UGI CORP /PA/, 10-K filed on 11/28/2014
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Sep. 30, 2014
Nov. 18, 2014
Mar. 31, 2014
Document and Entity Information [Abstract]
 
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
 
Entity Central Index Key
0000884614 
 
 
Document Type
10-K 
 
 
Document Period End Date
Sep. 30, 2014 
 
 
Amendment Flag
false 
 
 
Document Fiscal Year Focus
2014 
 
 
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
 
 
$ 5,249,082,631 
Entity Common Stock, Shares Outstanding
 
172,425,384 
 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Current assets
 
 
Cash and cash equivalents
$ 419.5 
$ 389.3 
Restricted cash
16.6 
8.3 
Accounts receivable (less allowances for doubtful accounts of $39.1 and $39.5, respectively)
684.7 
745.6 
Accrued utility revenues
14.3 
18.9 
Inventories
423.0 
365.5 
Deferred income taxes
10.1 
10.6 
Utility regulatory assets
13.2 
8.2 
Derivative instruments
14.5 
23.8 
Prepaid expenses and other current assets
67.1 
57.1 
Total current assets
1,663.0 
1,627.3 
Property, plant and equipment
 
 
Non-utility
4,608.2 
4,612.7 
Utilities
2,568.5 
2,427.8 
Total property, plant and equipment
7,176.7 
7,040.5 
Accumulated depreciation and amortization
(2,633.0)
(2,560.3)
Net property, plant, and equipment
4,543.7 
4,480.2 
Goodwill
2,833.4 
2,873.7 
Intangible assets, net
576.4 
607.9 
Utility regulatory assets
255.0 
236.7 
Derivative instruments
12.5 
0.4 
Other assets
209.0 
182.6 
Total assets
10,093.0 
10,008.8 
Current liabilities
 
 
Current maturities of long-term debt
77.2 
67.2 
Short-term borrowings
210.8 
227.9 
Accounts payable
459.8 
472.3 
Employee compensation and benefits accrued
106.5 
97.0 
Deposits and advances
211.5 
205.2 
Derivative instruments
40.2 
30.0 
Accrued interest
57.9 
60.6 
Other current liabilities
267.0 
264.7 
Total current liabilities
1,430.9 
1,424.9 
Debt and other liabilities
 
 
Long-term debt
3,433.6 
3,542.2 
Deferred income taxes
1,005.1 
962.3 
Deferred investment tax credits
3.9 
4.3 
Derivative instruments
16.6 
25.4 
Other noncurrent liabilities
539.7 
501.8 
Total liabilities
6,429.8 
6,460.9 
Commitments and contingencies (Note 16)
   
   
UGI Corporation stockholders’ equity:
 
 
UGI Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,770,641 and 173,675,691 shares, respectively)
1,215.6 
1,208.1 
Retained earnings
1,509.4 
1,308.3 
Accumulated other comprehensive (loss) income
(21.2)
8.4 
Treasury stock, at cost
(44.7)
(32.3)
Total UGI Corporation stockholders’ equity
2,659.1 
2,492.5 
Noncontrolling interests, principally in AmeriGas Partners
1,004.1 
1,055.4 
Total equity
3,663.2 
3,547.9 
Total liabilities and equity
$ 10,093.0 
$ 10,008.8 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Current assets
 
 
Allowance for Doubtful Accounts
$ 39.1 
$ 39.5 
UGI Corporation stockholders’ equity:
 
 
UGI Common Stock, without par value (in dollars per share)
$ 0.00 
$ 0.00 
UGI Common Stock, without par value authorized (in shares)
450,000,000 
450,000,000 
UGI Common Stock, without par value, issued (in shares)
173,770,641 
173,675,691 
Consolidated Statements of Income (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Revenues
 
 
 
Non-utility
$ 7,191.9 
$ 6,255.7 
$ 5,638.8 
Utility
1,085.4 
939.0 
882.5 
Revenues
8,277.3 
7,194.7 
6,521.3 
Cost of sales (excluding depreciation shown below):
 
 
 
Non-utility
4,612.8 
3,858.4 
3,640.0 
Utility
562.9 
466.0 
459.1 
Operating and administrative expenses
1,752.6 
1,692.0 
1,591.1 
Utility taxes other than income taxes
16.6 
16.9 
17.3 
Depreciation
305.7 
301.4 
263.2 
Amortization
57.2 
61.7 
51.8 
Other income, net
(36.1)
(32.8)
(39.8)
Total costs and expenses
7,271.7 
6,363.6 
5,982.7 
Operating income
1,005.6 
831.1 
538.6 
Loss from equity investees
(0.1)
(0.4)
(0.3)
Loss on extinguishments of debt
(13.3)
Interest expense
(237.7)
(240.3)
(220.4)
Income before income taxes
767.8 
590.4 
304.6 
Income taxes
(235.2)
(162.8)
(106.9)
Net income
532.6 
427.6 
197.7 
(Deduct net income) add net loss attributable to noncontrolling interests, principally in AmeriGas Partners
(195.4)
(149.5)
12.5 
Net income attributable to UGI Corporation
$ 337.2 
$ 278.1 
$ 210.2 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
Basic (in dollars per share)
$ 1.95 
$ 1.63 
$ 1.24 
Diluted (in dollars per share)
$ 1.92 
$ 1.60 
$ 1.24 
Average common shares outstanding (thousands):
 
 
 
Basic (in shares)
172,733 
170,885 
168,872 
Diluted (in shares)
175,231 
173,282 
170,148 
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Statement of Comprehensive Income [Abstract]
 
 
 
Net income
$ 532.6 
$ 427.6 
$ 197.7 
Net gains (losses) on derivative instruments (net of tax of $(12.2), $(7.2) and $29.3, respectively)
54.0 
14.4 
(105.4)
Reclassifications of net (gains) losses on derivative instruments (net of tax of $2.0, $(10.3) and $(14.6), respectively)
(45.2)
53.5 
56.3 
Foreign currency translation adjustments (net of tax of $13.8, $(6.6) and $2.8, respectively)
(23.2)
28.8 
(20.6)
Foreign currency (losses) gains on long-term intra-company transactions (net of tax of $10.6, $(0.8) and $0.7, respectively)
(19.8)
3.2 
(1.7)
Benefit plans (net of tax of $2.6, $(3.8) and $6.0, respectively)
(5.2)
5.3 
(11.5)
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $(0.6), $(0.8) and $(0.5), respectively)
1.0 
1.2 
0.7 
Other comprehensive (loss) income
(38.4)
106.4 
(82.2)
Comprehensive income
494.2 
534.0 
115.5 
(Deduct comprehensive income) add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
(186.6)
(192.3)
38.6 
Comprehensive income attributable to UGI Corporation
$ 307.6 
$ 341.7 
$ 154.1 
Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Statement of Comprehensive Income [Abstract]
 
 
 
Tax on (loss) gain on derivative instruments
$ (12.2)
$ (7.2)
$ 29.3 
Tax on reclassifications on derivative instruments
2.0 
(10.3)
(14.6)
Tax on foreign currency translation
13.8 
(6.6)
2.8 
Tax on foreign currency gain and losses on long-term intra-company transactions
10.6 
(0.8)
0.7 
Tax on benefit plans
2.6 
(3.8)
6.0 
Tax on reclassification of benefit plans and prior service costs
$ (0.6)
$ (0.8)
$ (0.5)
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$ 532.6 
$ 427.6 
$ 197.7 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
362.9 
363.1 
315.0 
Deferred income taxes, net
66.7 
48.7 
90.2 
Provision for uncollectible accounts
43.5 
30.2 
26.5 
Unrealized losses (gains) on derivative instruments
18.6 
(0.2)
(17.2)
Equity-based compensation expense
25.8 
17.6 
14.5 
Loss on extinguishments of debt
13.3 
Other, net
(38.2)
(41.4)
(11.0)
Net change in:
 
 
 
Accounts receivable and accrued utility revenues
18.1 
(110.8)
65.5 
Inventories
(65.1)
4.6 
89.2 
Utility deferred fuel costs, net of changes in unsettled derivatives
(17.6)
9.3 
(8.2)
Accounts payable
3.7 
38.7 
(78.7)
Other current assets
(1.2)
36.3 
(12.5)
Other current liabilities
55.6 
(22.2)
23.4 
Net cash provided by operating activities
1,005.4 
801.5 
707.7 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(456.8)
(486.0)
(339.4)
Acquisitions of businesses, net of cash acquired
(37.1)
(78.9)
(1,580.5)
(Increase) decrease in restricted cash
(8.3)
(5.3)
14.2 
Other, net
14.6 
16.9 
1.2 
Net cash used by investing activities
(487.6)
(553.3)
(1,904.5)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Dividends on UGI Common Stock
(136.1)
(125.8)
(119.1)
Distributions on AmeriGas Partners publicly held Common Units
(237.7)
(226.5)
(181.7)
Issuances of debt
174.5 
227.1 
1,550.2 
Repayments of debt
(242.6)
(168.7)
(299.9)
Receivables Facility net (repayments) borrowings
(22.5)
30.0 
(14.3)
Increase in credit agreement borrowings
5.8 
32.3 
41.7 
Issuances of UGI Common Stock
10.9 
36.4 
23.2 
Repurchases of UGI Common Stock
(39.8)
Issuances of AmeriGas Partners Common Units
276.6 
Other
11.8 
9.1 
1.8 
Net cash (used) provided by financing activities
(475.7)
(186.1)
1,278.5 
Effect of exchange rate changes on cash
(11.9)
7.3 
(0.3)
Cash and cash equivalents increase
30.2 
69.4 
81.4 
CASH AND CASH EQUIVALENTS
 
 
 
End of year
419.5 
389.3 
319.9 
Beginning of year
389.3 
319.9 
238.5 
Increase
30.2 
69.4 
81.4 
Cash paid for:
 
 
 
Interest
228.3 
243.6 
168.8 
Income taxes
$ 141.6 
$ 60.0 
$ 33.3 
Consolidated Statements of Changes In Equity (USD $)
Total
Total UGI Corporation Stockholder's Equity
Common Stock, Without Par Value
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Treasury Stock
Noncontrolling Interests
Balance, beginning of year at Sep. 30, 2011
 
 
 
 
 
 
$ 213,000,000 
Balance, beginning of year at Sep. 30, 2011
 
 
937,400,000 
1,064,900,000 
(1,000,000)
(27,800,000)
 
Employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld
 
 
13,600,000 
 
 
6,400,000 
 
Dividend reinvestment plan
 
 
2,200,000 
 
 
900,000 
 
Excess tax benefits realized on equity-based compensation
 
 
1,800,000 
 
 
 
 
Equity-based compensation expense
 
 
8,300,000 
 
 
 
 
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax
 
 
194,400,000 
 
1,900,000 
 
(321,400,000)
Net income attributable to UGI Corporation
210,200,000 
 
 
210,200,000 
 
 
 
Cash dividends on common stock ($0.791, $0.737 and $0.707 per share, respectively)
 
 
 
(119,100,000)
 
 
 
Net gains (losses) on derivative instruments, net of tax
(105,400,000)
 
 
 
(45,600,000)
 
 
Reclassification of net (gains) losses on derivative instruments, net of tax
56,300,000 
 
 
 
22,600,000 
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
(11,500,000)
 
 
 
(11,500,000)
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
(700,000)
 
 
 
700,000 
 
 
Foreign currency (losses) gains on long-term intra-company transactions, net of tax
(1,700,000)
 
 
 
(1,700,000)
 
 
Foreign currency translation adjustments, net of tax
(20,600,000)
 
 
 
(20,600,000)
 
 
Repurchases of common stock
 
 
 
 
 
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(8,200,000)
 
Net income (loss) attributable to noncontrolling interests, principally in AmeriGas Partners
(12,500,000)
 
 
 
 
 
(12,500,000)
Net gains (losses) on derivative instruments
 
 
 
 
 
 
(59,800,000)
Reclassification of net (gains) losses on derivative instruments
 
 
 
 
 
 
33,700,000 
Dividends and distributions
 
 
 
 
 
 
(182,100,000)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
276,600,000 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
1,132,600,000 
Other
 
 
 
 
 
 
5,500,000 
Balance, end of year at Sep. 30, 2012
3,315,400,000 
 
 
 
 
 
1,085,600,000 
Balance, end of year at Sep. 30, 2012
 
2,229,800,000 
1,157,700,000 
1,156,000,000 
(55,200,000)
(28,700,000)
 
Employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld
 
 
29,700,000 
 
 
35,200,000 
 
Dividend reinvestment plan
 
 
1,400,000 
 
 
800,000 
 
Excess tax benefits realized on equity-based compensation
 
 
9,400,000 
 
 
 
 
Equity-based compensation expense
 
 
9,900,000 
 
 
 
 
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax
 
 
 
 
Net income attributable to UGI Corporation
278,100,000 
 
 
278,100,000 
 
 
 
Cash dividends on common stock ($0.791, $0.737 and $0.707 per share, respectively)
 
 
 
(125,800,000)
 
 
 
Net gains (losses) on derivative instruments, net of tax
14,400,000 
 
 
 
9,800,000 
 
 
Reclassification of net (gains) losses on derivative instruments, net of tax
53,500,000 
 
 
 
15,300,000 
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
5,300,000 
 
 
 
5,300,000 
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
(1,200,000)
 
 
 
1,200,000 
 
 
Foreign currency (losses) gains on long-term intra-company transactions, net of tax
3,200,000 
 
 
 
3,200,000 
 
 
Foreign currency translation adjustments, net of tax
28,800,000 
 
 
 
28,800,000 
 
 
Repurchases of common stock
 
 
 
 
 
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(39,600,000)
 
Net income (loss) attributable to noncontrolling interests, principally in AmeriGas Partners
149,500,000 
 
 
 
 
 
149,500,000 
Net gains (losses) on derivative instruments
 
 
 
 
 
 
4,600,000 
Reclassification of net (gains) losses on derivative instruments
 
 
 
 
 
 
38,200,000 
Dividends and distributions
 
 
 
 
 
 
(226,700,000)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
Other
 
 
 
 
 
 
4,200,000 
Balance, end of year at Sep. 30, 2013
3,547,900,000 
 
 
 
 
 
1,055,400,000 
Balance, end of year at Sep. 30, 2013
2,492,500,000 
2,492,500,000 
1,208,100,000 
1,308,300,000 
8,400,000 
(32,300,000)
 
Employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld
 
 
(16,400,000)
 
 
65,800,000 
 
Dividend reinvestment plan
 
 
 
 
 
 
Excess tax benefits realized on equity-based compensation
 
 
12,500,000 
 
 
 
 
Equity-based compensation expense
 
 
11,400,000 
 
 
 
 
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax
 
 
 
 
Net income attributable to UGI Corporation
337,200,000 
 
 
337,200,000 
 
 
 
Cash dividends on common stock ($0.791, $0.737 and $0.707 per share, respectively)
 
 
 
(136,100,000)
 
 
 
Net gains (losses) on derivative instruments, net of tax
54,000,000 
 
 
 
21,600,000 
 
 
Reclassification of net (gains) losses on derivative instruments, net of tax
(45,200,000)
 
 
 
(4,000,000)
 
 
Benefit plans, principally actuarial (losses) gains, net of tax
(5,200,000)
 
 
 
(5,200,000)
 
 
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income
(1,000,000)
 
 
 
1,000,000 
 
 
Foreign currency (losses) gains on long-term intra-company transactions, net of tax
(19,800,000)
 
 
 
(19,800,000)
 
 
Foreign currency translation adjustments, net of tax
(23,200,000)
 
 
 
(23,200,000)
 
 
Repurchases of common stock
 
 
 
 
 
(39,800,000)
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(38,400,000)
 
Net income (loss) attributable to noncontrolling interests, principally in AmeriGas Partners
195,400,000 
 
 
 
 
 
195,400,000 
Net gains (losses) on derivative instruments
 
 
 
 
 
 
32,400,000 
Reclassification of net (gains) losses on derivative instruments
 
 
 
 
 
 
(41,200,000)
Dividends and distributions
 
 
 
 
 
 
(238,000,000)
AmeriGas Partners Common Unit public offering
 
 
 
 
 
 
AmeriGas Partners Common Units issued for Heritage Acquisition
 
 
 
 
 
 
Other
 
 
 
 
 
 
100,000 
Balance, end of year at Sep. 30, 2014
3,663,200,000 
 
 
 
 
 
1,004,100,000 
Balance, end of year at Sep. 30, 2014
$ 2,659,100,000 
$ 2,659,100,000 
$ 1,215,600,000 
$ 1,509,400,000 
$ (21,200,000)
$ (44,700,000)
 
Consolidated Statements of Changes in Equity (Parenthetical) (Retained Earnings, USD $)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Retained Earnings
 
 
 
Cash dividends on Common Stock per share
$ 0.791 
$ 0.737 
$ 0.707 
Nature of Operations
Nature of Operations
Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production 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”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prior to its merger with AmeriGas OLP on July 1, 2013, 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”). HOLP and Titan LLC (collectively, “Heritage Propane”) were acquired on January 12, 2012, from Energy Transfer Partners, L.P. (“ETP”) (see Note 4 for additional information about the acquisition of Heritage Propane). AmeriGas OLP along with HOLP and Titan LLC (prior to their mergers with and into AmeriGas OLP) are referred to herein as the “Operating Partnership.” AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2014, 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 General Partner also holds incentive distribution rights that entitle it to receive distribution from AmeriGas Partners under certain circumstances (see Note 15). The remaining 73.7% interest in AmeriGas Partners comprises 69,110,322 Common Units held by the public.
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 “UGI International.”
Enterprises, through UGI Energy Services, LLC (formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013) and its subsidiaries conduct an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC and its predecessor company, UGI Energy Services, Inc. are referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
Our natural gas distribution utility business (“Gas Utility”) is 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.” 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. Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Summary of Significant Accounting Policies
Significant Accounting Policies
Summary of 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.
On July 29, 2014, UGI's Board of Directors approved a three-for-two common stock split. The additional shares were distributed September 5, 2014, to shareholders of record on August 22, 2014. All references to shares and per share amounts have been retroactively adjusted to reflect the three-for-two stock split.
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 public’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, 2014. 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 $77.8 and $82.0 at September 30, 2014 and 2013, respectively (including $17.4 and $16.4, respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
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”) Topic “Regulated Operations.” 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. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. 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 9.
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, also on a nonrecurring basis. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
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.
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 markets that are not active, 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.
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.
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. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments
Derivative instruments are reported in the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exemption under GAAP. 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.
Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative 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. Unrealized gains and losses on certain commodity derivative 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.
Substantially all of Midstream & Marketing’s commodity derivative instruments do not qualify for, or are not designated as, cash flow hedges. In addition, effective April 1, 2014, AmeriGas Propane determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative instruments. Changes in the fair values of these commodity derivative instruments are reflected in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income.
From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.
Cash flows from derivative 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 other information, see Note 18.
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 UGI International 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 UGI International 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 Partnership has 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 taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2014, 2013 and 2012, interest (income) expense recognized in income taxes on the Consolidated Statements of Income was not material.
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 2014, Fiscal 2013 and Fiscal 2012:
(Thousands of shares)
 
2014
 
2013
 
2012
Average common shares outstanding for basic computation
 
172,733

 
170,885

 
168,872

Incremental shares issuable for stock options and common stock awards (a)
 
2,498

 
2,397

 
1,276

Average common shares outstanding for diluted computation
 
175,231

 
173,282

 
170,148


(a)
For Fiscal 2014, Fiscal 2013 and Fiscal 2012, there were approximately 0 shares, 132 shares and 122 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
Changes in AOCI during Fiscal 2014 are as follows:
 
Postretirement
Benefit
Plans
 
Derivative
Instruments
 
Foreign
Currency
 
Total
AOCI - September 30, 2013
$
(16.4
)
 
$
(26.9
)
 
$
51.7

 
$
8.4

Other comprehensive (loss) income before reclassification adjustments (after-tax)
(5.2
)
 
54.0

 
(43.0
)
 
5.8

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
    Reclassification adjustments (pre-tax)
1.6

 
(47.2
)
 

 
(45.6
)
    Reclassification adjustments tax (expense) benefit
(0.6
)
 
2.0

 

 
1.4

    Reclassification adjustments (after-tax)
1.0

 
(45.2
)
 

 
(44.2
)
Other comprehensive (loss) income
(4.2
)
 
8.8

 
(43.0
)
 
(38.4
)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners

 
8.8

 

 
8.8

Other comprehensive (loss) income attributable to UGI
(4.2
)
 
17.6

 
(43.0
)
 
(29.6
)
AOCI - September 30, 2014
$
(20.6
)
 
$
(9.3
)
 
$
8.7

 
$
(21.2
)

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 18.

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 principally represents those cash balances in our commodity futures brokerage accounts that 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 10 to 40 years for buildings and improvements; 6 to 40 years for storage and customer tanks and cylinders; 25 to 40 years for electricity generation facilities; 25 to 40 years for pipeline and related assets, and 3 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 10 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 2.3% in Fiscal 2014, 2.3% in Fiscal 2013 and 2.2% in Fiscal 2012. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.5% in Fiscal 2014, 2.4% in Fiscal 2013 and 2.4% in Fiscal 2012. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets.
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 generally not exceeding 10 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. Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets 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 an operating segment or one level below an 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. In accordance with GAAP, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. 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.

There were no accumulated impairment losses at September 30, 2014, and no provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2014, Fiscal 2013 or Fiscal 2012. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 12).
Impairment of Long-Lived Assets and Cost Basis Investments
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 2014, Fiscal 2013 or Fiscal 2012.
We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. During Fiscal 2013, we recorded a pre-tax loss of $6.3 associated with an other-than-temporary impairment of an investment in a private equity partnership.

Deferred Debt Issuance Costs
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $36.7 and $39.4 at September 30, 2014 and 2013, respectively. We are amortizing these costs over the terms of the related debt.
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 $200.0 and $214.6 at September 30, 2014 and 2013, 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 effects 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 16.
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 8).
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 on 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 14.
Accounting Changes
Accounting Changes
Accounting Changes
Adoption of New Accounting Standards
Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In Fiscal 2014, the Company adopted new accounting guidance regarding disclosures for items reclassified out of AOCI. The disclosures required by the new accounting guidance are included in Note 2 and Note 18 to Consolidated Financial Statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.
Disclosures about Offsetting Assets and Liabilities. Effective October 1, 2013, the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively to all periods presented. The required disclosures are included in Note 18 to Consolidated Financial Statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.
Accounting Standards Not Yet Adopted
Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in ASC 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This standard is effective for the Company beginning in Fiscal 2018 and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

Discontinued Operations. In April 2014, the FASB issued authoritative guidance amending existing requirements for reporting discontinued operations.  Under the new guidance, discontinued operations reporting will be limited to disposal transactions that represent strategic shifts having a major effect on operations and financial results. The amended guidance also enhances disclosures and requires assets and liabilities of a discontinued operation to be classified as such for all periods presented in the financial statements. Public entities will apply the amended guidance prospectively to all disposals occurring within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company will adopt this standard on October 1, 2015. Due to the change in requirements for reporting discontinued operations described above, presentation and disclosure of future disposal transactions after adoption may be different than under current standards.
Acquisitions
Acquisitions and Dispositions
Acquisitions
AmeriGas Partners Acquisition of Heritage Propane
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane from ETP (“Heritage Acquisition”). Total consideration paid for the Heritage Acquisition totaled $2,604.8, comprising $1,472.2 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of $1,132.6. In order to finance the cash portion of the Heritage Acquisition, AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners, issued Senior Notes (see Note 6).
The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. (the “Contributor”). The acquired business conducted its propane operations in 41 states. 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 was consistent with our growth strategies, one of which is to grow the Partnership’s 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 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 final allocation of the purchase price to the assets acquired and liabilities assumed for the Heritage Acquisition 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 (a)
 
91.1

Goodwill (a) (b)
 
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

(a)
During Fiscal 2013, the Partnership made correcting adjustments to trademarks and tradenames and goodwill which are not reflected in the table above (see Note 12).
(b)
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 15-year period.
Transaction expenses associated with the Heritage Acquisition, which are included in operating and administrative expenses in the Consolidated Statements 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. As a result of combining the Heritage Propane operations with the Partnership’s legacy operations, it is impracticable to determine the impact of the Heritage Propane operations on the revenues and earnings of the Company.
The following presents unaudited Fiscal 2012 pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred at the beginning of the period:
 
 
2012
Revenues
 
$
7,013.0

Net income attributable to UGI Corporation
 
$
208.4

Earnings per common share attributable to UGI Corporation stockholders:
 
 
Basic
 
$
1.23

Diluted
 
$
1.22


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.
Other Acquisitions
During Fiscal 2014, Energy Services acquired a retail natural gas marketing business located principally in western Pennsylvania from EQT Energy, LLC, an affiliate of EQT Corporation, for cash consideration of $20 and AmeriGas OLP acquired several retail propane distribution businesses for $15.7 in cash.
During Fiscal 2013, Flaga acquired BP’s LPG distribution business in Poland for total cash consideration of approximately $36 which Flaga financed with cash proceeds from the issuance of long-term debt (see Note 6); AmeriGas OLP acquired two domestic retail propane distribution businesses for total cash consideration of $20; and Energy Services acquired a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania for approximately $23 in cash.
During Fiscal 2012, AmeriGas OLP acquired several retail propane distribution businesses for $13.5 in cash.
Short-term Borrowings
Short-term Debt
Short-term Borrowings
Short-term borrowings are comprised of the following at September 30:
 
2014
 
2013
Credit Agreements:
 
 
 
AmeriGas Propane
$
109.0

 
$
116.9

UGI International
8.0

 
6.5

UGI Utilities
86.3

 
17.5

Energy Services

 
57.0

Energy Services Accounts Receivable Securitization Facility
7.5

 
30.0

Total short-term borrowings
$
210.8

 
$
227.9



AmeriGas Propane
In June 2014, AmeriGas OLP entered into an Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks which provides for borrowings up to $525 (including a sublimit of $125 for letters of credit) and expires in June 2019. The AmeriGas Credit Agreement amends and restates AmeriGas OLP’s prior credit agreement entered into in June 2011, as amended from time to time. The AmeriGas 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 one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. Under the AmeriGas Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.50%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.50%; and the facility fee ranges from 0.30% to 0.45%. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Credit Agreement).
The weighted-average interest rates on AmeriGas OLP borrowings under the AmeriGas Credit Agreement and the prior credit agreement at September 30, 2014 and 2013, were 2.16% and 2.69%, respectively. At September 30, 2014 and 2013, issued and outstanding letters of credit, which reduce available borrowings under these credit agreements, totaled $64.7 and $53.7, respectively.
Restrictive Covenants. The AmeriGas Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas Credit Agreement requires that AmeriGas OLP and AmeriGas Partners 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 and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is 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.
UGI International
Antargaz has a Senior Facilities Agreement comprising a variable rate term loan (see Note 6) and a €40 credit facility (“Senior Facilities Agreement Credit Facility”). Borrowings under the Senior Facilities Agreement Credit Facility bear interest at one-, two-, three- or six-month euribor, plus a margin. The margin on the Senior Facilities Agreement Credit Facility borrowings (which range from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the Senior Facilities Agreement. Borrowings under the Senior Facilities Agreement Credit Facility are collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. There were no amounts outstanding under the Senior Facilities Agreement Credit Facility at September 30, 2014 or 2013.
At September 30, 2014, 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”). Both the Multi-Currency Working Capital Facility and the Euro Working Capital Facility are currently scheduled to expire in December 2014. At September 30, 2014, there were no borrowings outstanding under the Flaga Credit Agreements. At September 30, 2013, borrowings outstanding under the Flaga Credit Agreements were €0.2 ($0.3).
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 rate on borrowings under the Flaga Credit Agreements at September 30, 2013 was 4.21%. Issued and outstanding letters of credit, which reduce available borrowings under the Flaga Credit Agreements, totaled €32.3 ($40.8) and €28.6 ($38.7) at September 30, 2014 and 2013, respectively.
Flaga also has certain in-country uncommitted overdraft facilities which it uses, from time to time, to fund short-term working capital needs. At September 30, 2014 and 2013, borrowings outstanding under these overdraft facilities totaled €6.3 ($8.0) and €4.6 ($6.2), respectively.
Restrictive Covenants and Guarantees. The 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 between the variable rate term loan (see Note 6) and the Senior Facilities Agreement Credit Facility.
The Flaga working capital facilities 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 (“UGI Utilities 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. UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The weighted-average interest rates on UGI Utilities Credit Agreement borrowings at September 30, 2014 and 2013 were 1.03% and 1.18%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities Credit Agreement, totaled $2.0 and $2.0 at September 30, 2014 and 2013, respectively.
Restrictive Covenants. The UGI Utilities 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
Credit Agreement. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 (including a $50 sublimit for letters of credit) which expires in June 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00. At September 30, 2014, there were no borrowings outstanding under the Energy Services Credit Agreement. At September 30, 2013, borrowings outstanding under the Energy Services Credit Agreement were $57.0.
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 2.5% or (ii) the Alternate Base Rate plus 1.5%. 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 Energy Services Credit Agreement borrowings at September 30, 2013 was 2.91%. 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 $200.
Accounts Receivable Securitization Facility. Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to May, and up to $75 of eligible receivables during the period June to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank and, prior to October 1, 2013, a commercial paper conduit of the bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank or, prior to October 1, 2013, the commercial paper conduit, remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or the commercial paper conduit. Energy Services continues to service, administer and collect trade receivables on behalf of the bank or commercial paper issuer, as applicable.
During Fiscal 2014, Fiscal 2013 and Fiscal 2012, Energy Services transferred trade receivables totaling $1,260.6, $975.3 and $836.0, respectively, to ESFC. During Fiscal 2014, Fiscal 2013 and Fiscal 2012, ESFC sold an aggregate $354.0, $291.0 and $286.0, respectively, of undivided interests in its trade receivables to the bank or the commercial paper conduit. At September 30, 2014, the outstanding balance of ESFC trade receivables was $46.4 of which $7.5 was sold to the bank. At September 30, 2013, the outstanding balance of ESFC trade receivables was $55.0 of which $30.0 amount was sold to the commercial paper conduit. Losses on sales of receivables to the bank or the commercial paper conduit during Fiscal 2014, Fiscal 2013 and Fiscal 2012, which amounts are included in interest expense on the Consolidated Statements of Income, totaled $0.6, $0.7 and $1.0, respectively.
Long-term Borrowings
Long-term Debt
Long-term Debt
Long-term debt comprises the following at September 30:
 
2014
 
2013
AmeriGas Propane:
 
 
 
AmeriGas Partners Senior Notes:
 
 
 
   7.00%, due May 2022
$
980.8

 
$
980.8

   6.75%, due May 2020
550.0

 
550.0

   6.50%, due May 2021
270.0

 
270.0

   6.25%, due August 2019
450.0

 
450.0

HOLP Senior Secured Notes
26.5

 
32.0

Other
14.4

 
17.3

Total AmeriGas Propane
2,291.7

 
2,300.1

UGI International:
 
 
 
Antargaz Senior Facilities term loan, due through March 2016
432.0

 
514.0

Flaga term loan, due September 2016
52.0

 
52.0

Flaga term loan, due through September 2016
50.5

 
54.1

Flaga term loan, due October 2016
24.1

 
25.8

Flaga term loan, due through June 2014

 
1.9

Other
6.4

 
6.6

Total UGI International
565.0

 
654.4

UGI Utilities:
 
 
 
Term Loan Credit Agreement

 
175.0

Senior Notes:
 
 
 
5.75%, due September 2016
175.0

 
175.0

4.98%, due March 2044
175.0

 

6.21%, due September 2036
100.0

 
100.0

Medium-Term Notes:
 
 
 
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
642.0

 
642.0

Other
12.1

 
12.9

Total long-term debt
3,510.8

 
3,609.4

Less: current maturities
(77.2
)
 
(67.2
)
Total long-term debt due after one year
$
3,433.6

 
$
3,542.2



Scheduled principal repayments of long-term debt due in fiscal years 2015 to 2019 follow:

 
2015
 
2016
 
2017
 
2018
 
2019
AmeriGas Propane
$
11.0

 
$
7.6

 
$
5.6

 
$
4.9

 
$
454.5

UGI Utilities
20.0

 
247.0

 
20.0

 
40.0

 

UGI International
45.0

 
492.9

 
25.4

 
0.9

 
0.7

Other
0.7

 
0.7

 
0.7

 
0.8

 
0.8

Total
$
76.7

 
$
748.2

 
$
51.7

 
$
46.6

 
$
456.0



AmeriGas Propane
In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (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.
The Partnership’s total long-term debt at September 30, 2014, includes $26.5 of HOLP Senior Secured Notes (including unamortized premium of $3.1). At September 30, 2014, the face interest rates on the HOLP Notes range from 7.89% to 8.87% with an effective interest rate of 6.75%. The HOLP Senior Secured Notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash.
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, 2014, these restrictions did not limit the amount of Available Cash. See Note 15 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 AmeriGas OLP to maintain a ratio of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined).
UGI International
At September 30, 2014, Antargaz has a €342 ($432.0) variable-rate term loan under its Senior Facilities Agreement with a consortium of banks. Scheduled maturities under the term loan are €34.2 ($43.2) due May 2015, and €307.8 ($388.8) due March 2016. Term loan borrowings bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the Senior Facilities Agreement. The margin on the term loan (which range from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 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, 2014 and 2013, the effective interest rates on Antargaz’ term loan were 4.79% and 4.41%, respectively. The Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables.
In order to finance the purchase of BP’s LPG distribution business in Poland in September 2013, Flaga entered into a $52 U.S. dollar-denominated three-year term loan which matures in September 2016. The $52 loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin of 1.25%. Flaga has effectively fixed the euribor component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $52 loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2014 and 2013, the effective interest rate on the $52 loan was 1.82%.
Flaga has a €19.1 ($24.1) euro-based variable-rate term loan that matures in October 2016. The €19.1 term loan 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 rates on this term loan at September 30, 2014 and 2013, were 3.40% and 3.85%, respectively.

Flaga also has a €40 ($50.5) euro-based term loan agreement under which €26.7 ($33.7) matures in August 2016 and €13.3 ($16.8) matures in September 2016. The term loans bear interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus margins. The margins on such borrowings range from 1.125% to 2.55% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of the interest rates on these term loans through September 2016 at 2.68% by entering into an interest rate swap agreement. The effective interest rates on these term loans at September 30, 2014 and 2013, were 4.25% and 4.68%, respectively.
Restrictive Covenants and Guarantees. The 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 between the variable-rate term loan and the Senior Facilities Agreement Credit Facility (see Note 5).
The Flaga term loans, interest rate and cross currency 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
In March 2014, UGI Utilities issued in a private placement $175 of 4.98% Senior Notes due March 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 of borrowings under UGI Utilities’ 364-day Term Loan Credit Agreement. Because the Company had the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis as of September 30, 2013, amounts outstanding under the Term Loan Credit Agreement were classified as long-term on the 2013 Consolidated Balance Sheet.
Restrictive Covenants. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.
Restricted Net Assets
At September 30, 2014, 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 $1,600.
Income Taxes
Income Taxes
Income Taxes
Income before income taxes comprises the following:

 
2014
 
2013
 
2012
Domestic
$
699.2

 
$
494.1

 
$
245.6

Foreign
68.6

 
96.3

 
59.0

Total income before income taxes
$
767.8

 
$
590.4

 
$
304.6



The provisions for income taxes consist of the following:

 
2014
 
2013
 
2012
Current expense (benefit):
 
 
 
 
 
Federal
$
102.4

 
$
53.3

 
$
(10.4
)
State
30.7

 
25.1

 
11.2

Foreign
37.0

 
37.3

 
18.8

Investment tax credit
(1.6
)
 
(1.6
)
 
(2.9
)
Total current expense
168.5

 
114.1

 
16.7

Deferred expense (benefit):
 
 
 
 
 
Federal
61.9

 
54.6

 
81.7

State
7.8

 
(0.7
)
 
7.0

Foreign
(2.7
)
 
(4.9
)
 
1.8

Investment tax credit amortization
(0.3
)
 
(0.3
)
 
(0.3
)
Total deferred expense
66.7

 
48.7

 
90.2

Total income tax expense
$
235.2

 
$
162.8

 
$
106.9



Federal income taxes for Fiscal 2014, Fiscal 2013 and Fiscal 2012 are net of foreign tax credits of $12.1, $34.9 and $5.2, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

 
2014
 
2013
 
2012
U.S. federal statutory tax rate
35.0
 %
 
35.0
 %
 
35.0
 %
Difference in tax rate due to:
 
 
 
 
 
Noncontrolling interests not subject to tax
(9.0
)
 
(8.7
)
 
1.2

State income taxes, net of federal benefit
3.4

 
3.4

 
4.0

Valuation allowance adjustments

 
(0.5
)
 
(1.5
)
Effects of foreign operations
1.0

 
(1.8
)
 
(3.3
)
Other, net
0.2

 
0.2

 
(0.3
)
Effective tax rate
30.6
 %
 
27.6
 %
 
35.1
 %

In December 2013, the French Parliament approved the Finance Bill for 2014 and amended the Finance Bill for 2013 (collectively, the “Finance Bills”). Among other things, the Finance Bills limit Antargaz’ ability to deduct certain interest expense for income tax purposes and temporarily increases the corporate surtax rate for a period of two years. Based upon our review of the Finance Bills and interpretive guidance, provisions of the Finance Bills associated with the deductibility of certain interest expense at Antargaz apply retroactively to such interest expense incurred during Fiscal 2013. In December 2013, the Company recorded additional income taxes of $5.7 to reflect the effects of the retroactive provisions of the Finance Bills and is included in effects of foreign operations in the effective tax rate table above.
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 Fiscal 2012 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 a valuation allowance adjustment 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. At September 30, 2014, unremitted earnings of foreign subsidiaries of approximately $42.7 were deemed to be indefinitely reinvested. No deferred tax liability has been recognized with regard to the remittance of such earnings. 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 2014, Fiscal 2013 and Fiscal 2012, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $2.0, $1.5 and $3.2, respectively. The higher state tax flow through amount in Fiscal 2012 reflects 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 was 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:
 
2014
 
2013
Excess book basis over tax basis of property, plant and equipment
$
675.7

 
$
626.9

Investment in AmeriGas Partners
325.1

 
313.0

Intangible assets and goodwill
53.0

 
65.1

Utility regulatory assets
110.0

 
101.6

Foreign currency translation adjustment

 
9.5

Other
3.5

 
2.7

Gross deferred tax liabilities
1,167.3

 
1,118.8

 
 
 
 
Pension plan liabilities
(40.6
)
 
(36.2
)
Employee-related benefits
(48.8
)
 
(47.9
)
Operating loss carryforwards
(27.9
)
 
(32.1
)
Foreign tax credit carryforwards
(47.8
)
 
(81.8
)
Utility regulatory liabilities
(14.8
)
 
(15.5
)
Foreign currency translation adjustment
(14.1
)
 

Derivative instruments
(11.0
)
 
(15.0
)
Other
(13.0
)
 
(20.5
)
Gross deferred tax assets
(218.0
)
 
(249.0
)
Deferred tax assets valuation allowance
59.2

 
97.6

Net deferred tax liabilities
$
1,008.5

 
$
967.4


At September 30, 2014, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $37.4 and $8.2, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $171.9 and expire through 2034. We also have operating loss carryforwards of $16.8 for certain operations of AmeriGas Propane that expire through 2033. At September 30, 2014, deferred tax assets relating to operating loss carryforwards include $8.4 for Flaga, $2.7 for Antargaz, $0.8 for UGI International Holdings BV, $6.5 for AmeriGas Propane and $9.5 for certain other subsidiaries. A valuation allowance of $15.1 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 $3.0 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. The table of deferred tax assets and liabilities do not include $6.7 for Fiscal 2014 and $5.9 for Fiscal 2013 of deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions.
We have foreign tax credit carryforwards of approximately $47.8 expiring through 2024 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 $38.4 in Fiscal 2014 due to decreases in unusable foreign tax credits of $34.0 and foreign operating loss carryforwards of $4.8, partially offset by increases in unusable state operating loss tax benefits of $0.4.
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 2010 tax year, our French tax returns are settled through the 2010 tax year. The Antargaz French tax returns from 2011 to 2013 are currently under audit. Our Austrian tax returns are settled through 2012 and our other European tax returns are effectively settled for various years from 2005 to 2012. 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, 2014, we have unrecognized income tax benefits totaling $2.5 including related accrued interest of $0.1. If these unrecognized tax benefits were subsequently recognized, $2.5 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. There is an expected change in unrecognized tax benefits and related interest in the next twelve months in the amount of $0.6.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
 
2014
 
2013
 
2012
Unrecognized tax benefits - beginning of year
$
3.4

 
$
2.9

 
$
6.3

Additions for tax positions of the current year
0.7

 
0.7

 
0.5

Additions for tax positions taken in prior years

 

 
0.6

Settlements with tax authorities
(1.7
)
 
(0.2
)
 
(4.5
)
Unrecognized tax benefits - end of year
$
2.4

 
$
3.4

 
$
2.9

Employee Retirement Plans
Employee Retirement Plans
Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans
In the U.S., we sponsor a 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 (“U.S. Pension Plan”). U.S. Pension Plan benefits are based on years of service, age and employee compensation.
We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all U.S. 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, 2014 and 2013. 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
 
2014
 
2013
 
2014
 
2013
Change in benefit obligations:
 
 
 
 
 
 
 
Benefit obligations — beginning of year
$
516.5

 
$
573.4

 
$
19.7

 
$
24.7

Service cost
9.4

 
11.3

 
0.5

 
0.6

Interest cost
26.1

 
23.8

 
0.9

 
0.9

Actuarial (gain) loss
46.8

 
(72.7
)
 
1.3

 
(3.6
)
Plan amendments

 
1.0

 

 
(1.8
)
Foreign currency
(2.4
)
 
1.5

 
(0.3
)
 
0.2

Benefits paid
(22.8
)
 
(21.8
)
 
(0.8
)
 
(1.3
)
Benefit obligations — end of year
$
573.6

 
$
516.5

 
$
21.3

 
$
19.7

 
 
 
 
 
 
 
 
Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets — beginning of year
$
415.3

 
$
369.9

 
$
11.7

 
$
11.2

Actual gain on plan assets
47.9

 
42.2

 
1.4

 
1.1

Foreign currency
(1.2
)
 
0.8

 

 

Employer contributions
20.2

 
24.2

 
0.5

 
0.7

Benefits paid
(22.8
)
 
(21.8
)
 
(0.8
)
 
(1.3
)
Fair value of plan assets — end of year
$
459.4

 
$
415.3

 
$
12.8

 
$
11.7

Funded status of the plans — end of year
$
(114.2
)
 
$
(101.2
)
 
$
(8.5
)
 
$
(8.0
)
 
 
 
 
 
 
 
 
Assets (liabilities) recorded in the balance sheet:
 
 
 
 
 
 
 
Assets in excess of liabilities — included in other noncurrent assets
$

 
$

 
$
4.0

 
$
3.2

Unfunded liabilities — included in other current liabilities
(1.1
)
 
(17.9
)
 
(0.1
)
 
(0.4
)
Unfunded liabilities — included in other noncurrent liabilities
(113.1
)
 
(83.3
)
 
(12.4
)
 
(10.8
)
Net amount recognized
$
(114.2
)
 
$
(101.2
)
 
$
(8.5
)
 
$
(8.0
)
 
 
 
 
 
 
 
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
 
 
 
 
Prior service credit
$
(0.1
)
 
$
(0.1
)
 
$
(0.1
)
 
$
(0.1
)
Net actuarial loss (gain)
20.8

 
16.7

 
0.8

 
(0.4
)
Total
$
20.7

 
$
16.6

 
$
0.7

 
$
(0.5
)
 
 
 
 
 
 
 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
1.9

 
$
2.2

 
$
(3.6
)
 
$
(4.3
)
Net actuarial loss
107.4

 
91.3

 
2.6

 
3.6

Total
$
109.3

 
$
93.5

 
$
(1.0
)
 
$
(0.7
)


In Fiscal 2015, we estimate that we will amortize approximately $10.3 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.2 of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our U.S. plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France, Belgium and the Netherlands. 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 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
 
 
2014
 
2013
 
2012
 
 
2014
 
2013
 
2012
 
Weighted-average assumptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate - benefit obligations
4.60
%
 
5.20
%
 
4.20
%
 
 
4.60
%
 
5.10% - 5.40%

 
4.10% - 4.30%

 
Discount rate - benefit cost
5.20
%
 
4.20
%
 
5.30
%
 
 
5.10% - 5.40%

 
4.10% - 4.30%

 
5.30
%
 
Expected return on plan assets
7.75
%
 
7.75
%
 
7.75
%
 
 
5.00
%
 
5.00
%
 
5.20
%
 
Rate of increase in salary levels
3.25
%
 
3.25
%
 
3.25
%
 
 
3.25
%
 
3.25
%
 
3.25
%
 

The ABOs for the U.S. Pension Plan were $499.1 and $451.3 as of September 30, 2014 and 2013, respectively.
Net periodic pension expense and other postretirement benefit cost includes the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Service cost
$
9.4

 
$
11.3

 
$
9.3

 
$
0.5

 
$
0.6

 
$
0.4

Interest cost
26.1

 
23.8

 
25.1

 
0.9

 
0.9

 
1.1

Expected return on assets
(29.7
)
 
(27.8
)
 
(26.2
)
 
(0.6
)
 
(0.5
)
 
(0.5
)
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
0.3

 
0.3

 
0.2

 
(0.5
)
 
(0.3
)
 
(0.3
)
Actuarial loss
7.7

 
15.1

 
8.4

 

 
0.4

 
0.3

Net benefit cost
13.8

 
22.7

 
16.8

 
0.3

 
1.1

 
1.0

Change in associated regulatory liabilities

 

 

 
3.7

 
3.3

 
3.2

Net benefit cost after change in regulatory liabilities
$
13.8

 
$
22.7

 
$
16.8

 
$
4.0

 
$
4.4

 
$
4.2



The 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 2014, Fiscal 2013 and Fiscal 2012, we made cash contributions to the U.S. Pension Plan of $19.2, $22.4 and $31.2 respectively. The minimum required contributions in Fiscal 2015 are not expected to be material.
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, if any, determined under GAAP. The difference between such amount 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 2015, if any, are not expected to be material.
Expected payments for pension and other postretirement welfare benefits are as follows:
 
Pension
Benefits
 
Other
Postretirement
Benefits
Fiscal 2015
$
25.6

 
$
1.1

Fiscal 2016
$
25.8

 
$
1.1

Fiscal 2017
$
27.2

 
$
1.0

Fiscal 2018
$
30.3

 
$
1.0

Fiscal 2019
$
32.6

 
$
1.0

Fiscal 2020 - 2024
$
175.1

 
$
4.9



The assumed domestic health care cost trend rates at September 30 are as follows:
 
2014
 
2013
Health care cost trend rate assumed for next year
7.0
%
 
7.5
%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
5.0
%
 
5.0
%
Fiscal year that the rate reaches the ultimate trend rate
2019

 
2019



A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2014 other postretirement benefit cost or September 30, 2014, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2014 and 2013, the PBOs of these plans, including obligations for amounts held in grantor trusts, were $38.4 and $33.9, respectively. We recorded pre-tax costs for these plans of $2.6 in Fiscal 2014, $3.0 in Fiscal 2013 and $3.0 in Fiscal 2012. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $10.2 and $9.4 at September 30, 2014 and 2013, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.9 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2015. During Fiscal 2014 and Fiscal 2013, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $0.3 and $21.6, respectively, including $21.0 in Fiscal 2013 to fund self-directed grantor trusts established by the Company for participants who chose to defer their Supplemental Defined Benefit Plan payment upon retirement. The total fair value of the grantor trust investment assets associated with the Supplemental Defined Benefit Plans, which are included in other assets on the Consolidated Balance Sheets, totaled $26.6 and $23.7 at September 30, 2014 and 2013, respectively.
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, to a much lesser extent, smallcap common stocks 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
 
2014
 
2013
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
55.6
%
 
57.5
%
 
52.5
%
 
40.0% - 65.0%
International
11.3
%
 
11.1
%
 
12.5
%
 
7.5% - 17.5%
Total
66.9
%
 
68.6
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
33.1
%
 
31.4
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 

VEBA
 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2014
 
2013
 
 
Domestic equity investments
67.9
%
 
65.6
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
32.1
%
 
34.4
%
 
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, actively managed mid- and small-cap mutual funds, and a self-directed portfolio of smallcap common stocks. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate 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 9.6% and 8.2% of U.S. Pension Plan assets at September 30, 2014 and 2013, respectively.
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 by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2014 and 2013 are as follows:
 
U.S. Pension Plan
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
Domestic equity investments:
 
 
 
 
 
 
 
   S&P 500 Index equity mutual funds
$
152.6

 
$

 
$

 
$
152.6

   Small and midcap equity mutual funds
41.4

 

 

 
41.4

   Smallcap common stocks
9.3

 

 

 
9.3

   UGI Corporation Common Stock
42.5

 

 

 
42.5

       Total domestic equity investments
245.8

 

 

 
245.8

International index equity mutual funds
49.9

 

 

 
49.9

Fixed income investments:
 
 
 
 
 
 
 
   Bond index mutual funds
141.0

 

 

 
141.0

   Cash equivalents

 
5.7

 

 
5.7

     Total fixed income investments
141.0

 
5.7

 

 
146.7

Total
$
436.7

 
$
5.7

 
$

 
$
442.4

 
 
 
 
 
 
 
 
September 30, 2013:
 
 
 
 
 
 
 
Domestic equity investments:
 
 
 
 
 
 
 
   S&P 500 Index equity mutual funds
$
141.8

 
$

 
$

 
$
141.8

   Small and midcap equity mutual funds
54.5

 

 

 
54.5

    UGI Corporation Common Stock
32.6

 

 

 
32.6

       Total domestic equity investments
228.9

 

 

 
228.9

International index equity mutual funds
44.4

 

 

 
44.4

Fixed income investments:
 
 
 
 
 
 
 
   Bond index mutual funds
120.9

 

 

 
120.9

   Cash equivalents

 
4.0

 

 
4.0

     Total fixed income investments
120.9

 
4.0

 

 
124.9

Total
$
394.2

 
$
4.0

 
$

 
$
398.2

 
VEBA
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
8.7

 
$

 
$

 
$
8.7

Bond index mutual fund
3.7

 

 

 
3.7

Cash equivalents

 
0.4

 

 
0.4

Total
$
12.4

 
$
0.4

 
$

 
$
12.8

 
 
 
 
 
 
 
 
September 30, 2013:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
7.7

 
$

 
$

 
$
7.7

Bond index mutual fund
3.8

 

 

 
3.8

Cash equivalents

 
0.2

 

 
0.2

Total
$
11.5

 
$
0.2

 
$

 
$
11.7



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 $14.7 in Fiscal 2014, $14.0 in Fiscal 2013 and $13.7 in Fiscal 2012. The Company also sponsors certain nonqualified supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined contribution plans. Such payments during Fiscal 2014, Fiscal 2013 or Fiscal 2012 were not material. At September 30, 2014 and 2013, the total fair values of the grantor trust investment assets, which amounts are included in other noncurrent assets on the Consolidated Balance Sheets, was $3.4.
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:
 
2014
 
2013
Regulatory assets:
 
 
 
Income taxes recoverable
$
110.7

 
$
106.1

Underfunded pension and postretirement plans
110.1

 
94.5

Environmental costs
14.6

 
17.1

Deferred fuel and power costs
11.8

 
8.3

Removal costs, net
16.8

 
13.3

Other
4.2

 
5.6

Total regulatory assets
$
268.2

 
$
244.9

Regulatory liabilities (a):
 
 
 
Postretirement benefits
$
18.6

 
$
16.5

Environmental overcollections
0.3

 
2.6

Deferred fuel and power refunds
0.3

 
8.3

State tax benefits — distribution system repairs
10.1

 
8.4

Other
3.2

 
1.5

Total regulatory liabilities
$
32.5

 
$
37.3


(a) Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Consolidated Balance Sheets.

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 65 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 16). Consistent with prior ratemaking treatment, UGI Gas anticipates it will recover in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites and UGI Gas is currently amortizing such costs over a five-year period. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2014, 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 and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs 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 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 instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2014 and 2013 were $1.4 and $1.7, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP related to derivative instruments, these electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At September 30, 2014 and 2013, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $0.3 and $(4.8), respectively. These amounts are reflected in current derivative assets and current derivative liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds 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 instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2014 and 2013, were not material.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 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. In addition, this regulatory liability includes the portion of prior service credits and net actuarial gains associated with certain other postretirement benefit plans.
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 (“DEP”) 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, 2014, UGI Utilities expects to recover these costs over periods of approximately 1 to 20 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
Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and rights of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and, in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line was approximately $2.6.
Inventories
Inventories
Inventories
Inventories comprise the following at September 30:

 
2014
 
2013
Non-utility LPG and natural gas
$
283.6

 
$
230.0

Gas Utility natural gas
82.7

 
78.9

Materials, supplies and other
56.7

 
56.6

Total inventories
$
423.0

 
$
365.5



At September 30, 2014, UGI Utilities is a party to four principal storage contract administrative agreements (“SCAAs”) having terms of one to three years. Pursuant to 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.

As of September 30, 2014, UGI Utilities has principal SCAAs with Energy Services and a non-affiliate. The carrying values of gas storage inventories released under SCAAs with non-affiliates at September 30, 2014 and 2013, comprising 3.9 billion cubic feet (“bcf”) and 0.6 bcf of natural gas, was $16.8 and $2.4, respectively. Effective November 1, 2014, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.
Property, Plant and Equipment
Property, Plant and Equipment
Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
 
2014
 
2013
Utilities:
 
 
 
Distribution
$
2,294.6

 
$
2,162.6

Transmission
88.2

 
86.6

General and other, including work in process
185.7

 
178.6

Total Utilities
2,568.5

 
2,427.8

 
 
 
 
Non-utility:
 
 
 
Land
170.2

 
178.4

Buildings and improvements
317.4

 
308.1

Transportation equipment
288.4

 
273.8

Equipment, primarily cylinders and tanks
3,042.7

 
3,161.9

Electric generation
273.4

 
264.8

Pipeline and related assets
162.3

 
22.5

Other, including work in process
353.8

 
403.2

Total non-utility
4,608.2

 
4,612.7

Total property, plant and equipment
$
7,176.7

 
$
7,040.5

Goodwill and Intangible Assets
Goodwill and Intangible Assets
Goodwill and Intangible Assets
Changes in the carrying amount of goodwill by reportable segment are as follows:
 
 
 
 
 
 
 
UGI International
 
 
 
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Antargaz
 
Flaga & Other
 
Corporate &
Other
 
Total
Balance September 30, 2012
$
1,919.2

 
$
182.1

 
$
2.8

 
$
612.0

 
$
95.2

 
$
7.0

 
$
2,818.3

Acquisitions
12.5

 

 

 

 

 

 
12.5

Correcting adjustment
9.3

 

 

 

 

 

 
9.3

Foreign currency translation

 

 

 
31.7

 
1.9

 

 
33.6

Balance September 30, 2013
1,941.0

 
182.1

 
2.8

 
643.7

 
97.1

 
7.0

 
2,873.7

Acquisitions
6.8

 

 
2.8

 

 

 

 
9.6

Purchase accounting adjustments
(2.7
)
 

 

 

 
0.9

 

 
(1.8
)
Foreign currency translation

 

 

 
(42.5
)
 
(5.6
)
 

 
(48.1
)
Balance September 30, 2014
$
1,945.1

 
$
182.1

 
$
5.6

 
$
601.2

 
$
92.4

 
$
7.0

 
$
2,833.4



The correcting adjustment to goodwill during Fiscal 2013 primarily reflects a correcting adjustment associated with the Heritage Acquisition.
Intangible assets comprise the following at September 30:
 
2014
 
2013
Customer relationships, noncompete agreements and other
$
712.0

 
$
704.8

Trademarks and tradenames (not subject to amortization)
128.2

 
130.2

Gross carrying amount
840.2

 
835.0

Accumulated amortization
(263.8
)
 
(227.1
)
Intangible assets, net
$
576.4

 
$
607.9



Amortization expense of intangible assets was $48.2, $52.8 and $44.5 for Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2015$51.9; Fiscal 2016$44.7; Fiscal 2017$37.9; Fiscal 2018$36.4; Fiscal 2019$34.7.
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, 2014 or 2013.
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, 2014 and 2013, 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
Common Stock
On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 10,000,000 shares of UGI Corporation Common Stock over a four-year period. Pursuant to such authorization, during Fiscal 2014, the Company purchased and placed in treasury stock 1,227,654 shares at a total cost of $39.8.
UGI Common Stock share activity for Fiscal 2012, Fiscal 2013 and Fiscal 2014 follows:
 
Issued
 
Treasury
 
Outstanding
Balance, September 30, 2011
173,260,641

 
(5,506,608
)
 
167,754,033

Issued:
 
 
 
 
 
Employee and director plans
176,250

 
1,237,388

 
1,413,638

Dividend reinvestment plan

 
157,491

 
157,491

Shares reacquired - employee and director plans

 
(394,530
)
 
(394,530
)
Balance, September 30, 2012
173,436,891

 
(4,506,259
)
 
168,930,632

Issued:
 
 
 
 
 
Employee and director plans
238,800

 
3,933,507

 
4,172,307

Dividend reinvestment plan

 
93,253

 
93,253

Shares reacquired - employee and director plans

 
(1,552,905
)
 
(1,552,905
)
Balance, September 30, 2013
173,675,691

 
(2,032,404
)
 
171,643,287

Issued:
 
 
 
 
 
Employee and director plans
94,950

 
2,928,140

 
3,023,090

Repurchases of Common Stock

 
(1,227,654
)
 
(1,227,654
)
Shares reacquired - employee and director plans

 
(1,164,942
)
 
(1,164,942
)
Balance, September 30, 2014
173,770,641

 
(1,496,860
)
 
172,273,781


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 15), 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 during Fiscal 2012.

Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common stock-based equity instruments and AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $25.8 ($16.6 after-tax), $17.6 ($11.4 after-tax) and $14.5 ($8.7 after-tax) in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively.
UGI Equity-Based Compensation Plans and Awards. On January 24, 2013, the Company’s shareholders approved the UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”). The 2013 OICP succeeds the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “2004 OECP”) for awards granted on or after January 24, 2013. The 2004 OECP will continue in effect but all future grants issued pursuant to it will be solely in the form of options to acquire Common Stock. Under the 2013 OICP, we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash 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 2013 OICP 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 2013 OICP 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 2004 OECP, we could grant options to acquire shares of UGI Common Stock, UGI Units and other equity-based awards to key employees and non-employee directors through January 23, 2013 (except with respect to the granting of stock option awards as previously mentioned). Under the 2004 OECP, the exercise price for stock options could not be less than the fair market value on the grant date. Awards granted under the 2004 OECP could vest immediately or ratably over a period of years, and stock options could be exercised no later than ten years from the date of grant. In addition, the 2004 OECP provided that the awards of UGI Units could include the crediting of dividend equivalents to participants’ accounts.
Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. 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 currently our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. Beginning during Fiscal 2012, options 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 pursuant to a net exercise as shares reacquired.
UGI Stock Option Awards. Stock option transactions under equity-based compensation plans during Fiscal 2012, Fiscal 2013 and Fiscal 2014 follow:
 
Shares
 
Weighted
Average
Option Price
 
Total
Intrinsic
Value
 
Weighted
Average
Contract Term
(Years)
Shares under option — September 30, 2011
11,509,769

 
$
17.03

 
$
15.1

 
6.2
Granted
2,262,075

 
$
19.51

 
 
 
 
Cancelled
(482,400
)
 
$
18.49

 
 
 
 
Exercised
(1,202,786
)
 
$
13.95

 
$
7.2

 
 
Shares under option — September 30, 2012
12,086,658

 
$
17.75

 
$
41.4

 
6.1
Granted
2,275,350

 
$
22.38

 
 
 
 
Cancelled
(134,754
)
 
$
20.34

 
 
 
 
Exercised
(4,033,302
)
 
$
16.39

 
$
35.4

 
 
Shares under option — September 30, 2013
10,193,952

 
$
19.28

 
$
69.6

 
6.8
Granted
1,665,600

 
$
27.93

 
 
 
 
Cancelled
(86,707
)
 
$
22.76

 
 
 
 
Exercised
(2,815,555
)
 
$
17.44

 
$
37.4

 
 
Shares under option — September 30, 2014
8,957,290

 
$
21.44

 
$
113.3

 
7.0
Options exercisable — September 30, 2012
7,976,547

 
$
16.88

 
 
 
 
Options exercisable — September 30, 2013
5,871,091

 
$
17.95

 
 
 
 
Options exercisable — September 30, 2014
5,073,347

 
$
19.45

 
$
74.2

 
6.0
Options not exercisable — September 30, 2014
3,883,943

 
$
24.02

 
$
39.1

 
8.5


Cash received from stock option exercises and associated tax benefits were $22.2 and $13.0, $30.8 and $12.1, and $9.4 and $2.3 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. As of September 30, 2014, there was $6.5 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.7 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2014:

 
Range of exercise prices
 
Under
$15.00
 
$15.01 -
$20.00
 
$20.01 -
$25.00
 
Over
$25.00
Options outstanding at September 30, 2014:
 
 
 
 
 
 
 
Number of options
102,000

 
3,452,480

 
3,500,910

 
1,901,900

Weighted average remaining contractual life (in years)
1.4

 
5.7

 
7.2

 
9.2

Weighted average exercise price
$
14.47

 
$
18.15

 
$
21.45

 
$
27.74

Options exercisable at September 30, 2014:
 
 
 
 
 
 
 
Number of options
102,000

 
2,727,509

 
2,077,840

 
165,998

Weighted average exercise price
$
14.47

 
$
17.81

 
$
21.27

 
$
26.85



UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.97 in Fiscal 2014, $3.29 in Fiscal 2013 and $2.87 in Fiscal 2012. 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 2014, Fiscal 2013 and Fiscal 2012 are as follows:

 
2014
 
2013
 
2012
Expected life of option
5.75 years
 
5.75 years
 
5.75 years
Weighted average volatility
24.3%
 
24.9%
 
24.7%
Weighted average dividend yield
2.9%
 
3.6%
 
3.5%
Expected volatility
23.7% - 24.4%
 
24.4% - 24.9%
 
24.7%
Expected dividend yield
2.7% - 2.9%
 
3.2% - 3.7%
 
3.3% - 3.7%
Risk free rate
1.8% - 2.0%
 
0.8% - 1.7%
 
0.8% - 1.1%


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 (i) companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and (ii) the Russell Midcap Utility Index, excluding telecommunication companies, for grants on or after January 1, 2011 (each a respective “UGI comparator group”). For grants issued on or after January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; and at the 90th percentile and above, 200%. For grants issued prior to January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, 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 plus the fair value of dividend equivalents if applicable. 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 groups 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
 
2014
 
2013
 
2012
Risk free rate
0.8
%
 
0.4
%
 
0.4
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
20.3
%
 
21.1
%
 
22.2
%
Dividend yield
2.7
%
 
3.3
%
 
3.5
%


The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $32.32 for Units granted in Fiscal 2014, $25.31 for Units granted in Fiscal 2013 and $18.17 for Units granted in Fiscal 2012.
The following table summarizes UGI Unit award activity for Fiscal 2014:
 
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, 2013
1,380,902

 
$
18.35

 
822,975

 
$
15.45

 
557,927

 
$
22.62

UGI Performance Units:
 
 
 
 
 
 
 
 
 
 
 
Granted
189,450

 
$
32.32

 
9,570

 
$
32.02

 
179,880

 
$
32.33

Forfeited
(7,200
)
 
$
24.95

 

 
$

 
(7,200
)
 
$
24.95

Vested

 
$

 
205,282

 
$
21.15

 
(205,282
)
 
$
21.15

Unit awards paid
(267,146
)
 
$
22.17

 
(267,146
)
 
$
22.17

 

 
$

UGI Stock Units:
 
 
 
 
 
 
 
 
 
 
 
Granted (a)
44,814

 
$
27.41

 
43,689

 
$
27.35

 
1,125

 
$
29.84

Vested

 
$

 
1,500

 
$
22.29

 
(1,500
)
 
$
22.29

Unit awards paid
(34,639
)
 
$
14.41

 
(34,639
)
 
$
14.41

 

 
$

September 30, 2014
1,306,181

 
$
20.58

 
781,231

 
$
16.60

 
524,950

 
$
26.51

(a)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2013 and Fiscal 2012 were 51,038 and 63,668, respectively.
During Fiscal 2014, Fiscal 2013 and Fiscal 2012, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
 
2014
 
2013
 
2012
UGI Performance Unit awards:
 
 
 
 
 
Number of original awards granted
331,038

 
328,025

 
316,125

Fiscal year granted
2011

 
2010

 
2009

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
174,168

 
97,622

 

Cash paid
$
3.1

 
$
1.6

 
$

UGI Stock Unit awards:
 
 
 
 
 
Number of original awards granted
34,639

 
54,269

 
49,347

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
22,604

 
35,274

 
32,636

Cash paid
$
0.4

 
$
0.5

 
$
0.2



During Fiscal 2014, Fiscal 2013 and Fiscal 2012, we granted UGI Unit awards representing 234,264, 381,900 and 359,768 shares, respectively, having weighted-average grant date fair values per Unit of $31.38, $24.87 and $18.45, respectively.
As of September 30, 2014, there was a total of approximately $8.8 of unrecognized compensation cost associated with 1,306,181 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.7 years. The total fair values of UGI Units that vested during Fiscal 2014, Fiscal 2013 and Fiscal 2012 were $8.7, $6.0 and $3.6, respectively. As of September 30, 2014 and 2013, total liabilities of $18.5 and $8.0, 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, 2014, 17,499,524 shares of Common Stock were available for future grants under the 2013 OICP, and up to 172,646 shares of Common Stock were available for future grants of stock options under the 2004 OECP.
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 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.
AmeriGas Stock Unit and AmeriGas Performance Unit awards entitle the grantee to AmeriGas Partners Common Units or cash once the service condition is met and, with respect to AmeriGas Performance Units, subject to market performance conditions. 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, or it may be zero, based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a master limited partnership peer group (“Alerian MLP Group”) and, for certain AmeriGas Performance Unit awards granted beginning in January 2014, based upon AmeriGas Partners’ TUR relative to the two other publicly traded propane master limited partnerships in the Alerian MLP Group (“Propane MLP Group”).
With respect to AmeriGas Performance Unit awards subject to measurement compared with the Alerian MLP Group, grantees may receive from 0% to 200% of the target award granted. For grants issued on or after January 1, 2013, if AmeriGas Partners’ TUR is below the 25th percentile compared to the peer group, the grantee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; at the 60th percentile, 125%; at the 75th percentile, 162.5%; and at the 90th percentile or above, 200%. For grants issued before January 1, 2013, grantees of AmeriGas Performance Units will not be paid if AmeriGas Partners’ TUR is below the 40th percentile of the Alerian MLP Group. At the 40th percentile, the grantee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; at the 60th percentile, 125%; at the 75th percentile, 150%; at the 90th percentile, 175%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings.
With respect to AmeriGas Performance Unit awards subject to measurement compared with the Propane MLP Group, grantees will receive 150% of the target award if AmeriGas Partners’ TUR exceeds the TUR of all the other members in the Propane MLP Group. Otherwise there will be no payout of such AmeriGas Performance Units. If one of the other two members of the Propane MLP Group ceases to exist as a publicly traded company or declares bankruptcy (“MLP Event”), the ultimate amount of such AmeriGas Performance Unit awards to be issued, and the amount of distribution equivalents to be paid, will depend upon AmeriGas Partners’ TUR rank relative to (1) the Alerian MLP Group for the entire performance period; (2) the Alerian MLP Group for the entire performance period and the Propane MLP Group through the date of the MLP Event; or (3) the Propane MLP Group through the date of the MLP Event.
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.
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 will be paid in Common Units, is accounted for as equity and the fair value of the award over the target, as well as 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
 
2014
 
2013
 
2012
Risk-free rate
0.8
%
 
0.4
%
 
0.4
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
21.1
%
 
20.7
%
 
23.0
%
Dividend yield
7.5
%
 
8.2
%
 
6.4
%


The General Partner granted awards under the 2010 Propane Plan representing 86,458, 65,136 and 248,818 Common Units in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively, having weighted-average grant date fair values per Common Unit subject to award of $43.34, $42.58 and $43.22, respectively. At September 30, 2014, 2,443,808 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 2014:
 
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, 2013
224,167

 
$
47.88

 
47,715

 
$
47.92

 
176,452

 
$
47.87

AmeriGas Performance Units:


 


 


 


 


 


  Granted
53,800

 
$
41.50

 
633

 
$
41.37

 
53,167

 
$
41.50

  Forfeited
(8,150
)
 
$
45.96

 

 
$

 
(8,150
)
 
$
45.96

  Vested

 
$

 
15,319

 
$
53.93

 
(15,319
)
 
$
53.93

  Performance criteria not met
(31,317
)
 
$
54.51

 
(31,317
)
 
$
54.51

 

 
$

AmeriGas Stock Units:
 
 
 
 
 
 
 
 
 
 
 
  Granted
32,658

 
$
46.37

 
15,936

 
$
48.00

 
16,722

 
$
44.81

  Forfeited
(7,783
)
 
$
51.10

 

 
$

 
(7,783
)
 
$
(51.10
)
  Vested

 
$

 
52,061

 
$
47.58

 
(52,061
)
 
$
47.58

  Awards paid
(63,140
)
 
$
48.00

 
(63,140
)
 
$
48.00

 

 
$

September 30, 2014
200,235

 
$
44.82

 
37,207

 
$
44.27

 
163,028

 
$
44.95



During Fiscal 2014, Fiscal 2013 and Fiscal 2012, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:
 
2014
 
2013
 
2012
AmeriGas Performance Unit awards:
 
 
 
 
 
Number of Common Units subject to original awards granted
41,251

 
48,150

 
53,600

Fiscal year granted
2011

 
2010

 
2009

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued

 

 

Cash paid
$

 
$

 
$

AmeriGas Stock Unit awards:
 
 
 
 
 
Number of Common Units subject to original awards granted
72,023

 
35,934

 
67,246

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued
40,842

 
23,192

 
44,016

Cash paid
$
1.4

 
$
0.6

 
$
1.0



As of September 30, 2014, there was a total of approximately $2.9 of unrecognized compensation cost associated with 200,235 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.7 years. The total fair values of Common Unit-based awards that vested during Fiscal 2014, Fiscal 2013 and Fiscal 2012 were $4.1, $2.8 and $5.1, respectively. As of September 30, 2014 and 2013, total liabilities of $1.5 and $1.1 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 Offerings
Partnership Distributions and Common Unit Offering
Partnership Distributions and Common Unit Offerings
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 (as defined in the Partnership Agreement) 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 2014, Fiscal 2013 and Fiscal 2012, 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. During Fiscal 2014, Fiscal 2013 and Fiscal 2012, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $32.4, $27.4 and $19.7, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2014, Fiscal 2013 and Fiscal 2012 of $23.9, $19.3 and $13.0, 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 AmeriGas Partners’ 6.50% Senior Notes pursuant to a tender offer (see Note 6), 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 $79.7 in Fiscal 2014, $82.5 in Fiscal 2013 and $77.9 in Fiscal 2012.
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
 
2015
 
2016
 
2017
 
2018
 
2019
 
After 2019
AmeriGas Propane
$
56.2

 
$
46.6

 
$
36.5

 
$
30.6

 
$
25.9

 
$
63.0

UGI Utilities
6.7

 
6.2

 
4.5

 
3.7

 
1.4

 
0.7

UGI International
7.8

 
6.1

 
4.4

 
2.0

 
0.4

 
0.5

Other
1.9

 
1.8

 
0.9

 
0.6

 
0.4

 
0.3

Total
$
72.6

 
$
60.7

 
$
46.3

 
$
36.9

 
$
28.1

 
$
64.5



Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility currently has gas supply agreements with producers and marketers with terms not exceeding 16 months. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2030. 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 2016. 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 three years. UGI International enters into fixed-price and variable-priced contracts to purchase a portion of its supply requirements that currently do not exceed three years.
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and UGI International supply, storage and service contracts existing at September 30, 2014:
 
2015
 
2016
 
2017
 
2018
 
2019
 
After 2019
UGI Utilities supply, storage and transportation contracts
$
156.9

 
$
66.8

 
$
44.9

 
$
30.8

 
$
23.6

 
$
66.4

Midstream & Marketing supply contracts
302.1

 
107.0

 
42.1

 
4.3

 

 

AmeriGas Propane supply contracts
130.8

 
74.3

 

 

 

 

UGI International supply contracts
144.7

 
72.8

 

 

 

 

Total
$
734.5

 
$
320.9

 
$
87.0

 
$
35.1

 
$
23.6

 
$
66.4



The Partnership and UGI International 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
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“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 is scheduled to terminate at the end of 2018. 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, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $10.7 and $14.0, 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, 2014, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform 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.
Other Matters

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”) had initiated an antitrust and consumer protection investigation into certain practices of the Partnership relating to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requested 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 responded to that subpoena and cooperated with subsequent requests for information. On March 27, 2014, the FTC issued an administrative complaint against the Partnership and UGI alleging that the General Partner and one of its competitors colluded in 2008 to persuade its common customer, Walmart Stores, Inc., to accept the cylinder fill reduction from 17 pounds to 15 pounds.  The complaint does not seek monetary remedies.  The Partnership and UGI filed their answer to the complaint on April 18, 2014.  On August 25, 2014, the parties entered into an Agreement Containing Consent Orders, and on August 27, 2014, the FTC issued an Order Withdrawing Matter from Adjudication for the Purpose of Considering a Proposed Consent Agreement. The consent agreement was accepted by the FTC on October 31, 2014, and is subject to a 30-day public comment period. Thereafter, the FTC may either withdraw its acceptance of the consent agreement or issue its decision and order in settlement of the proceeding.  

Purported Class Action Lawsuits.  Following the issuance of the FTC’s administrative complaint described above, more than 35 class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers.  The class action lawsuits allege that the Partnership and its competitor colluded in 2008 to reduce the fill level and combined to persuade its common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws.  The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.  On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the Western District of Missouri.  We are unable to reasonably estimate the impact, if any, arising from such litigation.  We believe we have strong defenses to the claims and intend to vigorously defend against them.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these 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 Instruments
The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2014 and 2013:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
10.6

 
$
19.8

 
$

 
$
30.4

Foreign currency contracts
$

 
$
12.8

 
$

 
$
12.8

Cross-currency swaps
$

 
$
2.1

 
$

 
$
2.1

Interest rate contracts
$

 
$
0.1

 
$

 
$
0.1

   Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(21.2
)
 
$
(32.9
)
 
$

 
$
(54.1
)
Foreign currency contracts
$

 
$
(0.1
)
 
$

 
$
(0.1
)
Interest rate contracts
$

 
$
(21.0
)
 
$

 
$
(21.0
)
 
 
 
 
 
 
 
 
Non-qualified supplemental postretirement grantor trust investments (a)
$
30.0

 
$

 
$

 
$
30.0

 
 
 
 
 
 
 
 
September 30, 2013 (b):
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2.6

 
$
22.8

 
$

 
$
25.4

Foreign currency contracts
$

 
$
0.9

 
$

 
$
0.9

  Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(8.8
)
 
$
(9.3
)
 
$

 
$
(18.1
)
Foreign currency contracts
$

 
$
(7.2
)
 
$

 
$
(7.2
)
Interest rate contracts
$

 
$
(31.0
)
 
$

 
$
(31.0
)
Cross-currency swaps
$

 
$
(1.2
)
 
$

 
$
(1.2
)
 
 
 
 
 
 
 
 
Non-qualified supplemental postretirement grantor trust investments (a)
$
27.1

 
$

 
$

 
$
27.1


(a)
Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8).
(b)
Certain immaterial amounts have been revised to correct the classification of derivatives.

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 instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are 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 our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,510.8 and $3,686.1, respectively. At September 30, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,609.4 and $3,761.8, 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 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 instruments, see Note 18. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.
Derivative Instruments and Hedging Activities
Disclosures About Derivative Instruments and Hedging Activities
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. For information on the accounting for our derivative instruments, see Note 2.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our UGI International 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, the Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At September 30, 2014 and 2013, total volumes associated with LPG commodity derivative instruments totaled 344.5 million gallons and 279.0 million gallons, respectively. The maximum period over which we are economically hedging our exposure to LPG commodity price risk is 21 months.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 16.9 million dekatherms and 15.0 million dekatherms, respectively. At September 30, 2014, the maximum period over which Gas Utility is economically 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 GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 9).
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of these contracts currently do not qualify for the NPNS exception under GAAP, the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Consolidated Balance Sheets in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS mechanism (see Note 9). At September 30, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 237.0 million kilowatt hours and 245.8 million kilowatt hours, respectively. At September 30, 2014, the maximum period over which these contracts extend is 8 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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 9). At September 30, 2014 and 2013, the total volumes associated with FTRs and NYISO capacity contracts totaled 232.1 million kilowatt hours and 189.3 million kilowatt hours, respectively. At September 30, 2014, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 8 months.
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 futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. During the second quarter of Fiscal 2014, Energy Services determined that it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation. These contracts, as well as other Midstream & Marketing derivative instruments described above, are not accounted for as hedges under GAAP. These derivative instruments are recorded at fair value with changes in fair value reflected in income.
At September 30, 2014 and 2013, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 113.7 million dekatherms and 24.3 million dekatherms, respectively. At September 30, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 41 months. At September 30, 2014 and 2013, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 394.4 million kilowatt hours and 206.6 million kilowatt hours, and 754.4 million kilowatt hours and 393.0 million kilowatt hours, respectively. At September 30, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 24 months for electricity call contracts and 12 months for electricity put contracts. At September 30, 2014, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 3.9 million dekatherms and 1.3 million gallons, respectively. At September 30, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.9 million dekatherms and 2.8 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.
A portion of our commodity derivative instruments are designated and qualify as cash flow hedges. At September 30, 2014, 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 $2.3.
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 and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of September 30, 2014 and 2013, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €401.1 and €440.5, 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, 2014 and 2013, we had no unsettled IRPAs.
During Fiscal 2012, UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income 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 Fiscal 2012 Consolidated Statement of Income.
We account for interest rate swaps and IRPAs as cash flow hedges. At September 30, 2014, 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 $2.7.
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 U.S. dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated U.S. dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2014 and 2013, we were hedging a total of $219.8 and $200.2 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 27 months. From time to time 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, 2014 and 2013, we had no euro-denominated net investment hedges.
We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2014, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.6.
Cross-Currency Swaps
During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk resulting from the issuance of $52.0 of U.S. dollar-denominated variable-rate debt. The cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. At September 30, 2014, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.
Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative 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 contracts generally require cash deposits in margin accounts. At September 30, 2014 and 2013, restricted cash in brokerage accounts totaled $16.6 and $7.0, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2014. 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, 2014, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on our Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.
In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

Fair Value of Derivative Instruments
The following table presents our derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30, 2014 and 2013:

 
2014
 
2013 (a)
Derivative assets:
 
 
 
Derivatives designated as hedging instruments:
 
 
 
Commodity contracts
$
2.8

 
$
18.0

Foreign currency contracts
12.8

 
0.9

Cross-currency contracts
2.1

 

Interest rate contracts
0.1

 

 
17.8

 
18.9

Derivatives accounted for under ASC 980:
 
 
 
Commodity contracts
1.7

 

Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
25.9

 
7.4

Total derivative assets - gross
45.4

 
26.3

Gross amounts offset in the balance sheet
(18.4
)
 
(2.1
)
Total derivative assets - net
$
27.0

 
$
24.2

 
 
 
 
Derivative liabilities:
 
 
 
Derivatives designated as hedging instruments:
 
 
 
Commodity contracts
$
(5.3
)
 
$
(4.5
)
Foreign currency contracts
(0.1
)
 
(7.2
)
Cross-currency contracts

 
(1.2
)
Interest rate contracts
(21.0
)
 
(31.0
)
 
(26.4
)
 
(43.9
)
Derivatives accounted for under ASC 980:
 
 
 
Commodity contracts
(2.2
)
 
(6.7
)
Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
(46.6
)
 
(6.9
)
Total derivative liabilities - gross
(75.2
)
 
(57.5
)
Gross amounts offset in the balance sheet
18.4

 
2.1

Total derivative liabilities - net
$
(56.8
)
 
$
(55.4
)

(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.
Effect of Derivative Instruments
The following tables provide information on the effects of derivative instruments in the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2014, 2013 and 2012:
 
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
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
50.8

 
$
8.3

 
$
(98.0
)
 
$
67.0

 
$
(49.5
)
 
$
(61.4
)
 
Cost of sales
Foreign currency contracts
15.3

 
(8.3
)
 
(0.5
)
 
(3.7
)
 
(0.1
)
 
2.1

 
Cost of sales
Cross-currency contracts
3.1

 
(1.2
)
 

 
(0.1
)
 

 

 
Interest expense
Interest rate contracts
(3.1
)
 
22.9

 
(36.8
)
 
(15.9
)
 
(14.2
)
 
(11.5
)
 
Interest expense /other income, net
Total
$
66.1

 
$
21.7

 
$
(135.3
)
 
$
47.3

 
$
(63.8
)
 
$
(70.8
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
$

 
$

 
$
0.6

 
 
 
 
 
 
 
 

 
Gain or (Loss)
Recognized in Income
Location of
Gain or (Loss)
Recognized in Income
 
 
2014
 
2013
 
2012
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(36.3
)
 
$
9.3

 
$
0.1

Cost of sales
 
Commodity contracts

 

 
0.2

Operating and administrative expenses / other income, net
 
Foreign currency contracts

 
(0.4
)
 
0.5

Other income, net
 
Total
$
(36.3
)
 
$
8.9

 
$
0.8

 
 


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 2014, Fiscal 2013 and Fiscal 2012.
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 energy products, 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, certain of these contracts qualify for NPNS 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.
Other Income, Net
Other Income, Net
Other Income, Net
Other income, net, comprises the following:
 
2014
 
2013
 
2012
Interest and interest-related income
$
3.6

 
$
2.2

 
$
2.4

Utility non-tariff service income
2.7

 
2.8

 
2.7

Finance charges
17.5

 
21.4

 
18.8

Gains on sales of fixed assets
5.4

 
1.4

 
1.9

Loss on private equity partnership investment

 
(6.3
)
 

Other, net
6.9

 
11.3

 
14.0

Total other income, net
$
36.1

 
$
32.8

 
$
39.8

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,
 
2013(a)
2012
 
2014
2013
 
2014
2013
 
2014
2013 (b)
Revenues
$
2,315.9

$
2,018.7

 
$
3,163.3

$
2,542.7

 
$
1,486.7

$
1,374.3

 
$
1,311.4

$
1,259.0

Operating income (loss)
$
363.7

$
294.2

 
$
588.6

$
507.7

 
$
62.7

$
41.5

 
$
(9.4
)
$
(12.3
)
Net income (loss)
$
217.5

$
167.8

 
$
387.8

$
341.7

 
$
(12.7
)
$
(22.8
)
 
$
(60.0
)
$
(59.1
)
Net income (loss) attributable to UGI Corporation
$
122.0

$
102.5

 
$
214.4

$
180.7

 
$
20.6

$
9.1

 
$
(19.8
)
$
(14.2
)
Earnings (loss) per common share attributable to UGI Corporation stockholders:
 
 
 
 
 
 
 
 
 
 
 
Basic
$
0.71

$
0.60

 
$
1.24

$
1.06

 
$
0.12

$
0.05

 
$
(0.11
)
$
(0.08
)
Diluted
$
0.70

$
0.60

 
$
1.22

$
1.05

 
$
0.12

$
0.05

 
$
(0.11
)
$
(0.08
)
(a)
Includes income tax expense of $5.7 to reflect the retroactive effects to Fiscal 2013 of new tax legislation in France regarding the deductibility of certain interest expense which decreased net income attributable to UGI Corporation by $5.7 or $0.03 per diluted share (see Note 7).
(b)
Includes impairment loss on private equity partnership investment which increased operating loss by $6.3 and net loss attributable to UGI Corporation by $3.7 or $0.02 per share (see Note 2).
Segment Information
Segment Information
Segment Information
Our operations comprise 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 “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”
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 lesser extent, the sale of LPG to retail customers in Belgium, the Netherlands and Luxembourg and the marketing of natural gas in France and Belgium. 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, pipeline transportation as well as fees from other energy services provided 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 UGI International, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of UGI International, are located in the United States.
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
8,277.3

 
$
(321.3
)
(c)
$
3,712.9

 
$
977.3

 
$
1,305.5

 
$
85.1

 
$
1,295.5

 
$
1,026.9

 
$
195.4

Cost of sales
$
5,175.7

 
$
(317.7
)
(c)
$
2,107.1

 
$
496.8

 
$
1,058.8

 
$
39.6

 
$
848.1

 
$
809.9

 
$
133.1

Operating income (loss)
$
1,005.6

 
$
0.2

 
$
472.0

 
$
236.2

 
$
180.5

 
$
18.1

 
$
79.1

 
$
38.4

 
$
(18.9
)
Loss from equity investees
(0.1
)
 

 

 

 

 

 
(0.1
)
 

 

Interest expense
(237.7
)
 

 
(165.6
)
 
(36.6
)
 
(2.9
)
 

 
(25.1
)
 
(4.9
)
 
(2.6
)
Income (loss) before income taxes
$
767.8

 
$
0.2

 
$
306.4

 
$
199.6

 
$
177.6

 
$
18.1

 
$
53.9

 
$
33.5

 
$
(21.5
)
Net income (loss) attributable to UGI
$
337.2

 
$

 
$
63.0

 
$
118.8

 
$
105.2

 
$
12.6

 
$
20.6

 
$
27.7

 
$
(10.7
)
Depreciation and amortization
$
362.9

 
$

 
$
197.2

 
$
54.8

 
$
12.3

 
$
10.7

 
$
54.5

 
$
27.1

 
$
6.3

Noncontrolling interests’ net income (loss)
$
195.4

 
$

 
$
195.8

 
$

 
$

 
$

 
$
(0.4
)
 
$

 
$

Partnership EBITDA (a)
$
655.3

 
$

 
$
664.8

 
$

 
$

 
$

 
$

 
$

 
$
(9.5
)
Total assets
$
10,093.0

 
$
(86.5
)
 
$
4,377.0

 
$
2,214.1

 
$
569.0

 
$
277.7

 
$
1,659.1

 
$
643.6

 
$
439.0

Short-term borrowings
$
210.8

 
$

 
$
109.0

 
$
86.3

 
$
7.5

 
$

 
$

 
$
8.0

 
$

Capital expenditures
$
436.4

 
$

 
$
113.9

 
$
156.4

 
$
67.8

 
$
15.6

 
$
50.2

 
$
23.0

 
$
9.5

Investments in equity investees
$
0.6

 
$

 
$

 
$

 
$

 
$

 
$

 
$
0.6

 
$

Goodwill
$
2,833.4

 
$

 
$
1,945.1

 
$
182.1

 
$
5.6

 
$

 
$
601.2

 
$
92.4

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
7,194.7

 
$
(223.8
)
(c)
$
3,168.8

 
$
839.0

 
$
969.4

 
$
71.4

 
$
1,322.6

 
$
856.6

 
$
190.7

Cost of sales
$
4,324.4

 
$
(217.5
)
(c)
$
1,657.2

 
$
407.2

 
$
836.9

 
$
39.9

 
$
845.0

 
$
653.4

 
$
102.3

Operating income
$
831.1

 
$
(1.1
)
 
$
394.4

 
$
196.5

 
$
82.5

 
$
7.5

 
$
111.4

 
$
35.6

 
$
4.3

Loss from equity investees
(0.4
)
 

 

 

 

 

 
(0.4
)
 

 

Interest expense
(240.3
)
 

 
(166.6
)
 
(37.4
)
 
(3.2
)
 

 
(25.3
)
 
(5.1
)
 
(2.7
)
Income before income taxes
590.4

 
(1.1
)
 
227.8

 
159.1

 
79.3

 
7.5

 
85.7

 
30.5

 
1.6

Net income attributable to UGI
$
278.1

 
$
(0.6
)
 
$
47.5

 
$
94.3

 
$
46.3

 
$
6.2

 
$
57.2

 
$
25.5

 
$
1.7

Depreciation and amortization
$
363.1

 
$

 
$
205.9

 
$
51.7

 
$
7.6

 
$
10.0

 
$
57.6

 
$
24.1

 
$
6.2

Noncontrolling interests’ net (loss) income
$
149.5

 
$

 
$
149.6

 
$

 
$

 
$

 
$
(0.2
)
 
$
0.1

 
$

Partnership EBITDA (a)
 

 


 
$
596.5

 


 


 


 


 


 


Total assets
$
10,008.8

 
$
(100.3
)
 
$
4,429.3

 
$
2,069

 
$
501.2

 
$
269.7

 
$
1,784.4

 
$
667.1

 
$
388.4

Short-term borrowings
$
227.9

 
$

 
$
116.9

 
$
17.5

 
$
87.0

 
$

 
$

 
$
6.5

 
$

Capital expenditures
$
489.1

 
$
(1.1
)
 
$
111.1

 
$
144.4

 
$
133.8

 
$
22.6

 
$
53.4

 
$
17.4

 
$
7.5

Investments in equity investees
$
0.3

 
$

 
$

 
$

 
$

 
$

 
$

 
$
0.3

 
$

Goodwill
$
2,873.7

 
$

 
$
1,941.0

 
$
182.1

 
$
2.8

 
$

 
$
643.7

 
$
97.1

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,521.3

 
$
(178.8
)
(c)
$
2,921.5

 
$
785.4

 
$
816.4

 
$
43.9

 
$
1,121.4

 
$
824.7

 
$
186.8

Cost of sales
$
4,099.1

 
$
(174.0
)
(c)
$
1,722.4

 
$
402.5

 
$
701.9

 
$
28.0

 
$
685.5

 
$
640.3

 
$
92.5

Operating income (loss)
$
538.6

 
$

 
$
168.7

 
$
174.1

 
$
70.8

 
$
(6.5
)
 
$
88.3

 
$
23.6

 
$
19.6

Loss from equity investees
(0.3
)
 

 

 

 

 

 
(0.3
)
 

 

Loss on extinguishments of debt
(13.3
)
 

 
(13.3
)
 

 

 

 

 

 

Interest expense
(220.4
)
 

 
(141.5
)
 
(40.1
)
 
(4.8
)
 

 
(26.3
)
 
(4.6
)
 
(3.1
)
Income (loss) before income taxes
$
304.6

 
$

 
$
13.9

 
$
134.0

 
$
66.0

 
$
(6.5
)
 
$
61.7

 
$
19.0

 
$
16.5

Net income (loss) attributable to UGI
$
210.2

 
$

 
$
15.4

 
$
81.6

 
$
38.7

 
$
(1.0
)
 
$
51.4

 
$
13.8

 
$
10.3

Depreciation and amortization
$
315.0

 
$

 
$
168.1

 
$
49.0

 
$
3.7

 
$
9.0

 
$
57.1

 
$
22.1

 
$
6.0

Noncontrolling interests’ net (loss) income
$
(12.5
)
 
$

 
$
(12.7
)
 
$

 
$

 
$

 
$
0.2

 
$

 
$

Partnership EBITDA (a)
 
 

 
$
322.1

 

 

 

 

 

 

Total assets
$
9,676.9

 
$
(104.1
)
 
$
4,533.8

 
$
2,045.5

 
$
368.5

 
$
258.2

 
$
1,686.5

 
$
531.8

 
$
356.7

Short-term borrowings
$
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

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
 
 
2014
 
2013
 
2012
Partnership EBITDA
 
$
664.8

 
$
596.5

 
$
322.1

Depreciation and amortization
 
(197.2
)
 
(205.9
)
 
(168.1
)
Loss on extinguishments of debt
 

 

 
13.3

Noncontrolling interests (i)
 
4.4

 
3.8

 
1.4

Operating income
 
$
472.0

 
$
394.4

 
$
168.7


(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, (4) UGI Corporation’s unallocated corporate and general expenses and interest income and (5) net (losses) gains on Midstream & Marketing’s unsettled commodity derivative instruments and certain settled commodity derivative instruments not associated with current period transactions, and net (losses) gains on AmeriGas Propane’s unsettled commodity derivative instruments entered into beginning April 1, 2014, totaling $(18.0), $7.4 and $15.1 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Condensed Financial Information of Registrant (Parent Company)
BALANCE SHEETS
(Millions of dollars)

 
September 30,
 
2014
 
2013
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
0.8

 
$
0.9

Accounts and notes receivable
3.9

 
2.9

Deferred income taxes
0.4

 
0.4

Prepaid expenses and other current assets
0.3

 
0.3

Total current assets
5.4

 
4.5

Investments in subsidiaries
2,663.9

 
2,488.7

Other assets
55.5

 
49.9

Total assets
$
2,724.8

 
$
2,543.1

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts and notes payable
$
11.8

 
$
11.0

Derivative instruments

 

Accrued liabilities
6.0

 
3.9

Total current liabilities
17.8

 
14.9

Noncurrent liabilities
47.9

 
35.7

Commitments and contingencies (Note 1)

 

Common stockholders’ equity:
 
 
 
Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,770,641 and 173,675,691 shares, respectively)
1,215.6

 
1,208.1

Retained earnings
1,509.4

 
1,308.3

Accumulated other comprehensive (loss) income
(21.2
)
 
8.4

Treasury stock, at cost
(44.7
)
 
(32.3
)
Total common stockholders’ equity
2,659.1

 
2,492.5

Total liabilities and common stockholders’ equity
$
2,724.8

 
$
2,543.1


Note 1 — Commitments and Contingencies:
In addition to the guarantees of Flaga’s and Antargaz’ debt as described in Note 6 to Consolidated Financial Statements, at September 30, 2014, UGI Corporation had agreed to indemnify the issuers of $65.1 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $500.0 of obligations to suppliers and customers of Energy Services and subsidiaries of which $414.1 of such obligations were outstanding as of September 30, 2014. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga, which obligations totaled $3.5 at September 30, 2014.
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

 
Year Ended
September 30,
 
2014
 
2013
 
2012
Revenues
$

 
$

 
$

Costs and expenses:
 
 
 
 
 
Operating and administrative expenses
44.5

 
36.9

 
27.8

Other income, net (a)
(44.2
)
 
(36.7
)
 
(28.1
)
 
0.3

 
0.2

 
(0.3
)
Operating (loss) income
(0.3
)
 
(0.2
)
 
0.3

Intercompany interest income
0.2

 
0.2

 
0.2

(Loss) income before income taxes
(0.1
)
 

 
0.5

Income tax expense
2.4

 
3.1

 
0.3

(Loss) income before equity in income of unconsolidated subsidiaries
(2.5
)
 
(3.1
)
 
0.2

Equity in income of unconsolidated subsidiaries
339.7

 
281.2

 
210.0

Net income
$
337.2

 
$
278.1

 
$
210.2

Earnings per common share:
 
 
 
 
 
Basic
$
1.95

 
$
1.63

 
$
1.24

Diluted
$
1.92

 
$
1.60

 
$
1.24

Average common shares outstanding (thousands):
 
 
 
 
 
Basic
172,733

 
170,885

 
168,872

Diluted
175,231

 
173,282

 
170,148


(a)
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,
 
2014
 
2013
 
2012
NET CASH PROVIDED BY OPERATING ACTIVITIES (a)
$
199.7

 
$
139.4

 
$
158.3

 
 
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Net investments in unconsolidated subsidiaries
(47.3
)
 
(59.1
)
 
(54.4
)
Net cash used by investing activities
(47.3
)
 
(59.1
)
 
(54.4
)
 
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Payment of dividends on Common Stock
(136.1
)
 
(125.8
)
 
(119.1
)
Purchases of UGI Common Stock
(39.8
)
 

 

Issuance of Common Stock
23.4

 
44.5

 
16.7

Net cash used by financing activities
(152.5
)
 
(81.3
)
 
(102.4
)
Cash and cash equivalents (decrease) increase
$
(0.1
)
 
$
(1.0
)
 
$
1.5

Cash and cash equivalents:
 
 
 
 
 
End of year
$
0.8

 
$
0.9

 
$
1.9

Beginning of year
0.9

 
1.9

 
0.4

(Decrease) increase
$
(0.1
)
 
$
(1.0
)
 
$
1.5


(a)
Includes dividends received from unconsolidated subsidiaries of $186.4, $155.2 and $156.0 for the years ended September 30, 2014, 2013 and 2012, respectively.
Valuation and Qualifying Accounts
Valuation and Qualifying Accounts
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)

 
Balance at
beginning
of year
 
Charged
(credited)
to costs and
expenses
 
Other
 
Balance at
end of
year
 
Year Ended September 30, 2014
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
39.5

 
$
43.5

 
$
(43.0
)
(1)
$
39.1

 
 
 
 
 
 
(0.9
)
(2)
 
 
Other reserves:
 
 
 
 
 
 
 
 
Deferred tax assets valuation allowance
$
97.6

 
$
0.4

 
$
(34.0
)
(3)
$
59.2

 
 
 
 
 
 
(4.8
)
(4)
 
 
Year Ended September 30, 2013
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
36.1

 
$
30.2

 
$
(27.4
)
(1)
$
39.5

 
 
 
 
 
 
0.6

(2)
 
 
Other reserves:
 
 
 
 
 
 
 
 
Deferred tax assets valuation allowance
$
77.0

 
$
(5.7
)
 
26.3

(3)
$
97.6

 
Year Ended September 30, 2012
 
 
 
 
 
 
 
 
Reserves deducted from assets in the consolidated balance sheet:
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
36.8

 
$
26.5

 
$
(26.8
)
(1)
$
36.1

 
 
 
 
 
 
(0.4
)
(2)
 
 
Other reserves:
 
 
 
 
 
 
 
 
Deferred tax assets valuation allowance
$
78.2

 
$
(4.0
)
 
$
2.8

(5)
$
77.0

 

(1)
Uncollectible accounts written off, net of recoveries.
(2)
Effects of currency exchange.
(3)
Foreign tax credit valuation allowance adjustment.
(4)
Decrease in unusable foreign operating loss carryforwards.
(5)
Acquisition.
Summary of Significant Accounting Policies (Policies)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Accounting Policies [Abstract]
 
 
Basis of Presentation
 
Principles of Consolidation
 
Effects of Regulation
 
Fair Value Measurements
 
Derivative Instruments
 
Foreign Currency Translation
 
Revenue Recognition
 
LPG Delivery Expenses
 
Income Taxes
 
Earnings Per Common Share
 
Comprehensive Income
 
Cash and Cash Equivalents
 
Restricted Cash
 
Inventories
 
Property, Plant and Equipment and Related Depreciation
 
Goodwill and Intangible Assets
 
Impairment of Long-Lived Assets
 
Deferred Debt Issuance Costs
 
Refundable Tank and Cylinder Deposits
 
Environmental Matters
 
Employee Retirement Plans
 
Equity-Based Compensation
 
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.
On July 29, 2014, UGI's Board of Directors approved a three-for-two common stock split. The additional shares were distributed September 5, 2014, to shareholders of record on August 22, 2014. All references to shares and per share amounts have been retroactively adjusted to reflect the three-for-two stock split.
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 public’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, 2014. 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 $77.8 and $82.0 at September 30, 2014 and 2013, respectively (including $17.4 and $16.4, respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
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”) Topic “Regulated Operations.” 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. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. 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 9.
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, also on a nonrecurring basis. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
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.
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 markets that are not active, 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.
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.
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. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments
Derivative instruments are reported in the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exemption under GAAP. 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.
Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative 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. Unrealized gains and losses on certain commodity derivative 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.
Substantially all of Midstream & Marketing’s commodity derivative instruments do not qualify for, or are not designated as, cash flow hedges. In addition, effective April 1, 2014, AmeriGas Propane determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative instruments. Changes in the fair values of these commodity derivative instruments are reflected in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income.
From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.
Cash flows from derivative 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 other information, see Note 18.
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 UGI International 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 UGI International 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 Partnership has 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 taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2014, 2013 and 2012, interest (income) expense recognized in income taxes on the Consolidated Statements of Income was not material.
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 comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
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 principally represents those cash balances in our commodity futures brokerage accounts that 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 10 to 40 years for buildings and improvements; 6 to 40 years for storage and customer tanks and cylinders; 25 to 40 years for electricity generation facilities; 25 to 40 years for pipeline and related assets, and 3 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 10 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 2.3% in Fiscal 2014, 2.3% in Fiscal 2013 and 2.2% in Fiscal 2012. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.5% in Fiscal 2014, 2.4% in Fiscal 2013 and 2.4% in Fiscal 2012. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets.
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 generally not exceeding 10 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. Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets 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 an operating segment or one level below an 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. In accordance with GAAP, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. 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.
Impairment of Long-Lived Assets and Cost Basis Investments
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
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $36.7 and $39.4 at September 30, 2014 and 2013, respectively. We are amortizing these costs over the terms of the related debt.
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 $200.0 and $214.6 at September 30, 2014 and 2013, 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 effects 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 16.
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 8).
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 on 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 14.
Summary of Significant Accounting Policies (Tables)
In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2014, Fiscal 2013 and Fiscal 2012:
(Thousands of shares)
 
2014
 
2013
 
2012
Average common shares outstanding for basic computation
 
172,733

 
170,885

 
168,872

Incremental shares issuable for stock options and common stock awards (a)
 
2,498

 
2,397

 
1,276

Average common shares outstanding for diluted computation
 
175,231

 
173,282

 
170,148


(a)
For Fiscal 2014, Fiscal 2013 and Fiscal 2012, there were approximately 0 shares, 132 shares and 122 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.
Changes in AOCI during Fiscal 2014 are as follows:
 
Postretirement
Benefit
Plans
 
Derivative
Instruments
 
Foreign
Currency
 
Total
AOCI - September 30, 2013
$
(16.4
)
 
$
(26.9
)
 
$
51.7

 
$
8.4

Other comprehensive (loss) income before reclassification adjustments (after-tax)
(5.2
)
 
54.0

 
(43.0
)
 
5.8

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
    Reclassification adjustments (pre-tax)
1.6

 
(47.2
)
 

 
(45.6
)
    Reclassification adjustments tax (expense) benefit
(0.6
)
 
2.0

 

 
1.4

    Reclassification adjustments (after-tax)
1.0

 
(45.2
)
 

 
(44.2
)
Other comprehensive (loss) income
(4.2
)
 
8.8

 
(43.0
)
 
(38.4
)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners

 
8.8

 

 
8.8

Other comprehensive (loss) income attributable to UGI
(4.2
)
 
17.6

 
(43.0
)
 
(29.6
)
AOCI - September 30, 2014
$
(20.6
)
 
$
(9.3
)
 
$
8.7

 
$
(21.2
)
Acquisitions Acquisitions (Tables)
The final allocation of the purchase price to the assets acquired and liabilities assumed for the Heritage Acquisition 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 (a)
 
91.1

Goodwill (a) (b)
 
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

(a)
During Fiscal 2013, the Partnership made correcting adjustments to trademarks and tradenames and goodwill which are not reflected in the table above (see Note 12).
(b)
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 15-year period.
The following presents unaudited Fiscal 2012 pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred at the beginning of the period:
 
 
2012
Revenues
 
$
7,013.0

Net income attributable to UGI Corporation
 
$
208.4

Earnings per common share attributable to UGI Corporation stockholders:
 
 
Basic
 
$
1.23

Diluted
 
$
1.22

Short-term Borrowings (Tables)
Schedule of Short-term Debt
Short-term borrowings are comprised of the following at September 30:
 
2014
 
2013
Credit Agreements:
 
 
 
AmeriGas Propane
$
109.0

 
$
116.9

UGI International
8.0

 
6.5

UGI Utilities
86.3

 
17.5

Energy Services

 
57.0

Energy Services Accounts Receivable Securitization Facility
7.5

 
30.0

Total short-term borrowings
$
210.8

 
$
227.9

Long-term Borrowings (Tables)
Long-term debt comprises the following at September 30:
 
2014
 
2013
AmeriGas Propane:
 
 
 
AmeriGas Partners Senior Notes:
 
 
 
   7.00%, due May 2022
$
980.8

 
$
980.8

   6.75%, due May 2020
550.0

 
550.0

   6.50%, due May 2021
270.0

 
270.0

   6.25%, due August 2019
450.0

 
450.0

HOLP Senior Secured Notes
26.5

 
32.0

Other
14.4

 
17.3

Total AmeriGas Propane
2,291.7

 
2,300.1

UGI International:
 
 
 
Antargaz Senior Facilities term loan, due through March 2016
432.0

 
514.0

Flaga term loan, due September 2016
52.0

 
52.0

Flaga term loan, due through September 2016
50.5

 
54.1

Flaga term loan, due October 2016
24.1

 
25.8

Flaga term loan, due through June 2014

 
1.9

Other
6.4

 
6.6

Total UGI International
565.0

 
654.4

UGI Utilities:
 
 
 
Term Loan Credit Agreement

 
175.0

Senior Notes:
 
 
 
5.75%, due September 2016
175.0

 
175.0

4.98%, due March 2044
175.0

 

6.21%, due September 2036
100.0

 
100.0

Medium-Term Notes:
 
 
 
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
642.0

 
642.0

Other
12.1

 
12.9

Total long-term debt
3,510.8

 
3,609.4

Less: current maturities
(77.2
)
 
(67.2
)
Total long-term debt due after one year
$
3,433.6

 
$
3,542.2

Scheduled principal repayments of long-term debt due in fiscal years 2015 to 2019 follow:

 
2015
 
2016
 
2017
 
2018
 
2019
AmeriGas Propane
$
11.0

 
$
7.6

 
$
5.6

 
$
4.9

 
$
454.5

UGI Utilities
20.0

 
247.0

 
20.0

 
40.0

 

UGI International
45.0

 
492.9

 
25.4

 
0.9

 
0.7

Other
0.7

 
0.7

 
0.7

 
0.8

 
0.8

Total
$
76.7

 
$
748.2

 
$
51.7

 
$
46.6

 
$
456.0

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

 
2014
 
2013
 
2012
Domestic
$
699.2

 
$
494.1

 
$
245.6

Foreign
68.6

 
96.3

 
59.0

Total income before income taxes
$
767.8

 
$
590.4

 
$
304.6

The provisions for income taxes consist of the following:

 
2014
 
2013
 
2012
Current expense (benefit):
 
 
 
 
 
Federal
$
102.4

 
$
53.3

 
$
(10.4
)
State
30.7

 
25.1

 
11.2

Foreign
37.0

 
37.3

 
18.8

Investment tax credit
(1.6
)
 
(1.6
)
 
(2.9
)
Total current expense
168.5

 
114.1

 
16.7

Deferred expense (benefit):
 
 
 
 
 
Federal
61.9

 
54.6

 
81.7

State
7.8

 
(0.7
)
 
7.0

Foreign
(2.7
)
 
(4.9
)
 
1.8

Investment tax credit amortization
(0.3
)
 
(0.3
)
 
(0.3
)
Total deferred expense
66.7

 
48.7

 
90.2

Total income tax expense
$
235.2

 
$
162.8

 
$
106.9

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

 
2014
 
2013
 
2012
U.S. federal statutory tax rate
35.0
 %
 
35.0
 %
 
35.0
 %
Difference in tax rate due to:
 
 
 
 
 
Noncontrolling interests not subject to tax
(9.0
)
 
(8.7
)
 
1.2

State income taxes, net of federal benefit
3.4

 
3.4

 
4.0

Valuation allowance adjustments

 
(0.5
)
 
(1.5
)
Effects of foreign operations
1.0

 
(1.8
)
 
(3.3
)
Other, net
0.2

 
0.2

 
(0.3
)
Effective tax rate
30.6
 %
 
27.6
 %
 
35.1
 %
Deferred tax liabilities (assets) comprise the following at September 30:
 
2014
 
2013
Excess book basis over tax basis of property, plant and equipment
$
675.7

 
$
626.9

Investment in AmeriGas Partners
325.1

 
313.0

Intangible assets and goodwill
53.0

 
65.1

Utility regulatory assets
110.0

 
101.6

Foreign currency translation adjustment

 
9.5

Other
3.5

 
2.7

Gross deferred tax liabilities
1,167.3

 
1,118.8

 
 
 
 
Pension plan liabilities
(40.6
)
 
(36.2
)
Employee-related benefits
(48.8
)
 
(47.9
)
Operating loss carryforwards
(27.9
)
 
(32.1
)
Foreign tax credit carryforwards
(47.8
)
 
(81.8
)
Utility regulatory liabilities
(14.8
)
 
(15.5
)
Foreign currency translation adjustment
(14.1
)
 

Derivative instruments
(11.0
)
 
(15.0
)
Other
(13.0
)
 
(20.5
)
Gross deferred tax assets
(218.0
)
 
(249.0
)
Deferred tax assets valuation allowance
59.2

 
97.6

Net deferred tax liabilities
$
1,008.5

 
$
967.4

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
 
2014
 
2013
 
2012
Unrecognized tax benefits - beginning of year
$
3.4

 
$
2.9

 
$
6.3

Additions for tax positions of the current year
0.7

 
0.7

 
0.5

Additions for tax positions taken in prior years

 

 
0.6

Settlements with tax authorities
(1.7
)
 
(0.2
)
 
(4.5
)
Unrecognized tax benefits - end of year
$
2.4

 
$
3.4

 
$
2.9

Employee Retirement Plans (Tables)
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, 2014 and 2013. 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
 
2014
 
2013
 
2014
 
2013
Change in benefit obligations:
 
 
 
 
 
 
 
Benefit obligations — beginning of year
$
516.5

 
$
573.4

 
$
19.7

 
$
24.7

Service cost
9.4

 
11.3

 
0.5

 
0.6

Interest cost
26.1

 
23.8

 
0.9

 
0.9

Actuarial (gain) loss
46.8

 
(72.7
)
 
1.3

 
(3.6
)
Plan amendments

 
1.0

 

 
(1.8
)
Foreign currency
(2.4
)
 
1.5

 
(0.3
)
 
0.2

Benefits paid
(22.8
)
 
(21.8
)
 
(0.8
)
 
(1.3
)
Benefit obligations — end of year
$
573.6

 
$
516.5

 
$
21.3

 
$
19.7

 
 
 
 
 
 
 
 
Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets — beginning of year
$
415.3

 
$
369.9

 
$
11.7

 
$
11.2

Actual gain on plan assets
47.9

 
42.2

 
1.4

 
1.1

Foreign currency
(1.2
)
 
0.8

 

 

Employer contributions
20.2

 
24.2

 
0.5

 
0.7

Benefits paid
(22.8
)
 
(21.8
)
 
(0.8
)
 
(1.3
)
Fair value of plan assets — end of year
$
459.4

 
$
415.3

 
$
12.8

 
$
11.7

Funded status of the plans — end of year
$
(114.2
)
 
$
(101.2
)
 
$
(8.5
)
 
$
(8.0
)
 
 
 
 
 
 
 
 
Assets (liabilities) recorded in the balance sheet:
 
 
 
 
 
 
 
Assets in excess of liabilities — included in other noncurrent assets
$

 
$

 
$
4.0

 
$
3.2

Unfunded liabilities — included in other current liabilities
(1.1
)
 
(17.9
)
 
(0.1
)
 
(0.4
)
Unfunded liabilities — included in other noncurrent liabilities
(113.1
)
 
(83.3
)
 
(12.4
)
 
(10.8
)
Net amount recognized
$
(114.2
)
 
$
(101.2
)
 
$
(8.5
)
 
$
(8.0
)
 
 
 
 
 
 
 
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
 
 
 
 
Prior service credit
$
(0.1
)
 
$
(0.1
)
 
$
(0.1
)
 
$
(0.1
)
Net actuarial loss (gain)
20.8

 
16.7

 
0.8

 
(0.4
)
Total
$
20.7

 
$
16.6

 
$
0.7

 
$
(0.5
)
 
 
 
 
 
 
 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
1.9

 
$
2.2

 
$
(3.6
)
 
$
(4.3
)
Net actuarial loss
107.4

 
91.3

 
2.6

 
3.6

Total
$
109.3

 
$
93.5

 
$
(1.0
)
 
$
(0.7
)
The expected rate of return on assets assumption is based on 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
 
 
2014
 
2013
 
2012
 
 
2014
 
2013
 
2012
 
Weighted-average assumptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate - benefit obligations
4.60
%
 
5.20
%
 
4.20
%
 
 
4.60
%
 
5.10% - 5.40%

 
4.10% - 4.30%

 
Discount rate - benefit cost
5.20
%
 
4.20
%
 
5.30
%
 
 
5.10% - 5.40%

 
4.10% - 4.30%

 
5.30
%
 
Expected return on plan assets
7.75
%
 
7.75
%
 
7.75
%
 
 
5.00
%
 
5.00
%
 
5.20
%
 
Rate of increase in salary levels
3.25
%
 
3.25
%
 
3.25
%
 
 
3.25
%
 
3.25
%
 
3.25
%
 

Net periodic pension expense and other postretirement benefit cost includes the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Service cost
$
9.4

 
$
11.3

 
$
9.3

 
$
0.5

 
$
0.6

 
$
0.4

Interest cost
26.1

 
23.8

 
25.1

 
0.9

 
0.9

 
1.1

Expected return on assets
(29.7
)
 
(27.8
)
 
(26.2
)
 
(0.6
)
 
(0.5
)
 
(0.5
)
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
0.3

 
0.3

 
0.2

 
(0.5
)
 
(0.3
)
 
(0.3
)
Actuarial loss
7.7

 
15.1

 
8.4

 

 
0.4

 
0.3

Net benefit cost
13.8

 
22.7

 
16.8

 
0.3

 
1.1

 
1.0

Change in associated regulatory liabilities

 

 

 
3.7

 
3.3

 
3.2

Net benefit cost after change in regulatory liabilities
$
13.8

 
$
22.7

 
$
16.8

 
$
4.0

 
$
4.4

 
$
4.2

Expected payments for pension and other postretirement welfare benefits are as follows:
 
Pension
Benefits
 
Other
Postretirement
Benefits
Fiscal 2015
$
25.6

 
$
1.1

Fiscal 2016
$
25.8

 
$
1.1

Fiscal 2017
$
27.2

 
$
1.0

Fiscal 2018
$
30.3

 
$
1.0

Fiscal 2019
$
32.6

 
$
1.0

Fiscal 2020 - 2024
$
175.1

 
$
4.9

 
2014
 
2013
Health care cost trend rate assumed for next year
7.0
%
 
7.5
%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
5.0
%
 
5.0
%
Fiscal year that the rate reaches the ultimate trend rate
2019

 
2019

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
 
2014
 
2013
 
 
Equity investments:
 
 
 
 
 
 
 
Domestic
55.6
%
 
57.5
%
 
52.5
%
 
40.0% - 65.0%
International
11.3
%
 
11.1
%
 
12.5
%
 
7.5% - 17.5%
Total
66.9
%
 
68.6
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
33.1
%
 
31.4
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 

VEBA
 
Actual
 
Target
Asset
Allocation
 
Permitted
Range
 
2014
 
2013
 
 
Domestic equity investments
67.9
%
 
65.6
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
32.1
%
 
34.4
%
 
35.0
%
 
30.0% - 40.0%
Total
100.0
%
 
100.0
%
 
100.0
%
 
 
The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2014 and 2013 are as follows:
 
U.S. Pension Plan
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
Domestic equity investments:
 
 
 
 
 
 
 
   S&P 500 Index equity mutual funds
$
152.6

 
$

 
$

 
$
152.6

   Small and midcap equity mutual funds
41.4

 

 

 
41.4

   Smallcap common stocks
9.3

 

 

 
9.3

   UGI Corporation Common Stock
42.5

 

 

 
42.5

       Total domestic equity investments
245.8

 

 

 
245.8

International index equity mutual funds
49.9

 

 

 
49.9

Fixed income investments:
 
 
 
 
 
 
 
   Bond index mutual funds
141.0

 

 

 
141.0

   Cash equivalents

 
5.7

 

 
5.7

     Total fixed income investments
141.0

 
5.7

 

 
146.7

Total
$
436.7

 
$
5.7

 
$

 
$
442.4

 
 
 
 
 
 
 
 
September 30, 2013:
 
 
 
 
 
 
 
Domestic equity investments:
 
 
 
 
 
 
 
   S&P 500 Index equity mutual funds
$
141.8

 
$

 
$

 
$
141.8

   Small and midcap equity mutual funds
54.5

 

 

 
54.5

    UGI Corporation Common Stock
32.6

 

 

 
32.6

       Total domestic equity investments
228.9

 

 

 
228.9

International index equity mutual funds
44.4

 

 

 
44.4

Fixed income investments:
 
 
 
 
 
 
 
   Bond index mutual funds
120.9

 

 

 
120.9

   Cash equivalents

 
4.0

 

 
4.0

     Total fixed income investments
120.9

 
4.0

 

 
124.9

Total
$
394.2

 
$
4.0

 
$

 
$
398.2

 
VEBA
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
8.7

 
$

 
$

 
$
8.7

Bond index mutual fund
3.7

 

 

 
3.7

Cash equivalents

 
0.4

 

 
0.4

Total
$
12.4

 
$
0.4

 
$

 
$
12.8

 
 
 
 
 
 
 
 
September 30, 2013:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
7.7

 
$

 
$

 
$
7.7

Bond index mutual fund
3.8

 

 

 
3.8

Cash equivalents

 
0.2

 

 
0.2

Total
$
11.5

 
$
0.2

 
$

 
$
11.7

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)
Regulatory Assets and Liabilities Associated with Utilities
The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:
 
2014
 
2013
Regulatory assets:
 
 
 
Income taxes recoverable
$
110.7

 
$
106.1

Underfunded pension and postretirement plans
110.1

 
94.5

Environmental costs
14.6

 
17.1

Deferred fuel and power costs
11.8

 
8.3

Removal costs, net
16.8

 
13.3

Other
4.2

 
5.6

Total regulatory assets
$
268.2

 
$
244.9

Regulatory liabilities (a):
 
 
 
Postretirement benefits
$
18.6

 
$
16.5

Environmental overcollections
0.3

 
2.6

Deferred fuel and power refunds
0.3

 
8.3

State tax benefits — distribution system repairs
10.1

 
8.4

Other
3.2

 
1.5

Total regulatory liabilities
$
32.5

 
$
37.3

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

 
2014
 
2013
Non-utility LPG and natural gas
$
283.6

 
$
230.0

Gas Utility natural gas
82.7

 
78.9

Materials, supplies and other
56.7

 
56.6

Total inventories
$
423.0

 
$
365.5

Property, Plant and Equipment (Tables)
Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
 
2014
 
2013
Utilities:
 
 
 
Distribution
$
2,294.6

 
$
2,162.6

Transmission
88.2

 
86.6

General and other, including work in process
185.7

 
178.6

Total Utilities
2,568.5

 
2,427.8

 
 
 
 
Non-utility:
 
 
 
Land
170.2

 
178.4

Buildings and improvements
317.4

 
308.1

Transportation equipment
288.4

 
273.8

Equipment, primarily cylinders and tanks
3,042.7

 
3,161.9

Electric generation
273.4

 
264.8

Pipeline and related assets
162.3

 
22.5

Other, including work in process
353.8

 
403.2

Total non-utility
4,608.2

 
4,612.7

Total property, plant and equipment
$
7,176.7

 
$
7,040.5

Goodwill and Intangible Assets (Tables)
Changes in the carrying amount of goodwill by reportable segment are as follows:
 
 
 
 
 
 
 
UGI International
 
 
 
 
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Antargaz
 
Flaga & Other
 
Corporate &
Other
 
Total
Balance September 30, 2012
$
1,919.2

 
$
182.1

 
$
2.8

 
$
612.0

 
$
95.2

 
$
7.0

 
$
2,818.3

Acquisitions
12.5

 

 

 

 

 

 
12.5

Correcting adjustment
9.3

 

 

 

 

 

 
9.3

Foreign currency translation

 

 

 
31.7

 
1.9

 

 
33.6

Balance September 30, 2013
1,941.0

 
182.1

 
2.8

 
643.7

 
97.1

 
7.0

 
2,873.7

Acquisitions
6.8

 

 
2.8

 

 

 

 
9.6

Purchase accounting adjustments
(2.7
)
 

 

 

 
0.9

 

 
(1.8
)
Foreign currency translation

 

 

 
(42.5
)
 
(5.6
)
 

 
(48.1
)
Balance September 30, 2014
$
1,945.1

 
$
182.1

 
$
5.6

 
$
601.2

 
$
92.4

 
$
7.0

 
$
2,833.4

Intangible assets comprise the following at September 30:
 
2014
 
2013
Customer relationships, noncompete agreements and other
$
712.0

 
$
704.8

Trademarks and tradenames (not subject to amortization)
128.2

 
130.2

Gross carrying amount
840.2

 
835.0

Accumulated amortization
(263.8
)
 
(227.1
)
Intangible assets, net
$
576.4

 
$
607.9

Common Stock and Equity Based Compensation (Tables)
UGI Common Stock share activity for Fiscal 2012, Fiscal 2013 and Fiscal 2014 follows:
 
Issued
 
Treasury
 
Outstanding
Balance, September 30, 2011
173,260,641

 
(5,506,608
)
 
167,754,033

Issued:
 
 
 
 
 
Employee and director plans
176,250

 
1,237,388

 
1,413,638

Dividend reinvestment plan

 
157,491

 
157,491

Shares reacquired - employee and director plans

 
(394,530
)
 
(394,530
)
Balance, September 30, 2012
173,436,891

 
(4,506,259
)
 
168,930,632

Issued:
 
 
 
 
 
Employee and director plans
238,800

 
3,933,507

 
4,172,307

Dividend reinvestment plan

 
93,253

 
93,253

Shares reacquired - employee and director plans

 
(1,552,905
)
 
(1,552,905
)
Balance, September 30, 2013
173,675,691

 
(2,032,404
)
 
171,643,287

Issued:
 
 
 
 
 
Employee and director plans
94,950

 
2,928,140

 
3,023,090

Repurchases of Common Stock

 
(1,227,654
)
 
(1,227,654
)
Shares reacquired - employee and director plans

 
(1,164,942
)
 
(1,164,942
)
Balance, September 30, 2014
173,770,641

 
(1,496,860
)
 
172,273,781

Stock option transactions under equity-based compensation plans during Fiscal 2012, Fiscal 2013 and Fiscal 2014 follow:
 
Shares
 
Weighted
Average
Option Price
 
Total
Intrinsic
Value
 
Weighted
Average
Contract Term
(Years)
Shares under option — September 30, 2011
11,509,769

 
$
17.03

 
$
15.1

 
6.2
Granted
2,262,075

 
$
19.51

 
 
 
 
Cancelled
(482,400
)
 
$
18.49

 
 
 
 
Exercised
(1,202,786
)
 
$
13.95

 
$
7.2

 
 
Shares under option — September 30, 2012
12,086,658

 
$
17.75

 
$
41.4

 
6.1
Granted
2,275,350

 
$
22.38

 
 
 
 
Cancelled
(134,754
)
 
$
20.34

 
 
 
 
Exercised
(4,033,302
)
 
$
16.39

 
$
35.4

 
 
Shares under option — September 30, 2013
10,193,952

 
$
19.28

 
$
69.6

 
6.8
Granted
1,665,600

 
$
27.93

 
 
 
 
Cancelled
(86,707
)
 
$
22.76

 
 
 
 
Exercised
(2,815,555
)
 
$
17.44

 
$
37.4

 
 
Shares under option — September 30, 2014
8,957,290

 
$
21.44

 
$
113.3

 
7.0
Options exercisable — September 30, 2012
7,976,547

 
$
16.88

 
 
 
 
Options exercisable — September 30, 2013
5,871,091

 
$
17.95

 
 
 
 
Options exercisable — September 30, 2014
5,073,347

 
$
19.45

 
$
74.2

 
6.0
Options not exercisable — September 30, 2014
3,883,943

 
$
24.02

 
$
39.1

 
8.5
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2014:

 
Range of exercise prices
 
Under
$15.00
 
$15.01 -
$20.00
 
$20.01 -
$25.00
 
Over
$25.00
Options outstanding at September 30, 2014:
 
 
 
 
 
 
 
Number of options
102,000

 
3,452,480

 
3,500,910

 
1,901,900

Weighted average remaining contractual life (in years)
1.4

 
5.7

 
7.2

 
9.2

Weighted average exercise price
$
14.47

 
$
18.15

 
$
21.45

 
$
27.74

Options exercisable at September 30, 2014:
 
 
 
 
 
 
 
Number of options
102,000

 
2,727,509

 
2,077,840

 
165,998

Weighted average exercise price
$
14.47

 
$
17.81

 
$
21.27

 
$
26.85

The assumptions we used for valuing option grants during Fiscal 2014, Fiscal 2013 and Fiscal 2012 are as follows:

 
2014
 
2013
 
2012
Expected life of option
5.75 years
 
5.75 years
 
5.75 years
Weighted average volatility
24.3%
 
24.9%
 
24.7%
Weighted average dividend yield
2.9%
 
3.6%
 
3.5%
Expected volatility
23.7% - 24.4%
 
24.4% - 24.9%
 
24.7%
Expected dividend yield
2.7% - 2.9%
 
3.2% - 3.7%
 
3.3% - 3.7%
Risk free rate
1.8% - 2.0%
 
0.8% - 1.7%
 
0.8% - 1.1%
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
 
2014
 
2013
 
2012
Risk free rate
0.8
%
 
0.4
%
 
0.4
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
20.3
%
 
21.1
%
 
22.2
%
Dividend yield
2.7
%
 
3.3
%
 
3.5
%
The following table summarizes UGI Unit award activity for Fiscal 2014:
 
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, 2013
1,380,902

 
$
18.35

 
822,975

 
$
15.45

 
557,927

 
$
22.62

UGI Performance Units:
 
 
 
 
 
 
 
 
 
 
 
Granted
189,450

 
$
32.32

 
9,570

 
$
32.02

 
179,880

 
$
32.33

Forfeited
(7,200
)
 
$
24.95

 

 
$

 
(7,200
)
 
$
24.95

Vested

 
$

 
205,282

 
$
21.15

 
(205,282
)
 
$
21.15

Unit awards paid
(267,146
)
 
$
22.17

 
(267,146
)
 
$
22.17

 

 
$

UGI Stock Units:
 
 
 
 
 
 
 
 
 
 
 
Granted (a)
44,814

 
$
27.41

 
43,689

 
$
27.35

 
1,125

 
$
29.84

Vested

 
$

 
1,500

 
$
22.29

 
(1,500
)
 
$
22.29

Unit awards paid
(34,639
)
 
$
14.41

 
(34,639
)
 
$
14.41

 

 
$

September 30, 2014
1,306,181

 
$
20.58

 
781,231

 
$
16.60

 
524,950

 
$
26.51

(a)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2013 and Fiscal 2012 were 51,038 and 63,668, respectively.
During Fiscal 2014, Fiscal 2013 and Fiscal 2012, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
 
2014
 
2013
 
2012
UGI Performance Unit awards:
 
 
 
 
 
Number of original awards granted
331,038

 
328,025

 
316,125

Fiscal year granted
2011

 
2010

 
2009

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
174,168

 
97,622

 

Cash paid
$
3.1

 
$
1.6

 
$

UGI Stock Unit awards:
 
 
 
 
 
Number of original awards granted
34,639

 
54,269

 
49,347

Payment of awards:
 
 
 
 
 
Shares of UGI Common Stock issued
22,604

 
35,274

 
32,636

Cash paid
$
0.4

 
$
0.5

 
$
0.2

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
 
2014
 
2013
 
2012
Risk-free rate
0.8
%
 
0.4
%
 
0.4
%
Expected life
3 years

 
3 years

 
3 years

Expected volatility
21.1
%
 
20.7
%
 
23.0
%
Dividend yield
7.5
%
 
8.2
%
 
6.4
%
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2014:
 
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, 2013
224,167

 
$
47.88

 
47,715

 
$
47.92

 
176,452

 
$
47.87

AmeriGas Performance Units:


 


 


 


 


 


  Granted
53,800

 
$
41.50

 
633

 
$
41.37

 
53,167

 
$
41.50

  Forfeited
(8,150
)
 
$
45.96

 

 
$

 
(8,150
)
 
$
45.96

  Vested

 
$

 
15,319

 
$
53.93

 
(15,319
)
 
$
53.93

  Performance criteria not met
(31,317
)
 
$
54.51

 
(31,317
)
 
$
54.51

 

 
$

AmeriGas Stock Units:
 
 
 
 
 
 
 
 
 
 
 
  Granted
32,658

 
$
46.37

 
15,936

 
$
48.00

 
16,722

 
$
44.81

  Forfeited
(7,783
)
 
$
51.10

 

 
$

 
(7,783
)
 
$
(51.10
)
  Vested

 
$

 
52,061

 
$
47.58

 
(52,061
)
 
$
47.58

  Awards paid
(63,140
)
 
$
48.00

 
(63,140
)
 
$
48.00

 

 
$

September 30, 2014
200,235

 
$
44.82

 
37,207

 
$
44.27

 
163,028

 
$
44.95

During Fiscal 2014, Fiscal 2013 and Fiscal 2012, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:
 
2014
 
2013
 
2012
AmeriGas Performance Unit awards:
 
 
 
 
 
Number of Common Units subject to original awards granted
41,251

 
48,150

 
53,600

Fiscal year granted
2011

 
2010

 
2009

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued

 

 

Cash paid
$

 
$

 
$

AmeriGas Stock Unit awards:
 
 
 
 
 
Number of Common Units subject to original awards granted
72,023

 
35,934

 
67,246

Payment of awards:
 
 
 
 
 
AmeriGas Partners Common Units issued
40,842

 
23,192

 
44,016

Cash paid
$
1.4

 
$
0.6

 
$
1.0



Commitments and Contingencies (Tables)
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
 
2015
 
2016
 
2017
 
2018
 
2019
 
After 2019
AmeriGas Propane
$
56.2

 
$
46.6

 
$
36.5

 
$
30.6

 
$
25.9

 
$
63.0

UGI Utilities
6.7

 
6.2

 
4.5

 
3.7

 
1.4

 
0.7

UGI International
7.8

 
6.1

 
4.4

 
2.0

 
0.4

 
0.5

Other
1.9

 
1.8

 
0.9

 
0.6

 
0.4

 
0.3

Total
$
72.6

 
$
60.7

 
$
46.3

 
$
36.9

 
$
28.1

 
$
64.5

The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and UGI International supply, storage and service contracts existing at September 30, 2014:
 
2015
 
2016
 
2017
 
2018
 
2019
 
After 2019
UGI Utilities supply, storage and transportation contracts
$
156.9

 
$
66.8

 
$
44.9

 
$
30.8

 
$
23.6

 
$
66.4

Midstream & Marketing supply contracts
302.1

 
107.0

 
42.1

 
4.3

 

 

AmeriGas Propane supply contracts
130.8

 
74.3

 

 

 

 

UGI International supply contracts
144.7

 
72.8

 

 

 

 

Total
$
734.5

 
$
320.9

 
$
87.0

 
$
35.1

 
$
23.6

 
$
66.4

Fair Value Measurement (Tables)
Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2014 and 2013:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2014:
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
10.6

 
$
19.8

 
$

 
$
30.4

Foreign currency contracts
$

 
$
12.8

 
$

 
$
12.8

Cross-currency swaps
$

 
$
2.1

 
$

 
$
2.1

Interest rate contracts
$

 
$
0.1

 
$

 
$
0.1

   Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(21.2
)
 
$
(32.9
)
 
$

 
$
(54.1
)
Foreign currency contracts
$

 
$
(0.1
)
 
$

 
$
(0.1
)
Interest rate contracts
$

 
$
(21.0
)
 
$

 
$
(21.0
)
 
 
 
 
 
 
 
 
Non-qualified supplemental postretirement grantor trust investments (a)
$
30.0

 
$

 
$

 
$
30.0

 
 
 
 
 
 
 
 
September 30, 2013 (b):
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2.6

 
$
22.8

 
$

 
$
25.4

Foreign currency contracts
$

 
$
0.9

 
$

 
$
0.9

  Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(8.8
)
 
$
(9.3
)
 
$

 
$
(18.1
)
Foreign currency contracts
$

 
$
(7.2
)
 
$

 
$
(7.2
)
Interest rate contracts
$

 
$
(31.0
)
 
$

 
$
(31.0
)
Cross-currency swaps
$

 
$
(1.2
)
 
$

 
$
(1.2
)
 
 
 
 
 
 
 
 
Non-qualified supplemental postretirement grantor trust investments (a)
$
27.1

 
$

 
$

 
$
27.1


(a)
Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8).
(b)
Certain immaterial amounts have been revised to correct the classification of derivatives.
Derivative Instruments and Hedging Activities (Tables)
The following table presents our derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30, 2014 and 2013:

 
2014
 
2013 (a)
Derivative assets:
 
 
 
Derivatives designated as hedging instruments:
 
 
 
Commodity contracts
$
2.8

 
$
18.0

Foreign currency contracts
12.8

 
0.9

Cross-currency contracts
2.1

 

Interest rate contracts
0.1

 

 
17.8

 
18.9

Derivatives accounted for under ASC 980:
 
 
 
Commodity contracts
1.7

 

Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
25.9

 
7.4

Total derivative assets - gross
45.4

 
26.3

Gross amounts offset in the balance sheet
(18.4
)
 
(2.1
)
Total derivative assets - net
$
27.0

 
$
24.2

 
 
 
 
Derivative liabilities:
 
 
 
Derivatives designated as hedging instruments:
 
 
 
Commodity contracts
$
(5.3
)
 
$
(4.5
)
Foreign currency contracts
(0.1
)
 
(7.2
)
Cross-currency contracts

 
(1.2
)
Interest rate contracts
(21.0
)
 
(31.0
)
 
(26.4
)
 
(43.9
)
Derivatives accounted for under ASC 980:
 
 
 
Commodity contracts
(2.2
)
 
(6.7
)
Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
(46.6
)
 
(6.9
)
Total derivative liabilities - gross
(75.2
)
 
(57.5
)
Gross amounts offset in the balance sheet
18.4

 
2.1

Total derivative liabilities - net
$
(56.8
)
 
$
(55.4
)

(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.
The following tables provide information on the effects of derivative instruments in the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2014, 2013 and 2012:
 
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
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
50.8

 
$
8.3

 
$
(98.0
)
 
$
67.0

 
$
(49.5
)
 
$
(61.4
)
 
Cost of sales
Foreign currency contracts
15.3

 
(8.3
)
 
(0.5
)
 
(3.7
)
 
(0.1
)
 
2.1

 
Cost of sales
Cross-currency contracts
3.1

 
(1.2
)
 

 
(0.1
)
 

 

 
Interest expense
Interest rate contracts
(3.1
)
 
22.9

 
(36.8
)
 
(15.9
)
 
(14.2
)
 
(11.5
)
 
Interest expense /other income, net
Total
$
66.1

 
$
21.7

 
$
(135.3
)
 
$
47.3

 
$
(63.8
)
 
$
(70.8
)
 
 
Net Investment Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign currency contracts
$

 
$

 
$
0.6

 
 
 
 
 
 
 
 

 
Gain or (Loss)
Recognized in Income
Location of
Gain or (Loss)
Recognized in Income
 
 
2014
 
2013
 
2012
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(36.3
)
 
$
9.3

 
$
0.1

Cost of sales
 
Commodity contracts

 

 
0.2

Operating and administrative expenses / other income, net
 
Foreign currency contracts

 
(0.4
)
 
0.5

Other income, net
 
Total
$
(36.3
)
 
$
8.9

 
$
0.8

 
 
Other Income Net (Tables)
Other Income, Net
Other income, net, comprises the following:
 
2014
 
2013
 
2012
Interest and interest-related income
$
3.6

 
$
2.2

 
$
2.4

Utility non-tariff service income
2.7

 
2.8

 
2.7

Finance charges
17.5

 
21.4

 
18.8

Gains on sales of fixed assets
5.4

 
1.4

 
1.9

Loss on private equity partnership investment

 
(6.3
)
 

Other, net
6.9

 
11.3

 
14.0

Total other income, net
$
36.1

 
$
32.8

 
$
39.8

Quarterly Data (unaudited) (Tables)
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,
 
2013(a)
2012
 
2014
2013
 
2014
2013
 
2014
2013 (b)
Revenues
$
2,315.9

$
2,018.7

 
$
3,163.3

$
2,542.7

 
$
1,486.7

$
1,374.3

 
$
1,311.4

$
1,259.0

Operating income (loss)
$
363.7

$
294.2

 
$
588.6

$
507.7

 
$
62.7

$
41.5

 
$
(9.4
)
$
(12.3
)
Net income (loss)
$
217.5

$
167.8

 
$
387.8

$
341.7

 
$
(12.7
)
$
(22.8
)
 
$
(60.0
)
$
(59.1
)
Net income (loss) attributable to UGI Corporation
$
122.0

$
102.5

 
$
214.4

$
180.7

 
$
20.6

$
9.1

 
$
(19.8
)
$
(14.2
)
Earnings (loss) per common share attributable to UGI Corporation stockholders:
 
 
 
 
 
 
 
 
 
 
 
Basic
$
0.71

$
0.60

 
$
1.24

$
1.06

 
$
0.12

$
0.05

 
$
(0.11
)
$
(0.08
)
Diluted
$
0.70

$
0.60

 
$
1.22

$
1.05

 
$
0.12

$
0.05

 
$
(0.11
)
$
(0.08
)
(a)
Includes income tax expense of $5.7 to reflect the retroactive effects to Fiscal 2013 of new tax legislation in France regarding the deductibility of certain interest expense which decreased net income attributable to UGI Corporation by $5.7 or $0.03 per diluted share (see Note 7).
(b)
Includes impairment loss on private equity partnership investment which increased operating loss by $6.3 and net loss attributable to UGI Corporation by $3.7 or $0.02 per share (see Note 2).
Segment Information (Tables)
Segment Information
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
8,277.3

 
$
(321.3
)
(c)
$
3,712.9

 
$
977.3

 
$
1,305.5

 
$
85.1

 
$
1,295.5

 
$
1,026.9

 
$
195.4

Cost of sales
$
5,175.7

 
$
(317.7
)
(c)
$
2,107.1

 
$
496.8

 
$
1,058.8

 
$
39.6

 
$
848.1

 
$
809.9

 
$
133.1

Operating income (loss)
$
1,005.6

 
$
0.2

 
$
472.0

 
$
236.2

 
$
180.5

 
$
18.1

 
$
79.1

 
$
38.4

 
$
(18.9
)
Loss from equity investees
(0.1
)
 

 

 

 

 

 
(0.1
)
 

 

Interest expense
(237.7
)
 

 
(165.6
)
 
(36.6
)
 
(2.9
)
 

 
(25.1
)
 
(4.9
)
 
(2.6
)
Income (loss) before income taxes
$
767.8

 
$
0.2

 
$
306.4

 
$
199.6

 
$
177.6

 
$
18.1

 
$
53.9

 
$
33.5

 
$
(21.5
)
Net income (loss) attributable to UGI
$
337.2

 
$

 
$
63.0

 
$
118.8

 
$
105.2

 
$
12.6

 
$
20.6

 
$
27.7

 
$
(10.7
)
Depreciation and amortization
$
362.9

 
$

 
$
197.2

 
$
54.8

 
$
12.3

 
$
10.7

 
$
54.5

 
$
27.1

 
$
6.3

Noncontrolling interests’ net income (loss)
$
195.4

 
$

 
$
195.8

 
$

 
$

 
$

 
$
(0.4
)
 
$

 
$

Partnership EBITDA (a)
$
655.3

 
$

 
$
664.8

 
$

 
$

 
$

 
$

 
$

 
$
(9.5
)
Total assets
$
10,093.0

 
$
(86.5
)
 
$
4,377.0

 
$
2,214.1

 
$
569.0

 
$
277.7

 
$
1,659.1

 
$
643.6

 
$
439.0

Short-term borrowings
$
210.8

 
$

 
$
109.0

 
$
86.3

 
$
7.5

 
$

 
$

 
$
8.0

 
$

Capital expenditures
$
436.4

 
$

 
$
113.9

 
$
156.4

 
$
67.8

 
$
15.6

 
$
50.2

 
$
23.0

 
$
9.5

Investments in equity investees
$
0.6

 
$

 
$

 
$

 
$

 
$

 
$

 
$
0.6

 
$

Goodwill
$
2,833.4

 
$

 
$
1,945.1

 
$
182.1

 
$
5.6

 
$

 
$
601.2

 
$
92.4

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate &
Other (b)
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
7,194.7

 
$
(223.8
)
(c)
$
3,168.8

 
$
839.0

 
$
969.4

 
$
71.4

 
$
1,322.6

 
$
856.6

 
$
190.7

Cost of sales
$
4,324.4

 
$
(217.5
)
(c)
$
1,657.2

 
$
407.2

 
$
836.9

 
$
39.9

 
$
845.0

 
$
653.4

 
$
102.3

Operating income
$
831.1

 
$
(1.1
)
 
$
394.4

 
$
196.5

 
$
82.5

 
$
7.5

 
$
111.4

 
$
35.6

 
$
4.3

Loss from equity investees
(0.4
)
 

 

 

 

 

 
(0.4
)
 

 

Interest expense
(240.3
)
 

 
(166.6
)
 
(37.4
)
 
(3.2
)
 

 
(25.3
)
 
(5.1
)
 
(2.7
)
Income before income taxes
590.4

 
(1.1
)
 
227.8

 
159.1

 
79.3

 
7.5

 
85.7

 
30.5

 
1.6

Net income attributable to UGI
$
278.1

 
$
(0.6
)
 
$
47.5

 
$
94.3

 
$
46.3

 
$
6.2

 
$
57.2

 
$
25.5

 
$
1.7

Depreciation and amortization
$
363.1

 
$

 
$
205.9

 
$
51.7

 
$
7.6

 
$
10.0

 
$
57.6

 
$
24.1

 
$
6.2

Noncontrolling interests’ net (loss) income
$
149.5

 
$

 
$
149.6

 
$

 
$

 
$

 
$
(0.2
)
 
$
0.1

 
$

Partnership EBITDA (a)
 

 


 
$
596.5

 


 


 


 


 


 


Total assets
$
10,008.8

 
$
(100.3
)
 
$
4,429.3

 
$
2,069

 
$
501.2

 
$
269.7

 
$
1,784.4

 
$
667.1

 
$
388.4

Short-term borrowings
$
227.9

 
$

 
$
116.9

 
$
17.5

 
$
87.0

 
$

 
$

 
$
6.5

 
$

Capital expenditures
$
489.1

 
$
(1.1
)
 
$
111.1

 
$
144.4

 
$
133.8

 
$
22.6

 
$
53.4

 
$
17.4

 
$
7.5

Investments in equity investees
$
0.3

 
$

 
$

 
$

 
$

 
$

 
$

 
$
0.3

 
$

Goodwill
$
2,873.7

 
$

 
$
1,941.0

 
$
182.1

 
$
2.8

 
$

 
$
643.7

 
$
97.1

 
$
7.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
6,521.3

 
$
(178.8
)
(c)
$
2,921.5

 
$
785.4

 
$
816.4

 
$
43.9

 
$
1,121.4

 
$
824.7

 
$
186.8

Cost of sales
$
4,099.1

 
$
(174.0
)
(c)
$
1,722.4

 
$
402.5

 
$
701.9

 
$
28.0

 
$
685.5

 
$
640.3

 
$
92.5

Operating income (loss)
$
538.6

 
$

 
$
168.7

 
$
174.1

 
$
70.8

 
$
(6.5
)
 
$
88.3

 
$
23.6

 
$
19.6

Loss from equity investees
(0.3
)
 

 

 

 

 

 
(0.3
)
 

 

Loss on extinguishments of debt
(13.3
)
 

 
(13.3
)
 

 

 

 

 

 

Interest expense
(220.4
)
 

 
(141.5
)
 
(40.1
)
 
(4.8
)
 

 
(26.3
)
 
(4.6
)
 
(3.1
)
Income (loss) before income taxes
$
304.6

 
$

 
$
13.9

 
$
134.0

 
$
66.0

 
$
(6.5
)
 
$
61.7

 
$
19.0

 
$
16.5

Net income (loss) attributable to UGI
$
210.2

 
$

 
$
15.4

 
$
81.6

 
$
38.7

 
$
(1.0
)
 
$
51.4

 
$
13.8

 
$
10.3

Depreciation and amortization
$
315.0

 
$

 
$
168.1

 
$
49.0

 
$
3.7

 
$
9.0

 
$
57.1

 
$
22.1

 
$
6.0

Noncontrolling interests’ net (loss) income
$
(12.5
)
 
$

 
$
(12.7
)
 
$

 
$

 
$

 
$
0.2

 
$

 
$

Partnership EBITDA (a)
 
 

 
$
322.1

 

 

 

 

 

 

Total assets
$
9,676.9

 
$
(104.1
)
 
$
4,533.8

 
$
2,045.5

 
$
368.5

 
$
258.2

 
$
1,686.5

 
$
531.8

 
$
356.7

Short-term borrowings
$
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

(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
 
 
2014
 
2013
 
2012
Partnership EBITDA
 
$
664.8

 
$
596.5

 
$
322.1

Depreciation and amortization
 
(197.2
)
 
(205.9
)
 
(168.1
)
Loss on extinguishments of debt
 

 

 
13.3

Noncontrolling interests (i)
 
4.4

 
3.8

 
1.4

Operating income
 
$
472.0

 
$
394.4

 
$
168.7


(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, (4) UGI Corporation’s unallocated corporate and general expenses and interest income and (5) net (losses) gains on Midstream & Marketing’s unsettled commodity derivative instruments and certain settled commodity derivative instruments not associated with current period transactions, and net (losses) gains on AmeriGas Propane’s unsettled commodity derivative instruments entered into beginning April 1, 2014, totaling $(18.0), $7.4 and $15.1 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Nature of Operations (Details)
Sep. 30, 2014
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)
69,110,322 
Summary of Significant Accounting Policies (Details) (USD $)
0 Months Ended 12 Months Ended
Jul. 29, 2014
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Accounting Policies [Abstract]
 
 
 
 
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, maximum
 
20.00% 
 
 
Maturities Period of highly liquid investments
 
three months or less 
 
 
Accumulated impairment losses
 
$ 0 
 
 
Provision for goodwill or other intangible asset impairments
 
Provisions for impairments
 
Other-than-temporary impairment of an investment in a private equity partnership pre-tax loss
 
6,300,000 
Net deferred debt issuance costs
 
36,700,000 
39,400,000 
 
Foreign subsidiary customer deposits
 
200,000,000 
214,600,000 
 
Average to include prudently incurred remediation costs
 
5 years 
 
 
Property, Plant and Equipment
 
 
 
 
Stockholders' Equity Note, Stock Split, Conversion Ratio
1.5 
 
 
 
Estimated maximum period of capitalized and amortized costs to install partnership and antargaz-owned tanks
 
10 years 
 
 
Estimated useful life of definite-lived intangible assets
 
15 years 
 
 
Gas Utility
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Depreciation expense as percentage of related average depreciable base
 
2.30% 
2.30% 
2.20% 
Electric Utility
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Depreciation expense as percentage of related average depreciable base
 
2.50% 
2.40% 
2.40% 
Non-utility Plant and Equipment |
Minimum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
10 years 
 
 
Non-utility Plant and Equipment |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
40 years 
 
 
Storage and Customer Tanks and Cylinders |
Minimum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
6 years 
 
 
Storage and Customer Tanks and Cylinders |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
40 years 
 
 
Electricity Generation Facilities |
Minimum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
25 years 
 
 
Electricity Generation Facilities |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
40 years 
 
 
Pipeline and Related Assets |
Minimum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
25 years 
 
 
Pipeline and Related Assets |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
40 years 
 
 
Vehicles, Equipment and Office Furniture and Fixtures |
Minimum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
3 years 
 
 
Vehicles, Equipment and Office Furniture and Fixtures |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
12 years 
 
 
Software and Software Development Costs [Member] |
Maximum
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Useful life (in years)
 
10 years 
 
 
Other Assets
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Cost method investments
 
77,800,000 
82,000,000 
 
Other Assets |
Private Equity Partnership That Invests in Renewable Energy Companies
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Cost method investments
 
$ 17,400,000 
$ 16,400,000 
 
Interest in a private equity partnership
 
3.50% 
 
 
Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Accounting Policies [Abstract]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
132,000 
122,000 
Shares used in computing basic and diluted earnings per share
 
 
 
Average common shares outstanding for basic computation
172,733,000 
170,885,000 
168,872,000 
Incremental shares issuable for stock options and common stock awards
2,498,000 1
2,397,000 1
1,276,000 1
Average common shares outstanding for diluted computation
175,231,000 
173,282,000 
170,148,000 
Summary of Significant Accounting Policies - Schedule of Changes in Accumulated Other Comprehensive Income (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Accumulated Other Comprehensive Income (Loss), Net Of Tax
 
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at beginning of year
$ 8.4 
 
 
Other comprehensive (loss) income before reclassification adjustments (after-tax)
5.8 
 
 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
Reclassification adjustments (pre-tax)
(45.6)
 
 
Reclassification adjustments tax (expense) benefit
1.4 
 
 
Reclassification adjustments (after-tax)
(44.2)
 
 
Other comprehensive (loss) income
(38.4)
106.4 
(82.2)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
8.8 
 
 
Comprehensive income attributable to UGI Corporation
(29.6)
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at end of year
(21.2)
8.4 
 
Postretirement Benefit Plans
 
 
 
Accumulated Other Comprehensive Income (Loss), Net Of Tax
 
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at beginning of year
(16.4)
 
 
Other comprehensive (loss) income before reclassification adjustments (after-tax)
(5.2)
 
 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
Reclassification adjustments (pre-tax)
1.6 
 
 
Reclassification adjustments tax (expense) benefit
(0.6)
 
 
Reclassification adjustments (after-tax)
1.0 
 
 
Other comprehensive (loss) income
(4.2)
 
 
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
 
Comprehensive income attributable to UGI Corporation
(4.2)
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at end of year
(20.6)
 
 
Derivative Instruments
 
 
 
Accumulated Other Comprehensive Income (Loss), Net Of Tax
 
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at beginning of year
(26.9)
 
 
Other comprehensive (loss) income before reclassification adjustments (after-tax)
54.0 
 
 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
Reclassification adjustments (pre-tax)
(47.2)
 
 
Reclassification adjustments tax (expense) benefit
2.0 
 
 
Reclassification adjustments (after-tax)
(45.2)
 
 
Other comprehensive (loss) income
8.8 
 
 
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
8.8 
 
 
Comprehensive income attributable to UGI Corporation
17.6 
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at end of year
(9.3)
 
 
Foreign Currency
 
 
 
Accumulated Other Comprehensive Income (Loss), Net Of Tax
 
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at beginning of year
51.7 
 
 
Other comprehensive (loss) income before reclassification adjustments (after-tax)
(43.0)
 
 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
Reclassification adjustments (pre-tax)
 
 
Reclassification adjustments tax (expense) benefit
 
 
Reclassification adjustments (after-tax)
 
 
Other comprehensive (loss) income
(43.0)
 
 
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
 
Comprehensive income attributable to UGI Corporation
(43.0)
 
 
Accumulated Other Comprehensive Income (Loss) - Balance at end of year
$ 8.7 
 
 
Acquisitions (Details) (USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended 12 Months Ended 12 Months Ended
Jan. 12, 2012
Heritage Propane
Customer
gal
States
Jan. 12, 2012
Heritage Propane
States
Sep. 30, 2012
Heritage Propane
Jan. 12, 2012
Heritage Operating LP
Jan. 12, 2012
Heritage Operating LP
Heritage Propane
Jan. 12, 2012
Titan Energy
Sep. 30, 2014
Energy Services
Sep. 30, 2013
Energy Services
Sep. 30, 2014
AmeriGas
Sep. 30, 2013
AmeriGas
propane_distribution_business
Sep. 30, 2012
AmeriGas
Sep. 30, 2013
UGI International
Business Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
Purchase price
 
$ 2,604.8 
 
 
 
 
 
 
 
 
 
 
Cash consideration
1,472.2 
 
 
 
 
 
20.0 
23.0 
15.7 
20.0 
13.5 
36.0 
Number of Businesses Acquired
 
 
 
 
 
 
 
 
 
 
 
Common Units issued by AmeriGas Partners (in units)
29,567,362 
29,567,362 
 
 
 
 
 
 
 
 
 
 
Fair value of Common Units issued as consideration in acquisition of Heritage Propane
1,132.6 
 
 
 
 
 
 
 
 
 
 
 
Number of states in which business operates
 
41 
 
 
 
 
 
 
 
 
 
 
Annual delivery of propane by acquired subsidiary (in gallons)
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
Number of retail customer
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
Limited partner interest (percentage)
 
 
 
99.999% 
 
99.99% 
 
 
 
 
 
 
Membership interest (percentage)
 
 
 
100.00% 
 
100.00% 
 
 
 
 
 
 
Remaining general partner interest (percentage)
 
 
 
0.001% 
 
0.01% 
 
 
 
 
 
 
Common units contributed to partnership (in units)
934,327 
 
 
 
 
 
 
 
 
 
 
 
Fair value of contributed Common Units (in usd)
 
 
 
 
41.7 
 
 
 
 
 
 
 
Transaction expenses included in Consolidated Statements of Income
 
 
$ 5.3 
 
 
 
 
 
 
 
 
 
Acquisitions Acquisitions - Allocation of Purchase Price (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Jan. 12, 2012
Heritage Propane
Jan. 12, 2012
Heritage Propane
Customer Relationships
Jan. 12, 2012
Heritage Propane
Trademarks and Trade Names
Business Acquisition
 
 
 
 
 
 
Business Acquisition, Goodwill, Expected Tax Deductible Amount, Period of Amortization
15 years 
 
 
 
 
 
Assets acquired:
 
 
 
 
 
 
Current assets
 
 
 
$ 301.4 
 
 
Property, plant & equipment
 
 
 
890.2 
 
 
Customer relationships
 
 
 
 
418.9 
 
Trademarks and tradenames
 
 
 
 
 
91.1 1
Goodwill
2,833.4 
2,873.7 
2,818.3 
1,217.7 1 2
 
 
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 
 
 
Acquisitions Acquisitions - Pro Forma Income Statement and Income Per Unit (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2012
Business Combinations [Abstract]
 
Revenues
$ 7,013.0 
Net income attributable to UGI Corporation
$ 208.4 
Earnings per common share attributable to UGI Corporation stockholders:
 
Basic
$ 1.23 
Diluted
$ 1.22 
Short-term Borrowings (Details)
12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 5 Months Ended 7 Months Ended
Sep. 30, 2014
Line of Credit
Flaga
USD ($)
Sep. 30, 2014
Line of Credit
Flaga
EUR (€)
Sep. 30, 2013
Line of Credit
Flaga
USD ($)
Sep. 30, 2013
Line of Credit
Flaga
EUR (€)
Sep. 30, 2014
Line of Credit
AmeriGas Credit Agreement
AmeriGas Propane
USD ($)
Jun. 30, 2014
Line of Credit
AmeriGas Credit Agreement
AmeriGas Propane
USD ($)
Sep. 30, 2013
Line of Credit
AmeriGas Credit Agreement
AmeriGas Propane
USD ($)
Sep. 30, 2014
Line of Credit
Senior Facilities Agreement Credit Facility
Antargaz
EUR (€)
Sep. 30, 2014
Line of Credit
Flaga Credit Agreements
Flaga
credit_agreement
Sep. 30, 2014
Line of Credit
Flaga Credit Agreements
Flaga
USD ($)
Sep. 30, 2014
Line of Credit
Flaga Credit Agreements
Flaga
EUR (€)
Sep. 30, 2013
Line of Credit
Flaga Credit Agreements
Flaga
USD ($)
Sep. 30, 2013
Line of Credit
Flaga Credit Agreements
Flaga
EUR (€)
Sep. 30, 2014
Line of Credit
Multi-Currency Working Capital Facility
Flaga
USD ($)
Sep. 30, 2014
Line of Credit
Euro Working Capital Facility
Flaga
USD ($)
Sep. 30, 2014
Line of Credit
UGI Utilities Credit Agreement
UGI Utilities
USD ($)
Sep. 30, 2013
Line of Credit
UGI Utilities Credit Agreement
UGI Utilities
USD ($)
Sep. 30, 2014
Line of Credit
Energy Services Credit Agreement
Energy Services
USD ($)
Sep. 30, 2013
Line of Credit
Energy Services Credit Agreement
Energy Services
USD ($)
Sep. 30, 2014
Line of Credit
Energy Services Credit Agreement
Energy Services
Federal Funds Rate
Sep. 30, 2014
Line of Credit
Energy Services Credit Agreement
Energy Services
London Interbank Offered Rate (LIBOR)
Sep. 30, 2014
Line of Credit
Energy Services Credit Agreement
Energy Services
Alternate Base Rate
Sep. 30, 2014
Line of Credit
Energy Services Credit Agreement
Energy Services
One -Month LIBOR Rate
Jun. 30, 2014
Letter of Credit
AmeriGas Credit Agreement
AmeriGas Propane
USD ($)
Sep. 30, 2014
Letter of Credit
UGI Utilities Credit Agreement
UGI Utilities
USD ($)
Sep. 30, 2014
Letter of Credit
Energy Services Credit Agreement
Energy Services
USD ($)
Sep. 30, 2014
Overdraft Facility
Multi-Currency Working Capital Facility
Flaga
USD ($)
Sep. 30, 2014
Receivables Facility
Energy Services Accounts Receivable Securitization Facility
Energy Services
USD ($)
Sep. 30, 2013
Receivables Facility
Energy Services Accounts Receivable Securitization Facility
Energy Services
USD ($)
Sep. 30, 2012
Receivables Facility
Energy Services Accounts Receivable Securitization Facility
Energy Services
USD ($)
Jun. 30, 2014
Minimum
AmeriGas Credit Agreement
AmeriGas Propane
Jun. 30, 2014
Minimum
AmeriGas Credit Agreement
AmeriGas Propane
Base Rate
Jun. 30, 2014
Minimum
AmeriGas Credit Agreement
AmeriGas Propane
Eurodollar
Sep. 30, 2014
Minimum
Line of Credit
Senior Facilities Agreement Credit Facility
Antargaz
Sep. 30, 2014
Minimum
Line of Credit
UGI Utilities Credit Agreement
UGI Utilities
Jun. 30, 2014
Maximum
AmeriGas Credit Agreement
AmeriGas Propane
Jun. 30, 2014
Maximum
AmeriGas Credit Agreement
AmeriGas Propane
Federal Funds Rate
Jun. 30, 2014
Maximum
AmeriGas Credit Agreement
AmeriGas Propane
Base Rate
Jun. 30, 2014
Maximum
AmeriGas Credit Agreement
AmeriGas Propane
Eurodollar
Sep. 30, 2014
Maximum
Line of Credit
Senior Facilities Agreement Credit Facility
Antargaz
Sep. 30, 2014
Maximum
Line of Credit
UGI Utilities Credit Agreement
UGI Utilities
Sep. 30, 2014
Maximum
Line of Credit
Energy Services Credit Agreement
Energy Services
Sep. 30, 2014
Energy Services Credit Agreement
Oct. 31, 2015
Subsequent Event
Receivables Facility
Energy Services Accounts Receivable Securitization Facility
Energy Services
USD ($)
May 31, 2015
Subsequent Event
Receivables Facility
Energy Services Accounts Receivable Securitization Facility
Energy Services
USD ($)
Short-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate at Period End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.00% 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
 
 
 
 
$ 525 
 
€ 40,000,000 
 
 
 
 
 
$ 46,000,000 
$ 0 
$ 300 
 
$ 240 
 
 
 
 
 
$ 125 
$ 100 
$ 50 
$ 6,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Basis Spread on Variable Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
2.50% 
1.50% 
1.00% 
 
 
 
 
 
 
 
 
0.50% 
1.50% 
1.75% 
0.00% 
 
0.50% 
1.50% 
2.50% 
2.50% 
2.00% 
 
 
 
 
Line of Credit Facility, Commitment Fee Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.30% 
 
 
 
 
0.45% 
 
 
 
 
 
 
 
 
 
Short-term Debt, Weighted Average Interest Rate
 
 
 
 
2.16% 
 
2.69% 
 
 
 
 
4.21% 
4.21% 
 
 
1.03% 
1.18% 
 
2.91% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of Credit Outstanding, Amount
 
 
 
 
64,700,000 
 
53,700,000 
 
 
40,800,000 
32,300,000 
38,700,000 
28,600,000 
 
 
2,000,000 
2,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Number of Credit Agreements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Amount Outstanding at Period End
8,000,000 
6,300,000 
6,200,000 
4,600,000 
 
 
 
 
 
300,000 
200,000 
 
 
 
 
57,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of Net Debt to EBITDA
 
 
 
 
 
 
 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of Consolidated Debt to Consolidated Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.65 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of Consolidated Indebtedness to EBITDA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.25 
 
 
 
Debt Instrument, Restrictive Covenant, Maximum Consolidated Total Indebtedness Ceiling
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Restrictive Covenant, Minimum Consolidated Net Worth Floor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Receivables Facility, Maximum Borrowing Capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75,000,000 
150,000,000 
Sale of Trade Receivables to Consolidated Special Purpose Subsidiary
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,260,600,000 
975,300,000 
836,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from Accounts Receivable Securitization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
354,000,000 
291,000,000 
286,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding Balance of ESFC Trade Receivables
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46,400,000 
55,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trade Receivables Sold to Commercial Paper Conduit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,500,000 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Losses on Sales of Receivables to Commercial Paper Conduit Included in Interest Expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 600,000 
$ 700,000 
$ 1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term Borrowings - Schedule of Short-term Debt (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Short-term Debt
 
 
Short-term Debt
$ 210.8 
$ 227.9 
AmeriGas Propane Credit Agreement
 
 
Short-term Debt
 
 
Short-term Debt
109.0 
116.9 
UGI International Credit Agreement
 
 
Short-term Debt
 
 
Short-term Debt
8.0 
6.5 
UGI Utilities Credit Agreement
 
 
Short-term Debt
 
 
Short-term Debt
86.3 
17.5 
Energy Services Credit Agreement
 
 
Short-term Debt
 
 
Short-term Debt
57.0 
Energy Services Accounts Receivable Securitization Facility
 
 
Short-term Debt
 
 
Short-term Debt
$ 7.5 
$ 30.0 
Long-term Borrowings (Details)
12 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended
Sep. 30, 2014
USD ($)
Sep. 30, 2013
USD ($)
Sep. 30, 2012
USD ($)
Sep. 30, 2014
AmeriGas Propane
USD ($)
Sep. 30, 2013
AmeriGas Propane
USD ($)
Sep. 30, 2014
AmeriGas Propane
Senior Notes
USD ($)
Sep. 30, 2013
AmeriGas Propane
Senior Notes
USD ($)
Jan. 12, 2012
AmeriGas Propane
Senior Notes
USD ($)
Sep. 30, 2014
AmeriGas Propane
Senior Notes
Maximum
Jun. 30, 2012
AmeriGas Propane
Senior Notes
7.00% Senior Notes, due 2022
USD ($)
Sep. 30, 2012
AmeriGas Propane
Senior Notes
7.00% Senior Notes, due 2022
USD ($)
Sep. 30, 2014
AmeriGas Propane
Senior Notes
7.00% Senior Notes, due 2022
USD ($)
Sep. 30, 2013
AmeriGas Propane
Senior Notes
7.00% Senior Notes, due 2022
USD ($)
Jan. 12, 2012
AmeriGas Propane
Senior Notes
7.00% Senior Notes, due 2022
USD ($)
Sep. 30, 2014
AmeriGas Propane
Senior Notes
6.75% Senior Notes, due 2020
USD ($)
Sep. 30, 2013
AmeriGas Propane
Senior Notes
6.75% Senior Notes, due 2020
USD ($)
Jan. 12, 2012
AmeriGas Propane
Senior Notes
6.75% Senior Notes, due 2020
Mar. 28, 2012
AmeriGas Propane
Senior Notes
6.50% Senior Notes, due 2021
Sep. 30, 2014
AmeriGas Propane
Senior Notes
6.50% Senior Notes, due 2021
USD ($)
Sep. 30, 2013
AmeriGas Propane
Senior Notes
6.50% Senior Notes, due 2021
USD ($)
Mar. 28, 2012
AmeriGas Propane
Senior Notes
6.50% Senior Notes, due 2021
USD ($)
Sep. 30, 2014
AmeriGas Propane
Senior Secured Notes
HOLP Senior Secured Notes
USD ($)
Sep. 30, 2013
AmeriGas Propane
Senior Secured Notes
HOLP Senior Secured Notes
USD ($)
Sep. 30, 2014
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
Sep. 30, 2014
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
EUR (€)
Sep. 30, 2013
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
Sep. 30, 2014
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
Minimum
Sep. 30, 2014
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
Maximum
Sep. 30, 2013
Flaga
Notes Payable to Banks
Flaga Term Loan, due September 2016
USD ($)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due September 2016
USD ($)
Sep. 30, 2013
Flaga
Notes Payable to Banks
Flaga Term Loan, due October 2016
USD ($)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due October 2016
USD ($)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due October 2016
EUR (€)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due October 2016
Minimum
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due October 2016
Maximum
Sep. 30, 2013
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
USD ($)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
USD ($)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
EUR (€)
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
Minimum
Sep. 30, 2014
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
Maximum
Sep. 30, 2014
UGI Utilities
USD ($)
Sep. 30, 2013
UGI Utilities
USD ($)
Mar. 31, 2014
UGI Utilities
Senior Notes
4.98% Senior Notes due 2044
USD ($)
Sep. 30, 2014
UGI Utilities
Senior Notes
4.98% Senior Notes due 2044
USD ($)
Mar. 31, 2016
Forecast
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
Mar. 31, 2016
Forecast
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
EUR (€)
May 31, 2015
Forecast
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
May 31, 2015
Forecast
Antargaz
Notes Payable to Banks
Antargaz Senior Facilities Term Loan, due 2016
EUR (€)
Sep. 30, 2016
Forecast
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
USD ($)
Sep. 30, 2016
Forecast
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
EUR (€)
Aug. 31, 2016
Forecast
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
USD ($)
Aug. 31, 2016
Forecast
Flaga
Notes Payable to Banks
Flaga Term Loan, due through September 2016
EUR (€)
Debt Instrument
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt
$ 3,510,800,000 
$ 3,609,400,000 
 
$ 2,291,700,000 
$ 2,300,100,000 
$ 450,000,000 
$ 450,000,000 
 
 
 
 
$ 980,800,000 
$ 980,800,000 
 
$ 550,000,000 
$ 550,000,000 
 
 
$ 270,000,000 
$ 270,000,000 
 
$ 26,500,000 
$ 32,000,000 
$ 432,000,000 
€ 342,000,000 
$ 514,000,000 
 
 
$ 52,000,000 
$ 52,000,000 
$ 25,800,000 
$ 24,100,000 
€ 19,100,000 
 
 
$ 54,100,000 
$ 50,500,000 
€ 40,000,000 
 
 
$ 642,000,000 
$ 642,000,000 
$ 175,000,000 
 
 
 
 
 
$ 16,800,000 
€ 13,300,000 
$ 33,700,000 
€ 26,700,000 
Principal repayments due in 2015
76,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43,200,000 
34,200,000 
 
 
 
 
Principal repayments due in 2016
748,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
388,800,000 
307,800,000 
 
 
 
 
 
 
Aggregate principal amount
 
 
 
 
 
 
 
550,000,000 
 
 
 
 
 
1,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate stated percentage
 
 
 
 
 
6.25% 
 
 
 
7.00% 
 
7.00% 
 
7.00% 
6.75% 
 
6.75% 
 
6.50% 
 
6.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.98% 
 
 
 
 
 
 
 
 
 
Percentage of Redemption at Option
 
 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guaranteed Debt
 
 
 
 
 
1,500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Tendered for Redemption
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
383,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Aggregate Amount Outstanding Tendered
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
82.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal Amount Outstanding Before Redemption
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
470,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemption Value of Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Early Redemption Percentage of Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
105.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Proration Factor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of Long-term Debt
242,600,000 
168,700,000 
299,900,000 
 
 
 
 
 
 
19,200,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
13,300,000 
 
 
 
 
 
 
 
13,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reduction in Net Income Attributable to Company
 
 
 
 
 
 
 
 
 
 
2,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Unamortized Premium
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Margin on Term Loan Base Rate Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.25% 
 
 
 
 
117.50% 
252.50% 
 
 
 
1.125% 
2.55% 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.89% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8.87% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Effective Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.75% 
 
4.79% 
4.79% 
4.41% 
 
 
1.82% 
1.82% 
3.85% 
3.40% 
3.40% 
 
 
4.68% 
4.25% 
4.25% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Margin on Credit Agreement Base Rate Borrowings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.75% 
2.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective EURIBOR Rate of Interest on Term Loan
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.45% 
2.45% 
 
 
 
 
 
1.79% 
 
 
 
 
2.68% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective EURIBOR Rate of Interest on Term Loan Thereafter
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.71% 
3.71% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of Net Debt to EBITDA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.50 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guarantor Obligations, Maximum Exposure, Undiscounted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
364 days 
 
 
 
 
 
 
 
 
 
Ratio of Consolidated Debt to Consolidated Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.65 
 
 
 
 
 
 
 
 
Amount of Net Assets Restricted from Transfer to Parent Company under Different Agreements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1,600,000,000 
 
 
 
 
 
 
 
 
Long-term Borrowings - Schedule of Long-term Debt Instruments (Details)
In Millions, unless otherwise specified
Sep. 30, 2014
USD ($)
Sep. 30, 2013
USD ($)
Sep. 30, 2014
AmeriGas Propane
USD ($)
Sep. 30, 2013
AmeriGas Propane
USD ($)
Sep. 30, 2014
AmeriGas Propane
Other
USD ($)
Sep. 30, 2013
AmeriGas Propane
Other
USD ($)
Sep. 30, 2014
UGI International
USD ($)
Sep. 30, 2013
UGI International
USD ($)
Sep. 30, 2014
UGI Utilities
USD ($)
Sep. 30, 2013
UGI Utilities
USD ($)
Sep. 30, 2014
Other
USD ($)
Sep. 30, 2013
Other
USD ($)
Sep. 30, 2014
Senior Notes
AmeriGas Propane
USD ($)
Sep. 30, 2013
Senior Notes
AmeriGas Propane
USD ($)
Sep. 30, 2014
Senior Notes
AmeriGas Propane
7.00% Senior Notes, due 2022
USD ($)
Sep. 30, 2013
Senior Notes
AmeriGas Propane
7.00% Senior Notes, due 2022
USD ($)
Jun. 30, 2012
Senior Notes
AmeriGas Propane
7.00% Senior Notes, due 2022
Jan. 12, 2012
Senior Notes
AmeriGas Propane
7.00% Senior Notes, due 2022
Sep. 30, 2014
Senior Notes
AmeriGas Propane
6.75% Senior Notes, due 2020
USD ($)
Sep. 30, 2013
Senior Notes
AmeriGas Propane
6.75% Senior Notes, due 2020
USD ($)
Jan. 12, 2012
Senior Notes
AmeriGas Propane
6.75% Senior Notes, due 2020
Sep. 30, 2014
Senior Notes
AmeriGas Propane
6.50% Senior Notes, due 2021
USD ($)
Sep. 30, 2013
Senior Notes
AmeriGas Propane
6.50% Senior Notes, due 2021
USD ($)
Mar. 28, 2012
Senior Notes
AmeriGas Propane
6.50% Senior Notes, due 2021
Sep. 30, 2014
Senior Notes
UGI Utilities
5.75% Senior Notes, due 2016
USD ($)
Sep. 30, 2013
Senior Notes
UGI Utilities
5.75% Senior Notes, due 2016
USD ($)
Sep. 30, 2014
Senior Notes
UGI Utilities
4.98% Senior Notes, due 2044
USD ($)
Sep. 30, 2013
Senior Notes
UGI Utilities
4.98% Senior Notes, due 2044
USD ($)
Sep. 30, 2014
Senior Notes
UGI Utilities
6.21% Senior Notes, due 2036
USD ($)
Sep. 30, 2013
Senior Notes
UGI Utilities
6.21% Senior Notes, due 2036
USD ($)
Sep. 30, 2014
Senior Secured Notes
AmeriGas Propane
HOLP Senior Secured Notes
USD ($)
Sep. 30, 2013
Senior Secured Notes
AmeriGas Propane
HOLP Senior Secured Notes
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
5.16% Medium-term Notes, due May 2015
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
5.16% Medium-term Notes, due May 2015
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
7.37% Medium-term Notes, due October 2015
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
7.37% Medium-term Notes, due October 2015
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
5.64% Medium-term Notes, due December 2015
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
5.64% Medium-term Notes, due December 2015
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
6.17% Medium-term Notes, due June 2017
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
6.17% Medium-term Notes, due June 2017
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
7.25% Medium-term Notes, due November 2017
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
7.25% Medium-term Notes, due November 2017
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
5.67% Medium-term Notes, due 2018
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
5.67% Medium-term Notes, due 2018
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
6.50% Medium-term Notes, due 2033
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
6.50% Medium-term Notes, due 2033
USD ($)
Sep. 30, 2014
Medium-term Notes
UGI Utilities
6.13% Medium-term Notes, due 2034
USD ($)
Sep. 30, 2013
Medium-term Notes
UGI Utilities
6.13% Medium-term Notes, due 2034
USD ($)
Sep. 30, 2014
Notes Payable to Banks
UGI International
Other
USD ($)
Sep. 30, 2013
Notes Payable to Banks
UGI International
Other
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Antargaz
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Antargaz
Antargaz Senior Facilities Term Loan, due 2016
EUR (€)
Sep. 30, 2013
Notes Payable to Banks
Antargaz
Antargaz Senior Facilities Term Loan, due 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due September 2016
USD ($)
Sep. 30, 2013
Notes Payable to Banks
Flaga
Flaga Term Loan, due September 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due through September 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due through September 2016
EUR (€)
Sep. 30, 2013
Notes Payable to Banks
Flaga
Flaga Term Loan, due through September 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due October 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due October 2016
EUR (€)
Sep. 30, 2013
Notes Payable to Banks
Flaga
Flaga Term Loan, due October 2016
USD ($)
Sep. 30, 2014
Notes Payable to Banks
Flaga
Flaga Term Loan, due June 2014
USD ($)
Sep. 30, 2013
Notes Payable to Banks
Flaga
Flaga Term Loan, due June 2014
USD ($)
Sep. 30, 2014
Notes Payable to Banks
UGI Utilities
Term Loan Credit Agreement
USD ($)
Sep. 30, 2013
Notes Payable to Banks
UGI Utilities
Term Loan Credit Agreement
USD ($)
Debt Instrument
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Effective Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.75% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.79% 
4.79% 
4.41% 
1.82% 
1.82% 
4.25% 
4.25% 
4.68% 
3.40% 
3.40% 
3.85% 
 
 
 
 
Total long-term debt
$ 3,510.8 
$ 3,609.4 
$ 2,291.7 
$ 2,300.1 
$ 14.4 
$ 17.3 
$ 565.0 
$ 654.4 
$ 642.0 
$ 642.0 
$ 12.1 
$ 12.9 
$ 450.0 
$ 450.0 
$ 980.8 
$ 980.8 
 
 
$ 550.0 
$ 550.0 
 
$ 270.0 
$ 270.0 
 
$ 175.0 
$ 175.0 
$ 175.0 
$ 0 
$ 100.0 
$ 100.0 
$ 26.5 
$ 32.0 
$ 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 
$ 6.4 
$ 6.6 
$ 432.0 
€ 342.0 
$ 514.0 
$ 52.0 
$ 52.0 
$ 50.5 
€ 40.0 
$ 54.1 
$ 24.1 
€ 19.1 
$ 25.8 
$ 0 
$ 1.9 
$ 0 
$ 175.0 
Less: current maturities
(77.2)
(67.2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total long-term debt due after one year
$ 3,433.6 
$ 3,542.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate stated percentage
 
 
 
 
 
 
 
 
 
 
 
 
6.25% 
 
7.00% 
 
7.00% 
7.00% 
6.75% 
 
6.75% 
6.50% 
 
6.50% 
5.75% 
 
4.98% 
 
6.21% 
 
 
 
5.16% 
 
7.37% 
 
5.64% 
 
6.17% 
 
7.25% 
 
5.67% 
 
6.50% 
 
6.13% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Borrowings - Schedule of Maturities of Long-term Debt (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Debt Instrument
 
2015
$ 76.7 
2016
748.2 
2017
51.7 
2018
46.6 
2019
456.0 
AmeriGas Propane
 
Debt Instrument
 
2015
11.0 
2016
7.6 
2017
5.6 
2018
4.9 
2019
454.5 
UGI Utilities
 
Debt Instrument
 
2015
20.0 
2016
247.0 
2017
20.0 
2018
40.0 
2019
UGI International
 
Debt Instrument
 
2015
45.0 
2016
492.9 
2017
25.4 
2018
0.9 
2019
0.7 
Other
 
Debt Instrument
 
2015
0.7 
2016
0.7 
2017
0.7 
2018
0.8 
2019
$ 0.8 
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended 1 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2014
Foreign Tax Credits
Sep. 30, 2014
Foreign Operating Loss Carryforwards
Sep. 30, 2014
State Operating Loss Benefits
Sep. 30, 2014
Accrued Interest Included
Sep. 30, 2012
Foreign Country
Sep. 30, 2014
Foreign Country
Sep. 30, 2014
State and Local Jurisdiction
Sep. 30, 2013
State and Local Jurisdiction
Sep. 30, 2012
State and Local Jurisdiction
Sep. 30, 2014
UGI International Holdings
Sep. 30, 2014
AmeriGas Propane
Sep. 30, 2014
Other Subsidiaries
Sep. 30, 2014
UGI International
Sep. 30, 2014
Flaga
Sep. 30, 2014
Flaga
Foreign Country
Sep. 30, 2014
Antargaz
Sep. 30, 2014
Antargaz
Foreign Country
Dec. 31, 2013
FRANCE
Foreign Country
Dec. 31, 2013
FRANCE
Antargaz
Foreign Country
Income Taxes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decrease in unusable foreign tax credits
$ 12.1 
$ 34.9 
$ 5.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.7 
5.7 
Income Tax Reconciliation, Change in Deferred Tax Assets Valuation Allowance
 
 
 
 
 
 
 
 
4.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undistributed Earnings of Foreign Subsidiaries
42.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
State Net Operating Loss carryforwards
 
 
 
 
 
 
 
 
 
 
171.9 
 
 
 
16.8 
 
 
 
37.4 
 
8.2 
 
 
Effect on income tax expense (benefit) of state tax flow through of accelerated depreciation
 
 
 
 
 
 
 
 
 
 
(2.0)
(1.5)
(3.2)
 
 
 
 
 
 
 
 
 
 
Deferred tax assets relating to operating loss carryforwards
27.9 
32.1 
 
 
 
 
 
 
 
 
 
 
 
0.8 
6.5 
9.5 
 
8.4 
 
2.7 
 
 
 
Valuation allowance provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries
15.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Valuation allowance operating loss carryforwards related to acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.0 
 
 
 
 
 
 
Deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions
 
 
 
 
 
 
 
 
 
 
6.7 
5.9 
 
 
 
 
 
 
 
 
 
 
 
Foreign tax credit carryforwards
 
 
 
 
 
 
 
 
 
47.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in valuation allowance
38.4 
 
 
 
34.0 
4.8 
(0.4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized income tax benefits
2.4 
3.4 
2.9 
6.3 
 
 
 
2.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued interest included in unrecognized income tax benefits
0.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits if recognized would impact the reported effective tax rate
2.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected change in unrecognized tax benefits and related interest
$ 0.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes - Income Before Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Income Tax Disclosure [Abstract]
 
 
 
Domestic
$ 699.2 
$ 494.1 
$ 245.6 
Foreign
68.6 
96.3 
59.0 
Income before income taxes
$ 767.8 
$ 590.4 
$ 304.6 
Income Taxes - Provisions for Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Current expense (benefit):
 
 
 
Federal
$ 102.4 
$ 53.3 
$ (10.4)
State
30.7 
25.1 
11.2 
Foreign
37.0 
37.3 
18.8 
Investment tax credit
(1.6)
(1.6)
(2.9)
Total current expense
168.5 
114.1 
16.7 
Deferred expense (benefit):
 
 
 
Federal
61.9 
54.6 
81.7 
State
7.8 
(0.7)
7.0 
Foreign
(2.7)
(4.9)
1.8 
Investment tax credit amortization
(0.3)
(0.3)
(0.3)
Total deferred expense
66.7 
48.7 
90.2 
Total income tax expense
$ 235.2 
$ 162.8 
$ 106.9 
Income Taxes - Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate (Details)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Income Tax Disclosure [Abstract]
 
 
 
U.S. federal statutory tax rate
35.00% 
35.00% 
35.00% 
Difference in tax rate due to:
 
 
 
Noncontrolling interests not subject to tax
(9.00%)
(8.70%)
1.20% 
State income taxes, net of federal benefit
3.40% 
3.40% 
4.00% 
Valuation allowance adjustments
0.00% 
(0.50%)
(1.50%)
Effects of foreign operations
1.00% 
(1.80%)
(3.30%)
Other, net
0.20% 
0.20% 
(0.30%)
Effective tax rate
30.60% 
27.60% 
35.10% 
Income Taxes - Deferred Tax Liabilities (Assets) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Income Tax Disclosure [Abstract]
 
 
Excess book basis over tax basis of property, plant and equipment
$ 675.7 
$ 626.9 
Investment in AmeriGas Partners
325.1 
313.0 
Intangible assets and goodwill
53.0 
65.1 
Utility regulatory assets
110.0 
101.6 
Foreign currency translation adjustment
9.5 
Other
3.5 
2.7 
Gross deferred tax liabilities
1,167.3 
1,118.8 
Pension plan liabilities
(40.6)
(36.2)
Employee-related benefits
(48.8)
(47.9)
Operating loss carryforwards
(27.9)
(32.1)
Foreign tax credit carryforwards
(47.8)
(81.8)
Utility regulatory liabilities
(14.8)
(15.5)
Foreign currency translation adjustment
(14.1)
Derivative instruments
(11.0)
(15.0)
Other
(13.0)
(20.5)
Gross deferred tax assets
(218.0)
(249.0)
Deferred tax assets valuation allowance
59.2 
97.6 
Net deferred tax liabilities
$ 1,008.5 
$ 967.4 
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Reconciliation of Unrecognized Tax Benefits
 
 
 
Unrecognized tax benefits - beginning of year
$ 3.4 
$ 2.9 
$ 6.3 
Additions for tax positions of the current year
0.7 
0.7 
0.5 
Additions for tax positions taken in prior years
0.6 
Settlements with tax authorities
(1.7)
(0.2)
(4.5)
Unrecognized tax benefits - end of year
$ 2.4 
$ 3.4 
$ 2.9 
Employee Retirement Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2014
U.S Pension Plans
Sep. 30, 2013
U.S Pension Plans
Sep. 30, 2012
U.S Pension Plans
Sep. 30, 2014
Supplemental Employee Retirement Plans
Sep. 30, 2013
Supplemental Employee Retirement Plans
Sep. 30, 2013
Portion Used to Fund Company Established Trusts
Supplemental Employee Retirement Plans
Sep. 30, 2015
Forecast
Sep. 30, 2014
Other Assets
Supplemental Employee Retirement Plans
Sep. 30, 2013
Other Assets
Supplemental Employee Retirement Plans
Sep. 30, 2014
Supplemental defined contribution executive retirement plans [Member]
Other Assets
Sep. 30, 2013
Supplemental defined contribution executive retirement plans [Member]
Other Assets
Defined Benefit Plan Disclosure
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of net actuarial losses
 
 
 
 
 
 
 
 
 
$ 10.3 
 
 
 
 
Amortization of prior service credits
 
 
 
 
 
 
 
 
 
0.2 
 
 
 
 
ABO for the Pension Plans
 
 
 
499.1 
451.3 
 
 
 
 
 
 
 
 
 
Contribution made to Pension Plan
 
 
 
19.2 
22.4 
31.2 
 
 
 
 
 
 
 
 
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans
38.4 
33.9 
 
 
 
 
 
 
 
 
 
 
 
 
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans
2.6 
3.0 
3.0 
 
 
 
 
 
 
 
 
 
 
 
Amounts recorded in UGI's stockholders include pre-tax losses representing unrecognized actuarial losses
(10.2)
(9.4)
 
 
 
 
 
 
 
 
 
 
 
 
Amount of expected amortization of pre-tax actuarial losses into retiree benefit cost
 
 
 
 
 
 
 
 
 
0.9 
 
 
 
 
Pension and Other Postretirement Benefit Contributions
 
 
 
 
 
 
 
 
 
 
 
Pension and Other Postretirement Benefit Contributions, Fair Value
 
 
 
442.4 
398.2 
 
 
 
 
 
26.6 
23.7 
3.4 
3.4 
Percentage of aggregate employer securities holdings to not to exceed fair value assets
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of common stock represented pension plan assets
9.60% 
8.20% 
 
 
 
 
 
 
 
 
 
 
 
 
Costs of benefits under savings plans
$ 14.7 
$ 14.0 
$ 13.7 
 
 
 
 
 
 
 
 
 
 
 
Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefits Obligations (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
Net actuarial loss (gain)
$ 10.2 
$ 9.4 
 
Pension Benefit
 
 
 
Change in benefit obligations:
 
 
 
Benefit obligations — beginning of year
516.5 
573.4 
 
Service cost
9.4 
11.3 
9.3 
Interest cost
26.1 
23.8 
25.1 
Actuarial (gain) loss
46.8 
(72.7)
 
Plan amendments
1.0 
 
Foreign currency
(2.4)
1.5 
 
Benefits paid
(22.8)
(21.8)
 
Benefit obligations — end of year
573.6 
516.5 
573.4 
Change in plan assets:
 
 
 
Fair value of plan assets — beginning of year
415.3 
369.9 
 
Actual gain on plan assets
47.9 
42.2 
 
Foreign currency
(1.2)
0.8 
 
Employer contributions
20.2 
24.2 
 
Benefits paid
(22.8)
(21.8)
 
Fair value of plan assets — end of year
459.4 
415.3 
369.9 
Funded status of the plans — end of year
(114.2)
(101.2)
 
Assets (liabilities) recorded in the balance sheet:
 
 
 
Assets in excess of liabilities — included in other noncurrent assets
 
Unfunded liabilities — included in other current liabilities
(1.1)
(17.9)
 
Unfunded liabilities — included in other noncurrent liabilities
(113.1)
(83.3)
 
Net amount recognized
(114.2)
(101.2)
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
Prior service credit
(0.1)
(0.1)
 
Net actuarial loss (gain)
20.8 
16.7 
 
Total
20.7 
16.6 
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
Prior service cost (credit)
1.9 
2.2 
 
Net actuarial loss
107.4 
91.3 
 
Total
109.3 
93.5 
 
Other Postretirement Benefits
 
 
 
Change in benefit obligations:
 
 
 
Benefit obligations — beginning of year
19.7 
24.7 
 
Service cost
0.5 
0.6 
0.4 
Interest cost
0.9 
0.9 
1.1 
Actuarial (gain) loss
1.3 
(3.6)
 
Plan amendments
(1.8)
 
Foreign currency
(0.3)
0.2 
 
Benefits paid
(0.8)
(1.3)
 
Benefit obligations — end of year
21.3 
19.7 
24.7 
Change in plan assets:
 
 
 
Fair value of plan assets — beginning of year
11.7 
11.2 
 
Actual gain on plan assets
1.4 
1.1 
 
Foreign currency
   
   
 
Employer contributions
0.5 
0.7 
 
Benefits paid
(0.8)
(1.3)
 
Fair value of plan assets — end of year
12.8 
11.7 
11.2 
Funded status of the plans — end of year
(8.5)
(8.0)
 
Assets (liabilities) recorded in the balance sheet:
 
 
 
Assets in excess of liabilities — included in other noncurrent assets
4.0 
3.2 
 
Unfunded liabilities — included in other current liabilities
(0.1)
(0.4)
 
Unfunded liabilities — included in other noncurrent liabilities
(12.4)
(10.8)
 
Net amount recognized
(8.5)
(8.0)
 
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
 
 
 
Prior service credit
(0.1)
(0.1)
 
Net actuarial loss (gain)
0.8 
(0.4)
 
Total
0.7 
(0.5)
 
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
Prior service cost (credit)
(3.6)
(4.3)
 
Net actuarial loss
2.6 
3.6 
 
Total
$ (1.0)
$ (0.7)
 
Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Pension Benefit
 
 
 
Weighted-average assumption:
 
 
 
Discount rate - benefit obligations
4.60% 
5.20% 
4.20% 
Discount rate - benefit cost
5.20% 
4.20% 
5.30% 
Expected return on plan assets
7.75% 
7.75% 
7.75% 
Rate of increase in salary levels
3.25% 
3.25% 
3.25% 
Other Postretirement Benefits
 
 
 
Weighted-average assumption:
 
 
 
Discount rate - benefit obligations
4.60% 
 
 
Discount rate - benefit cost
 
 
5.30% 
Expected return on plan assets
5.00% 
5.00% 
5.20% 
Rate of increase in salary levels
3.25% 
3.25% 
3.25% 
Minimum |
Other Postretirement Benefits
 
 
 
Weighted-average assumption:
 
 
 
Discount rate - benefit obligations
 
5.10% 
4.10% 
Discount rate - benefit cost
5.10% 
4.10% 
 
Maximum |
Other Postretirement Benefits
 
 
 
Weighted-average assumption:
 
 
 
Discount rate - benefit obligations
 
5.40% 
4.30% 
Discount rate - benefit cost
5.40% 
4.30% 
 
Employee Retirement Plans - Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Pension Benefit
 
 
 
Defined Benefit Plan Disclosure
 
 
 
Service cost
$ 9.4 
$ 11.3 
$ 9.3 
Interest cost
26.1 
23.8 
25.1 
Expected return on assets
(29.7)
(27.8)
(26.2)
Amortization of:
 
 
 
Prior service cost (benefit)
0.3 
0.3 
0.2 
Actuarial loss
7.7 
15.1 
8.4 
Net benefit cost
13.8 
22.7 
16.8 
Change in associated regulatory liabilities
   
   
   
Net benefit cost after change in regulatory liabilities
13.8 
22.7 
16.8 
Other Postretirement Benefits
 
 
 
Defined Benefit Plan Disclosure
 
 
 
Service cost
0.5 
0.6 
0.4 
Interest cost
0.9 
0.9 
1.1 
Expected return on assets
(0.6)
(0.5)
(0.5)
Amortization of:
 
 
 
Prior service cost (benefit)
(0.5)
(0.3)
(0.3)
Actuarial loss
0.4 
0.3 
Net benefit cost
0.3 
1.1 
1.0 
Change in associated regulatory liabilities
3.7 
3.3 
3.2 
Net benefit cost after change in regulatory liabilities
$ 4.0 
$ 4.4 
$ 4.2 
Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Pension Benefit
 
Defined Benefit Plan Disclosure
 
Fiscal 2015
$ 25.6 
Fiscal 2016
25.8 
Fiscal 2017
27.2 
Fiscal 2018
30.3 
Fiscal 2019
32.6 
Fiscal 2020-2024
175.1 
Other Postretirement Benefits
 
Defined Benefit Plan Disclosure
 
Fiscal 2015
1.1 
Fiscal 2016
1.1 
Fiscal 2017
1.0 
Fiscal 2018
1.0 
Fiscal 2019
1.0 
Fiscal 2020-2024
$ 4.9 
Employee Retirement Plans - Schedule of Health Care Cost Trend Rates (Details)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Defined Benefit Plan Disclosure
 
 
Fiscal year that the rate reaches the ultimate trend rate
2019 
2019 
Maximum
 
 
Defined Benefit Plan Disclosure
 
 
Health care cost trend rate assumed for next year
7.00% 
7.50% 
Minimum
 
 
Defined Benefit Plan Disclosure
 
 
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
5.00% 
5.00% 
Employee Retirement Plans - Pension Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Pension Benefit
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
100.00% 
100.00% 
 
Target Asset Allocation
100.00% 
 
 
Pension and Other Postretirement Benefit Contributions, Fair Value
$ 459.4 
$ 415.3 
$ 369.9 
Pension Benefit |
Equity Securities
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
66.90% 
68.60% 
 
Target Asset Allocation
65.00% 
 
 
Permitted Range - Minimum
60.00% 
 
 
Permitted Range - Maximum
70.00% 
 
 
Pension Benefit |
Domestic Equity Investments
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
55.60% 
57.50% 
 
Target Asset Allocation
52.50% 
 
 
Permitted Range - Minimum
40.00% 
 
 
Permitted Range - Maximum
65.00% 
 
 
Pension Benefit |
International Index Mutual Funds
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
11.30% 
11.10% 
 
Target Asset Allocation
12.50% 
 
 
Permitted Range - Minimum
7.50% 
 
 
Permitted Range - Maximum
17.50% 
 
 
Pension Benefit |
Fixed Income Funds And Cash Equivalents
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
33.10% 
31.40% 
 
Target Asset Allocation
35.00% 
 
 
Permitted Range - Minimum
30.00% 
 
 
Permitted Range - Maximum
40.00% 
 
 
VEBA Trust
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
100.00% 
100.00% 
 
Target Asset Allocation
100.00% 
 
 
Pension and Other Postretirement Benefit Contributions, Fair Value
12.8 
11.7 
 
VEBA Trust |
Domestic Equity Investments
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
67.90% 
65.60% 
 
Target Asset Allocation
65.00% 
 
 
Permitted Range - Minimum
60.00% 
 
 
Permitted Range - Maximum
70.00% 
 
 
VEBA Trust |
Fixed Income Funds And Cash Equivalents
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Actual Pension Plan
32.10% 
34.40% 
 
Target Asset Allocation
35.00% 
 
 
Permitted Range - Minimum
30.00% 
 
 
Permitted Range - Maximum
40.00% 
 
 
Other Assets |
Supplemental defined contribution executive retirement plans [Member]
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans
 
 
 
Pension and Other Postretirement Benefit Contributions, Fair Value
$ 3.4 
$ 3.4 
 
Employee Retirement Plans - Fair Value of U.S. Pension Plan and VEBA Trust Assets (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
VEBA Trust
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
$ 12.8 
$ 11.7 
VEBA Trust |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
8.7 
7.7 
VEBA Trust |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
3.7 
3.8 
VEBA Trust |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
0.4 
0.2 
U.S Pension Plans
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
442.4 
398.2 
U.S Pension Plans |
Domestic Equity Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
245.8 
228.9 
U.S Pension Plans |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
152.6 
141.8 
U.S Pension Plans |
Small and Midcap Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
41.4 
54.5 
U.S Pension Plans |
Smallcap Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
9.3 
 
U.S Pension Plans |
UGI Corporation Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
42.5 
32.6 
U.S Pension Plans |
International Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
49.9 
44.4 
U.S Pension Plans |
Fixed Income Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
146.7 
124.9 
U.S Pension Plans |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
141.0 
120.9 
U.S Pension Plans |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
5.7 
4.0 
Level 1 |
VEBA Trust
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
12.4 
11.5 
Level 1 |
VEBA Trust |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
8.7 
7.7 
Level 1 |
VEBA Trust |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
3.7 
3.8 
Level 1 |
VEBA Trust |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 1 |
U.S Pension Plans
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
436.7 
394.2 
Level 1 |
U.S Pension Plans |
Domestic Equity Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
245.8 
228.9 
Level 1 |
U.S Pension Plans |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
152.6 
141.8 
Level 1 |
U.S Pension Plans |
Small and Midcap Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
41.4 
54.5 
Level 1 |
U.S Pension Plans |
Smallcap Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
9.3 
 
Level 1 |
U.S Pension Plans |
UGI Corporation Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
42.5 
32.6 
Level 1 |
U.S Pension Plans |
International Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
49.9 
44.4 
Level 1 |
U.S Pension Plans |
Fixed Income Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
141.0 
120.9 
Level 1 |
U.S Pension Plans |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
141.0 
120.9 
Level 1 |
U.S Pension Plans |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
VEBA Trust
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
0.4 
0.2 
Level 2 |
VEBA Trust |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
VEBA Trust |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
VEBA Trust |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
0.4 
0.2 
Level 2 |
U.S Pension Plans
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
5.7 
4.0 
Level 2 |
U.S Pension Plans |
Domestic Equity Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
Small and Midcap Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
Smallcap Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
 
Level 2 |
U.S Pension Plans |
UGI Corporation Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
International Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
Fixed Income Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
5.7 
4.0 
Level 2 |
U.S Pension Plans |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 2 |
U.S Pension Plans |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
5.7 
4.0 
Level 3 |
VEBA Trust
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
VEBA Trust |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
VEBA Trust |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
VEBA Trust |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Domestic Equity Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
S&P 500 Index Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Small and Midcap Equity Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Smallcap Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
 
Level 3 |
U.S Pension Plans |
UGI Corporation Common Stock
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
International Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Fixed Income Investments
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Bond Index Mutual Funds
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Level 3 |
U.S Pension Plans |
Cash Equivalents
 
 
Fair Value of Pension Plan Assets
 
 
Fair Value of Plan Assets
   
   
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Apr. 30, 2013
Sep. 30, 2014
Minimum
Sep. 30, 2014
Maximum
Sep. 30, 2014
Removal Costs, Net
Maximum
Sep. 30, 2014
Other Regulatory Assets (Liabilities) [Member]
Minimum
Sep. 30, 2014
Other Regulatory Assets (Liabilities) [Member]
Maximum
Regulatory Assets and Liabilities
 
 
 
 
 
 
 
 
Average remaining depreciable lives of the associated property
 
 
 
1 year 
65 years 
 
 
 
Unrealized gains (losses) on derivative financial instruments contracts
$ (1.4)
$ (1.7)
 
 
 
 
 
 
Fair value of electric utility electricity supply contracts
0.3 
(4.8)
 
 
 
 
 
 
Period to recover costs related to other regulatory assets
 
 
 
 
 
5 years 
1 year 
20 years 
Net Book Value of Asset Transferred
 
 
$ 2.6 
 
 
 
 
 
Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Utilities (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Regulatory Assets and Liabilities
 
 
Regulatory assets
$ 268.2 
$ 244.9 
Regulatory liabilities
32.5 
37.3 
Postretirement Benefits
 
 
Regulatory Assets and Liabilities
 
 
Regulatory liabilities
18.6 
16.5 
Environmental Overcollections
 
 
Regulatory Assets and Liabilities
 
 
Regulatory liabilities
0.3 
2.6 
Deferred Fuel and Power Refunds
 
 
Regulatory Assets and Liabilities
 
 
Regulatory liabilities
0.3 
8.3 
State Tax Benefits - Distribution System Repairs
 
 
Regulatory Assets and Liabilities
 
 
Regulatory liabilities
10.1 
8.4 
Other Regulatory Liabilities
 
 
Regulatory Assets and Liabilities
 
 
Regulatory liabilities
3.2 
1.5 
Income Taxes Recoverable
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
110.7 
106.1 
Underfunded Pension and Postretirement Plans
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
110.1 
94.5 
Environmental Costs
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
14.6 
17.1 
Deferred Fuel and Power Costs
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
11.8 
8.3 
Removal Costs, Net
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
16.8 
13.3 
Other Regulatory Assets
 
 
Regulatory Assets and Liabilities
 
 
Regulatory assets
$ 4.2 
$ 5.6 
Inventories (Details) (UGI Utilities, USD $)
In Millions, unless otherwise specified
12 Months Ended 0 Months Ended
Sep. 30, 2014
Minimum
Sep. 30, 2014
Maximum
Sep. 30, 2014
Storage Contract Administrative Agreements
Storage_Agreement
ft3
Sep. 30, 2013
Storage Contract Administrative Agreements
ft3
Nov. 1, 2014
New Storage Agreement
Energy Services
Public Utilities, Inventory
 
 
 
 
 
Number of storage agreements (in storage agreements)
 
 
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)
 
 
3,900,000,000 
600,000,000 
 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
 
 
$ 16.8 
$ 2.4 
 
Storage Agreement Term
1 year 
3 years 
 
 
1 year 
Inventories - Schedule of Inventories (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Public Utilities, Inventory
 
 
Total inventories
$ 423.0 
$ 365.5 
Non-utility LPG and Natural Gas
 
 
Public Utilities, Inventory
 
 
Total inventories
283.6 
230.0 
Gas Utility Natural Gas
 
 
Public Utilities, Inventory
 
 
Total inventories
82.7 
78.9 
Materials, Supplies and Other
 
 
Public Utilities, Inventory
 
 
Total inventories
$ 56.7 
$ 56.6 
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Property, Plant and Equipment
 
 
Utilities
$ 2,568.5 
$ 2,427.8 
Non-utility
4,608.2 
4,612.7 
Total property, plant and equipment
7,176.7 
7,040.5 
Distribution
 
 
Property, Plant and Equipment
 
 
Utilities
2,294.6 
2,162.6 
Transmission
 
 
Property, Plant and Equipment
 
 
Utilities
88.2 
86.6 
General and Other, Including Work-in-Process
 
 
Property, Plant and Equipment
 
 
Utilities
185.7 
178.6 
Land
 
 
Property, Plant and Equipment
 
 
Non-utility
170.2 
178.4 
Building and Improvements
 
 
Property, Plant and Equipment
 
 
Non-utility
317.4 
308.1 
Transportation Equipment
 
 
Property, Plant and Equipment
 
 
Non-utility
288.4 
273.8 
Equipment, Primarily Cylinders and Tanks
 
 
Property, Plant and Equipment
 
 
Non-utility
3,042.7 
3,161.9 
Electric Generation
 
 
Property, Plant and Equipment
 
 
Non-utility
273.4 
264.8 
Pipeline and Related Assets
 
 
Property, Plant and Equipment
 
 
Non-utility
162.3 
22.5 
Other, Including Work-in-Process
 
 
Property, Plant and Equipment
 
 
Non-utility
$ 353.8 
$ 403.2 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
Amortization expense of intangible assets
$ 48.2 
$ 52.8 
$ 44.5 
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
 
 
 
Fiscal 2015
51.9 
 
 
Fiscal 2016
44.7 
 
 
Fiscal 2017
37.9 
 
 
Fiscal 2018
36.4 
 
 
Fiscal 2019
$ 34.7 
 
 
Goodwill and Intangible Assets - Changes in the Carrying Amount of Goodwill (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Goodwill
 
 
Goodwill - balance at beginning of period
$ 2,873.7 
$ 2,818.3 
Acquisitions
9.6 
12.5 
Correcting adjustment
(1.8)
9.3 
Foreign currency translation
(48.1)
33.6 
Goodwill - balance at beginning of period
2,833.4 
2,873.7 
AmeriGas Propane
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
1,941.0 
1,919.2 
Acquisitions
6.8 
12.5 
Correcting adjustment
(2.7)
9.3 
Foreign currency translation
Goodwill - balance at beginning of period
1,945.1 
1,941.0 
Gas Utility
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
182.1 
182.1 
Acquisitions
Correcting adjustment
Foreign currency translation
Goodwill - balance at beginning of period
182.1 
182.1 
Energy Services
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
2.8 
2.8 
Acquisitions
2.8 
Correcting adjustment
Foreign currency translation
Goodwill - balance at beginning of period
5.6 
2.8 
Antargaz
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
643.7 
612.0 
Acquisitions
Correcting adjustment
Foreign currency translation
(42.5)
31.7 
Goodwill - balance at beginning of period
601.2 
643.7 
Flaga & Other
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
97.1 
95.2 
Acquisitions
   
Correcting adjustment
0.9 
Foreign currency translation
(5.6)
1.9 
Goodwill - balance at beginning of period
92.4 
97.1 
Corporate & Other
 
 
Goodwill
 
 
Goodwill - balance at beginning of period
7.0 1
7.0 1
Acquisitions
Correcting adjustment
Foreign currency translation
Goodwill - balance at beginning of period
$ 7.0 1
$ 7.0 1
[1] Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, (4) UGI Corporation’s unallocated corporate and general expenses and interest income and (5) net (losses) gains on Midstream & Marketing’s unsettled commodity derivative instruments and certain settled commodity derivative instruments not associated with current period transactions, and net (losses) gains on AmeriGas Propane’s unsettled commodity derivative instruments entered into beginning April 1, 2014, totaling $(18.0), $7.4 and $15.1 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
Goodwill and Intangible Assets - Components of Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
Customer relationships, noncompete agreements and other
$ 712.0 
$ 704.8 
Trademarks and tradenames (not subject to amortization)
128.2 
130.2 
Gross carrying amount
840.2 
835.0 
Accumulated amortization
(263.8)
(227.1)
Intangible assets, net
$ 576.4 
$ 607.9 
Series Preferred Stock (Details)
Sep. 30, 2014
Sep. 30, 2013
UGI Series Preferred Stock
 
 
Preferred Stock, Authorized
10,000,000 
 
Preferred Stock, Shares Outstanding
0.0 
0.0 
UGI Utilities Series Preferred Stock
 
 
Preferred Stock, Authorized
2,000,000 
 
Preferred Stock, Shares Outstanding
0.0 
0.0 
Common Stock And Equity Based Compensation (Details) (USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Jan. 30, 2014
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2012
UGI Corporation
Sep. 30, 2014
UGI Corporation Common Stock
Sep. 30, 2013
UGI Corporation Common Stock
Sep. 30, 2012
UGI Corporation Common Stock
Jan. 30, 2014
UGI Corporation Common Stock
Mar. 31, 2012
AmeriGas Partners Common Units
Sep. 30, 2014
UGI Stock Option Awards
Sep. 30, 2013
UGI Stock Option Awards
Sep. 30, 2012
UGI Stock Option Awards
Sep. 30, 2014
Amerigas Performance Units and Stock Units
Sep. 30, 2013
Amerigas Performance Units and Stock Units
Sep. 30, 2012
Amerigas Performance Units and Stock Units
Sep. 30, 2014
AmeriGas Performance Unit
Sep. 30, 2014
AmeriGas Partners Common Units
Sep. 30, 2014
UGI Performance Units and Stock Units
Sep. 30, 2013
UGI Performance Units and Stock Units
Sep. 30, 2012
UGI Performance Units and Stock Units
Sep. 30, 2014
UGI Stock Units
Sep. 30, 2013
UGI Stock Units
Sep. 30, 2012
UGI Stock Units
Sep. 30, 2014
UGI Performance Units
Sep. 30, 2013
UGI Performance Units
Sep. 30, 2012
UGI Performance Units
Jan. 12, 2012
Heritage Propane
Jan. 12, 2012
Heritage Propane
Sep. 30, 2014
Noncontrolling Interests
Sep. 30, 2013
Noncontrolling Interests
Sep. 30, 2012
Noncontrolling Interests
Sep. 30, 2012
Noncontrolling Interests
UGI Corporation
Sep. 30, 2014
2004 Omnibus Equity Compensation Plan (OECP)
UGI Corporation Common Stock
Sep. 30, 2014
2004 Omnibus Equity Compensation Plan (OECP)
UGI Performance Units and Stock Units
Sep. 30, 2014
2004 Omnibus Equity Compensation Plan (OECP)
UGI Performance Units
Sep. 30, 2014
2013 Omnibus Incentive Compensation Plan (OICP)
UGI Corporation Common Stock
Jan. 24, 2013
2013 Omnibus Incentive Compensation Plan (OICP)
UGI Corporation Common Stock
Sep. 30, 2014
2013 Omnibus Incentive Compensation Plan (OICP)
UGI Performance Units and Stock Units
Sep. 30, 2014
2013 Omnibus Incentive Compensation Plan (OICP)
UGI Performance Units
Sep. 30, 2014
2010 Propane Plan
Amerigas Performance Units and Stock Units
Jun. 30, 2010
2010 Propane Plan
Amerigas Performance Units and Stock Units
Sep. 30, 2013
2010 Propane Plan
AmeriGas Performance Unit
Sep. 30, 2014
2010 Propane Plan
AmeriGas Partners Common Units
Sep. 30, 2013
2010 Propane Plan
AmeriGas Partners Common Units
Sep. 30, 2012
2010 Propane Plan
AmeriGas Partners Common Units
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum number of shares authorized for repurchase
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Issued During Period, Shares, Share-based Compensation, Gross
 
 
 
 
 
94,950 
238,800 
176,250 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Treasury stock acquired (in usd)
 
$ 44.7 
$ 32.3 
 
 
 
 
 
$ 39.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Units issued by AmeriGas Partners (in units)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29,567,362 
29,567,362 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Units sold in public offering
 
 
 
 
 
 
 
 
 
7,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in stockholders' equity, net
 
 
 
 
196.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(321.4)
(321.4)
 
 
 
 
 
 
 
 
 
 
 
 
 
Pre-tax equity-based compensation expense
 
25.8 
17.6 
14.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
After tax equity-based compensation expense
 
16.6 
11.4 
8.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shares of UGI Common Stock granted as awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,750,000 
 
 
 
2,800,000 
 
 
 
 
Cash received from stock option exercises
 
22.2 
30.8 
9.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Associated tax benefits
 
13.0 
12.1 
2.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized compensation cost associated with unvested Amerigas unit awards
 
6.5 
 
 
 
 
 
 
 
 
 
 
 
2.9 
 
 
 
 
8.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-average period for unvested Amerigas unit awards
 
1 year 8 months 12 days 
 
 
 
 
 
 
 
 
 
 
 
1 year 8 months 12 days 
 
 
 
 
1 year 8 months 12 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-average fair value of stock option granted under stock plans
 
 
 
 
 
 
 
 
 
 
$ 4.97 
$ 3.29 
$ 2.87 
 
 
 
 
 
 
 
 
 
 
 
$ 32.32 
$ 25.31 
$ 18.17 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 43.34 
$ 42.58 
$ 43.22 
Award performance period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Target award paid to employee
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
grantees may receive 0% to 200% of the target award granted. For such grants, 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% 
 
 
 
grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; and at the 90th percentile and above, 200% 
 
 
 
 
 
 
 
Minimum percentage amount of guarantee on target award granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.00% 
 
 
 
0.00% 
 
 
 
 
 
 
Maximum percentage amount of guarantee on target award granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200.00% 
 
 
 
200.00% 
 
 
 
 
 
 
Percentage of target award paid at 40th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
70.00% 
 
 
 
 
 
 
Percentage of target award paid at 50th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
100.00% 
 
 
 
 
 
 
Percentage of target award paid at 100th percentile
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
200.00% 
 
 
 
200.00% 
 
 
 
 
 
 
Expected term of Performance Unit awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
Granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
53,800 
32,658 
234,264 
381,900 
359,768 
44,814 1
51,038 
63,668 
189,450 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
86,458 
65,136 
248,818 
Weighted average grant date fair value unit awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 41.50 
$ 46.37 
$ 31.38 
$ 24.87 
$ 18.45 
$ 27.41 1
 
 
$ 32.32 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized compensation cost associated with common unit
 
 
 
 
 
 
 
 
 
 
 
 
 
200,235 
224,167 
 
 
 
1,306,181 
1,380,902 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of AmeriGas units vested
 
 
 
 
 
 
 
 
 
 
 
 
 
4.1 
2.8 
5.1 
 
 
8.7 
6.0 
3.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities associated with share based compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1.5 
$ 1.1 
 
 
 
$ 18.5 
$ 8.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of common units subject to original awards granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
172,646 
 
 
17,499,524 
 
 
 
 
 
 
2,443,808 
 
 
Performance units ultimately paid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
Granted Under Plan Term (in years)
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Repurchase Program, Period in Force
4 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock and Equity Based Compensation - Common Stock Share Activity (Details) (UGI Corporation Common Stock)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Common Stock Share Activity
 
 
 
Shares, Issued
173,675,691 
173,436,891 
173,260,641 
Shares, Outstanding
171,643,287 
168,930,632 
167,754,033 
Stock Issued During Period, Shares, Share-based Compensation, Gross
94,950 
238,800 
176,250 
Stock Issued And Outstanding During Period, Shares, Share-based Compensation, Gross
3,023,090 
4,172,307 
1,413,638 
Stock Issued During Period, Shares, Dividend Reinvestment Plan
 
Stock Issued And Outstanding During Period, Shares, Dividend Reinvestment Plan
 
93,253 
157,491 
Stock Repurchased During Period, Shares
 
 
Stock Repurchased and Outstanding During Period, Shares
(1,227,654)
 
 
Stock Reacquired During Period, Shares, Share-based Compensation
Stock Reacquired And Outstanding During Period, Shares, Share-based Compensation
(1,164,942)
(1,552,905)
(394,530)
Shares, Issued
173,770,641 
173,675,691 
173,436,891 
Shares, Outstanding
172,273,781 
171,643,287 
168,930,632 
Treasury Stock
 
 
 
Common Stock Share Activity
 
 
 
Shares, Issued
2,032,404 
4,506,259 
5,506,608 
Stock Issued During Period, Shares, Share-based Compensation, Gross
2,928,140 
3,933,507 
1,237,388 
Stock Issued During Period, Shares, Dividend Reinvestment Plan
 
93,253 
157,491 
Stock Repurchased During Period, Shares
(1,227,654)
 
 
Stock Reacquired During Period, Shares, Share-based Compensation
(1,164,942)
(1,552,905)
(394,530)
Shares, Issued
1,496,860 
2,032,404 
4,506,259 
Common Stock and Equity Based Compensation - Stock Option Awards (Details) (UGI Stock Option Awards, USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2011
UGI Stock Option Awards
 
 
 
 
Shares
 
 
 
 
Shares under option - beginning balance (in shares)
10,193,952 
12,086,658 
11,509,769 
 
Granted
1,665,600 
2,275,350 
2,262,075 
 
Cancelled
(86,707)
(134,754)
(482,400)
 
Exercised
(2,815,555)
(4,033,302)
(1,202,786)
 
Shares under option - ending balance (in shares)
8,957,290 
10,193,952 
12,086,658 
11,509,769 
Weighted Average Option Price
 
 
 
 
Shares under option - beginning balance (in usd per share)
$ 19.28 
$ 17.75 
$ 17.03 
 
Granted
$ 27.93 
$ 22.38 
$ 19.51 
 
Cancelled
$ 22.76 
$ 20.34 
$ 18.49 
 
Exercised
$ 17.44 
$ 16.39 
$ 13.95 
 
Shares under option - ending balance (in usd per share)
$ 21.44 
$ 19.28 
$ 17.75 
$ 17.03 
Total Intrinsic Value
 
 
 
 
Shares under option - beginning balance (in usd)
$ 69.6 
$ 41.4 
$ 15.1 
 
Exercised
37.4 
35.4 
7.2 
 
Shares under option - beginning balance (in usd)
113.3 
69.6 
41.4 
15.1 
Weighted Average Contract Term
 
 
 
 
Weighted average contract term (in years)
7 years 0 months 0 days 
6 years 9 months 18 days 
6 years 1 month 6 days 
6 years 2 months 12 days 
Options Exercisable [Abstract]
 
 
 
 
Options exercisable (in shares)
5,073,347 
5,871,091 
7,976,547 
 
Option exercisable (in usd per share)
$ 19.45 
$ 17.95 
$ 16.88 
 
Option exercisable (in usd)
74.2 
 
 
 
Option exercisable (in years)
6 years 0 months 0 days 
 
 
 
Options Not Exercisable [Abstract]
 
 
 
 
Options not exercisable (in shares)
3,883,943 
 
 
 
Options not exercisable (in usd per share)
$ 24.02 
 
 
 
Options not exercisable (in usd)
$ 39.1 
 
 
 
Options not exercisable (in years)
8 years 6 months 
 
 
 
Common Stock and Equity Based Compensation Common Stock and Equity Based Compensation - Additional Information Relating to Stock Options Outstanding and Exercisable (Details) (UGI Stock Option Awards, USD $)
12 Months Ended
Sep. 30, 2014
Under $15.00
 
Share-based Compensation Arrangement by Share-based Payment Award
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit
$ 0 
Number of options
102,000 
Weighted average remaining contractual life (in years)
1 year 4 months 24 days 
Weighted average exercise price
$ 14.47 
Number of options
102,000 
Weighted average exercise price
$ 14.47 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit
$ 15.00 
$15.01 - $20.00
 
Share-based Compensation Arrangement by Share-based Payment Award
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit
$ 15.01 
Number of options
3,452,480 
Weighted average remaining contractual life (in years)
5 years 8 months 12 days 
Weighted average exercise price
$ 18.15 
Number of options
2,727,509 
Weighted average exercise price
$ 17.81 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit
$ 20 
$20.01 - $25.00
 
Share-based Compensation Arrangement by Share-based Payment Award
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit
$ 20.01 
Number of options
3,500,910 
Weighted average remaining contractual life (in years)
7 years 2 months 12 days 
Weighted average exercise price
$ 21.45 
Number of options
2,077,840 
Weighted average exercise price
$ 21.27 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit
$ 25 
Over $25.00
 
Share-based Compensation Arrangement by Share-based Payment Award
 
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit
$ 25.01 
Number of options
1,901,900 
Weighted average remaining contractual life (in years)
9 years 2 months 12 days 
Weighted average exercise price
$ 27.74 
Number of options
165,998 
Weighted average exercise price
$ 26.85 
Common Stock and Equity Based Compensation - Assumptions Used for Valuing Option Grants (Details) (UGI Stock Option Awards)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
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
24.30% 
24.90% 
24.70% 
Weighted average dividend yield
2.90% 
3.60% 
3.50% 
Minimum
 
 
 
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected volatility
23.70% 
24.40% 
24.70% 
Expected dividend yield
2.70% 
3.20% 
3.30% 
Risk-free rate
1.80% 
0.80% 
0.80% 
Maximum
 
 
 
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
 
 
 
Expected volatility
24.40% 
24.90% 
24.70% 
Expected dividend yield
2.90% 
3.70% 
3.70% 
Risk-free rate
2.00% 
1.70% 
1.10% 
Common Stock And Equity Based Compensation - UGI Performance Unit Award Activity (Details) (USD $)
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
UGI Performance Units and Stock Units
 
 
 
UGI Unit Award Activity
 
 
 
Number of Equity-based Units - beginning balance (in units)
1,380,902 
 
 
Granted
234,264 
381,900 
359,768 
Number of Equity-based Units - ending balance (in units)
1,306,181 
1,380,902 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Weighted Average Grant Date Fair Value - beginning balance (in usd per unit)
$ 18.35 
 
 
Granted
$ 31.38 
$ 24.87 
$ 18.45 
Weighted Average Grant Date Fair Value - ending balance (in usd per unit)
$ 20.58 
$ 18.35 
 
UGI Performance Units
 
 
 
UGI Unit Award Activity
 
 
 
Granted
189,450 
 
 
Forfeited
(7,200)
 
 
Vested
 
 
Unit awards paid
(267,146)
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 32.32 
 
 
Forfeited
$ 24.95 
 
 
Vested
$ 0.00 
 
 
Unit awards paid
$ 22.17 
 
 
UGI Stock Units
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
Shares Granted under Stock Awards
approximately 70% in shares 
 
 
UGI Unit Award Activity
 
 
 
Granted
44,814 1
51,038 
63,668 
Vested
 
 
Unit awards paid
(34,639)
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 27.41 1
 
 
Vested
$ 0 
 
 
Unit awards paid
$ 14.41 
 
 
Vested |
UGI Performance Units and Stock Units
 
 
 
UGI Unit Award Activity
 
 
 
Number of Equity-based Units - ending balance (in units)
781,231 
822,975 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Weighted Average Grant Date Fair Value - ending balance (in usd per unit)
$ 16.60 
$ 15.45 
 
Vested |
UGI Performance Units
 
 
 
UGI Unit Award Activity
 
 
 
Granted
9,570 
 
 
Forfeited
 
 
Vested
205,282 
 
 
Unit awards paid
(267,146)
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 32.02 
 
 
Forfeited
$ 0.00 
 
 
Vested
$ 21.15 
 
 
Unit awards paid
$ 22.17 
 
 
Vested |
UGI Stock Units
 
 
 
UGI Unit Award Activity
 
 
 
Granted
43,689 1
 
 
Vested
1,500 
 
 
Unit awards paid
(34,639)
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 27.35 1
 
 
Vested
$ 22.29 
 
 
Unit awards paid
$ 14.41 
 
 
Non-Vested |
UGI Performance Units and Stock Units
 
 
 
UGI Unit Award Activity
 
 
 
Number of Equity-based Units - ending balance (in units)
524,950 
557,927 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Weighted Average Grant Date Fair Value - ending balance (in usd per unit)
$ 26.51 
$ 22.62 
 
Non-Vested |
UGI Performance Units
 
 
 
UGI Unit Award Activity
 
 
 
Granted
179,880 
 
 
Forfeited
(7,200)
 
 
Vested
(205,282)
 
 
Unit awards paid
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 32.33 
 
 
Forfeited
$ 24.95 
 
 
Vested
$ 21.15 
 
 
Unit awards paid
$ 0 
 
 
Non-Vested |
UGI Stock Units
 
 
 
UGI Unit Award Activity
 
 
 
Granted
1,125 1
 
 
Vested
(1,500)
 
 
Unit awards paid
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
 
Granted
$ 29.84 1
 
 
Vested
$ 22.29 
 
 
Unit awards paid
$ 0 
 
 
Common Stock And Equity Based Compensation - Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
UGI Performance Units
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
Number of original awards granted
331,038 
328,025 
316,125 
Fiscal year granted
2011 
2010 
2009 
Payment of awards:
 
 
 
Shares of UGI Common Stock issued
174,168 
97,622 
Cash paid
$ 3.1 
$ 1.6 
$ 0 
UGI Stock Units
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
Number of original awards granted
34,639 
54,269 
49,347 
Payment of awards:
 
 
 
Shares of UGI Common Stock issued
22,604 
35,274 
32,636 
Cash paid
$ 0.4 
$ 0.5 
$ 0.2 
Common Stock And Equity Based Compensation - AmeriGas Common Unit Based Award Activity (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended
Sep. 30, 2014
Amerigas Performance Units and Stock Units
Sep. 30, 2013
Amerigas Performance Units and Stock Units
Sep. 30, 2014
AmeriGas Performance Unit
Sep. 30, 2014
AmeriGas Partners Common Units
Sep. 30, 2014
Vested
Amerigas Performance Units and Stock Units
Sep. 30, 2013
Vested
Amerigas Performance Units and Stock Units
Sep. 30, 2014
Vested
AmeriGas Performance Unit
Sep. 30, 2014
Vested
AmeriGas Partners Common Units
Sep. 30, 2014
Non-Vested
Amerigas Performance Units and Stock Units
Sep. 30, 2013
Non-Vested
Amerigas Performance Units and Stock Units
Sep. 30, 2014
Non-Vested
AmeriGas Performance Unit
Sep. 30, 2014
Non-Vested
AmeriGas Partners Common Units
Number of AmeriGas Partners Common Units Subject to Award
 
 
 
 
 
 
 
 
 
 
 
 
Number of Equity-based Units - beginning balance (in units)
200,235 
224,167 
 
 
37,207 
47,715 
 
 
163,028 
176,452 
 
 
Granted
 
 
53,800 
32,658 
 
 
633 
15,936 
 
 
53,167 
16,722 
Forfeited
 
 
(8,150)
(7,783)
 
 
 
 
(8,150)
(7,783)
Vested
 
 
 
 
15,319 
52,061 
 
 
(15,319)
(52,061)
Performance criteria not met
 
 
(31,317)
 
 
 
(31,317)
 
 
 
 
Awards paid
 
 
 
(63,140)
 
 
 
(63,140)
 
 
 
Number of Equity-based Units - ending balance (in units)
200,235 
224,167 
 
 
37,207 
47,715 
 
 
163,028 
176,452 
 
 
Weighted Average Grant Date Fair Value (per Unit)
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Grant Date Fair Value - beginning balance (in usd per unit)
$ 44.82 
$ 47.88 
 
 
$ 44.27 
$ 47.92 
 
 
$ 44.95 
$ 47.87 
 
 
Granted
 
 
$ 41.50 
$ 46.37 
 
 
$ 41.37 
$ 48.00 
 
 
$ 41.50 
$ 44.81 
Forfeited
 
 
$ 45.96 
$ 51.10 
 
 
$ 0.00 
$ 0.00 
 
 
$ 45.96 
$ (51.10)
Vested
 
 
$ 0.00 
$ 0.00 
 
 
$ 53.93 
$ 47.58 
 
 
$ 53.93 
$ 47.58 
Performance criteria not met
 
 
$ 54.51 
 
 
 
$ 54.51 
 
 
 
$ 0.00 
 
Unit awards paid
 
 
 
$ 48.00 
 
 
 
$ 48.00 
 
 
 
$ 0.00 
Weighted Average Grant Date Fair Value - ending balance (in usd per unit)
$ 44.82 
$ 47.88 
 
 
$ 44.27 
$ 47.92 
 
 
$ 44.95 
$ 47.87 
 
 
Common Stock And Equity Based Compensation - AmeriGas Common Unit Based Awards in Common Units and Cash (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
AmeriGas Performance Unit
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
Number of Common Units subject to original awards granted
41,251 
48,150 
53,600 
Fiscal year granted
2011 
2010 
2009 
Payment of awards:
 
 
 
AmeriGas Partners Common Units issued
Cash paid
$ 0 
$ 0 
$ 0 
AmeriGas Partners Common Units
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award
 
 
 
Number of Common Units subject to original awards granted
72,023 
35,934 
67,246 
Payment of awards:
 
 
 
AmeriGas Partners Common Units issued
40,842 
23,192 
44,016 
Cash paid
$ 1.4 
$ 0.6 
$ 1.0 
Partnership Distributions and Common Unit Offerings (Details) (USD $)
12 Months Ended 1 Months Ended 12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Mar. 31, 2012
AmeriGas Partners
Mar. 31, 2012
6.50% Senior Notes Pursuant to Tender Offer
AmeriGas Partners
Sep. 30, 2014
Minimum
Sep. 30, 2013
Minimum
Sep. 30, 2012
Minimum
Distribution Made to Limited Partner
 
 
 
 
 
 
 
 
Policy for distribution to partner
45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) 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% 
 
 
 
 
 
 
 
Quarterly distribution
 
 
 
 
 
$ 0.55 
 
 
First target distribution
$ 0.055 
 
 
 
 
 
 
 
Available cash for per common unit
 
 
 
 
 
$ 0.605 
$ 0.605 
$ 0.605 
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 
 
 
 
 
 
 
 
General Partners distribution based on ownership interest
$ 32,400,000 
$ 27,400,000 
$ 19,700,000 
 
 
 
 
 
Incentive distributions received by the General partner
23,900,000 
19,300,000 
13,000,000 
 
 
 
 
 
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 
276,600,000 
 
 
 
 
General partners' contributed capital
 
 
 
2,800,000 
 
 
 
 
Aggregate principal amount
 
 
 
 
$ 200,000,000 
 
 
 
Interest rate stated percentage
 
 
 
 
6.50% 
 
 
 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
lawsuit
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2014
CPG MGP Properties
Sep. 30, 2014
PNG MGP Properties
Sep. 30, 2008
Partnership
lb
Sep. 30, 2014
Environmental Issue
Sep. 30, 2014
Maximum
Gas Utility
Sep. 30, 2014
Maximum
Midstream and Marketing
Sep. 30, 2014
Maximum
Partnership
Sep. 30, 2014
Maximum
UGI International
Sep. 30, 2014
The Partnership and UGI International
Minimum
Sep. 30, 2014
The Partnership and UGI International
Maximum
Sep. 30, 2014
UGI International
Minimum
Sep. 30, 2014
UGI International
Maximum
Commitments and Contingencies
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate rental expense for leases
$ 79.7 
$ 82.5 
$ 77.9 
 
 
 
 
 
 
 
 
 
 
 
 
Term of contracts
 
 
 
 
 
 
 
16 months 
2 years 
3 years 
3 years 
 
 
 
 
Contract terms subject to annual price and quantity ddjustments (in years)
 
 
 
 
 
 
 
 
 
 
 
1 year 
3 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
$ 10.7 
$ 14.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
Base year for determination of investigation and remediation cost (in years)
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
Amount of propane in cylinders being sold
 
 
 
 
 
17 
 
 
 
 
 
 
 
 
 
Reduced amount of propane in cylinders being sold
 
 
 
 
 
15 
 
 
 
 
 
 
 
 
 
Loss Contingency Class Action Lawsuit
35 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments and Contingencies - Minimum Future Payments Under Operating Leases (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Commitments and Contingencies
 
2015
$ 72.6 
2016
60.7 
2017
46.3 
2018
36.9 
2018
28.1 
After 2019
64.5 
AmeriGas Propane
 
Commitments and Contingencies
 
2015
56.2 
2016
46.6 
2017
36.5 
2018
30.6 
2018
25.9 
After 2019
63.0 
UGI Utilities
 
Commitments and Contingencies
 
2015
6.7 
2016
6.2 
2017
4.5 
2018
3.7 
2018
1.4 
After 2019
0.7 
UGI International
 
Commitments and Contingencies
 
2015
7.8 
2016
6.1 
2017
4.4 
2018
2.0 
2018
0.4 
After 2019
0.5 
Other
 
Commitments and Contingencies
 
2015
1.9 
2016
1.8 
2017
0.9 
2018
0.6 
2018
0.4 
After 2019
$ 0.3 
Commitments and Contingencies - Contractual Obligations Under Supply Storage and Service Contracts (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Recorded Unconditional Purchase Obligation
 
2015
$ 734.5 
2016
320.9 
2017
87.0 
2018
35.1 
2019
23.6 
After 2019
66.4 
UGI Utilities Supply, Storage and Transportation Contracts
 
Recorded Unconditional Purchase Obligation
 
2015
156.9 
2016
66.8 
2017
44.9 
2018
30.8 
2019
23.6 
After 2019
66.4 
Midstream & Marketing Supply Contracts
 
Recorded Unconditional Purchase Obligation
 
2015
302.1 
2016
107.0 
2017
42.1 
2018
4.3 
2019
After 2019
AmeriGas Propane Supply Contracts
 
Recorded Unconditional Purchase Obligation
 
2015
130.8 
2016
74.3 
2017
2018
2019
After 2019
UGI International Supply Contracts
 
Recorded Unconditional Purchase Obligation
 
2015
144.7 
2016
72.8 
2017
2018
2019
After 2019
$ 0 
Fair Value Measurement (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Fair Value Disclosures [Abstract]
 
 
Long-term Debt
$ 3,510.8 
$ 3,609.4 
Estimated fair value long-term debt
$ 3,686.1 
$ 3,761.8 
Fair Value Measurement - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
$ 45.4 
$ 26.3 1
Derivative financial liabilities
75.2 
57.5 1
Recurring Basis
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Non-qualified supplemental postretirement grantor trust investments
30.0 2
27.1 2
Recurring Basis |
Commodity Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
30.4 
25.4 1
Derivative financial liabilities
(54.1)
(18.1)1
Recurring Basis |
Foreign Currency Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
12.8 
0.9 1
Derivative financial liabilities
(0.1)
(7.2)1
Recurring Basis |
Interest Rate Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
0.1 
 
Derivative financial liabilities
(21.0)
(31.0)1
Recurring Basis |
Cross-currency Swaps
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
2.1 
 
Derivative financial liabilities
 
(1.2)1
Level 1 |
Recurring Basis
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Non-qualified supplemental postretirement grantor trust investments
30.0 2
27.1 2
Level 1 |
Recurring Basis |
Commodity Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
10.6 
2.6 1
Derivative financial liabilities
(21.2)
(8.8)1
Level 1 |
Recurring Basis |
Foreign Currency Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
1
Derivative financial liabilities
1
Level 1 |
Recurring Basis |
Interest Rate Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
 
Derivative financial liabilities
1
Level 1 |
Recurring Basis |
Cross-currency Swaps
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
 
Derivative financial liabilities
 
1
Level 2 |
Recurring Basis
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Non-qualified supplemental postretirement grantor trust investments
2
2
Level 2 |
Recurring Basis |
Commodity Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
19.8 
22.8 1
Derivative financial liabilities
(32.9)
(9.3)1
Level 2 |
Recurring Basis |
Foreign Currency Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
12.8 
0.9 1
Derivative financial liabilities
(0.1)
(7.2)1
Level 2 |
Recurring Basis |
Interest Rate Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
0.1 
 
Derivative financial liabilities
(21.0)
(31.0)1
Level 2 |
Recurring Basis |
Cross-currency Swaps
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
2.1 
 
Derivative financial liabilities
 
(1.2)1
Level 3 |
Recurring Basis
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Non-qualified supplemental postretirement grantor trust investments
2
2
Level 3 |
Recurring Basis |
Commodity Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
1
Derivative financial liabilities
1
Level 3 |
Recurring Basis |
Foreign Currency Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
1
Derivative financial liabilities
1
Level 3 |
Recurring Basis |
Interest Rate Contracts
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
 
Derivative financial liabilities
1
Level 3 |
Recurring Basis |
Cross-currency Swaps
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative financial assets
 
Derivative financial liabilities
 
$ 0 1
Derivative Instruments and Hedging Activities (Details)
In Millions, unless otherwise specified
0 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Sep. 30, 2014
gal
Sep. 30, 2013
gal
Sep. 30, 2014
USD ($)
Sep. 30, 2013
USD ($)
Sep. 30, 2014
Interest Rate Swaps [Member]
EUR (€)
Sep. 30, 2013
Interest Rate Swaps [Member]
EUR (€)
Sep. 30, 2014
Foreign Currency [Member]
USD ($)
Sep. 30, 2013
Foreign Currency [Member]
USD ($)
Sep. 30, 2012
Interest Rate Protection Agreements [Member]
USD ($)
Sep. 30, 2014
Interest Rate Protection Agreements [Member]
USD ($)
Sep. 30, 2013
Interest Rate Protection Agreements [Member]
USD ($)
Sep. 30, 2014
Net Investment Hedges
EUR (€)
Sep. 30, 2013
Net Investment Hedges
EUR (€)
Sep. 30, 2014
Electric transmission congestion - Electric Utility [Member]
kWh
Sep. 30, 2013
Electric transmission congestion - Electric Utility [Member]
kWh
Sep. 30, 2014
LPG [Member]
Sep. 30, 2014
Natural Gas [Member]
DTH
Sep. 30, 2013
Natural Gas [Member]
DTH
Sep. 30, 2014
Electricity (millions of kilowatt-hours) [Member]
Call Option [Member]
kWh
Sep. 30, 2013
Electricity (millions of kilowatt-hours) [Member]
Call Option [Member]
kWh
Sep. 30, 2014
Electricity (millions of kilowatt-hours) [Member]
Put Option [Member]
kWh
Sep. 30, 2013
Electricity (millions of kilowatt-hours) [Member]
Put Option [Member]
kWh
Sep. 30, 2014
Brokerage Accounts [Member]
USD ($)
Sep. 30, 2013
Brokerage Accounts [Member]
USD ($)
Sep. 30, 2014
Gas Utility
DTH
Sep. 30, 2013
Gas Utility
DTH
Sep. 30, 2014
Electric Utility - Forward Contract [Member]
kWh
Sep. 30, 2013
Electric Utility - Forward Contract [Member]
kWh
Sep. 30, 2014
Midstream And Marketing Natural Gas [Member]
DTH
Sep. 30, 2013
Midstream And Marketing Natural Gas [Member]
DTH
Sep. 30, 2014
Midstream And Marketing Propane Storage [Member]
gal
Sep. 30, 2013
Midstream And Marketing Propane Storage [Member]
gal
Sep. 30, 2014
Minimum
Foreign Currency [Member]
Sep. 30, 2014
Maximum
Foreign Currency [Member]
Sep. 30, 2014
Flaga Term Loan, due September 2016 [Member]
Flaga [Member]
Notes Payable to Banks
USD ($)
Sep. 30, 2013
Flaga Term Loan, due September 2016 [Member]
Flaga [Member]
Notes Payable to Banks
USD ($)
Sep. 30, 2013
Flaga Term Loan, due September 2016 [Member]
Flaga [Member]
Notes Payable to Banks
Cross Currency Contracts
USD ($)
Derivative
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative, Nonmonetary Notional Amount, Volume
344,500,000 
279,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge
 
 
21 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (in units)
 
 
 
 
 
 
 
 
 
 
 
 
 
232,100,000 
189,300,000 
 
113,700,000 
24,300,000 
394,400,000 
754,400,000 
206,600,000 
393,000,000 
 
 
16,900,000 
15,000,000 
237,000,000 
245,800,000 
3,900,000 
2,900,000 
1,300,000 
2,800,000 
 
 
 
 
 
Maximum length of time hedged in price risk cash flow hedges
 
 
 
 
 
 
27 months 
 
 
 
 
 
 
 
 
41 months 
 
 
24 months 
 
12 months 
 
 
 
12 months 
 
8 months 
 
 
 
 
 
 
 
 
 
 
Fair values of electric utility's forward purchase power agreements
 
 
$ (75.2)
$ (57.5)1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months
 
 
(2.3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underlying variable rate debt
 
 
 
 
401.1 
440.5 
219.8 
200.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
(2.7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
4.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt
 
 
3,510.8 
3,609.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52.0 
52.0 
52.0 
Restricted Cash in brokerage accounts
 
 
$ 16.6 
$ 8.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 16.6 
$ 7.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Instruments and Hedging Activities - Schedule of Derivative Assets, Liabilities and the Effects of Offsetting (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Derivatives, Fair Value
 
 
Derivative financial assets
$ 45.4 
$ 26.3 1
Derivative asset offset amount, net
(18.4)
(2.1)1
Total derivative assets - net
27.0 
24.2 1
Derivative financial liabilities
75.2 
57.5 1
Derivative liability offset amount, net
18.4 
2.1 1
Total derivative liabilities - net
(56.8)
(55.4)1
Designated as Hedging Instruments
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
17.8 
18.9 1
Derivative financial liabilities
(26.4)
(43.9)1
Designated as Hedging Instruments |
Commodity Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
2.8 
18.0 1
Derivative financial liabilities
(5.3)
(4.5)1
Designated as Hedging Instruments |
Foreign Currency Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
12.8 
0.9 1
Derivative financial liabilities
(0.1)
(7.2)1
Designated as Hedging Instruments |
Cross Currency Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
2.1 
1
Derivative financial liabilities
(1.2)1
Designated as Hedging Instruments |
Interest Rate Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
0.1 
1
Derivative financial liabilities
(21.0)
(31.0)1
Not Designated as Hedging Instruments |
Commodity Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
25.9 
7.4 1
Derivative financial liabilities
46.6 
6.9 1
Accounted for Under ASC 980 |
Commodity Contracts
 
 
Derivatives, Fair Value
 
 
Derivative financial assets
1.7 
1
Derivative financial liabilities
$ (2.2)
$ (6.7)1
Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Not Designated as Hedging Instruments
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Gain or (loss) recognized in income
$ (36.3)
$ 8.9 
$ 0.8 
Cash Flow Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
66.1 
21.7 
(135.3)
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income
47.3 
(63.8)
(70.8)
Commodity Contracts |
Not Designated as Hedging Instruments |
Cost of Sales
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Gain or (loss) recognized in income
(36.3)
9.3 
0.1 
Commodity Contracts |
Not Designated as Hedging Instruments |
Operating and Administrative Expenses/Other Income
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Gain or (loss) recognized in income
0.2 
Commodity Contracts |
Cash Flow Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
50.8 
8.3 
(98.0)
Commodity Contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income
67.0 
(49.5)
(61.4)
Foreign Currency Contracts |
Not Designated as Hedging Instruments |
Other income, net
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Gain or (loss) recognized in income
(0.4)
0.5 
Foreign Currency Contracts |
Cash Flow Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
15.3 
(8.3)
(0.5)
Foreign Currency Contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income
(3.7)
(0.1)
2.1 
Foreign Currency Contracts |
Net Investment Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
0.6 
Cross Currency Contracts |
Cash Flow Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
3.1 
(1.2)
Cross Currency Contracts |
Cash Flow Hedges |
Interest Expense/Other Income
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income
(0.1)
Interest Rate Contracts |
Cash Flow Hedges
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests
(3.1)
22.9 
(36.8)
Interest Rate Contracts |
Cash Flow Hedges |
Interest expense/other income, net [Member]
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income
$ (15.9)
$ (14.2)
$ (11.5)
Other Income Net (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Component of Operating Income [Abstract]
 
 
 
Interest and interest-related income
$ 3.6 
$ 2.2 
$ 2.4 
Utility non-tariff service income
2.7 
2.8 
2.7 
Finance charges
17.5 
21.4 
18.8 
Gains on sales of fixed assets
5.4 
1.4 
1.9 
Loss on private equity partnership investment
(6.3)
Other, net
6.9 
11.3 
14.0 
Total other income, net
$ 36.1 
$ 32.8 
$ 39.8 
Quarterly Data (unaudited) (Details) (USD $)
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Net income attributable to UGI Corporation
$ (19,800,000)
$ 20,600,000 
$ 214,400,000 
$ 122,000,000 1
$ (14,200,000)2
$ 9,100,000 
$ 180,700,000 
$ 102,500,000 
$ 337,200,000 
$ 278,100,000 
$ 210,200,000 
Earnings Per Share, Diluted
$ (0.11)
$ 0.12 
$ 1.22 
$ 0.70 1
$ (0.08)2
$ 0.05 
$ 1.05 
$ 0.60 
$ 1.92 
$ 1.60 
$ 1.24 
Other-than-temporary impairment of an investment in a private equity partnership pre-tax loss
 
 
 
 
 
 
 
 
6,300,000 
Increase in net loss due to impairment loss
 
 
 
 
 
 
 
 
 
3,700,000 
 
Increase in net loss per diluted share due to impairment loss
 
 
 
 
 
 
 
 
 
$ 0.02 
 
FRANCE |
Foreign Tax Authority [Member]
 
 
 
 
 
 
 
 
 
 
 
Income tax expense
 
 
 
5,700,000 
 
 
 
 
 
 
 
Restatement Adjustment [Member]
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to UGI Corporation
 
 
 
$ 5.7 
 
 
 
 
 
 
 
Earnings Per Share, Diluted
 
 
 
$ 0.03 
 
 
 
 
 
 
 
Quarterly Data (unaudited) - Schedule of Quarterly Data(Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,311.4 
$ 1,486.7 
$ 3,163.3 
$ 2,315.9 1
$ 1,259.0 2
$ 1,374.3 
$ 2,542.7 
$ 2,018.7 
$ 8,277.3 
$ 7,194.7 
$ 6,521.3 
Operating income (loss)
(9.4)
62.7 
588.6 
363.7 1
(12.3)2
41.5 
507.7 
294.2 
1,005.6 
831.1 
538.6 
Net income (loss)
(60.0)
(12.7)
387.8 
217.5 1
(59.1)2
(22.8)
341.7 
167.8 
532.6 
427.6 
197.7 
Net income (loss) attributable to UGI Corporation
$ (19.8)
$ 20.6 
$ 214.4 
$ 122.0 1
$ (14.2)2
$ 9.1 
$ 180.7 
$ 102.5 
$ 337.2 
$ 278.1 
$ 210.2 
Earnings (loss) per share attributable to UGI stockholders:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
$ (0.11)
$ 0.12 
$ 1.24 
$ 0.71 1
$ (0.08)2
$ 0.05 
$ 1.06 
$ 0.60 
$ 1.95 
$ 1.63 
$ 1.24 
Diluted (in dollars per share)
$ (0.11)
$ 0.12 
$ 1.22 
$ 0.70 1
$ (0.08)2
$ 0.05 
$ 1.05 
$ 0.60 
$ 1.92 
$ 1.60 
$ 1.24 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Reportable_Segments
States
Sep. 30, 2012
Segment Reporting [Abstract]
 
 
 
Number of Reportable Segments
 
 
Number of states to which product sale with propane revenue
 
50 
 
General Partner's interest in AmeriGas OLP
 
1.01% 
 
Gains (Losses) On Unsettled Commodity Derivative Instruments, Net
$ (18.0)
$ 7.4 
$ 15.1 
Segment Information - Schedule of Segment Reporting (Details) (USD $)
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,311,400,000 
$ 1,486,700,000 
$ 3,163,300,000 
$ 2,315,900,000 1
$ 1,259,000,000 2
$ 1,374,300,000 
$ 2,542,700,000 
$ 2,018,700,000 
$ 8,277,300,000 
$ 7,194,700,000 
$ 6,521,300,000 
Cost of sales
 
 
 
 
 
 
 
 
5,175,700,000 
4,324,400,000 
4,099,100,000 
Operating income (loss)
(9,400,000)
62,700,000 
588,600,000 
363,700,000 1
(12,300,000)2
41,500,000 
507,700,000 
294,200,000 
1,005,600,000 
831,100,000 
538,600,000 
Loss from equity investees
 
 
 
 
 
 
 
 
(100,000)
(400,000)
(300,000)
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
(13,300,000)
Interest expense
 
 
 
 
 
 
 
 
(237,700,000)
(240,300,000)
(220,400,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
767,800,000 
590,400,000 
304,600,000 
Net income (loss) attributable to UGI
(19,800,000)
20,600,000 
214,400,000 
122,000,000 1
(14,200,000)2
9,100,000 
180,700,000 
102,500,000 
337,200,000 
278,100,000 
210,200,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
362,900,000 
363,100,000 
315,000,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
195,400,000 
149,500,000 
(12,500,000)
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
655,300,000 3
 
 
Total assets
10,093,000,000 
 
 
 
10,008,800,000 
 
 
 
10,093,000,000 
10,008,800,000 
9,676,900,000 
Short-term borrowings
210,800,000 
 
 
 
227,900,000 
 
 
 
210,800,000 
227,900,000 
165,100,000 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
436,400,000 
489,100,000 
343,200,000 
Investments in equity investees
600,000 
 
 
 
300,000 
 
 
 
600,000 
300,000 
300,000 
Goodwill
2,833,400,000 
 
 
 
2,873,700,000 
 
 
 
2,833,400,000 
2,873,700,000 
2,818,300,000 
Eliminations
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
(321,300,000)4
(223,800,000)4
(178,800,000)4
Cost of sales
 
 
 
 
 
 
 
 
(317,700,000)4
(217,500,000)4
(174,000,000)4
Operating income (loss)
 
 
 
 
 
 
 
 
200,000 
(1,100,000)
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
200,000 
(1,100,000)
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
   
(600,000)
Depreciation and amortization
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
(86,500,000)
 
 
 
(100,300,000)
 
 
 
(86,500,000)
(100,300,000)
(104,100,000)
Short-term borrowings
 
 
 
 
 
 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
   
(1,100,000)
Investments in equity investees
 
 
 
 
 
 
Goodwill
 
 
 
 
 
 
AmeriGas Propane
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
3,712,900,000 
3,168,800,000 
2,921,500,000 
Cost of sales
 
 
 
 
 
 
 
 
2,107,100,000 
1,657,200,000 
1,722,400,000 
Operating income (loss)
 
 
 
 
 
 
 
 
472,000,000 
394,400,000 
168,700,000 
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
(13,300,000)
Interest expense
 
 
 
 
 
 
 
 
(165,600,000)
(166,600,000)
(141,500,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
306,400,000 
227,800,000 
13,900,000 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
63,000,000 
47,500,000 
15,400,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
197,200,000 
205,900,000 
168,100,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
195,800,000 
149,600,000 
(12,700,000)
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
664,800,000 3
596,500,000 3
322,100,000 3
Total assets
4,377,000,000 
 
 
 
4,429,300,000 
 
 
 
4,377,000,000 
4,429,300,000 
4,533,800,000 
Short-term borrowings
109,000,000 
 
 
 
116,900,000 
 
 
 
109,000,000 
116,900,000 
49,900,000 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
113,900,000 
111,100,000 
103,100,000 
Investments in equity investees
 
 
 
 
 
 
Goodwill
1,945,100,000 
 
 
 
1,941,000,000 
 
 
 
1,945,100,000 
1,941,000,000 
1,919,200,000 
Gas Utility
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
977,300,000 
839,000,000 
785,400,000 
Cost of sales
 
 
 
 
 
 
 
 
496,800,000 
407,200,000 
402,500,000 
Operating income (loss)
 
 
 
 
 
 
 
 
236,200,000 
196,500,000 
174,100,000 
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(36,600,000)
(37,400,000)
(40,100,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
199,600,000 
159,100,000 
134,000,000 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
118,800,000 
94,300,000 
81,600,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
54,800,000 
51,700,000 
49,000,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
2,214,100,000 
 
 
 
2,069,000,000 
 
 
 
2,214,100,000 
2,069,000,000 
2,045,500,000 
Short-term borrowings
86,300,000 
 
 
 
17,500,000 
 
 
 
86,300,000 
17,500,000 
9,200,000 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
156,400,000 
144,400,000 
109,000,000 
Investments in equity investees
 
 
 
 
 
 
Goodwill
182,100,000 
 
 
 
182,100,000 
 
 
 
182,100,000 
182,100,000 
182,100,000 
Energy Services
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
1,305,500,000 
969,400,000 
816,400,000 
Cost of sales
 
 
 
 
 
 
 
 
1,058,800,000 
836,900,000 
701,900,000 
Operating income (loss)
 
 
 
 
 
 
 
 
180,500,000 
82,500,000 
70,800,000 
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(2,900,000)
(3,200,000)
(4,800,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
177,600,000 
79,300,000 
66,000,000 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
105,200,000 
46,300,000 
38,700,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
12,300,000 
7,600,000 
3,700,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
569,000,000 
 
 
 
501,200,000 
 
 
 
569,000,000 
501,200,000 
368,500,000 
Short-term borrowings
7,500,000 
 
 
 
87,000,000 
 
 
 
7,500,000 
87,000,000 
85,000,000 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
67,800,000 
133,800,000 
36,000,000 
Investments in equity investees
 
 
 
 
 
 
Goodwill
5,600,000 
 
 
 
2,800,000 
 
 
 
5,600,000 
2,800,000 
2,800,000 
Electric Generation
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
85,100,000 
71,400,000 
43,900,000 
Cost of sales
 
 
 
 
 
 
 
 
39,600,000 
39,900,000 
28,000,000 
Operating income (loss)
 
 
 
 
 
 
 
 
18,100,000 
7,500,000 
(6,500,000)
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
Income (loss) before income taxes
 
 
 
 
 
 
 
 
18,100,000 
7,500,000 
(6,500,000)
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
12,600,000 
6,200,000 
(1,000,000)
Depreciation and amortization
 
 
 
 
 
 
 
 
10,700,000 
10,000,000 
9,000,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
277,700,000 
 
 
 
269,700,000 
 
 
 
277,700,000 
269,700,000 
258,200,000 
Short-term borrowings
 
 
 
 
 
 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
15,600,000 
22,600,000 
24,400,000 
Investments in equity investees
 
 
 
 
 
 
Goodwill
 
 
 
 
 
 
Antargaz
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
1,295,500,000 
1,322,600,000 
1,121,400,000 
Cost of sales
 
 
 
 
 
 
 
 
848,100,000 
845,000,000 
685,500,000 
Operating income (loss)
 
 
 
 
 
 
 
 
79,100,000 
111,400,000 
88,300,000 
Loss from equity investees
 
 
 
 
 
 
 
 
(100,000)
(400,000)
(300,000)
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(25,100,000)
(25,300,000)
(26,300,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
53,900,000 
85,700,000 
61,700,000 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
20,600,000 
57,200,000 
51,400,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
54,500,000 
57,600,000 
57,100,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
(400,000)
(200,000)
200,000 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
1,659,100,000 
 
 
 
1,784,400,000 
 
 
 
1,659,100,000 
1,784,400,000 
1,686,500,000 
Short-term borrowings
 
 
 
 
 
 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
50,200,000 
53,400,000 
47,300,000 
Investments in equity investees
 
 
 
 
 
 
Goodwill
601,200,000 
 
 
 
643,700,000 
 
 
 
601,200,000 
643,700,000 
612,000,000 
Flaga & Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
1,026,900,000 
856,600,000 
824,700,000 
Cost of sales
 
 
 
 
 
 
 
 
809,900,000 
653,400,000 
640,300,000 
Operating income (loss)
 
 
 
 
 
 
 
 
38,400,000 
35,600,000 
23,600,000 
Loss from equity investees
 
 
 
 
 
 
 
 
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(4,900,000)
(5,100,000)
(4,600,000)
Income (loss) before income taxes
 
 
 
 
 
 
 
 
33,500,000 
30,500,000 
19,000,000 
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
27,700,000 
25,500,000 
13,800,000 
Depreciation and amortization
 
 
 
 
 
 
 
 
27,100,000 
24,100,000 
22,100,000 
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
100,000 
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
   3
 
 
Total assets
643,600,000 
 
 
 
667,100,000 
 
 
 
643,600,000 
667,100,000 
531,800,000 
Short-term borrowings
8,000,000 
 
 
 
6,500,000 
 
 
 
8,000,000 
6,500,000 
21,000,000 
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
23,000,000 
17,400,000 
16,900,000 
Investments in equity investees
600,000 
 
 
 
300,000 
 
 
 
600,000 
300,000 
300,000 
Goodwill
92,400,000 
 
 
 
97,100,000 
 
 
 
92,400,000 
97,100,000 
95,200,000 
Corporate & Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
195,400,000 5
190,700,000 5
186,800,000 5
Cost of sales
 
 
 
 
 
 
 
 
133,100,000 5
102,300,000 5
92,500,000 5
Operating income (loss)
 
 
 
 
 
 
 
 
(18,900,000)5
4,300,000 5
19,600,000 5
Loss from equity investees
 
 
 
 
 
 
 
 
5
5
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(2,600,000)5
(2,700,000)5
(3,100,000)5
Income (loss) before income taxes
 
 
 
 
 
 
 
 
(21,500,000)5
1,600,000 5
16,500,000 5
Net income (loss) attributable to UGI
 
 
 
 
 
 
 
 
(10,700,000)5
1,700,000 5
10,300,000 5
Depreciation and amortization
 
 
 
 
 
 
 
 
6,300,000 5
6,200,000 5
6,000,000 5
Noncontrolling interests’ net income (loss)
 
 
 
 
 
 
 
 
5
5
5
Partnership EBITDA (a)
 
 
 
 
 
 
 
 
(9,500,000)3 5
 
 
Total assets
439,000,000 5
 
 
 
388,400,000 5
 
 
 
439,000,000 5
388,400,000 5
356,700,000 5
Short-term borrowings
5
 
 
 
5
 
 
 
5
5
5
Property, Plant and Equipment, Additions
 
 
 
 
 
 
 
 
9,500,000 5
7,500,000 5
6,500,000 5
Investments in equity investees
5
 
 
 
5
 
 
 
5
5
Goodwill
$ 7,000,000 5
 
 
 
$ 7,000,000 5
 
 
 
$ 7,000,000 5
$ 7,000,000 5
$ 7,000,000 5
[5] Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, (4) UGI Corporation’s unallocated corporate and general expenses and interest income and (5) net (losses) gains on Midstream & Marketing’s unsettled commodity derivative instruments and certain settled commodity derivative instruments not associated with current period transactions, and net (losses) gains on AmeriGas Propane’s unsettled commodity derivative instruments entered into beginning April 1, 2014, totaling $(18.0), $7.4 and $15.1 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
Segment Information - Reconciliation of Partnership EBITDA to AmeriGas Propane Operating Income (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Reconciliation of partnership EBITDA
 
 
 
 
 
 
 
 
 
 
 
Partnership EBITDA
 
 
 
 
 
 
 
 
$ 655.3 1
 
 
Depreciation and amortization
 
 
 
 
 
 
 
 
(362.9)
(363.1)
(315.0)
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
13.3 
Operating income
(9.4)
62.7 
588.6 
363.7 2
(12.3)3
41.5 
507.7 
294.2 
1,005.6 
831.1 
538.6 
AmeriGas Propane
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of partnership EBITDA
 
 
 
 
 
 
 
 
 
 
 
Partnership EBITDA
 
 
 
 
 
 
 
 
664.8 1
596.5 1
322.1 1
Depreciation and amortization
 
 
 
 
 
 
 
 
(197.2)
(205.9)
(168.1)
Loss on extinguishments of debt
 
 
 
 
 
 
 
 
13.3 
Noncontrolling interests (i)
 
 
 
 
 
 
 
 
4.4 4
3.8 4
1.4 4
Operating income
 
 
 
 
 
 
 
 
$ 472.0 
$ 394.4 
$ 168.7 
Condensed Financial Information of Registrant (Parent Company) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Guarantee Obligations
 
 
 
Dividend received from unconsolidated subsidiaries
$ 186.4 
$ 155.2 
$ 156.0 
Parent Company
 
 
 
Guarantee Obligations
 
 
 
Surety bonds indemnified
65.1 
 
 
Maximum amount authorized to guarantee obligations to suppliers and customers
500.0 
 
 
Current carrying value
414.1 
 
 
Flaga
 
 
 
Guarantee Obligations
 
 
 
Amount of floating to fixed rate interest rate swaps at Flaga
$ 3.5 
 
 
Condensed Financial Information of Registrant (Parent Company) - Balance Sheets (Details) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2011
Current assets
 
 
 
 
Cash and cash equivalents
$ 419.5 
$ 389.3 
$ 319.9 
$ 238.5 
Deferred income taxes
10.1 
10.6 
 
 
Total current assets
1,663.0 
1,627.3 
 
 
Other assets
209.0 
182.6 
 
 
Total assets
10,093.0 
10,008.8 
9,676.9 
 
Current liabilities
 
 
 
 
Derivative instruments
40.2 
30.0 
 
 
Total current liabilities
1,430.9 
1,424.9 
 
 
Commitments and contingencies (Note 1)
   
   
 
 
Common stockholders’ equity:
 
 
 
 
UGI Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,770,641 and 173,675,691 shares, respectively)
1,215.6 
1,208.1 
 
 
Retained earnings
1,509.4 
1,308.3 
 
 
Accumulated other comprehensive (loss) income
(21.2)
8.4 
 
 
Treasury stock, at cost
(44.7)
(32.3)
 
 
Total UGI Corporation stockholders’ equity
2,659.1 
2,492.5 
 
 
Total liabilities and equity
10,093.0 
10,008.8 
 
 
Condensed Financial Information of Registrant [Abstract]
 
 
 
 
UGI Common Stock, without par value (in dollars per share)
$ 0.00 
$ 0.00 
 
 
UGI Common Stock, without par value authorized (in shares)
450,000,000 
450,000,000 
 
 
UGI Common Stock, without par value, issued (in shares)
173,770,641 
173,675,691 
 
 
Parent Company
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
0.8 
0.9 
1.9 
0.4 
Accounts and notes receivable
3.9 
2.9 
 
 
Deferred income taxes
0.4 
0.4 
 
 
Prepaid expenses and other current assets
0.3 
0.3 
 
 
Total current assets
5.4 
4.5 
 
 
Investments in subsidiaries
2,663.9 
2,488.7 
 
 
Other assets
55.5 
49.9 
 
 
Total assets
2,724.8 
2,543.1 
 
 
Current liabilities
 
 
 
 
Accounts and notes payable
11.8 
11.0 
 
 
Derivative instruments
 
 
Accrued liabilities
6.0 
3.9 
 
 
Total current liabilities
17.8 
14.9 
 
 
Noncurrent liabilities
47.9 
35.7 
 
 
Commitments and contingencies (Note 1)
   
   
 
 
Common stockholders’ equity:
 
 
 
 
UGI Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,770,641 and 173,675,691 shares, respectively)
1,215.6 
1,208.1 
 
 
Retained earnings
1,509.4 
1,308.3 
 
 
Accumulated other comprehensive (loss) income
(21.2)
8.4 
 
 
Treasury stock, at cost
(44.7)
(32.3)
 
 
Total UGI Corporation stockholders’ equity
2,659.1 
2,492.5 
 
 
Total liabilities and equity
$ 2,724.8 
$ 2,543.1 
 
 
Condensed Financial Information of Registrant [Abstract]
 
 
 
 
UGI Common Stock, without par value (in dollars per share)
$ 0 
$ 0 
 
 
UGI Common Stock, without par value authorized (in shares)
450,000,000 
450,000,000 
 
 
UGI Common Stock, without par value, issued (in shares)
173,770,641 
173,675,691 
 
 
Condensed Financial Information of Registrant (Parent Company) - Statements of Income (Details) (USD $)
Share data in Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Condensed Financial Statements, Captions
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,311,400,000 
$ 1,486,700,000 
$ 3,163,300,000 
$ 2,315,900,000 1
$ 1,259,000,000 2
$ 1,374,300,000 
$ 2,542,700,000 
$ 2,018,700,000 
$ 8,277,300,000 
$ 7,194,700,000 
$ 6,521,300,000 
Costs and Expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and administrative expenses
 
 
 
 
 
 
 
 
1,752,600,000 
1,692,000,000 
1,591,100,000 
Other income, net
 
 
 
 
 
 
 
 
(36,100,000)
(32,800,000)
(39,800,000)
Total costs and expenses
 
 
 
 
 
 
 
 
7,271,700,000 
6,363,600,000 
5,982,700,000 
Operating (loss) income
(9,400,000)
62,700,000 
588,600,000 
363,700,000 1
(12,300,000)2
41,500,000 
507,700,000 
294,200,000 
1,005,600,000 
831,100,000 
538,600,000 
Income tax expense
 
 
 
 
 
 
 
 
235,200,000 
162,800,000 
106,900,000 
Equity in income of unconsolidated subsidiaries
 
 
 
 
 
 
 
 
(100,000)
(400,000)
(300,000)
Net income attributable to UGI Corporation
(19,800,000.0)
20,600,000.0 
214,400,000.0 
122,000,000.0 1
(14,200,000.0)2
9,100,000.0 
180,700,000.0 
102,500,000.0 
337,200,000.0 
278,100,000.0 
210,200,000.0 
Earnings per common share:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
$ (0.11)
$ 0.12 
$ 1.24 
$ 0.71 1
$ (0.08)2
$ 0.05 
$ 1.06 
$ 0.60 
$ 1.95 
$ 1.63 
$ 1.24 
Diluted (in dollars per share)
$ (0.11)
$ 0.12 
$ 1.22 
$ 0.70 1
$ (0.08)2
$ 0.05 
$ 1.05 
$ 0.60 
$ 1.92 
$ 1.60 
$ 1.24 
Average common shares outstanding (thousands):
 
 
 
 
 
 
 
 
 
 
 
Basic (in shares)
 
 
 
 
 
 
 
 
172,733 
170,885 
168,872 
Diluted (in shares)
 
 
 
 
 
 
 
 
175,231 
173,282 
170,148 
Parent Company
 
 
 
 
 
 
 
 
 
 
 
Condensed Financial Statements, Captions
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
Costs and Expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and administrative expenses
 
 
 
 
 
 
 
 
44,500,000 
36,900,000 
27,800,000 
Other income, net
 
 
 
 
 
 
 
 
(44,200,000)3
(36,700,000)3
(28,100,000)3
Total costs and expenses
 
 
 
 
 
 
 
 
300,000 
200,000 
(300,000)
Operating (loss) income
 
 
 
 
 
 
 
 
(300,000)
(200,000)
300,000 
Intercompany interest income
 
 
 
 
 
 
 
 
200,000 
200,000 
200,000 
(Loss) income before income taxes
 
 
 
 
 
 
 
 
(100,000)
500,000 
Income tax expense
 
 
 
 
 
 
 
 
2,400,000 
3,100,000 
300,000 
(Loss) income before equity in income of unconsolidated subsidiaries
 
 
 
 
 
 
 
 
(2,500,000)
(3,100,000)
200,000 
Equity in income of unconsolidated subsidiaries
 
 
 
 
 
 
 
 
339,700,000 
281,200,000 
210,000,000 
Net income attributable to UGI Corporation
 
 
 
 
 
 
 
 
$ 337,200,000.0 
$ 278,100,000.0 
$ 210,200,000.0 
Earnings per common share:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
 
 
 
 
 
 
 
 
$ 1.95 
$ 1.63 
$ 1.24 
Diluted (in dollars per share)
 
 
 
 
 
 
 
 
$ 1.92 
$ 1.60 
$ 1.24 
Average common shares outstanding (thousands):
 
 
 
 
 
 
 
 
 
 
 
Basic (in shares)
 
 
 
 
 
 
 
 
172,733 
170,885 
168,872 
Diluted (in shares)
 
 
 
 
 
 
 
 
175,231 
173,282 
170,148 
[3] 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) - Statements of Cash Flows (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Condensed Financial Statements, Captions
 
 
 
NET CASH PROVIDED BY OPERATING ACTIVITIES
$ 1,005.4 
$ 801.5 
$ 707.7 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Net cash used by investing activities
(487.6)
(553.3)
(1,904.5)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Dividends on UGI Common Stock
(136.1)
(125.8)
(119.1)
Repurchases of UGI Common Stock
(39.8)
Issuance of Common Stock
10.9 
36.4 
23.2 
Net cash (used) provided by financing activities
(475.7)
(186.1)
1,278.5 
Cash and cash equivalents increase
30.2 
69.4 
81.4 
CASH AND CASH EQUIVALENTS
 
 
 
End of year
419.5 
389.3 
319.9 
Beginning of year
389.3 
319.9 
238.5 
Increase
30.2 
69.4 
81.4 
Parent Company
 
 
 
Condensed Financial Statements, Captions
 
 
 
NET CASH PROVIDED BY OPERATING ACTIVITIES
199.7 1
139.4 1
158.3 1
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Net investments in unconsolidated subsidiaries
(47.3)
(59.1)
(54.4)
Net cash used by investing activities
(47.3)
(59.1)
(54.4)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Dividends on UGI Common Stock
(136.1)
(125.8)
(119.1)
Repurchases of UGI Common Stock
(39.8)
Issuance of Common Stock
23.4 
44.5 
16.7 
Net cash (used) provided by financing activities
(152.5)
(81.3)
(102.4)
Cash and cash equivalents increase
(0.1)
(1.0)
1.5 
CASH AND CASH EQUIVALENTS
 
 
 
End of year
0.8 
0.9 
1.9 
Beginning of year
0.9 
1.9 
0.4 
Increase
$ (0.1)
$ (1.0)
$ 1.5 
Valuation and Qualifying Accounts (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2012
Reserves Deducted From Assets In The Consolidated Balance Sheet
 
 
 
Valuation and Qualifying Account
 
 
 
Balance at beginning of year
$ 39.5 
$ 36.1 
$ 36.8 
Charged (credited) to costs and expenses
43.5 
30.2 
26.5 
Balance at end of year
39.1 
39.5 
36.1 
Reserves Deducted From Assets In The Consolidated Balance Sheet |
Allowance for Doubtful Accounts
 
 
 
Valuation and Qualifying Account
 
 
 
Other
43.0 1
27.4 1
26.8 1
Reserves Deducted From Assets In The Consolidated Balance Sheet |
Allowance for Foreign Currency Exchange Effects
 
 
 
Valuation and Qualifying Account
 
 
 
Other
0.9 2
(0.6)2
0.4 2
Other Reserves
 
 
 
Valuation and Qualifying Account
 
 
 
Balance at beginning of year
97.6 
77.0 
78.2 
Charged (credited) to costs and expenses
0.4 
(5.7)
(4.0)
Balance at end of year
59.2 
97.6 
77.0 
Other Reserves |
Valuation Allowance, Tax Credit Carryforward
 
 
 
Valuation and Qualifying Account
 
 
 
Other
34.0 3
26.3 3
 
Other Reserves |
Valuation Allowance, Operating Loss Carryforwards
 
 
 
Valuation and Qualifying Account
 
 
 
Other
4.8 4
 
 
Other Reserves |
Reserves of Businesses Acquired
 
 
 
Valuation and Qualifying Account
 
 
 
Other
 
 
$ 2.8 5