1.4
)
Benefit obligations — end of year
$
573.4

 
$
462.9

 
$
24.7

 
$
20.5

 
 
 
 
 
 
 
 
Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets — beginning of year
$
290.0

 
$
287.9

 
$
9.8

 
$
10.0

Actual gain on plan assets
51.2

 
2.6

 
1.7

 
0.1

Foreign currency
(0.5
)
 
—

 
—

 
—

Employer contributions
32.2

 
19.2

 
1.1

 
1.1

Acquisitions
17.3

 
—

 
—

 
—

Benefits paid
(20.3
)
 
(19.7
)
 
(1.4
)
 
(1.4
)
Fair value of plan assets — end of year
$
369.9

 
$
290.0

 
$
11.2

 
$
9.8

Funded status of the plans — end of year
$
(203.5
)
 
$
(172.9
)
 
$
(13.5
)
 
$
(10.7
)
 
 
 
 
 
 
 
 
(Liabilities) recorded in the balance sheet:
 
 
 
 
 
 
 
Unfunded liabilities — included in other current liabilities
$
(15.8
)
 
$
(27.6
)
 
$
(0.6
)
 
$
(0.6
)
Unfunded liabilities — included in other noncurrent liabilities
(187.7
)
 
(145.3
)
 
(12.9
)
 
(10.1
)
Net amount recognized
$
(203.5
)
 
$
(172.9
)
 
$
(13.5
)
 
$
(10.7
)
 
 
 
 
 
 
 
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
 
 
 
 
Prior service credit
$
(0.1
)
 
$
(0.2
)
 
$
(0.1
)
 
$
(0.1
)
Net actuarial loss (gain)
25.3

 
13.6

 
0.4

 
(0.8
)
Total
$
25.2

 
$
13.4

 
$
0.3

 
$
(0.9
)
 
 
 
 
 
 
 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
1.5

 
$
1.8

 
$
(2.8
)
 
$
(3.2
)
Net actuarial loss
184.5

 
146.9

 
5.8

 
6.3

Total
$
186.0

 
$
148.7

 
$
3.0

 
$
3.1

Actuarial assumptions for our domestic plans 
The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

 
Pension Plan
 
Other Postretirement Benefits
 
2012
 
2011 (a)
 
2010
 
2009
 
2012
 
2011
 
2010
 
2009
Weighted-average assumptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.20
%
 
5.30
%
 
5.00
%
 
5.50
%
 
4.20
%
 
5.30
%
 
5.00
%
 
5.50
%
Expected return on plan assets
7.75
%
 
8.00
%
 
8.50
%
 
8.50
%
 
5.20
%
 
5.50
%
 
5.50
%
 
5.50
%
Rate of increase in salary levels
3.25
%
 
3.50
%
 
3.75
%
 
3.75
%
 
3.25
%
 
3.50
%
 
3.75
%
 
3.75
%
______________
(a)
The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the U.S. Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011.
Component of net periodic pension expense and other postretirement benefit costs 
Net periodic pension expense and other postretirement benefit cost includes the following components:

 
Pension Benefits
 
Other Postretirement Benefits
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Service cost
$
9.3

 
$
8.8

 
$
8.7

 
$
0.4

 
$
0.4

 
$
0.4

Interest cost
25.1

 
24.1

 
23.5

 
1.1

 
1.1

 
1.1

Expected return on assets
(26.2
)
 
(25.8
)
 
(25.8
)
 
(0.5
)
 
(0.5
)
 
(0.5
)
Curtailment gain
—

 
—

 
—

 
—

 
(3.2
)
 
—

Settlement loss
—

 
—

 
1.0

 
—

 
—

 
—

Amortization of:
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
0.2

 
0.2

 
—

 
(0.3
)
 
(0.7
)
 
(0.4
)
Actuarial loss
8.4

 
7.5

 
5.9

 
0.3

 
0.4

 
0.1

Net benefit cost (income)
16.8

 
14.8

 
13.3

 
1.0

 
(2.5
)
 
0.7

Change in associated regulatory liabilities
—

 
—

 
—

 
3.2

 
3.1

 
3.1

Net benefit cost after change in regulatory liabilities
$
16.8

 
$
14.8

 
$
13.3

 
$
4.2

 
$
0.6

 
$
3.8

Expected payments for pension benefits and other postretirement welfare benefits 
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
 
Pension
Benefits
 
Other
Postretirement
Benefits
Fiscal 2013
$
22.3

 
$
1.9

Fiscal 2014
23.3

 
1.9

Fiscal 2015
24.6

 
1.9

Fiscal 2016
27.4

 
1.9

Fiscal 2017
28.0

 
1.8

Fiscal 2018 - 2022
158.0

 
8.7

Pension Plans 
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan

 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2012
 
2011
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
53.5
%
 
49.4
%
 
52.5
%
 
40.0% - 65.0%
International
10.5
%
 
10.7
%
 
12.5
%
 
7.5% - 17.5%
Total
64.0
%
 
60.1
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
36.0
%
 
39.9
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 

VEBA

 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2012
 
2011
 
 
Domestic equity investments
68.5
%
 
62.2
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
31.5
%
 
37.8
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 
Fair value of U.S. pension plan and VEBA trust assets 
The fair values of the U.S. Pension Plan and VEBA trust assets at September 30, 2012 and 2011, by asset class are as follows:

 
U.S. Pension Plan
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2012:
 
 
 
 
 
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
$
188.2

 
$
—

 
$
—

 
$
188.2

International
36.9

 
—

 
—

 
36.9

Fixed income
123.3

 
—

 
—

 
123.3

Cash equivalents
—

 
3.1

 
—

 
3.1

Total
$
348.4

 
$
3.1

 
$
—

 
$
351.5

 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
$
143.1

 
$
—

 
$
—

 
$
143.1

International
31.0

 
—

 
—

 
31.0

Fixed income
113.6

 
—

 
—

 
113.6

Cash equivalents
—

 
2.0

 
—

 
2.0

Total
$
287.7

 
$
2.0

 
$
—

 
$
289.7


 
VEBA
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2012:
 
 
 
 
 
 
 
Domestic equity
$
7.7

 
$
—

 
$
—

 
$
7.7

Fixed income
3.4

 
—

 
—

 
3.4

Cash equivalents
—

 
0.1

 
—

 
0.1

Total
$
11.1

 
$
0.1

 
$
—

 
$
11.2

 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Domestic equity
$
6.1

 
$
—

 
$
—

 
$
6.1

Fixed income
3.3

 
—

 
—

 
3.3

Cash equivalents
—

 
0.4

 
—

 
0.4

Total
$
9.4

 
$
0.4

 
$
—

 
$
9.8

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 Utilities are included in our accompanying balance sheets at September 30:
 
2012
 
2011
Regulatory assets:
 
 
 
Income taxes recoverable
$
103.2

 
$
97.9

Underfunded pension and postretirement plans
188.2

 
150.7

Environmental costs
16.8

 
19.5

Deferred fuel and power costs
11.6

 
12.2

Removal costs, net
12.7

 
12.3

Other
5.9

 
7.8

Total regulatory assets
$
338.4

 
$
300.4

 
 
 
 
Regulatory liabilities:
 
 
 
Postretirement benefits
$
13.1

 
$
11.5

Environmental overcollections
2.9

 
4.7

Deferred fuel and power refunds
4.4

 
6.6

State tax benefits — distribution system repairs
7.4

 
6.3

Other
0.5

 
0.7

Total regulatory liabilities
$
28.3

 
$
29.8

Inventories (Tables)
Inventories
Inventories comprise the following at September 30:

 
2012
 
2011
Non-utility LPG and natural gas
$
240.7

 
$
222.2

Gas Utility natural gas
57.7

 
95.6

Materials, supplies and other
58.5

 
45.2

Total inventories
$
356.9

 
$
363.0

Property, Plant and Equipment (Tables)
Property, Plant and Equipment
Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:

 
2012
 
2011
Utilities:
 
 
 
Distribution
$
2,047.8

 
$
1,951.9

Transmission
85.4

 
83.4

General and other, including work in process
162.5

 
165.7

Total Utilities
2,295.7

 
2,201.0

 
 
 
 
Non-utility:
 
 
 
Land
175.0

 
98.5

Buildings and improvements
283.3

 
214.8

Transportation equipment
246.5

 
112.6

Equipment, primarily cylinders and tanks
3,041.1

 
2,127.6

Electric generation
254.3

 
230.0

Other, including work in process
223.2

 
300.0

Total non-utility
4,223.4

 
3,083.5

Total property, plant and equipment
$
6,519.1

 
$
5,284.5

Goodwill and Intangible Assets (Tables)
Component of company's intangible assets 
Goodwill and intangible assets comprise the following at September 30:

 
2012
 
2011
Goodwill (not subject to amortization)
$
2,818.3

 
$
1,562.2

Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
$
691.9

 
$
232.1

Trademarks and tradenames (not subject to amortization)
137.2

 
47.9

Gross carrying amount
829.1

 
280.0

Accumulated amortization
(170.9
)
 
(132.2
)
Intangible assets, net
$
658.2

 
$
147.8

Changes in the carrying amount of goodwill 
Changes in the carrying amount of goodwill are as follows:

 
 
 
 
 
 
 
International Propane
 
 
 
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Antargaz
 
Flaga & Other
 
Corporate &
Other
 
Total
Balance September 30, 2010
$
683.1

 
$
180.1

 
$
2.8

 
$
602.7

 
$
87.0

 
$
7.0

 
$
1,562.7

Goodwill acquired
13.1

 
—

 
—

 
—

 
—

 
—

 
13.1

Purchase accounting adjustments
0.1

 
2.0

 
—

 
—

 
(3.2
)
 
—

 
(1.1
)
Foreign currency translation
—

 
—

 
—

 
(10.9
)
 
(1.6
)
 
—

 
(12.5
)
Balance September 30, 2011
696.3

 
182.1

 
2.8

 
591.8

 
82.2

 
7.0

 
1,562.2

Goodwill acquired
1,223.1

 
—

 
—

 
46.4

 
13.7

 
—

 
1,283.2

Purchase accounting adjustments
(0.2
)
 
—

 
—

 
—

 
—

 
—

 
(0.2
)
Foreign currency translation
—

 
—

 
—

 
(26.2
)
 
(0.7
)
 
—

 
(26.9
)
Balance September 30, 2012
$
1,919.2

 
$
182.1

 
$
2.8

 
$
612.0

 
$
95.2

 
$
7.0

 
$
2,818.3

Common Stock and Equity Based Compensation (Tables)
Common stock share activity 
UGI Common Stock share activity for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follows:
 
Issued
 
Treasury
 
Outstanding
Balance, September 30, 2009
115,261,294

 
(6,514,587
)
 
108,746,707

Issued:
 
 
 
 
 
Employee and director plans
139,000

 
1,390,207

 
1,529,207

Dividend reinvestment plan
—

 
97,673

 
97,673

Balance, September 30, 2010
115,400,294

 
(5,026,707
)
 
110,373,587

Issued:
 
 
 
 
 
Employee and director plans
106,800

 
1,263,065

 
1,369,865

Dividend reinvestment plan
—

 
92,570

 
92,570

Balance, September 30, 2011
115,507,094

 
(3,671,072
)
 
111,836,022

Issued:
 
 
 
 
 
Employee and director plans
117,500

 
824,925

 
942,425

Dividend reinvestment plan
—

 
104,994

 
104,994

Shares reacquired - employee and director plans
—

 
(263,020
)
 
(263,020
)
Balance, September 30, 2012
115,624,594

 
(3,004,173
)
 
112,620,421

Stock Option Awards 
Stock option transactions under the OECP and predecessor plans for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follow:
 
Shares
 
Weighted
Average
Option Price
 
Total
Intrinsic
Value
 
Weighted
Average
Contract Term
(Years)
Shares under option — September 30, 2009
7,501,493

 
$
22.74

 
$
23.2

 
6.4
Granted
1,394,300

 
$
24.37

 
 
 
 
Cancelled
(62,501
)
 
$
25.12

 
 
 
 
Exercised
(1,276,247
)
 
$
18.09

 
$
11.7

 
 
Shares under option — September 30, 2010
7,557,045

 
$
23.81

 
$
36.2

 
6.5
Granted
1,443,558

 
$
31.55

 
 
 
 
Cancelled
(235,437
)
 
$
27.79

 
 
 
 
Exercised
(1,091,987
)
 
$
20.95

 
$
11.4

 
 
Shares under option — September 30, 2011
7,673,179

 
$
25.55

 
$
15.1

 
6.2
Granted
1,508,050

 
$
29.26

 
 
 
 
Cancelled
(321,600
)
 
$
27.74

 
 
 
 
Exercised
(801,857
)
 
$
20.93

 
$
7.2

 
 
Shares under option — September 30, 2012
8,057,772

 
$
26.62

 
$
41.4

 
6.1
Options exercisable — September 30, 2010
4,706,376

 
$
22.99

 
 
 
 
Options exercisable — September 30, 2011
4,879,784

 
$
24.15

 
 
 
 
Options exercisable — September 30, 2012
5,317,698

 
$
25.32

 
$
34.2

 
5.0
Non-vested options — September 30, 2012
2,740,074

 
$
29.13

 
$
7.2

 
8.3
Additional information relating to stock options outstanding and exercisable 
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2012:

 
Range of exercise prices
 
Under
$20.00
 
$20.00 -
$25.00
 
$25.01 -
$30.00
 
Over
$30.00
Options outstanding at September 30, 2012:
 
 
 
 
 
 
 
Number of options
162,300

 
2,996,470

 
3,529,044

 
1,369,958

Weighted average remaining contractual life (in years)
1.5

 
5.3

 
6.3

 
7.8

Weighted average exercise price
$
16.92

 
$
23.29

 
$
27.99

 
$
31.53

Options exercisable at September 30, 2012:
 
 
 
 
 
 
 
Number of options
162,300

 
2,546,170

 
2,164,909

 
444,319

Weighted average exercise price
$
16.92

 
$
23.12

 
$
27.26

 
$
31.60

Assumption used for valuing option grants 
The assumptions we used for valuing option grants during Fiscal 2012, Fiscal 2011 and Fiscal 2010 are as follows:

 
2012
 
2011
 
2010
Expected life of option
5.75 years
 
5.75 years
 
5.75 years
Weighted average volatility
24.7%
 
24.3%
 
24.0%
Weighted average dividend yield
3.5%
 
3.4%
 
3.3%
Expected volatility
24.7%
 
23.8% - 24.3%
 
24.0%
Expected dividend yield
3.3% - 3.7%
 
3.1% - 3.4%
 
3.3% - 3.4%
Risk free rate
0.8% - 1.1%
 
1.2% - 2.4%
 
1.7% - 3.1%
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs 
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:

 
Grants Awarded in Fiscal
 
2012
 
2011
 
2010
Risk free rate
0.4
%
 
1.0
%
 
1.7
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
22.2
%
 
27.6
%
 
28.0
%
Dividend yield
3.5
%
 
3.2
%
 
3.3
%
UGI unit award activity 
The following table summarizes UGI Unit award activity for Fiscal 2012:
 
Total
 
Vested
 
Non-Vested
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
September 30, 2011
900,283

 
$
24.13

 
598,955

 
$
21.41

 
301,328

 
$
29.56

UGI Performance Units:
 
 
 
 
 
 
 
 
 
 
 
Granted
197,400

 
$
27.25

 
33,518

 
$
29.16

 
163,882

 
$
26.86

Forfeited
(51,411
)
 
$
27.94

 
—

 
$
—

 
(51,411
)
 
$
27.94

Vested
—

 
$
—

 
110,083

 
$
29.04

 
(110,083
)
 
$
29.04

Performance criteria not met
(170,481
)
 
$
27.82

 
(170,481
)
 
$
27.82

 
—

 
$
—

UGI Stock Units:
 
 
 
 
 
 
 
 
 
 
 
Granted (a)
42,445

 
$
29.69

 
40,945

 
$
29.53

 
1,500

 
$
34.06

Vested
—

 
$
—

 
—

 
$
—

 
—

 
$
—

Unit awards paid
(32,898
)
 
$
26.17

 
(32,898
)
 
$
26.17

 
—

 
$
—

September 30, 2012
885,338

 
$
24.09

 
580,122

 
$
21.72

 
305,216

 
$
28.59

(a)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2011 and Fiscal 2010 were 61,945 and 27,060, respectively.
Schedule of Payment for UGI Performance Unit and UGI Stock Unit awards in shares and cash 
During Fiscal 2012, Fiscal 2011 and Fiscal 2010, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
 
2012
 
2011
 
2010
UGI Performance Unit awards:
 
 
 
 
 
Number of original awards granted
210,750

 
197,917

 
193,983

Fiscal year granted
2009

 
2008

 
2007

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
—

 
142,494

 
123,169

Cash paid
$
—

 
$
7.5

 
$
2.6

 
 
 
 
 
 
UGI Stock Unit awards:
 
 
 
 
 
Number of original awards granted
32,898

 
22,400

 
—

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
21,757

 
17,545

 
—

Cash paid
$
0.2

 
$
0.2

 
$
—

Weighted Average Assumption used to determine the fair value of AmeriGas Performance unit Awards and related compensation costs 
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:

 
Grants Awarded in Fiscal
 
2012
 
2011
 
2010
Risk-free rate
0.4
%
 
1.0
%
 
1.7
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
23.0
%
 
34.6
%
 
35.0
%
Dividend yield
6.4
%
 
5.8
%
 
6.8
%
AmeriGas Common Unit based award activity 
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2012:
 
Total
 
Vested
 
Non-Vested
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
AmeriGas
Partners
Common
Units
Subject
to Award
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
September 30, 2011
155,356

 
$
41.79

 
62,638

 
$
38.20

 
92,718

 
$
44.22

AmeriGas Performance Units:


 


 


 


 


 


  Granted
55,150

 
$
48.28

 
8,665

 
$
48.28

 
46,485

 
$
48.28

  Forfeited
(15,068
)
 
$
50.37

 
—

 
$
—

 
(15,068
)
 
$
50.37

  Vested
—

 
$
—

 
36,833

 
$
39.28

 
(36,833
)
 
$
39.28

  Performance criteria not met
(48,633
)
 
$
32.17

 
(48,633
)
 
$
32.17

 
—

 
$
—

AmeriGas Stock Units:
 
 
 
 
 
 
 
 
 
 
 
  Granted
193,668

 
$
41.77

 
66,244

 
$
41.81

 
127,424

 
$
41.76

  Forfeited
(10,360
)
 
$
41.42

 
—

 
$
—

 
(10,360
)
 
$
41.42

  Vested
—

 
$
—

 
6,050

 
$
35.05

 
(6,050
)
 
$
35.05

  Awards paid
(66,146
)
 
$
40.72

 
(66,146
)
 
$
40.72

 
—

 
$
—

September 30, 2012
263,967

 
$
44.70

 
65,651

 
$
45.42

 
198,316

 
$
44.47

AmeriGas Common Unit Based Awards In Common Units And Cash 
During Fiscal 2012, Fiscal 2011 and Fiscal 2010, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:

 
2012 (a)
 
2011
 
2010
Number of Common Units subject to original awards granted
60,200

 
41,064

 
49,650

Fiscal year granted
2009

 
2008

 
2007

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued
3,500

 
35,787

 
42,121

Cash paid
$
0.1

 
$
1.2

 
$
1.2


(a) In addition, 40,516 AmeriGas Stock Units, and $0.9 in cash, were paid to Heritage Propane employees associated with awards granted in Fiscal 2012.

Commitments and Contingencies (Tables)
Minimum future payments under operating leases 
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 2017
AmeriGas Propane
$
62.0

 
$
48.8

 
$
39.4

 
$
30.3

 
$
23.1

 
$
63.9

UGI Utilities
5.4

 
4.3

 
3.4

 
3.1

 
1.8

 
2.3

International Propane
8.0

 
5.6

 
3.4

 
2.6

 
2.4

 
2.3

Other
2.0

 
1.7

 
1.3

 
1.1

 
0.3

 
0.1

Total
$
77.4

 
$
60.4

 
$
47.5

 
$
37.1

 
$
27.6

 
$
68.6

Contractual obligations under supply storage and service contracts 
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2012:
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 2017
UGI Utilities supply, storage and transportation contracts
$
173.9

 
$
95.0

 
$
61.8

 
$
43.3

 
$
26.5

 
$
62.7

Midstream & Marketing supply contracts
171.1

 
51.4

 
4.7

 
—

 
—

 
—

AmeriGas Propane supply contracts
141.4

 
87.0

 
87.7

 
3.2

 
—

 
—

International Propane supply contracts
226.4

 
143.4

 
143.4

 
58.0

 
—

 
—

Total
$
712.8

 
$
376.8

 
$
297.6

 
$
104.5

 
$
26.5

 
$
62.7

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 September 30, 2012 and 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
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
)
 
 
 
 
 
 
 
 
September 30, 2011:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
3.5

 
$
3.3

 
$
—

 
$
6.8

Foreign currency contracts
$
—

 
$
5.3

 
$
—

 
$
5.3

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(28.1
)
 
$
(16.1
)
 
$
—

 
$
(44.2
)
Foreign currency contracts
$
—

 
$
(3.3
)
 
$
—

 
$
(3.3
)
Interest rate contracts
$
—

 
$
(44.4
)
 
$
—

 
$
(44.4
)
Disclosures About Derivative Instruments and Hedging Activities (Tables)
Outstanding derivative commodity instruments volumes 
At September 30, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

 
 
Volumes
Commodity
 
2012
 
2011
LPG (millions of gallons)
 
243.9

 
138.0

Natural gas (millions of dekatherms, net)
 
23.6

 
26.1

Electricity calls (millions of kilowatt hours)
 
1,415.7

 
1,219.8

Electricity puts (millions of kilowatt hours)
 
135.3

 
204.9

Balance sheet location and fair value of derivative assets and liabilities 
The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of September 30, 2012 and 2011:

 
Derivative Assets
 
Derivative Liabilities
 
 
 
Fair Value
 
 
 
Fair Value
 
 
 
September 30,
 
 
 
September 30,
 
Balance Sheet
Location
 
2012
 
2011
 
Balance Sheet
Location
 
2012
 
2011
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 Commodity contracts
Derivative financial instruments
and Other assets
 
$
6.5

 
$
1.1

 
Derivative financial instruments
and Other noncurrent liabilities
 
$
(50.7
)
 
$
(32.5
)
Foreign currency contracts
Derivative financial instruments
and Other assets
 
1.8

 
5.2

 
Derivative financial instruments
and Other noncurrent liabilities
 
—

 
—

Interest rate contracts
 
 
—

 
—

 
Derivative financial instruments
and Other noncurrent liabilities
 
(71.9
)
 
(44.4
)
Total Derivatives Designated as Hedging Instruments
 
 
$
8.3

 
$
6.3

 
 
 
$
(122.6
)
 
$
(76.9
)
Derivatives Accounted for Under ASC 980:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 
$
5.3

 
$
—

 
Derivative financial instruments and Other noncurrent liabilities
 
$
(9.4
)
 
$
(11.7
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
 
 
$
—

—

$
—

 
Derivative financial instruments
 
$
—

 
$
(3.3
)
Commodity contracts
Derivative financial instruments
and Other assets
 
1.3

 
5.8

 
 
 
(0.9
)
 
—

Total Derivatives Not Designated as Hedging Instruments
 
 
$
1.3

 
$
5.8

 
 
 
$
(0.9
)
 
$
(3.3
)
Total Derivatives
 
 
$
14.9

 
$
12.1

 
 
 
$
(132.9
)
 
$
(91.9
)
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest 
The following tables provide information on the effects of derivative instruments in the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2012 and 2011:
 
Gain or (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain or (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain or (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
(135.1
)
 
$
2.2

 
$
(41.7
)
 
$
(115.4
)
 
$
(17.4
)
 
$
(21.0
)
 
Cost of sales
Foreign currency contracts
(0.5
)
 
6.9

 
3.2

 
2.1

 
(0.8
)
 
0.7

 
Cost of sales
Interest rate contracts
(36.8
)
 
(35.8
)
 
(12.6
)
 
(11.5
)
 
(14.1
)
 
(28.2
)
 
Interest expense /other income
Total
$
(172.4
)
 
$
(26.7
)
 
$
(51.1
)
 
$
(124.8
)
 
$
(32.3
)
 
$
(48.5
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
$
0.6

 
$
0.2

 
$
5.0

 
 
 
 
 
 
 
 

Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
Gain or (Loss)
Recognized in Income
Location of
Gain or (Loss)
Recognized in Income
 
 
2012
 
2011
 
2010
Commodity contracts
$
(16.8
)
 
$
2.1

 
$
1.3

Cost of sales
 
Commodity contracts
0.2

 
0.3

 
0.2

Operating expenses / other income
 
Foreign currency contracts
0.5

 
(6.1
)
 
—

Other income
 
Total
$
(16.1
)
 
$
(3.7
)
 
$
1.5

 
 
Other Income Net (Tables)
Other Income, Net
Other income, net, comprises the following:

 
2012
 
2011
 
2010
Interest and interest-related income
$
2.4

 
$
2.3

 
$
2.9

Antargaz Competition Authority matter
—

 
9.4

 
—

Utility non-tariff service income
2.7

 
6.4

 
2.4

Foreign currency hedge gain (loss)
0.5

 
(6.1
)
 
—

Gain on sale of Atlantic Energy, LLC
—

 
—

 
36.5

Finance charges
18.8

 
15.1

 
11.3

Partnership interest rate protection agreement loss
—

 
—

 
(12.2
)
Other, net
13.9

 
19.4

 
17.1

Total other income, net
$
38.3

 
$
46.5

 
$
58.0

Quarterly Data (Unaudited) (Tables)
Adjusted Unaudited Quarterly Data
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.

 
 
December 31,
 
March 31,
 
June 30,
 
September 30,
 
 
2011 (a)
 
2010 (b)
 
2012 (c)
 
2011 (d)
 
2012
 
2011
 
2012
 
2011 (e)
Revenues
 
$
1,688.8

 
$
1,765.6

 
$
2,427.5

 
$
2,181.0

 
$
1,277.2

 
$
1,105.4

 
$
1,125.7

 
$
1,039.3

Operating income (loss)
 
$
188.3

 
$
252.3

 
$
380.8

 
$
357.0

 
$
(19.2
)
 
$
17.2

 
$
(28.6
)
 
$
(10.5
)
Loss from equity investees
 
$
(0.1
)
 
$
(0.2
)
 
$
—

 
$
(0.4
)
 
$
(0.1
)
 
$
(0.2
)
 
$
(0.1
)
 
$
(0.1
)
(Loss) gain on extinguishments of debt
 
$
—

 
$
—

 
$
(13.4
)
 
$
(18.8
)
 
$
0.1

 
$
—

 
$
—

 
$
(19.3
)
Net income (loss)
 
$
110.1

 
$
155.0

 
$
227.0

 
$
215.6

 
$
(76.5
)
 
$
(13.5
)
 
$
(74.0
)
 
$
(48.9
)
Net income (loss) attributable to UGI Corporation
 
$
87.0

 
$
113.1

 
$
133.4

 
$
149.4

 
$
(6.3
)
 
$
(7.2
)
 
$
(14.7
)
 
$
(22.4
)
Earnings (loss) per share attributable to UGI stockholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
$0.78
 
$1.02
 
$1.19
 
$1.34
 
$(0.06)
 
$(0.06)
 
$(0.13)
 
$(0.20)
Diluted
 
$0.77
 
$1.01
 
$1.18
 
$1.32
 
$(0.06)
 
$(0.06)
 
$(0.13)
 
$(0.20)
(a)
Includes adjustment to foreign tax credit valuation allowance which increased net income by $5.5 or $0.05 per diluted share.
(b)
Includes the reversal of previously recorded nontaxable accrual associated with the Antargaz Competition Authority Matter which increased operating income and net income attributable to UGI Corporation by $9.4 or $0.08 per diluted share (see Note 15).
(c)
Includes loss on extinguishment of Partnership long-term debt which decreased net income attributable to UGI Corporation by $2.2 or $0.02 per diluted share (see Note 5).
(d)
Includes loss on extinguishment of Partnership long-term debt which decreased net income attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).
(e)
Includes loss on extinguishment of Partnership long-term debt which increased net loss attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).
Segment Information (Tables)
Segment Information

 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
International Propane
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,519.2

 
$
(178.8
)
(c)
$
2,921.6

 
$
785.4

 
$
816.4

 
$
43.0

 
$
1,121.3

 
$
824.7

 
$
185.6

Cost of sales
$
4,111.2

 
$
(174.0
)
(c)
$
1,719.7

 
$
402.5

 
$
703.8

 
$
27.1

 
$
685.5

 
$
640.3

 
$
106.3

Operating income (loss)
$
521.3

 
$
—

 
$
170.3

 
$
172.2

 
$
68.9

 
$
(6.5
)
 
$
88.2

 
$
23.6

 
$
4.6

Loss from equity investees
$
(0.3
)
 
—

 
—

 
—

 
—

 
—

 
(0.3
)
 
—

 
—

Loss on extinguishments of debt
$
(13.3
)
 
—

 
(13.3
)
 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(221.5
)
 
—

 
(142.6
)
 
(40.1
)
 
(4.8
)
 
—

 
(26.3
)
 
(4.6
)
 
(3.1
)
Income (loss) before income taxes
$
286.2

 
$
—

 
$
14.4

 
$
132.1

 
$
64.1

 
$
(6.5
)
 
$
61.6

 
$
19.0

 
$
1.5

Net income (loss) attributable to UGI
$
199.4

 
$
—

 
$
15.9

 
$
80.5

 
$
37.6

 
$
(1.2
)
 
$
51.3

 
$
13.8

 
$
1.5

Depreciation and amortization
$
316.0

 
$
—

 
$
169.1

 
$
49.0

 
$
3.7

 
$
9.0

 
$
57.1

 
$
22.1

 
$
6.0

Noncontrolling interests’ net (loss) income
$
(12.8
)
 
$
—

 
$
(13.0
)
 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
324.7

 

 

 

 

 

 

Total assets
$
9,709.7

 
$
(104.1
)
 
$
4,539.6

 
$
2,070.4

 
$
368.5

 
$
258.2

 
$
1,686.5

 
$
531.8

 
$
358.8

Bank loans
$
165.1

 
$
—

 
$
49.9

 
$
9.2

 
$
85.0

 
$
—

 
$
—

 
$
21.0

 
$
—

Capital expenditures
$
343.2

 
$
—

 
$
103.1

 
$
109.0

 
$
36.0

 
$
24.4

 
$
47.3

 
$
16.9

 
$
6.5

Investments in equity investees
$
0.3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

Goodwill
$
2,818.3

 
$
—

 
$
1,919.2

 
$
182.1

 
$
2.8

 
$
—

 
$
612.0

 
$
95.2

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,091.3

 
$
(233.0
)
(c)
$
2,538.0

 
$
1,026.4

 
$
1,023.8

 
$
49.1

 
$
1,050.6

 
$
438.1

 
$
198.3

Cost of sales
$
4,010.9

 
$
(228.6
)
(c)
$
1,605.3

 
$
610.6

 
$
902.2

 
$
31.1

 
$
649.8

 
$
321.0

 
$
119.5

Operating income (loss)
$
616.0

 
$
—

 
$
242.9

 
$
199.6

 
$
84.2

 
$
(1.3
)
 
$
89.2

 
$
(3.1
)
 
$
4.5

Loss from equity investees
$
(0.9
)
 
—

 
—

 
—

 
—

 
—

 
(0.9
)
 
—

 
—

Loss on extinguishments of debt
$
(38.1
)
 
—

 
(38.1
)
 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(138.0
)
 
—

 
(63.5
)
 
(40.4
)
 
(2.0
)
 
(0.7
)
 
(25.5
)
 
(2.7
)
 
(3.2
)
Income (loss) before income taxes
$
439.0

 
$
—

 
$
141.3

 
$
159.2

 
$
82.2

 
$
(2.0
)
 
$
62.8

 
$
(5.8
)
 
$
1.3

Net income (loss) attributable to UGI
$
232.9

 
$
—

 
$
39.9

 
$
99.3

 
$
48.4

 
$
4.1

 
$
44.2

 
$
(3.2
)
 
$
0.2

Depreciation and amortization
$
227.9

 
$
—

 
$
94.7

 
$
48.4

 
$
2.4

 
$
5.6

 
$
52.1

 
$
18.5

 
$
6.2

Noncontrolling interests’ net income
$
75.3

 
$
—

 
$
75.0

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
297.1

 

 

 

 

 

 

Total assets
$
6,663.3

 
$
(93.3
)
 
$
1,800.4

 
$
2,028.7

 
$
338.2

 
$
242.5

 
$
1,636.6

 
$
428.8

 
$
281.4

Bank loans
$
138.7

 
$
—

 
$
95.5

 
$
—

 
$
24.3

 
$
—

 
$
—

 
$
18.9

 
$
—

Capital expenditures
$
355.6

 
$
—

 
$
77.2

 
$
91.3

 
$
63.1

 
$
49.7

 
$
48.9

 
$
16.5

 
$
8.9

Investments in equity investees
$
0.3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

Goodwill
$
1,562.2

 
$
—

 
$
696.3

 
$
182.1

 
$
2.8

 
$
—

 
$
591.8

 
$
82.2

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
5,591.4

 
$
(203.9
)
(c)
$
2,320.3

 
$
1,047.5

 
$
1,105.3

 
$
58.5

 
$
887.1

 
$
172.4

 
$
204.2

Cost of sales
$
3,584.0

 
$
(197.1
)
(c)
$
1,395.1

 
$
653.4

 
$
998.0

 
$
30.6

 
$
465.9

 
$
116.2

 
$
121.9

Operating income (loss)
$
659.2

 
$
—

 
$
235.8

 
$
175.3

 
$
110.8

 
$
9.2

 
$
115.1

 
$
1.9

 
$
11.1

Loss from equity investees
$
(2.1
)
 
—

 
—

 
—

 
—

 
—

 
(2.0
)
 
(0.1
)
 
—

Loss on extinguishments of debt
 
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
$
(133.8
)
 
—

 
(65.1
)
 
(40.5
)
 
(0.1
)
 
(0.1
)
 
(22.4
)
 
(3.0
)
 
(2.6
)
Income (loss) before income taxes
$
523.3

 
$
—

 
$
170.7

 
$
134.8

 
$
110.7

 
$
9.1

 
$
90.7

 
$
(1.2
)
 
$
8.5

Net income attributable to UGI
$
261.0

 
$
—

 
$
47.3

 
$
83.1

 
$
61.2

 
$
7.0

 
$
60.0

 
$
(1.2
)
 
$
3.6

Depreciation and amortization
$
210.2

 
$
—

 
$
87.4

 
$
49.5

 
$
3.3

 
$
4.4

 
$
48.9

 
$
11.5

 
$
5.2

Noncontrolling interests’ net income (loss)
$
94.7

 
$
—

 
$
91.1

 
$
—

 
$
3.3

 
$
—

 
$
0.3

 
$
—

 
$
—

Partnership EBITDA (a)
 
 

 
$
321.0

 

 

 

 

 

 

Total assets
$
6,374.0

 
$
(81.1
)
 
$
1,690.6

 
$
1,996.3

 
$
245.8

 
$
205.0

 
$
1,678.3

 
$
320.2

 
$
318.9

Bank loans
$
200.4

 
$
—

 
$
91.0

 
$
17.0

 
$
—

 
$
—

 
$
68.2

 
$
24.2

 
$
—

Capital expenditures
$
352.9

 
$
—

 
$
83.2

 
$
73.5

 
$
48.3

 
$
68.1

 
$
51.4

 
$
7.6

 
$
20.8

Investments in equity investees
$
0.4

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

Goodwill
$
1,562.7

 
$
—

 
$
683.1

 
$
180.1

 
$
2.8

 
$
—

 
$
602.7

 
$
87.0

 
$
7.0

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:

Year ended September 30,
 
2012
 
2011
 
2010
 
 
Partnership EBITDA
 
$
324.7

 
$
297.1

 
$
321.0

 
 
Depreciation and amortization
 
(169.1
)
 
(94.7
)
 
(87.4
)
 
 
Loss on extinguishments of debt
 
13.3

 
38.1

 
—

 
 
Noncontrolling interests (i)
 
1.4

 
2.4

 
2.2

 
 
Operating income
 
$
170.3

 
$
242.9

 
$
235.8

 
 

(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 principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Nature of Operations (Details)
Sep. 30, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
General Partner held a general partner interest in AmeriGas Partners
1.00% 
Percentage of our 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)
39,477,103 
Number of Units Held by Affiliates (in units)
29,567,362 
Significant Accounting Policies (Details)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Shares used in computing basic and diluted earnings per share
 
 
 
Average common shares outstanding for basic computation
112,581 1
111,674 1
109,588 
Incremental shares issuable for stock options and common stock awards
851 1
1,270 1
923 
Average common shares outstanding for diluted computation
113,432 1
112,944 1
110,511 
Significant Accounting Policies (Details 1) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Components of AOCI
 
 
Postretirement Benefit Plans
$ (22.9)
$ (12.1)
Derivative Instruments Net Losses
(58.8)
(47.6)
Foreign Currency Translation Adjustments
19.7 
42.0 
Total
$ (62.0)
$ (17.7)
Significant Accounting Policies (Details Textual) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Accounting Policies [Abstract]
 
 
 
Ownership interests in certain subsidiaries under equity method investment
100% or Less 
 
 
Ownership interests in certain subsidiaries under equity method investment, maximum
100.00% 
 
 
Voting rights in investment businesses not traded publicly accounted for under the cost method
20% or Less 
 
 
Voting rights in investment businesses not traded publicly accounted for under the cost method, maximum
20.00% 
 
 
Investments in other assets
$ 80.0 
$ 72.4 
 
Interest (income) expense on tax deficiencies and penalties
(0.1)
0.2 
(0.2)
Antidilutive outstanding stock option award
81,000 
3,700,000 
 
Reclassification of benefit plans actuarial losses and prior service costs net of tax to regulatory assets
 
 
83.3 
Maturities Period of highly liquid investments
three months or less 
 
 
Estimated maximum period of capitalized and amortized costs to install partnership and antargaz-owned tanks
10 years 
 
 
Maximum period of benefit for computer software amortization expense
15 years 
 
 
Net deferred debt issuance costs
46.6 
30.7 
 
Foreign subsidiary customer deposits
$ 205.1 
$ 204.4 
 
Average to Include Prudently Incurred Remediation Costs
5 years 
 
 
Building and Building Improvements [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
15 years 
 
 
Building and Building Improvements [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
40 years 
 
 
Storage and customer tanks and cylinders [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
7 years 
 
 
Storage and customer tanks and cylinders [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
40 years 
 
 
Electric Utility [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Depreciation expense as percentage of related average depreciable base
2.40% 
2.60% 
2.60% 
Electric Generation, Transmission and Distribution Equipment [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
25 years 
 
 
Electric Generation, Transmission and Distribution Equipment [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
35 years 
 
 
Vehicles, equipment and office furniture and fixtures [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
2 years 
 
 
Vehicles, equipment and office furniture and fixtures [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Useful Life (in years)
12 years 
 
 
Gas Utility [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Depreciation expense as percentage of related average depreciable base
2.20% 
2.30% 
2.50% 
Acquisitions and Dispositions (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Finite Lived Intangible Asset Useful Life
 
Estimated useful life (in years)
15 years 
Heritage Propane [Member]
 
Assets acquired:
 
Current assets
$ 301.4 
Property, plant & equipment
890.2 
Customer relationships (estimated useful life of 15 years)
418.9 
Trademarks and tradenames
91.1 
Goodwill
1,217.7 
Other assets
9.9 
Total assets acquired
2,929.2 
Liabilities assumed:
 
Current liabilities
(238.1)
Long-term debt
(62.9)
Other noncurrent liabilities
(23.4)
Total liabilities assumed
(324.4)
Total
$ 2,604.8 
Customer Relationships [Member] |
Heritage Propane [Member]
 
Finite Lived Intangible Asset Useful Life
 
Estimated useful life (in years)
15 years 
Acquisitions and Dispositions (Details 2) (Heritage Propane [Member], USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Heritage Propane [Member]
 
 
Partnership unaudited consolidated results of operations
 
 
Revenues
$ 7,010.9 
$ 7,522.0 
Net income attributable to UGI Corporation
$ 197.6 
$ 223.5 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
Basic (in dollars per share)
$ 1.76 
$ 2.00 
Diluted (in dollars per share)
$ 1.74 
$ 1.98 
Acquisitions and Dispositions (Details Textual) (Details)
In Millions, except Share data, unless otherwise specified
12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended
Sep. 30, 2012
USD ($)
Sep. 30, 2011
USD ($)
Sep. 30, 2010
USD ($)
Jan. 12, 2012
Heritage Propane [Member]
USD ($)
Jun. 30, 2012
Heritage Propane [Member]
USD ($)
Apr. 30, 2012
Heritage Propane [Member]
USD ($)
Sep. 30, 2012
Heritage Propane [Member]
USD ($)
Dec. 31, 2011
Heritage Propane [Member]
Customer
gal
Oct. 31, 2011
International Propane [Member]
USD ($)
Oct. 31, 2011
International Propane [Member]
EUR (€)
Jan. 12, 2012
Energy Transfer Partners, LP [Member]
States
Jan. 12, 2012
Heritage Operating LP [Member]
Jan. 12, 2012
Titan Energy GP LLC [Member]
Sep. 30, 2012
Amerigas [Member]
USD ($)
Sep. 30, 2011
Amerigas [Member]
USD ($)
Sep. 30, 2010
Amerigas [Member]
USD ($)
Sep. 30, 2011
International Propane [Member]
USD ($)
Sep. 30, 2010
International Propane [Member]
USD ($)
Jul. 30, 2010
Atlantic Energy [Member]
USD ($)
gal
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2020 [Member]
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2020 [Member]
Heritage Propane [Member]
USD ($)
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2022 [Member]
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2022 [Member]
Heritage Propane [Member]
USD ($)
Jan. 12, 2012
General Partner [Member]
Heritage Propane [Member]
USD ($)
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchase price of the acquisition
 
 
 
$ 2,598.2 
 
 
 
 
$ 179.0 
€ 133.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business acquired by parent through subsidiaries for cash
 
 
 
1,465.6 
 
 
1,472.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common units issued by AmeriGas Partners (in units)
 
 
 
29,567,362 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable
 
 
 
1,132.6 
 
 
1,132.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Working Capital Adjustment, Additional Cash Paid
 
 
 
 
 
25.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchase price adjustment cash received
 
 
 
 
18.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of states in which business operates (in states)
 
 
 
 
 
 
 
 
 
 
41 
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual Delivery of Propane by Acquired Subsidiary (in gallons)
 
 
 
 
 
 
 
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of Retail Customer (in customers)
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Contribution by Contributor in Form of Limited Partner Interest
 
 
 
 
 
 
 
 
 
 
 
99.999% 
99.99% 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Contribution by Contributor in Form of Membership Interest
 
 
 
 
 
 
 
 
 
 
 
100.00% 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Remaining Contribution by Contributor in Form of General Partner Interest
 
 
 
0.001% 
 
 
 
 
 
 
 
 
0.01% 
 
 
 
 
 
 
 
 
 
 
 
Partners' Capital Account, Units, Contributed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934,327 
Partners' Capital Account, Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41.7 
Long-term Debt
3,514.3 
2,157.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
550.0 
 
1,000.0 
 
Interest rate stated percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.75% 
6.75% 
7.00% 
7.00% 
 
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents
 
 
 
 
 
 
60.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Acquisition Related Costs
 
 
 
 
 
 
5.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash consideration to acquire business
1,580.5 
52.5 
83.0 
 
 
 
 
 
 
 
 
 
 
13.5 
34.0 
34.3 
19.0 
48.7 
 
 
 
 
 
 
Ownership percentage acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46.00% 
 
 
 
 
 
 
Discontinued Operations and Disposal Groups [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from sale of investment in Atlantic Energy
   
   
66.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
49.0 
 
 
 
 
 
Amount of gallon marine import and transhipment facility that company owns and operates (in gallons)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20,000,000 
 
 
 
 
 
Pre-tax gain on the sale which amount is included in other income, net
 
 
36.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in net income attributable to parent due to gain on sale
 
 
$ 17.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Aug. 31, 2011
6.25%, Due August 2019 [Member]
Sep. 30, 2012
Other [Member]
Sep. 30, 2011
Other [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
7.00%, due May 2022 [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
7.00%, due May 2022 [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
6.75%, due May 2020 [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
6.75%, due May 2020 [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
6.50%, Due May 2021 [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
6.50%, Due May 2021 [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
6.25%, Due August 2019 [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
6.25%, Due August 2019 [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
HOLP Senior Secured Notes [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
Other [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
Other [Member]
Sep. 30, 2012
International Propane [Member]
Sep. 30, 2011
International Propane [Member]
Sep. 30, 2012
International Propane [Member]
Antargaz 2011 Senior Facilities term loan due March 2016 [Member]
Sep. 30, 2011
International Propane [Member]
Antargaz 2011 Senior Facilities term loan due March 2016 [Member]
Sep. 30, 2012
International Propane [Member]
Flaga term loan due through September 2016 [Member]
Sep. 30, 2011
International Propane [Member]
Flaga term loan due through September 2016 [Member]
Sep. 30, 2012
International Propane [Member]
Flaga term loan due October 2016 [Member]
Sep. 30, 2011
International Propane [Member]
Flaga term loan due October 2016 [Member]
Sep. 30, 2011
International Propane [Member]
Flaga term loan due through June 2014 [Member]
Sep. 30, 2012
International Propane [Member]
Other [Member]
Sep. 30, 2011
International Propane [Member]
Other [Member]
Sep. 30, 2012
UGI Utilities [Member]
Sep. 30, 2011
UGI Utilities [Member]
Sep. 30, 2012
UGI Utilities [Member]
6.375%, due September 2013 [Member]
Sep. 30, 2011
UGI Utilities [Member]
6.375%, due September 2013 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.75%, due September 2016 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.75%, due September 2016 [Member]
Sep. 30, 2012
UGI Utilities [Member]
6.21%, due September 2036 [Member]
Sep. 30, 2011
UGI Utilities [Member]
6.21%, due September 2036 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.53%, due September 2012 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.53%, due September 2012 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.37%, due August 2013 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.37%, due August 2013 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.16%, due May 2015 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.16%, due May 2015 [Member]
Sep. 30, 2012
UGI Utilities [Member]
7.37%, due October 2015 [Member]
Sep. 30, 2011
UGI Utilities [Member]
7.37%, due October 2015 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.64%, due December 2015 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.64%, due December 2015 [Member]
Sep. 30, 2012
UGI Utilities [Member]
6.17%, due June 2017 [Member]
Sep. 30, 2011
UGI Utilities [Member]
6.17%, due June 2017 [Member]
Sep. 30, 2012
UGI Utilities [Member]
7.25%, due November 2017 [Member]
Sep. 30, 2011
UGI Utilities [Member]
7.25%, due November 2017 [Member]
Sep. 30, 2012
UGI Utilities [Member]
5.67%, due January 2018 [Member]
Sep. 30, 2011
UGI Utilities [Member]
5.67%, due January 2018 [Member]
Sep. 30, 2012
UGI Utilities [Member]
6.50%, due August 2033 [Member]
Sep. 30, 2011
UGI Utilities [Member]
6.50%, due August 2033 [Member]
Sep. 30, 2012
UGI Utilities [Member]
6.13%, due October 2034 [Member]
Sep. 30, 2011
UGI Utilities [Member]
6.13%, due October 2034 [Member]
Long-Term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Carrying value long-term debt
$ 3,514.3 
$ 2,157.7 
 
$ 12.4 
$ 12.9 
$ 2,328.0 
$ 933.5 
$ 980.8 
$ 0 
$ 550.0 
$ 0 
$ 270.0 
$ 470.0 
$ 450.0 
$ 450.0 
$ 55.6 
$ 21.6 
$ 13.5 
$ 573.9 
$ 571.3 
$ 488.7 
$ 508.7 
$ 51.4 
$ 53.5 
$ 24.6 
$ 0 
$ 5.6 
$ 5.6 
$ 3.5 
$ 600.0 
$ 640.0 
$ 108.0 
$ 108.0 
$ 175.0 
$ 175.0 
$ 100.0 
$ 100.0 
$ 0 
$ 40.0 
$ 25.0 
$ 25.0 
$ 20.0 
$ 20.0 
$ 22.0 
$ 22.0 
$ 50.0 
$ 50.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
$ 20.0 
Less: current maturities
(166.7)
(47.4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total long-term debt due after one year
$ 3,347.6 
$ 2,110.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate stated percentage
 
 
6.25% 
 
 
 
 
7.00% 
 
6.75% 
 
6.50% 
 
6.25% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.375% 
 
5.75% 
 
6.21% 
 
5.53% 
 
5.37% 
 
5.16% 
 
7.37% 
 
5.64% 
 
6.17% 
 
7.25% 
 
5.67% 
 
6.50% 
 
6.13% 
 
Debt (Details 1) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Principal Repayment of long-term debt
 
2013
$ 166.1 
2014
64.4 
2015
74.4 
2016
702.3 
2017
50.3 
Other [Member]
 
Principal Repayment of long-term debt
 
2013
0.6 
2014
0.6 
2015
0.5 
2016
0.6 
2017
0.6 
AmeriGas Propane [Member]
 
Principal Repayment of long-term debt
 
2013
30.0 
2014
10.9 
2015
8.9 
2016
6.5 
2017
4.6 
UGI Utilities [Member]
 
Principal Repayment of long-term debt
 
2013
133.0 
2014
   
2015
20.0 
2016
247.0 
2017
20.0 
International Propane [Member]
 
Principal Repayment of long-term debt
 
2013
2.5 
2014
52.9 
2015
45.0 
2016
448.2 
2017
$ 25.1 
Debt (AmeriGas Propane) (Narrative) (Details) (USD $)
3 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 3 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2012
Amerigas Partners Senior Notes Due 2020 [Member]
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2020 [Member]
Jun. 30, 2012
Amerigas Partners Senior Notes Due 2022 [Member]
Sep. 30, 2012
Amerigas Partners Senior Notes Due 2022 [Member]
Jan. 12, 2012
Amerigas Partners Senior Notes Due 2022 [Member]
Mar. 28, 2012
6.50% Senior Note Due May 2021 [Member]
Jan. 31, 2011
6.50% Senior Note Due May 2021 [Member]
Sep. 30, 2011
6.50% Senior Note Due May 2021 [Member]
Jan. 12, 2012
6.50% Senior Note Due May 2021 [Member]
Feb. 28, 2011
7.25%, Due, May 2015 [Member]
Feb. 28, 2011
8.875%, Due May 2011 [Member]
Mar. 31, 2011
8.875%, Due May 2011 [Member]
Aug. 31, 2011
6.25%, Due August 2019 [Member]
Sep. 30, 2011
6.25%, Due August 2019 [Member]
Aug. 31, 2011
7.125%, Due May 2016 [Member]
Sep. 30, 2011
7.125%, Due May 2016 [Member]
Sep. 30, 2012
AmeriGas 2011 Credit Agreement [Member]
Sep. 30, 2011
AmeriGas 2011 Credit Agreement [Member]
Jun. 30, 2011
AmeriGas 2011 Credit Agreement [Member]
Jun. 30, 2011
AmeriGas 2011 Credit Agreement [Member]
Letter of Credit [Member]
Sep. 30, 2012
Amended AmeriGas 2011 Credit Agreement [Member]
Sep. 30, 2011
Ameri Gas Predecessor Credit Agreement [Member]
Sep. 30, 2011
Minimum [Member]
AmeriGas 2011 Credit Agreement [Member]
Sep. 30, 2011
Maximum [Member]
AmeriGas 2011 Credit Agreement [Member]
Sep. 30, 2012
Amerigas Propane [Member]
Sep. 30, 2011
Amerigas Propane [Member]
Sep. 30, 2010
Amerigas Propane [Member]
Sep. 30, 2012
Amerigas Propane [Member]
6.25%, Due August 2019 [Member]
Sep. 30, 2011
Amerigas Propane [Member]
6.25%, Due August 2019 [Member]
Sep. 30, 2012
Amerigas Propane [Member]
Heritage Propane Debt [Member]
Sep. 30, 2012
Amerigas Propane [Member]
HOLP Senior Secured Notes [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate principal amount
 
 
 
 
 
 
 
 
 
 
 
 
$ 550,000,000 
 
 
$ 1,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage senior notes due (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
6.75% 
 
 
7.00% 
 
 
 
6.50% 
7.25% 
8.875% 
 
6.25% 
 
7.125% 
 
 
 
 
 
 
 
 
 
 
 
 
6.25% 
 
 
 
Guaranteed Debt
1,500,000,000 
 
 
 
 
 
 
 
1,500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Redemption at Option
 
 
 
 
 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Tendered for Redemption
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
383,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Aggregate Amount Outstanding Tendered
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
82.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amount outstanding before redemption
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
470,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from issuance of senior notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
470,000,000 
 
 
 
 
 
450,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemption Value of Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Early Redemption Percentage of Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
105.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of proration factor (as a percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of Long-term Debt
 
 
 
 
 
 
 
 
299,900,000 
1,383,600,000 
94,800,000 
 
 
19,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of Senior Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
415,000,000 
14,600,000 
 
 
 
350,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
0 1
100,000 
(13,400,000)2
0 3
(19,300,000)1
0 
(18,800,000)4
0 5
(13,300,000)
(38,100,000)
   
 
 
 
(13,300,000)
 
 
 
 
 
 
 
(18,800,000)
 
 
 
(19,300,000)
 
 
 
 
 
 
 
 
(13,300,000)
(38,100,000)
   
 
 
 
 
Reduction in net income attributable to UGI Corporation due to extinguishment loss
 
 
 
 
 
 
 
 
2,200,000 
5,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt
3,514,300,000 
 
 
 
2,157,700,000 
 
 
 
3,514,300,000 
2,157,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,328,000,000 
933,500,000 
 
450,000,000 
450,000,000 
62,500,000 
55,600,000 
Unamortized Premium
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,400,000 
Interest Rate, Stated Percentage Rate Range, Minimum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.26% 
Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8.87% 
Effective interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.75% 
Credit agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
325,000,000 
 
525,000,000 
 
 
 
 
 
 
 
 
 
 
Rate of Interest above Federal Fund Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit agreement sublimit for letters of credit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
Margin on Credit Agreement Base Rate Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.75% 
1.75% 
 
 
 
 
 
 
 
Margin on credit agreement Eurodollar rate borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.75% 
2.75% 
 
 
 
 
 
 
 
Credit Agreement Facility Fee Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.30% 
0.50% 
 
 
 
 
 
 
 
Borrowings outstanding, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
49,900,000 
 
 
 
 
95,500,000 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate at Period End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.72% 
2.29% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit agreement outstanding, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 47,900,000 
 
 
 
 
$ 35,700,000 
 
 
 
 
 
 
 
 
 
Debt (International Propane) (Narrative) (Details)
3 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Mar. 31, 2011
Sep. 30, 2011
USD ($)
Sep. 30, 2011
EUR (€)
Sep. 30, 2012
USD ($)
Mar. 31, 2011
Antargaz 2011 Senior Facilities [Member]
Mar. 31, 2011
Antargaz 2011 Senior Facilities [Member]
Variable Rate Term Loan [Member]
EUR (€)
Sep. 30, 2011
Antargaz 2011 Senior Facilities [Member]
Variable Rate Term Loan [Member]
Sep. 30, 2012
Antargaz 2011 Senior Facilities [Member]
Variable Rate Term Loan [Member]
EUR (€)
Sep. 30, 2012
Flaga [Member]
Dec. 31, 2011
Flaga [Member]
EUR (€)
Sep. 30, 2012
International Propane [Member]
EUR (€)
Sep. 30, 2011
International Propane [Member]
Euro based variable rate term loan [Member]
Sep. 30, 2012
International Propane [Member]
Euro based variable rate term loan [Member]
Mar. 31, 2011
International Propane [Member]
Euro based variable rate term loan [Member]
EUR (€)
Sep. 30, 2011
Flaga Predecessor Variable Rate Term Loan [Member]
EUR (€)
Sep. 30, 2012
Flaga multi-currency working capital facility [Member]
EUR (€)
Working_Capital_Facility
Sep. 30, 2012
Flaga 2011 Multi Currency Working Capital Facility [Member]
USD ($)
Sep. 30, 2012
Flaga 2011 Multi Currency Working Capital Facility [Member]
EUR (€)
Sep. 30, 2011
Flaga 2011 Multi Currency Working Capital Facility [Member]
USD ($)
Sep. 30, 2011
Flaga 2011 Multi Currency Working Capital Facility [Member]
EUR (€)
Sep. 30, 2012
Flaga euro-denominated working capital facility [Member]
EUR (€)
Sep. 30, 2011
Minimum [Member]
Antargaz 2011 Senior Facilities [Member]
Sep. 30, 2012
Minimum [Member]
Flaga [Member]
Sep. 30, 2011
Minimum [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
Sep. 30, 2011
Maximum [Member]
Antargaz 2011 Senior Facilities [Member]
Sep. 30, 2012
Maximum [Member]
Flaga [Member]
Sep. 30, 2011
Maximum [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
Sep. 30, 2011
Matures in August 2016 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
EUR (€)
Sep. 30, 2011
Matures in September 2016 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
EUR (€)
Sep. 30, 2012
Maturity Date 2014 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
USD ($)
Sep. 30, 2012
Maturity Date 2014 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
EUR (€)
Sep. 30, 2011
Maturity Date 2014 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
USD ($)
Sep. 30, 2011
Maturity Date 2014 [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
EUR (€)
Sep. 30, 2011
Maturity Date 2014 [Member]
Minimum [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
Sep. 30, 2011
Maturity Date 2014 [Member]
Maximum [Member]
International Propane [Member]
Euro based variable rate term loan [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Term Period of Senior Facilities Agreement
1 year 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from issuance of senior notes
 
 
 
 
 
€ 380,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowing capacity under revolving credit agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
40,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
26,700,000 
13,300,000 
 
 
 
 
 
 
Maturities under term loan, May 2015
 
 
 
74,400,000 
 
 
 
38,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturities under term loan, May 2016
 
 
 
702,300,000 
 
 
 
34,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturities under term loan, March 2017
 
 
 
50,300,000 
 
 
 
307,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Margin on credit agreement base rate borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.75% 
 
0.23% 
2.50% 
 
2.55% 
 
 
 
 
 
 
2.625% 
3.50% 
Effective underlying EURIBOR rate of interest on term loan
 
 
 
 
 
 
2.45% 
 
179.00% 
 
 
2.68% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.16% 
2.16% 
 
 
Effective underlying EURIBOR rate of interest on term loan after September 2015
 
 
 
 
 
 
3.71% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective interest rate on term loan
 
 
 
 
 
 
4.66% 
 
4.35% 
 
 
4.76% 
5.18% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Carrying value long-term debt
 
2,157,700,000 
 
3,514,300,000 
 
 
 
 
 
19,100,000 
 
 
 
 
24,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,600,000 
2,800,000 
5,600,000 
4,200,000 
 
 
Margin on Term Loan Base Rate Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
117.50% 
 
 
252.50% 
 
 
 
 
 
 
 
 
 
Credit agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46,000,000 
 
6,000,000 
 
 
12,000,000 
 
 
 
 
 
 
40,000,000 
 
 
 
 
 
 
 
Semi Annual Principal Payments Due
 
 
 
 
 
 
 
 
 
 
700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate on credit agreements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.04% 
5.04% 
5.04% 
5.04% 
 
 
Line of Credit Facility, Number of Working Capital Facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowings outstanding, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,300,000 
11,900,000 
16,500,000 
12,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate at Period End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.31% 
2.31% 
3.39% 
3.39% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit agreement outstanding, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24,700,000 
19,200,000 
16,200,000 
12,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of Net Debt to EBITDA
 
3.50 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guarantor Obligations, Maximum Exposure, Undiscounted
 
 
€ 100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (UGI Utilities) (Narrative) (Details) (UGI Utilities 2011 Credit Agreement [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2012
Letter of Credit [Member]
Sep. 30, 2012
Minimum [Member]
Sep. 30, 2012
Maximum [Member]
Debt Instrument [Line Items]
 
 
 
 
 
Credit agreement
 
$ 300 
 
 
 
Revolving Credit Agreement Sublimit for Letters of Credit
 
 
100 
 
 
Margin on Credit Agreement Base Rate Borrowings
 
 
 
0.00% 
2.00% 
Borrowings outstanding, amount
 
9.2 
 
 
 
Line of Credit Facility, Interest Rate at Period End
 
1.21% 
 
 
 
Letters of Credit Outstanding, Amount
$ 2.0 
$ 2.0 
 
 
 
Ratio of consolidated debt to consolidated capital
0.65 
 
 
 
 
Debt (Energy Services) (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2011
Sep. 30, 2012
Debt Instrument [Line Items]
 
 
Amount of net assets restricted from transfer to UGI under different agreements
 
$ 1,400 
Energy services credit agreement [Member]
 
 
Debt Instrument [Line Items]
 
 
Credit agreement
170 
 
Ratio of consolidated total indebtedness to EBITDA
2.00 
 
Letters of Credit Outstanding, Amount
10.0 
85.0 
Rate of Interest above LIBOR Rate
3.00% 
 
Rate of Interest above Alternate Base Rate
2.00% 
 
Rate of interest above Federal fund Rate
0.50% 
 
Rate of interest above one month LIBOR Rate
1.00% 
 
Line of Credit Facility, Interest Rate at Period End
3.25% 
3.25% 
Minimum consolidated total indebtedness for maximum ratio of Consolidated total indebtedness to Consolidated total capitalization
250 
 
Minimum Consolidated Net Worth, for Maximum Ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization
150 
 
Receivables securitization facility under energy services
200 
 
Letter of Credit [Member] |
Energy services credit agreement [Member]
 
 
Debt Instrument [Line Items]
 
 
Revolving Credit Agreement Sublimit for Letters of Credit
$ 50 
 
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Income Tax Expense (Benefit) [Abstract]
 
 
 
Domestic
$ 227.3 
$ 388.8 
$ 448.8 
Foreign
58.9 
50.2 
74.5 
Income before income taxes
$ 286.2 
$ 439.0 
$ 523.3 
Income Taxes (Details 1) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Current expense (benefit):
 
 
 
Federal
$ (10.4)
$ 24.4 
$ 60.5 
State
11.2 
14.5 
20.4 
Foreign
18.8 
15.0 
25.8 
Investment tax credit
(2.9)
(5.8)
(1.7)
Total current expense
16.7 
48.1 
105.0 
Deferred expense (benefit):
 
 
 
Federal
76.2 
79.3 
54.5 
State
5.2 
2.4 
6.4 
Foreign
1.8 
1.4 
2.1 
Investment tax credit amortization
(0.3)
(0.4)
(0.4)
Total deferred expense
82.9 
82.7 
62.6 
Total income tax expense
$ 99.6 
$ 130.8 
$ 167.6 
Income Taxes (Details 2)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate
 
 
 
U.S. federal statutory tax rate
35.00% 
35.00% 
35.00% 
Difference in tax rate due to:
 
 
 
Noncontrolling interests not subject to tax
1.30% 
(6.00%)
(6.40%)
State income taxes, net of federal benefit
3.80% 
2.20% 
3.50% 
Valuation allowance adjustments
(1.60%)
0.00% 
(0.20%)
Effects of foreign operations
(3.60%)
(0.60%)
(0.60%)
Other, net
(0.10%)
(0.80%)
0.70% 
Effective tax rate
34.80% 
29.80% 
32.00% 
Income Taxes (Details 3) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Deferred tax liabilities (assets)
 
 
Excess book basis over tax basis of property, plant and equipment
$ 582.0 
$ 490.4 
Investment In AmeriGas Partners
293.2 
172.7 
Intangible assets and goodwill
61.2 
52.1 
Utility regulatory assets
140.4 
124.7 
Foreign currency translation adjustment
3.6 
8.5 
Other
6.8 
7.2 
Gross deferred tax liabilities
1,087.2 
855.6 
Pension plan liabilities
(72.7)
(62.8)
Employee-related benefits
(43.0)
(42.7)
Operating loss carryforwards
(38.0)
(31.8)
Foreign tax credit carryforwards
(55.5)
(60.1)
Utility regulatory liabilities
(11.8)
(12.4)
Derivative financial instruments
(37.7)
(30.5)
Other
(31.9)
(32.9)
Gross deferred tax assets
(290.6)
(273.2)
Deferred tax assets valuation allowance
81.6 
81.9 
Net deferred tax liabilities
$ 878.2 
$ 664.3 
Income Taxes (Details 4) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Reconciliation of beginning and ending amount of unrecognized tax benefit
 
 
 
Beginning Balance
$ 6.3 
$ 5.4 
$ 2.3 
Additions for tax positions of the current year
0.5 
0.4 
4.3 
Additions for tax positions of prior years
0.6 
1.0 
 
Reductions as a result of tax positions taken in prior years
 
 
(0.2)
Settlements with tax authorities
(4.5)
(0.5)
(1.0)
Ending Balance
$ 2.9 
$ 6.3 
$ 5.4 
Income Taxes (Details Textual) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended
Sep. 30, 2012
Sep. 30, 2010
Sep. 30, 2011
Sep. 30, 2009
Sep. 30, 2012
Accrued Interest Included [Member]
Sep. 30, 2012
Foreign Country [Member]
Sep. 30, 2012
State and Local Jurisdiction [Member]
Sep. 30, 2011
State and Local Jurisdiction [Member]
Sep. 30, 2010
State and Local Jurisdiction [Member]
Sep. 30, 2012
New Tax Method [Member]
Sep. 30, 2012
Flaga [Member]
Sep. 30, 2012
Flaga [Member]
Foreign Country [Member]
Sep. 30, 2012
Antargaz [Member]
Sep. 30, 2012
Antargaz [Member]
Foreign Country [Member]
Sep. 30, 2012
UGI International Holdings [Member]
Sep. 30, 2012
AmeriGas Propane [Member]
Sep. 30, 2012
Other Subsidiaries [Member]
Income Taxes [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in unusable foreign tax credits
$ 5.2 
$ 2.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Reconciliation, Change in Deferred Tax Assets Valuation Allowance
 
 
 
 
 
4.6 
 
 
 
 
 
 
 
 
 
 
 
State Net Operating Loss carryforwards
 
 
 
 
 
 
213.3 
 
 
18.6 
 
50.2 
 
5.3 
 
 
 
Income Tax Expense (Benefit), Accelerated Depreciation
 
 
 
 
 
 
(3.2)
(7.9)
(2.5)
 
 
 
 
 
 
 
 
Deferred tax assets relating to operating loss carryforwards
38.0 
 
31.8 
 
 
 
 
 
 
 
12.1 
 
1.8 
 
0.9 
5.2 
17.9 
Valuation allowance provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries
17.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Valuation allowance operating loss carryforwards related to acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.0 
 
Valuation allowance provided for deferred tax assets related to certain operations of Antargaz and UGI International Holdings, B.V. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses
 
 
 
 
 
 
 
 
 
 
 
 
7.9 
 
 
 
 
Foreign tax credit carryforwards
 
 
 
 
 
55.5 
 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in valuation allowance
(0.3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Income Tax Expense (Benefit), Unused Foreign Tax Credit
(4.6)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unusable net operating losses obtained in connection with overseas acquisitions
1.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in unusable state operating losses
1.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unusable Net Operating Losses In Connection With Business Acquisition
1.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized income tax benefits
2.9 
5.4 
6.3 
2.3 
3.1 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued interest included in unrecognized income tax benefits
0.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits if recognized would impact the reported effective tax rate
1.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tax positions for which the deductibility is highly certain but uncertainty about the timing
$ 1.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Employee Retirement Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Amounts recorded in UGI Corporation stockholders' equity (pre-tax):
 
 
 
Net actuarial loss (gain)
$ 11.0 
$ 7.6 
 
Pension Benefit [Member]
 
 
 
Change in benefit obligations:
 
 
 
Benefit obligations - beginning of year
462.9 
471.8 
 
Service cost
9.3 
8.8 
8.7 
Interest cost
25.1 
24.1 
23.5 
Actuarial loss (gain)
82.4 
(22.0)
 
Plan amendments
0.1 
   
 
Acquisitions
14.6 
   
 
Foreign currency
(0.7)
(0.1)
 
Benefits paid
(20.3)
(19.7)
 
Benefit obligations - end of year
573.4 
462.9 
471.8 
Change in plan assets:
 
 
 
Fair value of plan assets - beginning of year
290.0 
287.9 
 
Actual gain on plan assets
51.2 
2.6 
 
Foreign currency
(0.5)
   
 
Employer contributions
32.2 
19.2 
 
Acquisitions
17.3 
   
 
Benefits paid
(20.3)
(19.7)
 
Fair value of plan assets - end of year
369.9 
290.0 
287.9 
Funded status of the plans - end of year
(203.5)
(172.9)
 
(Liabilities) recorded in the balance sheet:
 
 
 
Unfunded liabilities - included in other current liabilities
(15.8)
(27.6)
 
Unfunded liabilities - included in other noncurrent liabilities
(187.7)
(145.3)
 
Net amount recognized
(203.5)
(172.9)
 
Amounts recorded in UGI Corporation stockholders' equity (pre-tax):
 
 
 
Prior service credit
(0.1)
(0.2)
 
Net actuarial loss (gain)
25.3 
13.6 
 
Total
25.2 
13.4 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
Prior service cost (credit)
1.5 
1.8 
 
Net actuarial loss
184.5 
146.9 
 
Total
186.0 
148.7 
 
Other Postretirement Benefits [Member]
 
 
 
Change in benefit obligations:
 
 
 
Benefit obligations - beginning of year
20.5 
22.9 
 
Service cost
0.4 
0.4 
0.4 
Interest cost
1.1 
1.1 
1.1 
Actuarial loss (gain)
3.2 
(2.4)
 
Plan amendments
1.0 
(0.1)
 
Acquisitions
   
   
 
Foreign currency
(0.1)
   
 
Benefits paid
(1.4)
(1.4)
 
Benefit obligations - end of year
24.7 
20.5 
22.9 
Change in plan assets:
 
 
 
Fair value of plan assets - beginning of year
9.8 
10.0 
 
Actual gain on plan assets
1.7 
0.1 
 
Foreign currency
   
   
 
Employer contributions
1.1 
1.1 
 
Acquisitions
   
   
 
Benefits paid
(1.4)
(1.4)
 
Fair value of plan assets - end of year
11.2 
9.8 
10.0 
Funded status of the plans - end of year
(13.5)
(10.7)
 
(Liabilities) recorded in the balance sheet:
 
 
 
Unfunded liabilities - included in other current liabilities
(0.6)
(0.6)
 
Unfunded liabilities - included in other noncurrent liabilities
(12.9)
(10.1)
 
Net amount recognized
(13.5)
(10.7)
 
Amounts recorded in UGI Corporation stockholders' equity (pre-tax):
 
 
 
Prior service credit
(0.1)
(0.1)
 
Net actuarial loss (gain)
0.4 
(0.8)
 
Total
0.3 
(0.9)
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
Prior service cost (credit)
(2.8)
(3.2)
 
Net actuarial loss
5.8 
6.3 
 
Total
$ 3.0 
$ 3.1 
 
Employee Retirement Plans (Details 1)
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2010
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2009
Pension Benefit [Member]
 
 
 
 
 
 
Weighted-average assumption:
 
 
 
 
 
 
Discount rate
5.00% 
5.50% 
4.20% 
5.30% 1
5.00% 
5.50% 
Expected return on plan assets
 
 
7.75% 
8.00% 1
8.50% 
8.50% 
Rate of increase in salary levels
 
 
3.25% 
3.50% 1
3.75% 
3.75% 
Other Postretirement Benefits [Member]
 
 
 
 
 
 
Weighted-average assumption:
 
 
 
 
 
 
Discount rate
 
 
4.20% 
5.30% 
5.00% 
5.50% 
Expected return on plan assets
 
 
5.20% 
5.50% 
5.50% 
5.50% 
Rate of increase in salary levels
 
 
3.25% 
3.50% 
3.75% 
3.75% 
Employee Retirement Plans (Details 2) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Pension Benefit [Member]
 
 
 
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
 
 
 
Service cost
$ 9.3 
$ 8.8 
$ 8.7 
Interest cost
25.1 
24.1 
23.5 
Expected return on assets
(26.2)
(25.8)
(25.8)
Curtailment gain
   
   
   
Settlement loss
   
   
1.0 
Amortization of:
 
 
 
Prior service cost (benefit)
0.2 
0.2 
   
Actuarial loss
8.4 
7.5 
5.9 
Net benefit cost (income)
16.8 
14.8 
13.3 
Change in associated regulatory liabilities
   
   
   
Net benefit cost after change in regulatory liabilities
16.8 
14.8 
13.3 
Other Postretirement Benefits [Member]
 
 
 
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
 
 
 
Service cost
0.4 
0.4 
0.4 
Interest cost
1.1 
1.1 
1.1 
Expected return on assets
(0.5)
(0.5)
(0.5)
Curtailment gain
   
(3.2)
   
Settlement loss
   
   
   
Amortization of:
 
 
 
Prior service cost (benefit)
(0.3)
(0.7)
(0.4)
Actuarial loss
0.3 
0.4 
0.1 
Net benefit cost (income)
1.0 
(2.5)
0.7 
Change in associated regulatory liabilities
3.2 
3.1 
3.1 
Net benefit cost after change in regulatory liabilities
$ 4.2 
$ 0.6 
$ 3.8 
Employee Retirement Plans (Details 3) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Pension Benefit [Member]
 
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
 
Fiscal 2013
$ 22.3 
Fiscal 2014
23.3 
Fiscal 2015
24.6 
Fiscal 2016
27.4 
Fiscal 2017
28.0 
Fiscal 2018-2022
158.0 
Other Postretirement Benefits [Member]
 
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
 
Fiscal 2013
1.9 
Fiscal 2014
1.9 
Fiscal 2015
1.9 
Fiscal 2016
1.9 
Fiscal 2017
1.8 
Fiscal 2018-2022
$ 8.7 
Employee Retirement Plans (Details 4)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Pension Benefit [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
100.00% 
100.00% 
Target Asset Allocation
100.00% 
 
Pension Benefit [Member] |
Equity Securities Domestic [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
53.50% 
49.40% 
Target Asset Allocation
52.50% 
 
Permitted Range - Minimum
40.00% 
 
Permitted Range - Maximum
65.00% 
 
Pension Benefit [Member] |
Equity Securities International [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
10.50% 
10.70% 
Target Asset Allocation
12.50% 
 
Permitted Range - Minimum
7.50% 
 
Permitted Range - Maximum
17.50% 
 
Pension Benefit [Member] |
Equity Securities [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
64.00% 
60.10% 
Target Asset Allocation
65.00% 
 
Permitted Range - Minimum
60.00% 
 
Permitted Range - Maximum
70.00% 
 
Pension Benefit [Member] |
Fixed Income Funds And Cash Equivalents [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
36.00% 
39.90% 
Target Asset Allocation
35.00% 
 
Permitted Range - Minimum
30.00% 
 
Permitted Range - Maximum
40.00% 
 
VEBA Trust [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
100.00% 
100.00% 
Target Asset Allocation
100.00% 
 
VEBA Trust [Member] |
Equity Securities Domestic [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
68.50% 
62.20% 
Target Asset Allocation
65.00% 
 
Permitted Range - Minimum
60.00% 
 
Permitted Range - Maximum
70.00% 
 
VEBA Trust [Member] |
Fixed Income Funds And Cash Equivalents [Member]
 
 
Pension Plan
 
 
Actual Pension Plan
31.50% 
37.80% 
Target Asset Allocation
35.00% 
 
Permitted Range - Minimum
30.00% 
 
Permitted Range - Maximum
40.00% 
 
Employee Retirement Plans (Details 5) (U.S Pension Plans [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
$ 351.5 
$ 289.7 
Equity Securities Domestic [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
188.2 
143.1 
Equity Securities International [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
36.9 
31.0 
Fixed Income [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
123.3 
113.6 
Cash Equivalents [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
3.1 
2.0 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
348.4 
287.7 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
188.2 
143.1 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Equity Securities International [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
36.9 
31.0 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Fixed Income [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
123.3 
113.6 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Cash Equivalents [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
3.1 
2.0 
Significant Other Observable Inputs (Level 2) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Equity Securities International [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Fixed Income [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Cash Equivalents [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
3.1 
2.0 
Unobservable Inputs (Level 3) [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Equity Securities International [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Fixed Income [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Cash Equivalents [Member]
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Employee Retirement Plans (Details 6) (VEBA Trust [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
$ 11.2 
$ 9.8 
Equity Securities Domestic [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
7.7 
6.1 
Fixed Income Funds [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
3.4 
3.3 
Cash and Cash Equivalents [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
0.1 
0.4 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
11.1 
9.4 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
7.7 
6.1 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Fixed Income Funds [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
3.4 
3.3 
Quoted Prices In Active Market For Identical Assets And Liabilities (Level 1) [Member] |
Cash and Cash Equivalents [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
0.1 
0.4 
Significant Other Observable Inputs (Level 2) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Fixed Income Funds [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Significant Other Observable Inputs (Level 2) [Member] |
Cash and Cash Equivalents [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
0.1 
0.4 
Unobservable Inputs (Level 3) [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Equity Securities Domestic [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Fixed Income Funds [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Unobservable Inputs (Level 3) [Member] |
Cash and Cash Equivalents [Member]
 
 
Fair Value of Plan Assets
 
 
Fair Value of Plan Assets
   
   
Employee Retirement Plans (Details Textual) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Amortization of net actuarial losses
$ (15.4)
 
 
Amortization of prior service credits
(0.1)
 
 
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans
29.5 
25.6 
 
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans
3.0 
3.0 
2.6 
Amounts recorded in UGI's stockholders include pre-tax losses representing unrecognized actuarial losses
(11.0)
(7.6)
 
Amount of expected amortization of pre-tax actuarial losses into retiree benefit cost
0.7 
 
 
Percentage of Aggregate Employer Securities Holdings to Not to Exceed Fair Value Assets
10.00% 
 
 
Percentage of UGI Common Stock represented Pension Plan Assets
7.50% 
7.60% 
 
Cost of benefits under the 401(k) savings plan
13.7 
10.4 
9.8 
Maximum [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Assumed domestic health care cost range
7.00% 
 
 
Minimum [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Assumed domestic health care cost range
5.00% 
 
 
U.S Pension Plans [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
ABO for the Pension Plans
496.4 
415.0 
 
Contribution made to Pension Plan
31.2 
18.7 
3.4 
Expected contribution to pensions plans in next twelve months
$ 16 
 
 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
$ 338.4 
$ 300.4 
Regulatory Liabilities
28.3 
29.8 
Postretirement benefits [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Liabilities
13.1 
11.5 
Environmental overcollections [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Liabilities
2.9 
4.7 
Deferred fuel and power refunds [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Liabilities
4.4 
6.6 
State tax benefits - distribution system repairs [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Liabilities
7.4 
6.3 
Other regulatory liabilities [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Liabilities
0.5 
0.7 
Income taxes recoverable [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
103.2 
97.9 
Underfunded pension and postretirement plans [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
188.2 
150.7 
Environmental costs [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
16.8 
19.5 
Deferred fuel and power costs [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
11.6 
12.2 
Removal costs, net [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
12.7 
12.3 
Other regulatory assets [Member]
 
 
Regulatory Assets and Liabilities [Line Items]
 
 
Regulatory Assets
$ 5.9 
$ 7.8 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textual) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Mar. 31, 2011
Sep. 30, 2012
Sep. 30, 2011
Dec. 1, 2010
mi
Sep. 30, 2012
Minimum [Member]
Sep. 30, 2012
Maximum [Member]
Sep. 30, 2012
UGI Central Penn Gas Inc [Member]
Jan. 14, 2011
UGI Central Penn Gas Inc [Member]
Oct. 3, 2012
Allentown, Pennsylvania Natural Gas Explosion [Member]
UGI Utilities [Member]
Claims
Feb. 9, 2011
Allentown, Pennsylvania Natural Gas Explosion [Member]
UGI Utilities [Member]
Person
Regulatory Assets and Liabilities [Line Items]
 
 
 
 
 
 
 
 
 
 
Average remaining depreciable lives of the associated property
 
 
 
 
1 year 
50 years 
 
 
 
 
Unrealized gains (losses) on derivative financial instruments contracts
 
$ (5.3)
$ (3.1)
 
 
 
 
 
 
 
Fair value of electric utility electricity supply contracts
 
9.2 
8.7 
 
 
 
 
 
 
 
Minimum period to recover costs related to other regulatory assets
 
1 year 
 
 
 
 
 
 
 
 
Maximum period to recover costs related to other regulatory assets
 
5 years 
 
 
 
 
 
 
 
 
Maximum Percentage of Incremental Operating Margin Traditional Ratemaking
 
5.00% 
 
 
 
 
 
 
 
 
Deaths From Natural Gas Explosion (in person)
 
 
 
 
 
 
 
 
 
5 
Alleged committed violations (in claims)
 
 
 
 
 
 
 
 
6 
 
Damages paid
 
 
 
 
 
 
 
 
0.4 
 
Accelerated Time Frame Replacing Remainder of Cast-Iron Mains
 
 
 
 
 
 
 
 
14 years 
 
Agreement to not Seek Recovery of Related Annual Cost of Capital Return Requirements
 
 
 
 
 
 
 
 
24 months 
 
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains
 
 
 
 
 
 
 
 
30 years 
 
Request to increase base operating revenues to fund system improvements and operations
 
 
 
 
 
 
 
16.5 
 
 
Additional base rate revenue using for increased distribution rates per settlement agreement
 
 
 
 
 
 
8.0 
 
 
 
Increase in Base Rate Revenue for Energy and Efficiency Conservation Program
 
 
 
 
 
 
0.9 
 
 
 
Reversal of Previous Increase in Base Rate Revenue for Energy and Efficiency Conservation Program
 
 
 
 
 
 
0.9 
 
 
 
Net book value of the storage facility assets
 
 
10.9 
 
 
 
 
 
 
 
Term Period of Senior Facilities Agreement
1 year 
 
 
 
 
 
 
 
 
 
Approval of the transfer length of natural gas pipeline (in miles)
 
 
 
9 
 
 
 
 
 
 
Net book value of the Auburn line
 
 
 
$ 1.1 
 
 
 
 
 
 
Inventories (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Inventories
 
 
Total inventories
$ 356.9 
$ 363.0 
Non-utility LPG and natural gas [Member]
 
 
Inventories
 
 
Total inventories
240.7 
222.2 
Gas Utility natural gas [Member]
 
 
Inventories
 
 
Total inventories
57.7 
95.6 
Materials, supplies and other [Member]
 
 
Inventories
 
 
Total inventories
$ 58.5 
$ 45.2 
Inventories (Details Textual) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
ft3
Sep. 30, 2011
ft3
Sep. 30, 2012
UGI Utilities [Member]
Storage Contract Administrative Agreements [Member]
Storage_Agreement
Sep. 30, 2012
UGI Utilities [Member]
Expires in October 2012 [Member]
Storage Contract Administrative Agreements [Member]
Storage_Agreement
Sep. 30, 2012
UGI Utilities [Member]
Expires in October 2013 [Member]
Storage Contract Administrative Agreements [Member]
Storage_Agreement
Nov. 1, 2012
UGI Utilities [Member]
New Storage Agreement [Member]
Storage Contract Administrative Agreements [Member]
Storage_Agreement
Public Utilities, Inventory [Line Items]
 
 
 
 
 
 
Number of storage agreements (in storage agreements)
 
 
3 
2 
1 
2 
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)
3,800,000,000 
3,900,000,000 
 
 
 
 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 11.4 
$ 19.0 
 
 
 
 
Storage Agreement Term
 
 
 
 
 
3 years 
Property, Plant and Equipment (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Property, Plant and Equipment [Line Items]
 
 
Utilities
$ 2,295.7 
$ 2,201.0 
Non-utility
4,223.4 
3,083.5 
Total property, plant and equipment
6,519.1 
5,284.5 
Distribution [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Utilities
2,047.8 
1,951.9 
Transmission [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Utilities
85.4 
83.4 
General and other, including work in process [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Utilities
162.5 
165.7 
Land [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
175.0 
98.5 
Building and improvements [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
283.3 
214.8 
Transportation equipment [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
246.5 
112.6 
Equipment, primarily cylinders and tanks [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
3,041.1 
2,127.6 
Electric generation [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
254.3 
230.0 
Other, including work in process [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Non-utility
$ 223.2 
$ 300.0 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
Goodwill (not subject to amortization)
$ 2,818.3 
$ 1,562.2 
$ 1,562.7 
Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
691.9 
232.1 
 
Trademarks and tradenames (not subject to amortization)
137.2 
47.9 
 
Gross carrying amount
829.1 
280.0 
 
Accumulated amortization
(170.9)
(132.2)
 
Intangible assets, net
$ 658.2 
$ 147.8 
 
Goodwill and Intangible Assets (Details 1) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
AmeriGas Propane [Member]
Sep. 30, 2011
AmeriGas Propane [Member]
Sep. 30, 2012
Gas Utility [Member]
Sep. 30, 2011
Gas Utility [Member]
Sep. 30, 2012
Energy Services [Member]
Sep. 30, 2011
Energy Services [Member]
Sep. 30, 2010
Energy Services [Member]
Sep. 30, 2012
Antargaz [Member]
Sep. 30, 2011
Antargaz [Member]
Sep. 30, 2012
Flaga & Other [Member]
Sep. 30, 2011
Flaga & Other [Member]
Sep. 30, 2012
Corporate & Other [Member]
Sep. 30, 2011
Corporate & Other [Member]
Sep. 30, 2010
Corporate & Other [Member]
Changes in the carrying amount of goodwill
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Goodwill, Beginning Balance
$ 1,562.2 
$ 1,562.7 
$ 696.3 
$ 683.1 
$ 182.1 
$ 180.1 
$ 2.8 
$ 2.8 
$ 2.8 
$ 591.8 
$ 602.7 
$ 82.2 
$ 87.0 
$ 7.0 1
$ 7.0 1
$ 7.0 1
Goodwill acquired
1,283.2 
13.1 
1,223.1 
13.1 
 
 
 
 
 
46.4 
 
13.7 
   
 
 
 
Purchase accounting adjustments
(0.2)
(1.1)
(0.2)
0.1 
   
2.0 
 
 
 
 
 
   
(3.2)
 
 
 
Foreign currency translation
(26.9)
(12.5)
 
 
 
 
 
 
 
(26.2)
(10.9)
(0.7)
(1.6)
 
 
 
Goodwill, Ending Balance
$ 2,818.3 
$ 1,562.2 
$ 1,919.2 
$ 696.3 
$ 182.1 
$ 182.1 
$ 2.8 
$ 2.8 
$ 2.8 
$ 612.0 
$ 591.8 
$ 95.2 
$ 82.2 
$ 7.0 1
$ 7.0 1
$ 7.0 1
Goodwill and Intangible Assets (Details Textual) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
Amortization, customer relationships and noncompete agreement intangibles over their estimated periods of benefit, maximum period
15 years 
 
 
Amortization expense of intangible assets
$ 44.5 
$ 20.4 
$ 19.9 
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
 
 
 
Fiscal 2013
51.8 
 
 
Fiscal 2014
50.5 
 
 
Fiscal 2015
47.4 
 
 
Fiscal 2016
41.3 
 
 
Fiscal 2017
$ 35.0 
 
 
Series Preferred Stock (Details Textual)
Sep. 30, 2012
UGI Series Preferred Stock [Member]
 
Series Preferred Stock (Textual) [Abstract]
 
Preferred Stock, Authorized
10,000,000 
UGI Utilities Series Preferred Stock [Member]
 
Series Preferred Stock (Textual) [Abstract]
 
Preferred Stock, Authorized
2,000,000 
Common Stock and Equity Based Compensation (Details)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2009
Sep. 30, 2012
Common Stock [Member]
Sep. 30, 2011
Common Stock [Member]
Sep. 30, 2010
Common Stock [Member]
Sep. 30, 2012
Treasury Stock [Member]
Sep. 30, 2011
Treasury Stock [Member]
Sep. 30, 2010
Treasury Stock [Member]
Sep. 30, 2012
Common Stock Outstanding [Member]
Sep. 30, 2011
Common Stock Outstanding [Member]
Sep. 30, 2010
Common Stock Outstanding [Member]
Common stock share activity
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock, Shares, Issued, Beginning Balance
115,624,594 
115,507,094 
115,400,294 
115,261,294 
 
 
 
 
 
 
 
 
 
Treasury Stock, Shares, Beginning Balance
(3,004,173)
(3,671,072)
(5,026,707)
(6,514,587)
 
 
 
 
 
 
 
 
 
Common Stock, Shares, Outstanding, Beginning Balance
112,620,421 
111,836,022 
110,373,587 
108,746,707 
 
 
 
 
 
 
 
 
 
Common Stock, Shares, Issued, Ending Balance
115,624,594 
115,507,094 
115,400,294 
115,261,294 
 
 
 
 
 
 
 
 
 
Treasury Stock, Shares, Ending Balance
(3,004,173)
(3,671,072)
(5,026,707)
(6,514,587)
 
 
 
 
 
 
 
 
 
Common Stock, Shares, Outstanding, Ending Balance
112,620,421 
111,836,022 
110,373,587 
108,746,707 
 
 
 
 
 
 
 
 
 
Issued
 
 
 
 
 
 
 
 
 
 
 
 
 
Employee and director plans
 
 
 
 
 
 
 
824,925 
1,263,065 
1,390,207 
942,425 
1,369,865 
1,529,207 
Employee and director plans, Issued
 
 
 
 
117,500 
106,800 
139,000 
 
 
 
 
 
 
Dividend reinvestment plan
 
 
 
 
 
 
 
104,994 
92,570 
97,673 
104,994 
92,570 
97,673 
Shares reacquired - employee and director plans
 
 
 
 
 
 
 
(263,020)
 
 
(263,020)
 
 
Common Stock and Equity Based Compensation (Details 1) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2009
UGI Stock Option Awards
 
 
 
 
Shares under option, Beginning Balance, Shares
7,673,179 
7,557,045 
7,501,493 
 
Shares under option, Granted
1,508,050 
1,443,558 
1,394,300 
 
Share under option, Cancelled
(321,600)
(235,437)
(62,501)
 
Share under option, Exercised
(801,857)
(1,091,987)
(1,276,247)
 
Share under option, Ending Balance, Shares
8,057,772 
7,673,179 
7,557,045 
7,501,493 
Weighted Average Option Price, Beginning Balance
$ 25.55 
$ 23.81 
$ 22.74 
 
Weighted Average Option Price, Granted
$ 29.26 
$ 31.55 
$ 24.37 
 
Weighted Average Option Price, Cancelled
$ 27.74 
$ 27.79 
$ 25.12 
 
Weighted Average Option Price, Exercised
$ 20.93 
$ 20.95 
$ 18.09 
 
Weighted Average Option Price, Ending Balance
$ 26.62 
$ 25.55 
$ 23.81 
$ 22.74 
Shares Under Option, Total Intrinsic Value, Beginning Balance
$ 15.1 
$ 36.2 
$ 23.2 
 
Exercised Shares, Total Intrinsic Value
7.2 
11.4 
11.7 
 
Share Under Option, Total Intrinsic Value, Ending Balance
41.4 
15.1 
36.2 
23.2 
Weighted Average Contract Term
6 years 1 month 6 days 
6 years 2 months 12 days 
6 years 6 months 
6 years 4 months 24 days 
Option exercisable, Shares
5,317,698 
4,879,784 
4,706,376 
 
Option exercisable, Weighted average option price
$ 25.32 
$ 24.15 
$ 22.99 
 
Option exercisable, Total intrinsic value
34.2 
 
 
 
Option exercisable, Weighted Average Contract Term
5 years 
 
 
 
Non vested options, Shares
2,740,074 
 
 
 
Non vested options, Weighted average option price
$ 29.13 
 
 
 
Non vested options, Total intrinsic value
$ 7.2 
 
 
 
Non Vested Options Weighted Average Contract Term
8 years 3 months 18 days 
 
 
 
Range 1 [Member]
 
 
 
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
 
 
 
 
Lower range limit
$ 0 
 
 
 
Upper range limit
$ 19.99 
 
 
 
Additional information relating to stock options outstanding and exercisable
 
 
 
 
Number of outstanding options
162,300 
 
 
 
Options outstanding , Weighted average remaining contractual life (in years)
1 year 6 months 
 
 
 
Options outstanding, Weighted average exercise price
$ 16.92 
 
 
 
Number of exercisable options
162,300 
 
 
 
Options exercisable, Weighted average exercise price
$ 16.92 
 
 
 
Range 2 [Member]
 
 
 
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
 
 
 
 
Lower range limit
$ 20 
 
 
 
Upper range limit
$ 25 
 
 
 
Additional information relating to stock options outstanding and exercisable
 
 
 
 
Number of outstanding options
2,996,470 
 
 
 
Options outstanding , Weighted average remaining contractual life (in years)
5 years 3 months 18 days 
 
 
 
Options outstanding, Weighted average exercise price
$ 23.29 
 
 
 
Number of exercisable options
2,546,170 
 
 
 
Options exercisable, Weighted average exercise price
$ 23.12 
 
 
 
Range 3 [Member]
 
 
 
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
 
 
 
 
Lower range limit
$ 25.01 
 
 
 
Upper range limit
$ 30 
 
 
 
Additional information relating to stock options outstanding and exercisable
 
 
 
 
Number of outstanding options
3,529,044 
 
 
 
Options outstanding , Weighted average remaining contractual life (in years)
6 years 3 months 18 days 
 
 
 
Options outstanding, Weighted average exercise price
$ 27.99 
 
 
 
Number of exercisable options
2,164,909 
 
 
 
Options exercisable, Weighted average exercise price
$ 27.26 
 
 
 
Range 4 [Member]
 
 
 
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
 
 
 
 
Lower range limit
$ 30.01 
 
 
 
Additional information relating to stock options outstanding and exercisable
 
 
 
 
Number of outstanding options
1,369,958 
 
 
 
Options outstanding , Weighted average remaining contractual life (in years)
7 years 9 months 18 days 
 
 
 
Options outstanding, Weighted average exercise price
$ 31.53 
 
 
 
Number of exercisable options
444,319 
 
 
 
Options exercisable, Weighted average exercise price
$ 31.60 
 
 
 
Common Stock and Equity Based Compensation (Details 2)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected life of option
5 years 9 months 
5 years 9 months 
5 years 9 months 
Weighted average volatility
24.70% 
24.30% 
24.00% 
Weighted average dividend yield
3.50% 
3.40% 
3.30% 
Minimum [Member]
 
 
 
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected volatility
24.70% 
23.80% 
24.00% 
Expected dividend yield
3.30% 
3.10% 
3.30% 
Risk-free rate
0.80% 
1.20% 
1.70% 
Maximum [Member]
 
 
 
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected volatility
24.70% 
24.30% 
24.00% 
Expected dividend yield
3.70% 
3.40% 
3.40% 
Risk-free rate
1.10% 
2.40% 
3.10% 
Common Stock and Equity Based Compensation (Details 3)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected life
5 years 9 months 
5 years 9 months 
5 years 9 months 
UGI Performance Units [Member]
 
 
 
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Risk-free rate
0.40% 
1.00% 
1.70% 
Expected life
3 years 
3 years 
3 years 
Expected volatility
22.20% 
27.60% 
28.00% 
Dividend Yield
3.50% 
3.20% 
3.30% 
Common Stock And Equity Based Compensation (Details 4) (USD $)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
UGI unit award activity
 
 
 
Number of UGI Units, Granted
239,845 
285,470 
231,710 
Weighted Average Grant Date Fair Value, Granted
$ 27.68 
$ 34.78 
$ 22.69 
UGI Performance Units and Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of Equity-based Units, Ending balance
885,338 
900,283 
 
Weighted Average Grant Date Fair Value, End of Period
$ 24.09 
$ 24.13 
 
UGI Performance Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
197,400 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 27.25 
 
 
Number of UGI Units, Forfeited
(51,411)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 27.94 
 
 
Number of UGI Unit Awards, Performance criteria not met
(170,481)
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 27.82 
 
 
UGI Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
42,445 1
61,945 
27,060 
Weighted Average Grant Date Fair Value, Granted
$ 29.69 1
 
 
Number of UGI Unit Awards Paid
(32,898)
 
 
Weighted Average Grant Date Fair Value, Unit awards paid
$ 26.17 
 
 
Number of Equity-based Units, Ending balance
885,338 
 
 
Vested [Member] |
UGI Performance Units and Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of Equity-based Units, Ending balance
580,122 
598,955 
 
Weighted Average Grant Date Fair Value, End of Period
$ 21.72 
$ 21.41 
 
Vested [Member] |
UGI Performance Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
33,518 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 29.16 
 
 
Number of UGI Units, Forfeited
0 
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 0.00 
 
 
Number of UGI Units, Vested
110,083 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 29.04 
 
 
Number of UGI Unit Awards, Performance criteria not met
(170,481)
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 27.82 
 
 
Vested [Member] |
UGI Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
40,945 1
 
 
Weighted Average Grant Date Fair Value, Granted
$ 29.53 1
 
 
Number of UGI Units, Vested
0 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 0.00 
 
 
Number of UGI Unit Awards Paid
(32,898)
 
 
Weighted Average Grant Date Fair Value, Unit awards paid
$ 26.17 
 
 
Non-Vested [Member] |
UGI Performance Units and Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of Equity-based Units, Ending balance
305,216 
301,328 
 
Weighted Average Grant Date Fair Value, End of Period
$ 28.59 
$ 29.56 
 
Non-Vested [Member] |
UGI Performance Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
163,882 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 26.86 
 
 
Number of UGI Units, Forfeited
(51,411)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 27.94 
 
 
Number of UGI Units, Vested
(110,083)
 
 
Weighted Average Grant Date Fair Value, Vested
$ 29.04 
 
 
Number of UGI Unit Awards, Performance criteria not met
0 
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 0.00 
 
 
Non-Vested [Member] |
UGI Stock Units [Member]
 
 
 
UGI unit award activity
 
 
 
Number of UGI Units, Granted
1,500 1
 
 
Weighted Average Grant Date Fair Value, Granted
$ 34.06 1
 
 
Number of UGI Units, Vested
0 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 0.00 
 
 
Common Stock And Equity Based Compensation (Details 5) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
UGI Performance Units [Member]
 
 
 
Payment to UGI Performance Units and UGI Stock Unit awards in share and cash:
 
 
 
Number of original awards granted
210,750 
197,917 
193,983 
Fiscal year granted
2009 
2008 
2007 
Payment of Awards:
 
 
 
Shares of UGI Common Stock issued
0 
142,494 
123,169 
Cash Paid
$ 0 
$ 7.5 
$ 2.6 
UGI Stock Units [Member]
 
 
 
Payment to UGI Performance Units and UGI Stock Unit awards in share and cash:
 
 
 
Number of original awards granted
32,898 
22,400 
0 
Payment of Awards:
 
 
 
Shares of UGI Common Stock issued
21,757 
17,545 
0 
Cash Paid
$ 0.2 
$ 0.2 
$ 0 
Common Stock And Equity Based Compensation (Details 6)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Weighted average assumptions used to determine the fair value of Amerigas performance unit awards and related compensation costs
 
 
 
Expected life
5 years 9 months 
5 years 9 months 
5 years 9 months 
AmeriGas Performance Unit [Member]
 
 
 
Weighted average assumptions used to determine the fair value of Amerigas performance unit awards and related compensation costs
 
 
 
Risk-free rate
0.40% 
1.00% 
1.70% 
Expected life
3 years 
3 years 
3 years 
Expected volatility
23.00% 
34.60% 
35.00% 
Dividend Yield
6.40% 
5.80% 
6.80% 
Common Stock And Equity Based Compensation (Details 7) (USD $)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
239,845 
285,470 
231,710 
Weighted Average Grant Date Fair Value, Granted
$ 27.68 
$ 34.78 
$ 22.69 
Amerigas Performance Units and Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of Equity-based Units, Ending balance
263,967 
155,356 
 
Weighted Average Grant Date Fair Value, End of Period
$ 44.70 
$ 41.79 
 
AmeriGas Performance Unit [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
55,150 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 48.28 
 
 
Number of AmeriGas Units, Forfeited
(15,068)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 50.37 
 
 
Number of AmeriGas Units, Vested
0 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 0.00 
 
 
Number of Equity-based Units, Performance criteria not met
(48,633)
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 32.17 
 
 
Number of Equity-based Units, Ending balance
263,967 
 
 
AmeriGas Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
193,668 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 41.77 
 
 
Number of AmeriGas Units, Forfeited
(10,360)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 41.42 
 
 
Number of AmeriGas Units, Vested
0 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 0.00 
 
 
Number of AmeriGas Unit Awards Paid
(66,146)
 
 
Weighted Average Grant Date Fair Value, Unit awards paid
$ 40.72 
 
 
Vested [Member] |
Amerigas Performance Units and Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of Equity-based Units, Ending balance
65,651 
62,638 
 
Weighted Average Grant Date Fair Value, End of Period
$ 45.42 
$ 38.20 
 
Vested [Member] |
AmeriGas Performance Unit [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
8,665 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 48.28 
 
 
Number of AmeriGas Units, Forfeited
0 
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 0.00 
 
 
Number of AmeriGas Units, Vested
36,833 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 39.28 
 
 
Number of Equity-based Units, Performance criteria not met
(48,633)
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 32.17 
 
 
Vested [Member] |
AmeriGas Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
66,244 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 41.81 
 
 
Number of AmeriGas Units, Forfeited
0 
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 0.00 
 
 
Number of AmeriGas Units, Vested
6,050 
 
 
Weighted Average Grant Date Fair Value, Vested
$ 35.05 
 
 
Number of AmeriGas Unit Awards Paid
(66,146)
 
 
Weighted Average Grant Date Fair Value, Unit awards paid
$ 40.72 
 
 
Non Vested [Member] |
Amerigas Performance Units and Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of Equity-based Units, Ending balance
198,316 
92,718 
 
Weighted Average Grant Date Fair Value, End of Period
 
$ 44.22 
 
Non Vested [Member] |
AmeriGas Performance Unit [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
46,485 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 48.28 
 
 
Number of AmeriGas Units, Forfeited
(15,068)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 50.37 
 
 
Number of AmeriGas Units, Vested
(36,833)
 
 
Weighted Average Grant Date Fair Value, Vested
$ 39.28 
 
 
Number of Equity-based Units, Performance criteria not met
0 
 
 
Weighted Average Grant Date Fair Value, Performance criteria not met
$ 0.00 
 
 
Non Vested [Member] |
AmeriGas Stock Units [Member]
 
 
 
AmeriGas Common Unit Based Award Activity
 
 
 
Number of AmeriGas units, Granted
127,424 
 
 
Weighted Average Grant Date Fair Value, Granted
$ 41.76 
 
 
Number of AmeriGas Units, Forfeited
(10,360)
 
 
Weighted Average Grant Date Fair Value, Forfeited
$ 41.42 
 
 
Number of AmeriGas Units, Vested
(6,050)
 
 
Weighted Average Grant Date Fair Value, Vested
$ 35.05 
 
 
Number of AmeriGas Unit Awards Paid
0 
 
 
Weighted Average Grant Date Fair Value, Unit awards paid
$ 0.00 
 
 
Common Stock And Equity Based Compensation (Details 8) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Number of UGI Units, Granted
239,845 
285,470 
231,710 
AmeriGas Stock Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Number of UGI Units, Granted
193,668 
 
 
AmeriGas Performance Unit [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Number of UGI Units, Granted
55,150 
 
 
AmeriGas Common Unit based awards in common Units and cash
 
 
 
Number of Common Units subject to original awards granted
60,200 1
41,064 
49,650 
Fiscal year granted
2009 1
2008 
2007 
Payment of Awards:
 
 
 
AmeriGas Partners common Units issued
3,500 1
35,787 
42,121 
Cash Paid
$ 0.1 1
$ 1.2 
$ 1.2 
Heritage Propane [Member]
 
 
 
Payment of Awards:
 
 
 
Cash Paid
$ 0.9 
 
 
Heritage Propane [Member] |
AmeriGas Stock Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Number of UGI Units, Granted
40,516 
 
 
Common Stock And Equity Based Compensation (Details Textual) (USD $)
In Millions, except Share data, unless otherwise specified
1 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended
Mar. 31, 2012
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2012
Employee Stock Option [Member]
Sep. 30, 2012
Equity Instruments Other Than Option [Member]
Sep. 30, 2012
Omnibus Equity Compensation Plan [Member]
Dec. 31, 2011
2010 Propane Plan [Member]
Sep. 30, 2012
2010 Propane Plan [Member]
Sep. 30, 2011
2010 Propane Plan [Member]
Sep. 30, 2010
2010 Propane Plan [Member]
Sep. 30, 2012
UGI Stock Units [Member]
Sep. 30, 2011
UGI Stock Units [Member]
Sep. 30, 2010
UGI Stock Units [Member]
Sep. 30, 2012
UGI Performance Units [Member]
Sep. 30, 2011
UGI Performance Units [Member]
Sep. 30, 2010
UGI Performance Units [Member]
Sep. 30, 2012
AmeriGas Performance Unit [Member]
Sep. 30, 2011
AmeriGas Performance Unit [Member]
Sep. 30, 2010
AmeriGas Performance Unit [Member]
Jun. 30, 2010
AmeriGas Performance Unit [Member]
Jan. 12, 2012
Heritage Propane [Member]
Mar. 31, 2012
Noncontrolling Interest [Member]
Sep. 30, 2012
Noncontrolling Interest [Member]
Sep. 30, 2011
Noncontrolling Interest [Member]
Sep. 30, 2010
Noncontrolling Interest [Member]
Mar. 31, 2012
AmeriGas Partners [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common units issued by AmeriGas Partners (in units)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29,567,362 
 
 
 
 
 
Units sold in public offering
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,000,000 
Increase in Stockholders' Equity, Net of Deferred Income Taxes
$ 196.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjustments to reflect change in ownership of Amerigas Partners, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(321.4)
(321.4)
0 
0 
 
Pre-tax equity-based compensation expense
 
14.5 
15.6 
13.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
After tax equity-based compensation expense
 
8.7 
10.3 
8.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options can be exercised
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
no later than ten years from the grant date 
 
 
 
 
 
 
 
 
 
Granted Under Plan Term (in years)
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shares of UGI Common Stock granted as awards
 
 
 
 
15,000,000 
3,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,800,000 
 
 
 
 
 
 
Cash received from stock option exercises
 
16.8 
22.9 
23.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Associated tax benefits
 
2.3 
3.8 
4.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized compensation cost associated with unvested Amerigas unit awards
 
4.2 
 
 
 
 
 
 
 
 
 
5.2 
 
 
 
 
 
3.0 
 
 
 
 
 
 
 
 
 
Weighted-average fair value of stock option granted under stock plans
 
$ 4.31 
$ 5.40 
$ 4.49 
 
 
 
 
$ 43.22 
$ 53.19 
$ 41.39 
 
 
 
$ 27.25 
$ 35.19 
$ 22.51 
 
 
 
 
 
 
 
 
 
 
Target award paid to employee
 
 
 
 
 
 
 
 
 
 
 
 
 
 
grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200% 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum percentage amount of guarantee on target award granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum percentage amount of guarantee on target award granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of target award paid at 40th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of target award paid at 50th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of target award paid at 100th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Expected term of Performance Unit awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
3 years 
 
 
 
 
 
 
 
 
 
Shares granted under UGI Stock Unit awards
 
approximately 70% in shares 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of UGI Units, Granted
 
239,845 
285,470 
231,710 
 
 
 
 
248,818 
49,287 
57,750 
42,445 1
61,945 
27,060 
197,400 
 
 
55,150 
 
 
 
 
 
 
 
 
 
Weighted average grant date fair value unit awards
 
$ 27.68 
$ 34.78 
$ 22.69 
 
 
 
 
 
 
 
$ 29.69 1
 
 
$ 27.25 
 
 
$ 48.28 
 
 
 
 
 
 
 
 
 
Unrecognized compensation cost associated with common unit
 
 
 
 
 
 
 
 
 
 
 
885,338 
 
 
 
 
 
263,967 
 
 
 
 
 
 
 
 
 
Weighted-average period for unvested Amerigas unit awards
 
2 years 
 
 
 
 
 
 
 
 
 
1 year 10 months 24 days 
 
 
 
 
 
2 years 0 months 
 
 
 
 
 
 
 
 
 
Performance units ultimately paid
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of common units subject to original awards granted
 
 
 
 
 
1,436,672 
1,436,672 
 
2,517,419 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of AmeriGas units vested
 
 
 
 
 
 
 
 
 
 
 
3.6 
6.8 
5.0 
 
 
 
5.1 
2.0 
2.0 
 
 
 
 
 
 
 
Liabilities associated with share based compensation
 
 
 
 
 
 
 
 
 
 
 
$ 5.0 
$ 6.0 
 
 
 
 
$ 1.1 
$ 1.2 
 
 
 
 
 
 
 
 
Partnership Distributions and Common Unit Offering (Details) (USD $)
12 Months Ended 1 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Mar. 31, 2012
AmeriGas Partners [Member]
Mar. 31, 2012
Senior Notes [Member]
6.50% Pursuant o Tender Offer [Member]
AmeriGas Partners [Member]
Distributions Made to Member or Limited Partner [Line Items]
 
 
 
 
 
Policy for distribution to partner
45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter 
 
 
 
 
Approximate distributions day range to partners (in days)
45 days 
 
 
 
 
Pre-Incentive distribution of the available cash to Limited Partners
98.00% 
 
 
 
 
Pre-Incentive distribution of available cash to General Partners
2.00% 
 
 
 
 
General Partner Interest in AmeriGas partners
1.00% 
 
 
 
 
General Partner Interest in AmeriGas OLP
1.01% 
 
 
 
 
Minimum quarterly distribution
$ 0.55 
 
 
 
 
First target distribution
$ 0.055 
 
 
 
 
Incentive distribution policy
When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605 
 
 
 
 
Minimum available cash for per common unit
$ 0.605 
 
 
 
 
General Partners distribution based on ownership interest
$ 19,700,000 
$ 9,000,000 
$ 6,900,000 
 
 
Incentive distributions received by the General partner
13,000,000 
5,000,000 
3,000,000 
 
 
Units sold in public offering
 
 
 
7,000,000 
 
Underwriteen public offering price per unit
 
 
 
41.25 
 
Issuances of AmeriGas Partners Common Units
276,600,000 
0 
0 
276,600,000 
 
General partners' contributed capital
 
 
 
2,800,000 
 
Aggregate principal amount
 
 
 
 
$ 200,000,000 
Percentage senior notes due (as a percent)
 
 
 
 
6.50% 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Minimum future payments under operating leases
 
2013
$ 77.4 
2014
60.4 
2015
47.5 
2016
37.1 
2017
27.6 
After 2017
68.6 
AmeriGas Propane [Member]
 
Minimum future payments under operating leases
 
2013
62.0 
2014
48.8 
2015
39.4 
2016
30.3 
2017
23.1 
After 2017
63.9 
UGI Utilities [Member]
 
Minimum future payments under operating leases
 
2013
5.4 
2014
4.3 
2015
3.4 
2016
3.1 
2017
1.8 
After 2017
2.3 
International Propane [Member]
 
Minimum future payments under operating leases
 
2013
8.0 
2014
5.6 
2015
3.4 
2016
2.6 
2017
2.4 
After 2017
2.3 
Other Businesses [Member]
 
Minimum future payments under operating leases
 
2013
2.0 
2014
1.7 
2015
1.3 
2016
1.1 
2017
0.3 
After 2017
$ 0.1 
Commitments and Contingencies (Details 1) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Contractual obligations under supply, storage and service contracts
 
2013
$ 712.8 
2014
376.8 
2015
297.6 
2016
104.5 
2017
26.5 
After 2017
62.7 
Gas Utility and Electric Utility supply, storage and transportation contracts [Member]
 
Contractual obligations under supply, storage and service contracts
 
2013
173.9 
2014
95.0 
2015
61.8 
2016
43.3 
2017
26.5 
After 2017
62.7 
Midstream & Marketing supply contracts [Member]
 
Contractual obligations under supply, storage and service contracts
 
2013
171.1 
2014
51.4 
2015
4.7 
2016
0 
2017
0 
After 2017
0 
AmeriGas Propane supply contracts [Member]
 
Contractual obligations under supply, storage and service contracts
 
2013
141.4 
2014
87.0 
2015
87.7 
2016
3.2 
2017
0 
After 2017
0 
International Propane supply contracts [Member]
 
Contractual obligations under supply, storage and service contracts
 
2013
226.4 
2014
143.4 
2015
143.4 
2016
58.0 
2017
0 
After 2017
$ 0 
Commitments and Contingencies (Details Textual) (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 12 Months Ended 12 Months Ended
Jul. 31, 2011
Customer
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2012
Gas Utility [Member]
Sep. 30, 2012
Midstream and Marketing [Member]
Sep. 30, 2012
Partnership [Member]
Sep. 30, 2008
Partnership [Member]
lb
Sep. 30, 2012
CPG MGP Properties [Member]
Sep. 30, 2012
PNG MGP Properties [Member]
Jun. 30, 2006
Key Span [Member]
Jun. 30, 2004
Key Span [Member]
Dec. 31, 2010
Antargaz Competition Authority [Member]
Sep. 30, 2012
Environmental Issue [Member]
Sep. 30, 2012
Minimum [Member]
Sep. 30, 2012
Maximum [Member]
Sep. 30, 2012
Maximum [Member]
International Propane [Member]
Partnership [Member]
Commitments and Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate rental expense for leases
 
$ 77.9 
$ 69.8 
$ 70.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
Term of contracts
 
 
 
 
1 year 
2 years 
4 years 
 
 
 
 
 
 
 
 
 
4 years 
Contract Terms, Subject to Annual Price And Quantity Adjustments (in years)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1 year 
3 years 
 
Environmental expenditures
 
 
 
 
 
 
 
 
1.8 
1.1 
 
 
 
 
 
 
 
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA
 
15.0 
17.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Base Year for Determination of Investigation and Remediation Cost (in years)
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
Approximate remediation cost spent by claimant
 
 
 
 
 
 
 
 
 
 
 
2.3 
 
 
 
 
 
Environmental exit cost anticipated by claimant
 
 
 
 
 
 
 
 
 
 
 
11 
 
 
 
 
 
Percentage of responsible for cleanup cost
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
 
 
Environmental exit cost based on third party estimate
 
 
 
 
 
 
 
 
 
 
10 
 
 
 
 
 
 
Additional environment exit cost based on claimant estimate
 
 
 
 
 
 
 
 
 
 
20 
 
 
 
 
 
 
Amount of propane in cylinders being sold
 
 
 
 
 
 
 
17 
 
 
 
 
 
 
 
 
 
Reduced amount of propane in cylinders being sold
 
 
 
 
 
 
 
15 
 
 
 
 
 
 
 
 
 
Number of residential customer (in customers)
400 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reversal of Competition Authority Matter Accrual
 
 
 
 
 
 
 
 
 
 
 
 
$ 9.4 
 
 
 
 
Fair Value Measurement (Details) (Fair Value, Measurements, Recurring [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Commodity contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial instruments, assets
$ 13.1 
$ 6.8 
Derivative financial instruments, liabilities
(61.0)
(44.2)
Foreign currency contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial instruments, assets
1.8 
5.3 
Derivative financial instruments, liabilities
 
(3.3)
Interest rate contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial instruments, liabilities
(71.9)
(44.4)
Quoted Prices In Active Market 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
8.6 
3.5 
Derivative financial instruments, liabilities
(7.8)
(28.1)
Quoted Prices In Active Market 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
0 
0 
Derivative financial instruments, liabilities
 
0 
Quoted Prices In Active Market 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
0 
0 
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
4.5 
3.3 
Derivative financial instruments, liabilities
(53.2)
(16.1)
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 
5.3 
Derivative financial instruments, liabilities
 
(3.3)
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, liabilities
(71.9)
(44.4)
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
0 
0 
Derivative financial instruments, liabilities
0 
0 
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
0 
0 
Derivative financial instruments, liabilities
 
0 
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
$ 0 
$ 0 
Fair Value Measurement (Details Textual) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Fair Value Disclosures [Abstract]
 
 
Carrying value long-term debt
$ 3,514.3 
$ 2,157.7 
Estimated fair value long-term debt
$ 3,787.6 
$ 2,223.4 
Disclosures About Derivative Instruments and Hedging Activities (Details)
Sep. 30, 2012
gal
Sep. 30, 2011
gal
LPG (millions of gallons) [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
243,900,000 
138,000,000 
Natural Gas (millions of kilowatt hours) [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
23,600,000 
26,100,000 
Electricity (millions of kilowatt-hours) [Member] |
Call Option [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
1,415,700,000 
1,219,800,000 
Electricity (millions of kilowatt-hours) [Member] |
Put Option [Member]
 
 
Outstanding derivative commodity instruments volumes
 
 
Outstanding derivative commodity instruments volumes
135,300,000 
204,900,000 
Disclosures About Derivative Instruments and Hedging Activities (Details 1) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
$ 14.9 
$ 12.1 
Total Derivatives Liability
(132.9)
(91.9)
Designated as Hedging Instrument [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
8.3 
6.3 
Total Derivatives Liability
(122.6)
(76.9)
Designated as Hedging Instrument [Member] |
Interest Rate Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
0 
0 
Derivatives Not Designated as Hedging Instruments [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
1.3 
5.8 
Total Derivatives Liability
(0.9)
(3.3)
Derivatives Not Designated as Hedging Instruments [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(0.9)
0 
Derivatives Not Designated as Hedging Instruments [Member] |
Foreign currency contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
0 
0 
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
6.5 
1.1 
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
1.8 
5.2 
Derivative Financial Instruments and Other Assets [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
1.3 
5.8 
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
(50.7)
(32.5)
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
0 
0 
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
(71.9)
(44.4)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] |
Accounted for Under ASC 980 [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
(9.4)
(11.7)
Derivative Financial Instruments [Member] |
Accounted for Under ASC 980 [Member] |
Commodity Contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Assets
5.3 
0 
Derivative Financial Instruments [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Foreign currency contracts [Member]
 
 
Balance sheet location and fair value of derivative assets and liabilities
 
 
Total Derivatives Liability
$ 0 
$ (3.3)
Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Derivatives Not Designated as Hedging Instruments [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Gain or (Loss) Recognized in Income
$ (16.1)
$ (3.7)
$ 1.5 
Cash Flow Hedges [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(172.4)
(26.7)
(51.1)
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
(124.8)
(32.3)
(48.5)
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
 
 
 
Gain or (Loss) Recognized in Income
(16.8)
2.1 
1.3 
Commodity Contracts [Member] |
Derivatives Not Designated as Hedging Instruments [Member] |
Operating Expenses/Other Income [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Gain or (Loss) Recognized in Income
0.2 
0.3 
0.2 
Commodity Contracts [Member] |
Cash Flow Hedges [Member] |
Cost of Sales [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(135.1)
2.2 
(41.7)
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
(115.4)
(17.4)
(21.0)
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
 
 
 
Gain or (Loss) Recognized in Income
0.5 
(6.1)
   
Foreign currency contracts [Member] |
Cash Flow Hedges [Member] |
Cost of Sales [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(0.5)
6.9 
3.2 
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
2.1 
(0.8)
0.7 
Foreign currency contracts [Member] |
Net Investment Hedges [Member]
 
 
 
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
0.6 
0.2 
5.0 
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
 
 
 
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion
(36.8)
(35.8)
(12.6)
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion
$ (11.5)
$ (14.1)
$ (28.2)
Disclosures About Derivative Instruments and Hedging Activities (Details Textual)
In Millions, unless otherwise specified
1 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Aug. 31, 2011
USD ($)
Sep. 30, 2010
USD ($)
Sep. 30, 2012
USD ($)
Sep. 30, 2011
USD ($)
Sep. 30, 2012
Interest Rate Swaps [Member]
EUR (€)
Sep. 30, 2011
Interest Rate Swaps [Member]
EUR (€)
Sep. 30, 2012
Foreign Currency [Member]
USD ($)
Sep. 30, 2011
Foreign Currency [Member]
USD ($)
Sep. 30, 2012
Interest Rate Protection Agreements [Member]
USD ($)
Sep. 30, 2011
Interest Rate Protection Agreements [Member]
USD ($)
Sep. 30, 2012
Net Investment Hedges [Member]
EUR (€)
Sep. 30, 2011
Net Investment Hedges [Member]
EUR (€)
Sep. 30, 2012
Electric transmission congestion - Electric Utility [Member]
kWh
Sep. 30, 2011
Electric transmission congestion - Electric Utility [Member]
kWh
Sep. 30, 2012
Electric transmission congestion (excluding Electric Utility) [Member]
kWh
Sep. 30, 2011
Electric transmission congestion (excluding Electric Utility) [Member]
kWh
Sep. 30, 2012
LPG [Member]
gal
Sep. 30, 2011
LPG [Member]
gal
Sep. 30, 2012
Natural Gas [Member]
DTH
Sep. 30, 2011
Natural Gas [Member]
DTH
Sep. 30, 2012
Electricity (millions of kilowatt-hours) [Member]
Call Option [Member]
kWh
Sep. 30, 2011
Electricity (millions of kilowatt-hours) [Member]
Call Option [Member]
kWh
Sep. 30, 2012
Electricity (millions of kilowatt-hours) [Member]
Put Option [Member]
kWh
Sep. 30, 2011
Electricity (millions of kilowatt-hours) [Member]
Put Option [Member]
kWh
Sep. 30, 2012
Gas Utility [Member]
DTH
Sep. 30, 2011
Gas Utility [Member]
DTH
Sep. 30, 2012
Electric Utility - Forward Contract [Member]
USD ($)
kWh
Sep. 30, 2011
Electric Utility - Forward Contract [Member]
USD ($)
kWh
Sep. 30, 2012
Midstream And Marketing Natural Gas [Member]
DTH
Sep. 30, 2012
Midstream And Marketing Propane Storage [Member]
gal
Derivative [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (in units)
 
 
 
 
 
 
 
 
 
 
 
 
189,700,000 
208,600,000 
988,800,000 
1,418,600,000 
243,900,000 
138,000,000 
23,600,000 
26,100,000 
1,415,700,000 
1,219,800,000 
135,300,000 
204,900,000 
19,200,000 
15,100,000 
570,400,000 
788,600,000 
4,300,000 
3,100,000 
Maximum length of time hedged in price risk cash flow hedges
 
 
 
 
 
 
30 months 
 
 
 
 
 
8 months 
 
 
 
26 months 
 
39 months 
 
36 months 
 
16 months 
 
12 months 
 
20 months 
 
 
 
Fair values of electric utility's forward purchase power agreements
 
 
$ 132.9 
$ 91.9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 9.2 
$ 8.7 
 
 
Maximum period of hedging exposure to variability in cash flows associated with price risk, weighted average
 
 
 
 
 
 
11 months 
 
 
 
 
 
 
 
 
 
5 months 
 
11 months 
 
10 months 
 
8 months 
 
 
 
 
 
 
 
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months
 
 
(53.0)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underlying variable rate debt
 
 
 
 
441.9 
424.2 
174.5 
133.9 
173.0 
173.0 
0 
14.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded loss amount included in Other Income, Net
 
 
 
 
 
 
 
 
(0.7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months
 
 
(0.8)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum approximate range of estimated dollar-denominated purchases of LPG
 
 
 
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum approximate range of estimated dollar-denominated purchases of LPG
 
 
 
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net losses associated with currency rate risk to be reclassified into earnings during the next 12 months
 
 
1.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash in brokerage accounts
 
 
3.0 
17.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Write off of settled but unamortized interest rate protection agreements included in extinguishment of debt
2.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long term debt not issued
 
 
 
150 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss as a result of the discontinuance of cash flow hedge accounting
 
$ 12.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy Services Accounts Receivable Securitization Facility (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Energy services accounts receivable securitization facility (Additional Textual) [Abstract]
 
 
 
Receivables facility
$ 200 
 
 
Energy Services [Member]
 
 
 
Energy services accounts receivable securitization facility (Textual) [Abstract]
 
 
 
Sale of trade receivables
836.0 
1,134.9 
1,147.3 
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
286.0 
88.0 
254.6 
Outstanding balance of trade receivables
43.5 
52.1 
 
Outstanding balance of trade receivables sold
 
14.3 
 
Losses on sales of receivables to commercial paper conduit included in interest expenses
1.0 
1.2 
 
Losses on sale of receivables to the commercial paper
 
 
$ 1.5 
Other Income Net (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Other Income Net
 
 
 
Interest and interest-related income
$ 2.4 
$ 2.3 
$ 2.9 
Antargaz Competition Authority matter
0 
9.4 
0 
Utility non-tariff service income
2.7 
6.4 
2.4 
Foreign currency hedge gain (loss)
0.5 
(6.1)
0 
Gain on sale of Atlantic Energy, LLC
0 
0 
36.5 
Finance charges
18.8 
15.1 
11.3 
Partnership interest rate protection agreement loss
0 
0 
(12.2)
Other, net
13.9 
19.4 
17.1 
Total other income, net
$ 38.3 
$ 46.5 
$ 58.0 
Quarterly Data (Unaudited) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,125.7 1
$ 1,277.2 
$ 2,427.5 2
$ 1,688.8 3
$ 1,039.3 1
$ 1,105.4 
$ 2,181.0 4
$ 1,765.6 5
$ 6,519.2 
$ 6,091.3 
$ 5,591.4 
Operating income (loss)
(28.6)1
(19.2)
380.8 2
188.3 3
(10.5)1
17.2 
357.0 4
252.3 5
521.3 
616.0 
659.2 
Loss from equity investees
(0.1)1
(0.1)
0 2
(0.1)3
(0.1)1
(0.2)
(0.4)4
(0.2)5
(0.3)
(0.9)
(2.1)
(Loss) gain on extinguishments of debt
0 1
0.1 
(13.4)2
0 3
(19.3)1
0 
(18.8)4
0 5
(13.3)
(38.1)
   
Net income (loss)
(74.0)1
(76.5)
227.0 2
110.1 3
(48.9)1
(13.5)
215.6 4
155.0 5
186.6 
308.2 
355.7 
Net income (loss) attributable to UGI Corporation
$ (14.7)1
$ (6.3)
$ 133.4 2
$ 87.0 3
$ (22.4)1
$ (7.2)
$ 149.4 4
$ 113.1 5
$ 199.4 
$ 232.9 
$ 261.0 
Earnings (loss) per share attributable to UGI Corporation stockholders:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
$ (0.13)1
$ (0.06)
$ 1.19 2
$ 0.78 3
$ (0.20)1
$ (0.06)
$ 1.34 4
$ 1.02 5
$ 1.77 
$ 2.09 
$ 2.38 
Diluted (in dollars per share)
$ (0.13)1
$ (0.06)
$ 1.18 2
$ 0.77 3
$ (0.20)1
$ (0.06)
$ 1.32 4
$ 1.01 5
$ 1.76 
$ 2.06 
$ 2.36 
Quarterly Data (Unaudited) (Details Textual) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Antargaz [Member]
Quarterly Data Unaudited (Textual)
 
 
 
 
 
Increase in net income due to adjustment to foreign tax credit valuation allowance
 
$ 5.5 
 
 
 
Increase in earnings per share diluted due to adjustment to foreign tax credit valuation allowance
 
$ 0.05 
 
 
 
Increase in operating income due to competition law clause
 
 
 
 
9.4 
Increase in earning per share diluted due to provision for competition law clause
 
 
 
 
$ 0.08 
Decrease in net income due to loss on extinguishment of debt
2.2 
 
 
5.2 
 
Decrease in earning per diluted share due to loss on extinguishment of debt
$ 0.02 
 
 
$ 0.05 
 
Increase in net loss due to loss on extinguishment of debt
 
 
$ 5.2 
 
 
Increase in net loss per diluted share due to loss on extinguishment of debt
 
 
$ 0.05 
 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,125.7 1
$ 1,277.2 
$ 2,427.5 2
$ 1,688.8 3
$ 1,039.3 1
$ 1,105.4 
$ 2,181.0 4
$ 1,765.6 5
$ 6,519.2 
$ 6,091.3 
$ 5,591.4 
Cost of sales
 
 
 
 
 
 
 
 
4,111.2 
4,010.9 
3,584.0 
Operating income (loss)
(28.6)1
(19.2)
380.8 2
188.3 3
(10.5)1
17.2 
357.0 4
252.3 5
521.3 
616.0 
659.2 
Loss from equity investees
(0.1)1
(0.1)
0 2
(0.1)3
(0.1)1
(0.2)
(0.4)4
(0.2)5
(0.3)
(0.9)
(2.1)
Loss on extinguishments of debt
0 1
0.1 
(13.4)2
0 3
(19.3)1
0 
(18.8)4
0 5
(13.3)
(38.1)
   
Interest expense
 
 
 
 
 
 
 
 
(221.5)
(138.0)
(133.8)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
286.2 
439.0 
523.3 
Net income (loss) attributable to UGI
(14.7)1
(6.3)
133.4 2
87.0 3
(22.4)1
(7.2)
149.4 4
113.1 5
199.4 
232.9 
261.0 
Depreciation and amortization
 
 
 
 
 
 
 
 
316.0 
227.9 
210.2 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
(12.8)
75.3 
94.7 
Total assets
9,709.7 
 
 
 
6,663.3 
 
 
 
9,709.7 
6,663.3 
6,374.0 
Bank loans
165.1 
 
 
 
138.7 
 
 
 
165.1 
138.7 
200.4 
Capital expenditures
 
 
 
 
 
 
 
 
343.2 
355.6 
352.9 
Investments in equity investees
0.3 
 
 
 
0.3 
 
 
 
0.3 
0.3 
0.4 
Goodwill
2,818.3 
 
 
 
1,562.2 
 
 
 
2,818.3 
1,562.2 
1,562.7 
Eliminations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
(178.8)6
(233.0)6
(203.9)6
Cost of sales
 
 
 
 
 
 
 
 
(174.0)6
(228.6)6
(197.1)6
Operating income (loss)
 
 
 
 
 
 
 
 
 
0 
0 
Loss from equity investees
 
 
 
 
 
 
 
 
   
 
 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
 
0 
0 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
   
0 
0 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
 
 
   
Total assets
(104.1)
 
 
 
(93.3)
 
 
 
(104.1)
(93.3)
(81.1)
Goodwill
 
 
 
 
 
 
 
 
 
 
   
AmeriGas Propane [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
2,921.6 
2,538.0 
2,320.3 
Cost of sales
 
 
 
 
 
 
 
 
1,719.7 
1,605.3 
1,395.1 
Operating income (loss)
 
 
 
 
 
 
 
 
170.3 
242.9 
235.8 
Loss from equity investees
 
 
 
 
 
 
 
 
   
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
(13.3)
(38.1)
   
Interest expense
 
 
 
 
 
 
 
 
(142.6)
(63.5)
(65.1)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
14.4 
141.3 
170.7 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
15.9 
39.9 
47.3 
Depreciation and amortization
 
 
 
 
 
 
 
 
169.1 
94.7 
87.4 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
(13.0)
75.0 
91.1 
Partnership EBITDA
 
 
 
 
 
 
 
 
324.7 7
297.1 7
321.0 7
Total assets
4,539.6 
 
 
 
1,800.4 
 
 
 
4,539.6 
1,800.4 
1,690.6 
Bank loans
49.9 
 
 
 
95.5 
 
 
 
49.9 
95.5 
91.0 
Capital expenditures
 
 
 
 
 
 
 
 
103.1 
77.2 
83.2 
Goodwill
1,919.2 
 
 
 
696.3 
 
 
 
1,919.2 
696.3 
683.1 
Gas Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
785.4 
1,026.4 
1,047.5 
Cost of sales
 
 
 
 
 
 
 
 
402.5 
610.6 
653.4 
Operating income (loss)
 
 
 
 
 
 
 
 
172.2 
199.6 
175.3 
Loss from equity investees
 
 
 
 
 
 
 
 
   
 
 
Interest expense
 
 
 
 
 
 
 
 
(40.1)
(40.4)
(40.5)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
132.1 
159.2 
134.8 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
80.5 
99.3 
83.1 
Depreciation and amortization
 
 
 
 
 
 
 
 
49.0 
48.4 
49.5 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
 
 
0 
Total assets
2,070.4 
 
 
 
2,028.7 
 
 
 
2,070.4 
2,028.7 
1,996.3 
Bank loans
9.2 
 
 
 
   
 
 
 
9.2 
   
17.0 
Capital expenditures
 
 
 
 
 
 
 
 
109.0 
91.3 
73.5 
Goodwill
182.1 
 
 
 
182.1 
 
 
 
182.1 
182.1 
180.1 
Energy Services [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
816.4 
1,023.8 
1,105.3 
Cost of sales
 
 
 
 
 
 
 
 
703.8 
902.2 
998.0 
Operating income (loss)
 
 
 
 
 
 
 
 
68.9 
84.2 
110.8 
Loss from equity investees
 
 
 
 
 
 
 
 
   
 
 
Interest expense
 
 
 
 
 
 
 
 
(4.8)
(2.0)
0.1 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
64.1 
82.2 
110.7 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
37.6 
48.4 
61.2 
Depreciation and amortization
 
 
 
 
 
 
 
 
3.7 
2.4 
3.3 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
 
 
3.3 
Total assets
368.5 
 
 
 
338.2 
 
 
 
368.5 
338.2 
245.8 
Bank loans
85.0 
 
 
 
24.3 
 
 
 
85.0 
24.3 
 
Capital expenditures
 
 
 
 
 
 
 
 
36.0 
63.1 
48.3 
Goodwill
2.8 
 
 
 
2.8 
 
 
 
2.8 
2.8 
2.8 
Electric Generation [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
43.0 
49.1 
58.5 
Cost of sales
 
 
 
 
 
 
 
 
27.1 
31.1 
30.6 
Operating income (loss)
 
 
 
 
 
 
 
 
(6.5)
(1.3)
9.2 
Loss from equity investees
 
 
 
 
 
 
 
 
0 
 
 
Interest expense
 
 
 
 
 
 
 
 
0 
0.7 
0.1 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
(6.5)
(2.0)
9.1 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
(1.2)
4.1 
7.0 
Depreciation and amortization
 
 
 
 
 
 
 
 
9.0 
5.6 
4.4 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
 
 
0 
Total assets
258.2 
 
 
 
242.5 
 
 
 
258.2 
242.5 
205.0 
Bank loans
0 
 
 
 
0 
 
 
 
0 
0 
 
Capital expenditures
 
 
 
 
 
 
 
 
24.4 
49.7 
68.1 
Goodwill
0 
 
 
 
0 
 
 
 
0 
0 
0 
Antargaz [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
1,121.3 
1,050.6 
887.1 
Cost of sales
 
 
 
 
 
 
 
 
685.5 
649.8 
465.9 
Operating income (loss)
 
 
 
 
 
 
 
 
88.2 
89.2 
115.1 
Loss from equity investees
 
 
 
 
 
 
 
 
(0.3)
(0.9)
(2.0)
Interest expense
 
 
 
 
 
 
 
 
(26.3)
(25.5)
(22.4)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
61.6 
62.8 
90.7 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
51.3 
44.2 
60.0 
Depreciation and amortization
 
 
 
 
 
 
 
 
57.1 
52.1 
48.9 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
0.2 
0.3 
0.3 
Total assets
1,686.5 
 
 
 
1,636.6 
 
 
 
1,686.5 
1,636.6 
1,678.3 
Bank loans
 
 
 
 
   
 
 
 
 
   
68.2 
Capital expenditures
 
 
 
 
 
 
 
 
47.3 
48.9 
51.4 
Goodwill
612.0 
 
 
 
591.8 
 
 
 
612.0 
591.8 
602.7 
Flaga & Other [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
824.7 
438.1 
172.4 
Cost of sales
 
 
 
 
 
 
 
 
640.3 
321.0 
116.2 
Operating income (loss)
 
 
 
 
 
 
 
 
23.6 
(3.1)
1.9 
Loss from equity investees
 
 
 
 
 
 
 
 
   
   
(0.1)
Interest expense
 
 
 
 
 
 
 
 
(4.6)
(2.7)
(3.0)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
19.0 
(5.8)
(1.2)
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
13.8 
(3.2)
(1.2)
Depreciation and amortization
 
 
 
 
 
 
 
 
22.1 
18.5 
11.5 
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
0 
 
   
Total assets
531.8 
 
 
 
428.8 
 
 
 
531.8 
428.8 
320.2 
Bank loans
21.0 
 
 
 
18.9 
 
 
 
21.0 
18.9 
24.2 
Capital expenditures
 
 
 
 
 
 
 
 
16.9 
16.5 
7.6 
Investments in equity investees
0.3 
 
 
 
0.3 
 
 
 
0.3 
0.3 
0.4 
Goodwill
95.2 
 
 
 
82.2 
 
 
 
95.2 
82.2 
87.0 
Corporate & Other [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
185.6 8
198.3 8
204.2 8
Cost of sales
 
 
 
 
 
 
 
 
106.3 8
119.5 8
121.9 8
Operating income (loss)
 
 
 
 
 
 
 
 
4.6 8
4.5 8
11.1 8
Loss from equity investees
 
 
 
 
 
 
 
 
   8
 
 
Interest expense
 
 
 
 
 
 
 
 
(3.1)8
(3.2)8
(2.6)8
Income (loss) before income taxes
 
 
 
 
 
 
 
 
1.5 8
1.3 8
8.5 8
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
1.5 8
0.2 8
3.6 8
Depreciation and amortization
 
 
 
 
 
 
 
 
6.0 8
6.2 8
5.2 8
Noncontrolling interests' net (loss) income
 
 
 
 
 
 
 
 
 
 
   8
Total assets
358.8 8
 
 
 
281.4 8
 
 
 
358.8 8
281.4 8
318.9 8
Bank loans
 
 
 
 
   8
 
 
 
 
   8
   8
Capital expenditures
 
 
 
 
 
 
 
 
6.5 8
8.9 8
20.8 8
Investments in equity investees
 
 
 
 
   8
 
 
 
 
   8
 
Goodwill
$ 7.0 8
 
 
 
$ 7.0 8
 
 
 
$ 7.0 8
$ 7.0 8
$ 7.0 8
Segment Information (Details 1) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Reconciliation of partnership EBITDA
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
 
 
 
 
 
 
 
$ (316.0)
$ (227.9)
$ (210.2)
Loss on extinguishments of debt
0 1
(0.1)
13.4 2
0 3
19.3 1
0 
18.8 4
0 5
13.3 
38.1 
   
Operating income
(28.6)1
(19.2)
380.8 2
188.3 3
(10.5)1
17.2 
357.0 4
252.3 5
521.3 
616.0 
659.2 
AmeriGas Propane [Member]
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of partnership EBITDA
 
 
 
 
 
 
 
 
 
 
 
Partnership EBITDA
 
 
 
 
 
 
 
 
324.7 6
297.1 6
321.0 6
Depreciation and amortization
 
 
 
 
 
 
 
 
(169.1)
(94.7)
(87.4)
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
13.3 
38.1 
   
Noncontrolling interests
 
 
 
 
 
 
 
 
1.4 7
2.4 7
2.2 7
Operating income
 
 
 
 
 
 
 
 
$ 170.3 
$ 242.9 
$ 235.8 
Segment Information (Details Textual)
12 Months Ended
Sep. 30, 2012
States
Reportable_Segments
Segment Reporting [Abstract]
 
Number of Reportable Segments
6 
Number of states to which product sale with propane revenue
50 
General Partner's interest in AmeriGas OLP
1.01% 
Condensed Financial Information of Registrant (Parent Company) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Sep. 30, 2009
Current assets:
 
 
 
 
Cash and cash equivalents
$ 319.9 
$ 238.5 
$ 260.7 
$ 280.1 
Deferred income taxes
56.8 
44.9 
 
 
Total current assets
1,504.5 
1,306.1 
 
 
Total assets
9,709.7 
6,663.3 
6,374.0 
 
Current liabilities:
 
 
 
 
Derivative financial instruments
100.9 
49.7 
 
 
Total current liabilities
1,487.0 
1,077.9 
 
 
Commitments and contingencies (Note 1)
   
   
 
 
Common stockholders' equity:
 
 
 
 
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,624,594 and 115,507,094 shares, respectively)
1,157.7 
937.4 
 
 
Retained earnings
1,166.1 
1,085.8 
 
 
Accumulated other comprehensive loss
(62.0)
(17.7)
 
 
Treasury stock, at cost
(28.7)
(27.8)
 
 
Total UGI Corporation stockholders' equity
2,233.1 
1,977.7 
 
 
Total liabilities and equity
9,709.7 
6,663.3 
 
 
Condensed financial information of registrant (Textual) [Abstract]
 
 
 
 
UGI Common Stock, without par value
$ 0 
$ 0 
 
 
UGI Common Stock, without par value authorized
300,000,000 
300,000,000 
 
 
UGI Common Stock, without par value, issued
115,624,594 
115,507,094 
115,400,294 
115,261,294 
Parent Company [Member]
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
1.9 
0.4 
1.0 
1.4 
Accounts and notes receivable
4.0 
4.9 
 
 
Deferred income taxes
0.4 
0.4 
 
 
Prepaid expenses and other current assets
0.3 
1.4 
 
 
Total current assets
6.6 
7.1 
 
 
Investments in subsidiaries
2,244.4 
1,992.1 
 
 
Deferred income taxes
28.3 
22.3 
 
 
Total assets
2,279.3 
2,021.5 
 
 
Current liabilities:
 
 
 
 
Accounts and notes payable
11.1 
11.4 
 
 
Derivative financial instruments
0 
3.3 
 
 
Accrued liabilities
2.4 
1.7 
 
 
Total current liabilities
13.5 
16.4 
 
 
Noncurrent liabilities
32.7 
27.4 
 
 
Commitments and contingencies (Note 1)
   
   
 
 
Common stockholders' equity:
 
 
 
 
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,624,594 and 115,507,094 shares, respectively)
1,157.7 
937.4 
 
 
Retained earnings
1,166.1 
1,085.8 
 
 
Accumulated other comprehensive loss
(62.0)
(17.7)
 
 
Treasury stock, at cost
(28.7)
(27.8)
 
 
Total UGI Corporation stockholders' equity
2,233.1 
1,977.7 
 
 
Total liabilities and equity
$ 2,279.3 
$ 2,021.5 
 
 
Condensed Financial Information of Registrant (Parent Company) (Details 1) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,125.7 1
$ 1,277.2 
$ 2,427.5 2
$ 1,688.8 3
$ 1,039.3 1
$ 1,105.4 
$ 2,181.0 4
$ 1,765.6 5
$ 6,519.2 
$ 6,091.3 
$ 5,591.4 
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Operating and administrative expenses
 
 
 
 
 
 
 
 
1,591.7 
1,266.4 
1,177.4 
Other income, net
 
 
 
 
 
 
 
 
(38.3)
(46.5)
(58.0)
Total costs and expenses
 
 
 
 
 
 
 
 
5,997.9 
5,475.3 
4,932.2 
Operating loss
(28.6)1
(19.2)
380.8 2
188.3 3
(10.5)1
17.2 
357.0 4
252.3 5
521.3 
616.0 
659.2 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
99.6 
130.8 
167.6 
Equity in income of unconsolidated subsidiaries
(0.1)1
(0.1)
0 2
(0.1)3
(0.1)1
(0.2)
(0.4)4
(0.2)5
(0.3)
(0.9)
(2.1)
Net income attributable to UGI Corporation
(14.7)1
(6.3)
133.4 2
87.0 3
(22.4)1
(7.2)
149.4 4
113.1 5
199.4 
232.9 
261.0 
Earnings per common share:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
$ (0.13)1
$ (0.06)
$ 1.19 2
$ 0.78 3
$ (0.20)1
$ (0.06)
$ 1.34 4
$ 1.02 5
$ 1.77 
$ 2.09 
$ 2.38 
Diluted (in dollars per share)
$ (0.13)1
$ (0.06)
$ 1.18 2
$ 0.77 3
$ (0.20)1
$ (0.06)
$ 1.32 4
$ 1.01 5
$ 1.76 
$ 2.06 
$ 2.36 
Average common shares outstanding (thousands):
 
 
 
 
 
 
 
 
 
 
 
Basic (in shares)
 
 
 
 
 
 
 
 
112,581 6
111,674 6
109,588 
Diluted (in shares)
 
 
 
 
 
 
 
 
113,432 6
112,944 6
110,511 
Parent Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
0 
0 
0 
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Operating and administrative expenses
 
 
 
 
 
 
 
 
27.8 
31.0 
31.8 
Other income, net
 
 
 
 
 
 
 
 
(28.1)7
(24.8)7
(31.7)7
Total costs and expenses
 
 
 
 
 
 
 
 
(0.3)
6.2 
0.1 
Operating loss
 
 
 
 
 
 
 
 
0.3 
(6.2)
(0.1)
Intercompany interest income
 
 
 
 
 
 
 
 
0.2 
0.1 
0 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
0.5 
(6.1)
(0.1)
Income tax expense (benefit)
 
 
 
 
 
 
 
 
0.3 
(1.1)
0.7 
Income (loss) before equity in income of unconsolidated subsidiaries
 
 
 
 
 
 
 
 
0.2 
(5.0)
(0.8)
Equity in income of unconsolidated subsidiaries
 
 
 
 
 
 
 
 
199.2 
237.9 
261.8 
Net income attributable to UGI Corporation
 
 
 
 
 
 
 
 
$ 199.4 
$ 232.9 
$ 261.0 
Earnings per common share:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
 
 
 
 
 
 
 
 
$ 1.77 
$ 2.09 
$ 2.38 
Diluted (in dollars per share)
 
 
 
 
 
 
 
 
$ 1.76 
$ 2.06 
$ 2.36 
Average common shares outstanding (thousands):
 
 
 
 
 
 
 
 
 
 
 
Basic (in shares)
 
 
 
 
 
 
 
 
112,581 
111,674 
109,588 
Diluted (in shares)
 
 
 
 
 
 
 
 
113,432 
112,944 
110,511 
[7] UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other income, net” in the Statements of Income above.
Condensed Financial Information of Registrant (Parent Company) (Details 2) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Condensed Financial Statements, Captions [Line Items]
 
 
 
NET CASH PROVIDED BY OPERATING ACTIVITIES
$ 707.7 
$ 554.7 
$ 598.8 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Net cash used by investing activities
(1,904.5)
(415.4)
(399.3)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends on Common Stock
(119.1)
(113.8)
(98.6)
Issuance of Common Stock
23.2 
27.3 
27.5 
Net cash provided (used) by financing activities
1,278.5 
(152.1)
(213.6)
Cash and cash equivalents increase (decrease)
81.4 
(22.2)
(19.4)
Cash and cash equivalents:
 
 
 
End of year
319.9 
238.5 
260.7 
Beginning of year
238.5 
260.7 
280.1 
Increase (decrease)
81.4 
(22.2)
(19.4)
Parent Company [Member]
 
 
 
Condensed Financial Statements, Captions [Line Items]
 
 
 
NET CASH PROVIDED BY OPERATING ACTIVITIES
158.3 1
201.6 1
173.0 1
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Net investments in unconsolidated subsidiaries
(54.4)
(119.4)
(106.6)
Net cash used by investing activities
(54.4)
(119.4)
(106.6)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends on Common Stock
(119.1)
(113.8)
(98.6)
Issuance of Common Stock
16.7 
31.0 
31.8 
Net cash provided (used) by financing activities
(102.4)
(82.8)
(66.8)
Cash and cash equivalents increase (decrease)
1.5 
(0.6)
(0.4)
Cash and cash equivalents:
 
 
 
End of year
1.9 
0.4 
1.0 
Beginning of year
0.4 
1.0 
1.4 
Increase (decrease)
$ 1.5 
$ (0.6)
$ (0.4)
Condensed Financial Information of Registrant (Parent Company) (Details Textual) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Additional condensed financial information of registrant (Textual) [Abstract]
 
 
 
Dividend received from unconsolidated subsidiaries
$ 156.0 
$ 188.9 
$ 172.8 
Parent Company [Member]
 
 
 
Additional condensed financial information of registrant (Textual) [Abstract]
 
 
 
Surety bonds indemnified
42.7 
 
 
Maximum amount authorized to guarantee obligations to suppliers and customers
425.0 
 
 
Current carrying value
347.6 
 
 
Flaga [Member]
 
 
 
Additional condensed financial information of registrant (Textual) [Abstract]
 
 
 
Amount of floating to fixed rate interest rate swaps at Flaga
$ 5.6 
 
 
Valuation and Qualifying Accounts (Details) (USD $)
12 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2010
Valuation and Qualifying Account (Textual) [Abstract]
 
 
 
Insurance indemnification receivables associated with its property and casualty liabilities
$ 20,900,000 
$ 11,300,000 
$ 7,200,000 
Allowance for Doubtful Accounts [Member]
 
 
 
Valuation and Qualifying Account
 
 
 
Beginning Balance
36,800,000 
34,600,000 
38,300,000 
Charged (credited) to costs and expenses
26,500,000 
20,000,000 
27,100,000 
Other
(27,200,000)1
(17,800,000)1
(30,800,000)1
Ending Balance
36,100,000 
36,800,000 
34,600,000 
Property and Casualty Liability [Member]
 
 
 
Valuation and Qualifying Account
 
 
 
Beginning Balance
65,300,000 2
65,700,000 2
72,300,000 
Charged (credited) to costs and expenses
31,500,000 
22,500,000 
15,200,000 
Valuation allowances and reserves, deductions on other adjustment
(34,000,000)3
(26,500,000)3
(27,400,000)3
Other Adjustments
 
3,600,000 4
5,600,000 4
Other Acquisition
32,500,000 
 
 
Ending Balance
95,300,000 2
65,300,000 2
65,700,000 2
Environmental, litigation and other [Member]
 
 
 
Valuation and Qualifying Account
 
 
 
Beginning Balance
36,900,000 
65,800,000 
66,300,000 
Charged (credited) to costs and expenses
1,200,000 
(5,300,000)
5,400,000 
Valuation allowances and reserves, deductions on other adjustment
(5,000,000)3
(25,400,000)3
(4,900,000)3
Other Adjustments
(400,000)4
1,800,000 4
(1,000,000)4
Other Acquisition
4,900,000 
 
 
Ending Balance
37,600,000 
36,900,000 
65,800,000 
Deferred tax assets valuation allowance [Member]
 
 
 
Valuation and Qualifying Account
 
 
 
Beginning Balance
81,900,000 
78,400,000 
87,800,000 
Charged (credited) to costs and expenses
(3,100,000)
3,500,000 
(9,400,000)
Other Recoveries
2,800,000 
0 
0 
Ending Balance
$ 81,600,000 
$ 81,900,000 
$ 78,400,000