Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Sep. 30, 2017 | Nov. 14, 2017 | Mar. 31, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | UGI CORP /PA/ | ||
Entity Central Index Key | 884,614 | ||
Document Type | 10-K | ||
Document Period End Date | Sep. 30, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
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 | $ 8,491,215,725 | ||
Entity Common Stock, Shares Outstanding | 173,152,120 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Current assets | ||
Cash and cash equivalents | $ 558.4 | $ 502.8 |
Restricted cash | 10.3 | 15.6 |
Accounts receivable (less allowances for doubtful accounts of $26.9 and $27.3, respectively) | 626.8 | 551.6 |
Accrued utility revenues | 13.3 | 12.8 |
Inventories | 278.6 | 210.3 |
Utility regulatory assets | 8.3 | 3.2 |
Derivative instruments | 63.1 | 30.9 |
Prepaid expenses and other current assets | 138.7 | 96.6 |
Total current assets | 1,697.5 | 1,423.8 |
Property, plant and equipment | ||
Non-utility | 5,564.6 | 5,346.4 |
Utility | 3,285.3 | 2,998.9 |
Total property, plant and equipment | 8,849.9 | 8,345.3 |
Accumulated depreciation and amortization | (3,312.9) | (3,107.3) |
Net property, plant, and equipment | 5,537 | 5,238 |
Goodwill | 3,107.2 | 2,989 |
Intangible assets, net | 611.7 | 580.3 |
Utility regulatory assets | 360.6 | 391.9 |
Derivative instruments | 9.2 | 6.5 |
Other assets | 259 | 217.7 |
Total assets | 11,582.2 | 10,847.2 |
Current liabilities | ||
Current maturities of long-term debt | 177.5 | 29.5 |
Short-term borrowings | 366.9 | 291.7 |
Accounts payable | 439.6 | 391.2 |
Employee compensation and benefits accrued | 124.7 | 115.1 |
Deposits and advances | 206.9 | 241.3 |
Derivative instruments | 25 | 48.5 |
Accrued interest | 60.7 | 48.1 |
Other current liabilities | 288.8 | 276.6 |
Total current liabilities | 1,690.1 | 1,442 |
Debt and other liabilities | ||
Long-term debt | 3,994.6 | 3,766 |
Deferred income taxes | 1,357 | 1,212.4 |
Deferred investment tax credits | 3 | 3.3 |
Derivative instruments | 21.8 | 21.9 |
Other noncurrent liabilities | 774.8 | 806.6 |
Total liabilities | 7,841.3 | 7,252.2 |
Commitments and contingencies (Note 15) | ||
UGI Corporation stockholders’ equity: | ||
UGI Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) | 1,188.6 | 1,201.6 |
Retained earnings | 2,106.7 | 1,834.1 |
Accumulated other comprehensive loss | (93.4) | (154.7) |
Treasury stock, at cost | (38.6) | (36.9) |
Total UGI Corporation stockholders’ equity | 3,163.3 | 2,844.1 |
Noncontrolling interests, principally in AmeriGas Partners | 577.6 | 750.9 |
Total equity | 3,740.9 | 3,595 |
Total liabilities and equity | $ 11,582.2 | $ 10,847.2 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Statement of Financial Position [Abstract] | ||
Allowance for doubtful accounts | $ 26.9 | $ 27.3 |
Common stock, shares authorized | 450,000,000 | 450,000,000 |
Common stock, shares issued | 173,987,691 | 173,894,141 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Statement [Abstract] | |||
Revenues | $ 6,120.7 | $ 5,685.7 | $ 6,691.1 |
Costs and Expenses | |||
Cost of sales (excluding depreciation shown below) | 2,837.3 | 2,437.5 | 3,736.5 |
Operating and administrative expenses | 1,857.8 | 1,865.9 | 1,773.9 |
Utility taxes other than income taxes | 15.6 | 15.8 | 16.1 |
Depreciation | 357.3 | 338.6 | 313.2 |
Amortization | 59 | 62.3 | 60.9 |
Other operating income, net | (10.5) | (22.4) | (44.4) |
Total costs and expenses | 5,116.5 | 4,697.7 | 5,856.2 |
Operating income | 1,004.2 | 988 | 834.9 |
Income (loss) from equity investees | 4.3 | (0.2) | (1.2) |
Loss on extinguishments of debt | (59.7) | (48.9) | 0 |
Losses on foreign currency contracts, net | (23.9) | 0 | 0 |
Interest expense | (223.5) | (228.9) | (241.9) |
Income before income taxes | 701.4 | 710 | 591.8 |
Income taxes | (177.6) | (221.2) | (177.8) |
Net income including noncontrolling interests | 523.8 | 488.8 | 414 |
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (87.2) | (124.1) | (133) |
Net income attributable to UGI Corporation | $ 436.6 | $ 364.7 | $ 281 |
Earnings per common share attributable to UGI Corporation stockholders: | |||
Basic (in dollars per share) | $ 2.51 | $ 2.11 | $ 1.62 |
Diluted (in dollars per share) | $ 2.46 | $ 2.08 | $ 1.60 |
Weighted-average common shares outstanding (thousands): | |||
Basic (in shares) | 173,662 | 173,154 | 173,115 |
Diluted (in shares) | 177,159 | 175,572 | 175,667 |
Dividends declared per common share (in dollars per share) | $ 0.975 | $ 0.930 | $ 0.890 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net income including noncontrolling interests | $ 523.8 | $ 488.8 | $ 414 |
Net gains (losses) on derivative instruments (net of tax of $(0.5), $12.3 and $(8.0), respectively) | 1.7 | (16.5) | 16.8 |
Reclassifications of net (gains) losses on derivative instruments (net of tax of $4.1, $5.0 and $(2.8), respectively) | (9.7) | (8.1) | 1.6 |
Foreign currency translation adjustments (net of tax of $(0.6), $0.0 and $(1.0), respectively) | 34.6 | (4.9) | (63.5) |
Foreign currency gains (losses) on long-term intra-company transactions (net of tax of $0.0, $0.0 and $(6.7), respectively) | 24.8 | (1.9) | (50.6) |
Benefit plans, principally actuarial gains (losses) (net of tax of $(3.8), $7.1 and $1.4, respectively) | 6.5 | (10.9) | (1.2) |
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(2.1), $(0.4) and $(0.8), respectively) | 3.4 | 2.2 | 1.4 |
Other comprehensive income (loss) | 61.3 | (40.1) | (95.5) |
Comprehensive income including noncontrolling interests | 585.1 | 448.7 | 318.5 |
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | (87.2) | (124.1) | (130.9) |
Comprehensive income attributable to UGI Corporation | $ 497.9 | $ 324.6 | $ 187.6 |
Consolidated Statements of Com6
Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Tax on gains (losses) on derivative instruments | $ (0.5) | $ 12.3 | $ (8) |
Tax on reclassifications of net (gains) losses on derivative instruments | 4.1 | 5 | (2.8) |
Tax on foreign currency translation adjustments | (0.6) | 0 | (1) |
Tax on foreign currency gain (losses) on long-term intra-company transactions | 0 | 0 | (6.7) |
Tax on benefit plans, principally actuarial gains (losses) | (3.8) | 7.1 | 1.4 |
Tax on reclassifications of benefit plans actuarial losses and net prior service credits | $ (2.1) | $ (0.4) | $ (0.8) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income including noncontrolling interests | $ 523.8 | $ 488.8 | $ 414 |
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | |||
Depreciation and amortization | 416.3 | 400.9 | 374.1 |
Deferred income taxes, net | 110.1 | 77.4 | 13.7 |
Provision for uncollectible accounts | 30.7 | 21.7 | 31.6 |
Changes in unrealized (gains) losses on derivative instruments | (82) | (91.6) | 119.1 |
Equity-based compensation expense | 19.3 | 23.8 | 29.2 |
Loss on extinguishments of debt | 59.7 | 48.9 | 0 |
Settlement of UGI Utilities interest rate protection agreements | 0 | (36) | 0 |
Loss on private equity partnership investment | 11 | 0 | 0 |
Other, net | 44.1 | (7.3) | (9.7) |
Net change in: | |||
Accounts receivable and accrued utility revenues | (103.6) | 37.3 | 163.3 |
Inventories | (64.7) | 29.4 | 181.4 |
Utility deferred fuel costs, net of changes in unsettled derivatives | (15.4) | (22.7) | 51.8 |
Accounts payable | 49.9 | (40) | (134.9) |
Other current assets | (37.5) | (8.6) | (25.6) |
Other current liabilities | 2.7 | 47.7 | (44.2) |
Net cash provided by operating activities | 964.4 | 969.7 | 1,163.8 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Expenditures for property, plant and equipment | (638.9) | (563.8) | (490.6) |
Acquisitions of businesses, net of cash acquired | (101.6) | (61.2) | (447.5) |
Decrease (increase) in restricted cash | 6.1 | 53.7 | (52.8) |
Other, net | (29) | 12.7 | 14.6 |
Net cash used by investing activities | (763.4) | (558.6) | (976.3) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Dividends on UGI Common Stock | (168.9) | (160.7) | (153.5) |
Distributions on AmeriGas Partners publicly held Common Units | (261.6) | (257.3) | (248.9) |
Issuances of debt, net of issuance costs | 1,307.1 | 1,629.5 | 660.3 |
Repayments of debt, including redemption premiums | (1,064.8) | (1,569.9) | (429.4) |
Receivables Facility net borrowings | 13.5 | 6 | 12 |
Increase (decrease) in short-term borrowings | 61.2 | 95.7 | (31.9) |
Issuances of UGI Common Stock | 11 | 13.7 | 11.9 |
Repurchases of UGI Common Stock | (43.3) | (47.6) | (34.1) |
Other | (0.8) | 15.5 | (3.5) |
Net cash used by financing activities | (146.6) | (275.1) | (217.1) |
Effect of exchange rate changes on cash and cash equivalents | 1.2 | (2.9) | (20.2) |
Cash and cash equivalents increase (decrease) | 55.6 | 133.1 | (49.8) |
CASH AND CASH EQUIVALENTS | |||
End of year | 558.4 | 502.8 | 369.7 |
Beginning of year | 502.8 | 369.7 | 419.5 |
Increase (decrease) | 55.6 | 133.1 | (49.8) |
Cash paid for: | |||
Interest | 202.1 | 228.9 | 227 |
Income taxes | $ 98 | $ 134.5 | $ 173.1 |
Consolidated Statements of Chan
Consolidated Statements of Changes In Equity - USD ($) $ in Millions | Total | Total UGI Corporation stockholders’ equity | Common stock, without par value | Retained earnings | Accumulated other comprehensive income (loss) | Treasury stock | Noncontrolling interests |
Balance, beginning of year at Sep. 30, 2014 | $ 1,215.6 | $ 1,502.6 | $ (21.2) | $ (44.7) | $ 1,004.1 | ||
Common stock issued: | |||||||
Employee and director plans (including losses on treasury stock transactions), net of tax withheld | (22.1) | ||||||
Employee and director plans | 40.5 | ||||||
Excess tax benefits realized on equity-based compensation | 8.3 | ||||||
Equity-based compensation expense | 13.2 | ||||||
Loss from acquisition of noncontrolling interests through business combination | (0.4) | ||||||
Net income including noncontrolling interests | $ 414 | 281 | 133 | ||||
Cash dividends on common stock | (153.5) | ||||||
Net gains (losses) on derivative instruments | 16.8 | 16.8 | |||||
Reclassification of net (gains) losses on derivative instruments | 1.6 | 3.7 | |||||
Benefit plans, principally actuarial gains (losses) | (1.2) | (1.2) | |||||
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(2.1), $(0.4) and $(0.8), respectively) | 1.4 | 1.4 | |||||
Foreign currency gains (losses) on long-term intra-company transactions | (50.6) | (50.6) | |||||
Foreign currency translation adjustments | (63.5) | (63.5) | |||||
Repurchases of common stock | (34.1) | ||||||
Reacquired common stock – employee and director plans | (6.6) | ||||||
Reclassification of net gains on derivative instruments | (2.1) | ||||||
Dividends and distributions | (249.4) | ||||||
Change in noncontrolling interests as a result of business combination | (5.2) | ||||||
Balance, end of year at Sep. 30, 2015 | 3,565.6 | $ 2,685.2 | 1,214.6 | 1,630.1 | (114.6) | (44.9) | 880.4 |
Common stock issued: | |||||||
Employee and director plans (including losses on treasury stock transactions), net of tax withheld | (39.7) | ||||||
Employee and director plans | 84.7 | ||||||
Excess tax benefits realized on equity-based compensation | 15.5 | ||||||
Equity-based compensation expense | 11.2 | ||||||
Net income including noncontrolling interests | 488.8 | 364.7 | 124.1 | ||||
Cash dividends on common stock | (160.7) | ||||||
Net gains (losses) on derivative instruments | (16.5) | (16.5) | |||||
Reclassification of net (gains) losses on derivative instruments | (8.1) | (8.1) | |||||
Benefit plans, principally actuarial gains (losses) | (10.9) | (10.9) | |||||
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(2.1), $(0.4) and $(0.8), respectively) | 2.2 | 2.2 | |||||
Foreign currency gains (losses) on long-term intra-company transactions | (1.9) | (1.9) | |||||
Foreign currency translation adjustments | (4.9) | (4.9) | |||||
Repurchases of common stock | (47.6) | ||||||
Reacquired common stock – employee and director plans | (29.1) | ||||||
Dividends and distributions | (257.3) | ||||||
Other | 3.7 | ||||||
Balance, end of year at Sep. 30, 2016 | 3,595 | 2,844.1 | 1,201.6 | 1,834.1 | (154.7) | (36.9) | 750.9 |
Common stock issued: | |||||||
Cumulative effect of change in accounting for share-based payments | 4.9 | ||||||
Employee and director plans (including losses on treasury stock transactions), net of tax withheld | (28.2) | ||||||
Employee and director plans | 49.6 | ||||||
Equity-based compensation expense | 13.2 | ||||||
Sale of treasury stock | 2 | 0.2 | |||||
Net income including noncontrolling interests | 523.8 | 436.6 | 87.2 | ||||
Cash dividends on common stock | (168.9) | ||||||
Net gains (losses) on derivative instruments | 1.7 | 1.7 | |||||
Reclassification of net (gains) losses on derivative instruments | (9.7) | (9.7) | |||||
Benefit plans, principally actuarial gains (losses) | 6.5 | 6.5 | |||||
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(2.1), $(0.4) and $(0.8), respectively) | 3.4 | 3.4 | |||||
Foreign currency gains (losses) on long-term intra-company transactions | 24.8 | 24.8 | |||||
Foreign currency translation adjustments | 34.6 | 34.6 | |||||
Repurchases of common stock | (43.3) | ||||||
Reacquired common stock – employee and director plans | (8.2) | ||||||
Dividends and distributions | (261.6) | ||||||
Other | 1.1 | ||||||
Balance, end of year at Sep. 30, 2017 | $ 3,740.9 | $ 3,163.3 | $ 1,188.6 | $ 2,106.7 | $ (93.4) | $ (38.6) | $ 577.6 |
Nature of Operations
Nature of Operations | 12 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Operations | Note 1 — 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; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”) and market energy products and services. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.” 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”). 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, 2017 , the General Partner held a 1% general partner interest and a 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 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances (see Note 14 ). Our wholly owned subsidiary, UGI Enterprises, LLC (“Enterprises”) (formerly known as UGI Enterprises, Inc. prior to its merger with and into UGI Enterprises, LLC effective October 1, 2017), through subsidiaries, conducts (1) an LPG distribution business in France and in northern, central and eastern European countries, and (2) natural gas marketing businesses in France, Belgium and the United Kingdom, and a natural gas and electricity marketing business in the Netherlands. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH (“Flaga”) and AvantiGas Limited. We refer to our foreign operations collectively as “UGI International.” On May 29, 2015, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding), an indirect wholly owned subsidiary of UGI, purchased all of the outstanding shares of Totalgaz SAS (the “Totalgaz Acquisition”), a retail distributor of LPG in France. The retail LPG distribution business of Totalgaz SAS and its subsidiaries is referred to herein as “Finagaz” and is included in our UGI International reportable segment (see Notes 4 and 21 ). The retail LPG distribution business of France SAS prior to the Totalgaz Acquisition is also referred to herein as “Antargaz.” UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries, energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.” UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned 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 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. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2 — 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. Certain prior-year amounts have been reclassified to conform to the current-year presentation. Also, during Fiscal 2017, we corrected an immaterial error in our cylinder deposit liability account at two UGI International subsidiaries that arose prior to Fiscal 2015 which decreased opening retained earnings as of October 1, 2015 by $6.8 , or 0.5% , increased other noncurrent liabilities by $10.6 and decreased deferred income tax liabilities by $3.8 . 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 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. Investments in business entities that are not publicly traded and in which we do not have significant influence over operating and financial policies are accounted for using the cost method. Our equity and cost method investments are included in “ Other assets ” on the Consolidated Balance Sheets and comprise the following amounts at September 30, 2017 and 2016: 2017 2016 Equity method investments $ 59.1 $ 25.9 Cost method investments (a) $ 61.3 $ 70.1 (a) Cost method investments at September 30, 2017 and 2016 include $7.0 and $18.0 , respectively, associated with our investment in a private equity partnership that invests in renewable energy companies. A wholly owned subsidiary of UGI, UGI PennEast, LLC, and four other members comprising wholly owned subsidiaries of Southern Company, New Jersey Resources, South Jersey Industries, and Enbridge, Inc., hold 20% membership interests each in PennEast Pipeline Company, LLC (“PennEast”). PennEast is focused on constructing an approximate 118 -mile natural gas pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Affiliates of all members plan to be customers of the pipeline under 15 -year contracts. PennEast is considered to be an equity method investment as we have the ability to exercise significant influence, but not control, over PennEast. We are obligated to provide capital contributions based upon our ownership percentage. Our investment in PennEast at September 30, 2017 and 2016 totaled $51.0 and $17.4 , respectively. Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “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 and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 8 . Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value 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 on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception 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 and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“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 occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “ Losses on foreign currency contracts, net ” on the Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flow from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flow from financing 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 17 . Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Revenue Recognition Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing and our UGI International energy marketing business record 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 rendered and commodities delivered 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 on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in “ Utility taxes other than income taxes ” on the Consolidated Statements of Income in accordance with regulatory practice. Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. 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 AmeriGas OLP 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. AmeriGas OLP 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. UGI Utilities records 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. UGI Utilities also records 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. We record interest on tax deficiencies and income tax penalties in “ Income taxes ” on the Consolidated Statements of Income. For Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , interest income or 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 attributable to UGI Corporation 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 2017 , Fiscal 2016 and Fiscal 2015 : (Thousands of shares) 2017 2016 2015 Weighted-average common shares outstanding for basic computation 173,662 173,154 173,115 Incremental shares issuable for stock options and common stock awards (a) 3,497 2,418 2,552 Weighted-average common shares outstanding for diluted computation 177,159 175,572 175,667 (a) For Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , there were 146 shares, 38 shares and 1 share, 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. See “ Equity-Based Compensation ” below for a description of the impact on the calculation of diluted shares for Fiscal 2017 , resulting from the adoption of new accounting guidance regarding share-based payments. Cash and Cash Equivalents For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased. 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 net realizable value. We determine cost using an average cost method for non-utility LPG and natural gas and Gas Utility natural gas; 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. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, allowance for funds used during construction (“AFUDC”). 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. At September 30, 2017 , estimated useful lives by type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 40 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 12 Computer software 1 10 We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis based upon the projected service lives of the various classes of its depreciable property. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Gas Utility 2.2 % 2.2 % 2.2 % Electric Utility 2.4 % 2.5 % 2.5 % When UGI 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 and amortized over five years , consistent with prior ratemaking treatment. No depreciation expense is included in cost of sales in the Consolidated Statements of Income. Goodwill and Intangible Assets We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames 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 for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. 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. 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. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3). For certain of our reporting units with goodwill, 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 bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including 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. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. There were no accumulated impairment losses at September 30, 2017 and 2016 , and no provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2017 , Fiscal 2016 or Fiscal 2015 . Impairment of Long-Lived Assets and Cost Basis Investments We evaluate long-lived assets for impairment 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 2017 , Fiscal 2016 or Fiscal 2015 . 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 2017, we recorded a pre-tax loss of $11.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “ Other operating income, net ” on the Consolidated Statements of Income. No other-than-temporary impairment losses were recognized during Fiscal 2016 or Fiscal 2015 . Deferred Debt Issuance Costs We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities are classified as “ Other assets ” on our Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in loss on extinguishment of debt. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and amortized over the lives of the new issuances. Refundable Tank and Cylinder Deposits Included in “ Other noncurrent liabilities ” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders primarily owned by subsidiaries of France SAS of $279.9 and $267.2 at September 30, 2017 and 2016 , 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 be reasonably 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, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 15 . Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our U.S. pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7 ). Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units” or “Unit awards”), 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 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. Prior to the adoption of new accounting guidance effective October 1, 2016, differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return were recorded in Common Stock (if the tax benefit exceeded the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeded the tax benefit and no tax windfall pool existed from previous awards). We calculated this tax windfall pool using the shortcut method. Effective October 1, 2016, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-Based Payments Accounting” (“ASU 2016-09”) issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding no longer include windfall tax benefits in the diluted shares calculation. In accordance with the required prospective method of transition relating to excess tax benefits, we recognized income tax benefits of $10.3 related to excess tax benefits for share-based awards that were exercised or vested during Fiscal 2017. This amount is reflected in “ Income taxes ” on the Consolidated Statements of Income. In addition, upon the adoption of ASU 2016-09, we recorded a $4.9 increase to retained earnings and decrease to deferred income tax liabilities for excess tax benefits related to prior period unrecognized state tax benefits. We elected to use the prospective method of transition for classifying excess tax benefits as cash flow from operating activities on the Consolidated Statements of Cash Flows and prior periods were not adjusted. We have historically presented employee taxes paid for net settled awards as a financing activity on the Consolidated Statements of Cash Flows and therefore there is no transition impact from this requirement. In addition, as provided by the new guidance, we elected to account for forfeitures of share-based payments when they occur. For additional information on our equity-based compensation plans and related disclosures, see Note 13 . |
Accounting Changes
Accounting Changes | 12 Months Ended |
Sep. 30, 2017 | |
Accounting Changes and Error Corrections [Abstract] | |
Accounting Changes | Note 3 — Accounting Changes Adoption of New Accounting Standards Definition of a Business. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance which clarifies the definition of a business. The new guidance is intended to assist entities with evaluating whether a set of transferred assets and activities comprises a business. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements. Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Employee Share-based Payments. Effective October 1, 2016, the Company adopted ASU 2016-09 regarding share-based payments. See Note 2 for a detailed description of the impact of the new guidance. Equity Method Accounting. Effective October 1, 2016, the Company adopted new accounting guidance regarding the accounting for an investment that qualifies for use of the equity method as a result of an increase in an investor’s level of ownership or influence. The guidance requires that the equity method investor add the cost of acquiring an additional interest to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date such investment qualifies for equity method accounting. The new guidance eliminates the previous requirement in such circumstances to apply the effects of the equity method of accounting retrospectively. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Accounting Standards Not Yet Adopted Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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 entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements. |
Acquisitions
Acquisitions | 12 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Acquisitions | Note 4 — Acquisitions Acquisition of Totalgaz On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, France SAS, acquired all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France, for €451.8 ( $496.6 ) in cash, including €30.0 ( $33.0 ) for estimated Acquisition Date working capital. In November 2015, France SAS received €1.1 ( $1.2 ) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition was consummated pursuant to the terms of a Share Purchase Agreement dated November 11, 2014, between Total Marketing Services, a subsidiary of global energy company, Total, and France SAS. The Totalgaz Acquisition nearly doubled our retail LPG distribution business in France and was consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Totalgaz Acquisition was funded from existing cash balances and a portion of loan proceeds from France SAS’s May 29, 2015, issuance of a €600 term loan under its 2015 Senior Facilities Agreement (see Note 5). The Company accounted for the Totalgaz Acquisition using the acquisition method. The components of the final Totalgaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 117.5 Other noncurrent liabilities 113.4 Total liabilities assumed $ 443.6 Goodwill 183.8 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Comprises $79.3 of customer relationships and $12.0 of tradenames ( $8.3 of which is subject to amortization), having average amortization periods of 15 years . We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows: • Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; • Tradenames were valued using the relief from royalty method, which estimates our theoretical royalty savings from ownership of the tradenames. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and • Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods. The excess of the purchase price for the Totalgaz Acquisition over the fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI International reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes. The Company recognized $16.1 of direct transaction-related costs associated with the Totalgaz Acquisition during Fiscal 2015, which are reflected primarily in “ Operating and administrative expenses ” on the Consolidated Statements of Income. The acquisition of Totalgaz did not have a material impact on the Company’s revenues or net income attributable to UGI for the year ended September 30, 2015. The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014. Amounts in the table below exclude costs associated with extinguishment of debt under Antargaz’ 2011 Senior Facilities Agreement (see Note 5 ): 2015 As Reported Pro Forma Adjusted Revenues $ 6,691.1 $ 7,065.8 Net income attributable to UGI Corporation $ 281.0 $ 341.2 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 1.62 $ 1.97 Diluted $ 1.60 $ 1.94 The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results. Other Acquisitions During Fiscal 2017, UGI International acquired an energy marketing business with operations in the Netherlands and an LPG distribution business with operations in Sweden, and AmeriGas Propane acquired several retail propane distribution businesses. During Fiscal 2016, UGI International acquired several LPG distribution businesses with operations in Austria, Norway and the United Kingdom, and AmeriGas Propane acquired several retail propane distribution businesses. During Fiscal 2015, in addition to the Totalgaz Acquisition in France, UGI International acquired an LPG distribution business with operations in Hungary, and AmeriGas Propane acquired several retail propane distribution businesses. Total cash paid and liabilities incurred in connection with these acquisitions were as follows: 2017 2016 2015 AmeriGas Propane UGI International AmeriGas Propane UGI International AmeriGas Propane UGI International Total cash paid $ 36.8 $ 99.7 $ 37.6 $ 24.1 $ 20.8 $ 17.6 Liabilities incurred (a) 10.8 20.6 11.8 — 4.2 — Total purchase price $ 47.6 $ 120.3 $ 49.4 $ 24.1 $ 25.0 $ 17.6 (a) Reflects notes payable to seller and liabilities associated with noncompete agreements. |
Debt
Debt | 12 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Note 5 — Debt Significant Financing Activities AmeriGas Propane. During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, $700 principal amount of 5.50% Senior Notes due May 2025 and $525 principal amount of 5.75% Senior Notes due May 2027 (collectively, the “AmeriGas 2017 Senior Notes”). The AmeriGas 2017 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2017 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ 7.00% Senior Notes, having an aggregate principal balance of $980.8 plus accrued and unpaid interest and early redemption premiums, and (2) for general corporate purposes. During Fiscal 2016, AmeriGas Partners issued in an underwritten offering $675 principal amount of 5.625% Senior Notes due May 2024 and $675 principal amount of 5.875% Senior Notes due August 2026 (collectively, the “AmeriGas 2016 Senior Notes”). The AmeriGas 2016 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2016 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ previously issued 6.50% Senior Notes, 6.75% Senior Notes and 6.25% Senior Notes, having an aggregate principal balance of $1,270.0 plus accrued and unpaid interest and early redemption premiums and (2) for general corporate purposes. In connection with the early repayments of AmeriGas’ Senior Notes, during Fiscal 2017 and 2016 , the Partnership recognized pre-tax losses which are reflected in “ Loss on extinguishments of debt ” on the Consolidated Statements of Income and comprise the following: 2017 2016 Early redemption premiums $ 51.3 $ 39.6 Write-off of unamortized debt issuance costs 8.4 9.3 Loss on extinguishments of debt $ 59.7 $ 48.9 UGI International. In April 2015, France SAS entered into a new five -year Senior Facilities Agreement with a consortium of banks consisting of a €600 variable-rate term loan and a €60 revolving credit facility (“2015 Senior Facilities Agreement”) in anticipation of its then-pending acquisition of Totalgaz, which was consummated in May 2015 (see Note 4 ). On May 29, 2015, France SAS borrowed €600 ( $659.6 ) under the 2015 Senior Facilities Agreement. The term loan proceeds were used (1) to fund a portion of the Totalgaz Acquisition, including related fees and expenses; (2) to make a capital contribution from France SAS to its wholly owned subsidiary, AGZ Holding, to prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) to settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As a result of prepaying the term loan outstanding under the 2011 Senior Facilities Agreement and concurrently settling the associated pay-fixed, receive-variable interest rate swaps, we recorded a pre-tax loss of $10.3 comprising a $9.0 loss on interest rate swaps and the write-off of $1.3 of debt issuance costs. These amounts are included in “ Interest expense ” on the Fiscal 2015 Consolidated Statement of Income. In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 term loan facility. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility. In October 2015, borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan were used to refinance a €19.1 ( $21.4 ) term loan and a €26.7 ( $29.8 ) term loan. Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Consolidated Statement of Cash Flows. In September 2015, Flaga terminated its then-existing $52 U.S. dollar-denominated variable-rate term loan due September 2016 and concurrently entered into a $59.1 U.S. dollar-denominated variable-rate term loan with the same bank. The $59.1 term loan matures in September 2018. Because the cash flows from the termination of the $52 term loan and the concurrent issuance of the $59.1 term loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Fiscal 2015 Consolidated Statement of Cash Flows. UGI Utilities. In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100 aggregate principal amount of 2.95% Senior Notes due June 2026 and $200 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100 aggregate principal amount of 4.12% Senior Notes due October 2046. The net proceeds of the issuance of these senior notes were used (1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term Notes and 5.64% Medium-term Notes; (2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and the information technology initiatives; and (3) for general corporate purposes. The UGI Utilities Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. On October 31, 2017, UGI Utilities entered into a $125 unsecured term loan (the “Utilities Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date. Proceeds from the Utilities Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 with the balance of the principal being due and payable in full on the maturity date. Under the Utilities Term Loan, 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 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Long-term Debt Long-term debt comprises the following at September 30: 2017 2016 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.50% due May 2025 $ 700.0 $ — 5.875% due August 2026 675.0 675.0 5.625% due May 2024 675.0 675.0 5.75% due May 2027 525.0 — 7.00%, due May 2022 — 980.8 HOLP Senior Secured Notes, including unamortized premium of $0.4 and $0.7, respectively (a) 11.3 15.2 Other 17.3 14.2 Unamortized debt issuance costs (31.3 ) (26.6 ) Total AmeriGas Propane 2,572.3 2,333.6 UGI International: France SAS Senior Facilities term loan, due through April 2020 (b) 708.9 674.4 Flaga variable-rate term loan, due October 2020 (c) 54.1 51.4 Flaga U.S. dollar variable-rate term loan, due September 2018 (d) 59.1 59.1 Other 21.3 1.4 Unamortized debt issuance costs (4.6 ) (6.7 ) Total UGI International 838.8 779.6 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 200.0 4.98%, due March 2044 175.0 175.0 4.12%, due October 2046 100.0 — 6.21%, due September 2036 100.0 100.0 2.95%, due June 2026 100.0 100.0 Medium-Term Notes: 6.13%, due October 2034 20.0 20.0 6.50%, due August 2033 20.0 20.0 5.67%, due January 2018 20.0 20.0 7.25%, due November 2017 20.0 20.0 6.17%, due June 2017 — 20.0 Unamortized debt issuance costs (3.9 ) (3.5 ) Total UGI Utilities 751.1 671.5 Other 9.9 10.8 Total long-term debt 4,172.1 3,795.5 Less: current maturities (177.5 ) (29.5 ) Total long-term debt due after one year $ 3,994.6 $ 3,766.0 (a) At September 30, 2017 and 2016 , the effective interest rate on the HOLP Senior Secured Notes was 6.75% . These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. (b) Borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of 0.0% . The margin on term loan borrowings (which ranges from 1.60% to 2.70% ) is dependent upon the ratio of France SAS’ consolidated total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement. At September 30, 2017 and 2016 , such margin was 1.90% . France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to fix the underlying euribor rate on term loan borrowings at 0.18% . At September 30, 2017 and 2016 , the effective interest rate on the term loan was approximately 2.10% . Principal amounts outstanding under the term loan are due as follows: €60 due April 2018; €60 due April 2019; and €480 due April 2020. (c) Borrowings bear interest at three-month euribor rates, plus a margin and other fees. The margin and other fees range from 1.20% to 2.60% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined, as well as fees defined by the local jurisdiction. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying market rate at 0.23% , effective October 2016. The effective interest rate on this term loan at September 30, 2017 and 2016 , was 1.80% and 2.11% , respectively. (d) Borrowings bear interest at a one-month LIBOR rate plus a margin of 1.125% . Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments by entering into a cross-currency swap arrangement with a bank. At September 30, 2017 and 2016 , the effective interest rate on this term loan was 0.87% . Scheduled principal repayments of long-term debt due in fiscal years 2018 to 2022 follows: 2018 2019 2020 2021 2022 AmeriGas Propane $ 8.6 $ 8.2 $ 7.5 $ 3.2 $ 1.2 UGI International 130.3 71.5 567.1 54.1 20.4 UGI Utilities 40.0 — — — — Other 0.7 0.8 0.8 0.9 0.9 Total $ 179.6 $ 80.5 $ 575.4 $ 58.2 $ 22.5 Credit Facilities and Short-term Borrowings Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility which is discussed below) as of September 30, 2017 and 2016 , is presented in the following table. Borrowings outstanding under these agreements are classified as “Short-term borrowings” on the Consolidated Balance Sheets. Expiration Date Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity Weighted Average Interest Rate - End of Year September 30, 2017 AmeriGas OLP (a) June 2019 $ 525.0 $ 140.0 $ 67.2 $ 317.8 3.74 % France SAS (b) April 2020 € 60.0 — — € 60.0 N.A. Flaga (c) October 2020 € 55.0 — € 6.5 € 48.5 N.A. Energy Services, LLC (d) March 2021 $ 240.0 — — $ 240.0 N.A. UGI Utilities (e) March 2020 $ 300.0 $ 170.0 $ 2.0 $ 128.0 2.11 % September 30, 2016 AmeriGas OLP (a) June 2019 $ 525.0 $ 153.2 $ 67.2 $ 304.6 2.79 % France SAS (b) April 2020 € 60.0 — — € 60.0 N.A. Flaga (c) October 2020 € 55.0 — € 9.6 € 45.4 N.A. Energy Services, LLC (d) March 2021 $ 240.0 $ — — $ 240.0 N.A. UGI Utilities (e) March 2020 $ 300.0 $ 112.5 $ 2.0 $ 185.5 1.42 % (a) The AmeriGas OLP Credit Agreement includes a $125 sublimit for letters of credit and 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, or one-, two-, three-, or six-month Eurodollar Rate, as defined, plus a margin. 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 EBITDA, as defined. (b) Borrowings under the 2015 Senior Facilities Agreement revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor) plus a margin. The margin on credit facility borrowings ranges from 1.45% to 2.55% based upon France SAS’s ratio of consolidated total net debt to EBITDA, as defined. (c) The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility and a €25 guarantee facility. Revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65% , are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, each as defined. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. Guarantees outstanding reduce the available capacity on the €25 guarantee facility. (d) The Energy Services, LLC Credit Agreement (“Energy Services Credit Agreement”) includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services, LLC and its subsidiaries. Energy Services, LLC may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined, does not exceed 3.00 to 1.00 . Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% , and (c) Adjusted LIBOR plus 1.00% . The margin on such borrowings is currently 2.25% . The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services, LLC. (e) The UGI Utilities Credit Agreement includes a $100 sublimit for letters of credit. Borrowings bear interest at prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. Accounts Receivable Securitization Facility. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services, LLC 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, LLC 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. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , which amounts are included in “ Interest expense ” on the Consolidated Statements of Income, were not material. Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , as well as the balance of ESFC trade receivables at September 30, 2017 , 2016 and 2015 follows: 2017 2016 2015 Trade receivables transferred to ESFC during the year $ 1,017.3 $ 756.4 $ 1,037.8 ESFC trade receivables sold to the bank during the year 243.0 204.0 306.5 ESFC trade receivables - end of year (a) 44.8 35.7 44.1 (a) At September 30, 2017 and 2016 , the amounts of ESFC trade receivables sold to the bank were $39.0 and $25.5 , respectively, and are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets. Restrictive Covenants Our long-term debt and credit facility agreements generally contain customary covenants and default provisions which may include, among other things, restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas Propane 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. 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, 2017, these restrictions did not limit the amount of Available Cash. See Note 14 for the definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P., as amended (“Partnership Agreement”). The HOLP Senior Secured Notes 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). The 2015 Senior Facilities Agreement requires France SAS and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed 3.50 to 1.00 as determined semiannually. France SAS will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend. Borrowings under the Flaga Credit Facility Agreement are guaranteed by UGI. The Flaga U.S. dollar term loan and associated interest rate and cross-currency swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt. 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. Certain of UGI Utilities’ Senior Notes contain financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. The Energy Services Credit Agreement requires that Energy Services, LLC and subsidiaries not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00. Restricted Net Assets At September 30, 2017 , the amount of net assets of UGI’s consolidated subsidiaries that were restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,500 . |
Income Taxes
Income Taxes | 12 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 6 — Income Taxes Income before income taxes comprises the following: 2017 2016 2015 Domestic $ 527.3 $ 518.9 $ 552.3 Foreign 174.1 191.1 39.5 Total income before income taxes $ 701.4 $ 710.0 $ 591.8 The provisions for income taxes consist of the following: 2017 2016 2015 Current expense (benefit): Federal $ (2.7 ) $ 44.2 $ 97.1 State 14.0 20.9 32.2 Foreign 56.2 78.7 36.0 Investment tax credit — — (1.2 ) Total current expense 67.5 143.8 164.1 Deferred expense (benefit): Federal 125.8 81.2 28.1 State 16.4 1.3 2.9 Foreign (31.8 ) (4.8 ) (17.0 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense 110.1 77.4 13.7 Total income tax expense $ 177.6 $ 221.2 $ 177.8 Federal income taxes for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are net of foreign tax credits of $40.9 , $25.6 and $63.0 , respectively. A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2017 2016 2015 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: Noncontrolling interests not subject to tax (4.3 ) (6.2 ) (7.9 ) State income taxes, net of federal benefit 2.9 3.0 3.3 Valuation allowance adjustments (1.1 ) (0.9 ) 0.8 Effects of foreign operations (1.1 ) 0.6 0.2 Deferred tax effects of French tax rate change (4.1 ) — — Excess tax benefits on share-based payments (1.3 ) — — Other, net (0.7 ) (0.3 ) (1.4 ) Effective tax rate 25.3 % 31.2 % 30.0 % 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 provisions reflect the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. At September 30, 2017 , unremitted earnings of foreign subsidiaries of approximately $119.7 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 2017 , Fiscal 2016 and Fiscal 2015 , the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $2.5 , $1.3 and $1.5 , respectively. Deferred tax liabilities (assets) comprise the following at September 30: 2017 2016 Excess book basis over tax basis of property, plant and equipment $ 975.8 $ 873.9 Investment in AmeriGas Partners 326.8 323.2 Intangible assets and goodwill 98.2 87.1 Utility regulatory assets 132.2 148.3 Other 11.7 11.9 Gross deferred tax liabilities 1,544.7 1,444.4 Pension plan liabilities (57.7 ) (79.7 ) Employee-related benefits (65.4 ) (63.1 ) Operating loss carryforwards (30.9 ) (31.5 ) Foreign tax credit carryforwards (106.1 ) (105.1 ) Utility regulatory liabilities (9.3 ) (13.9 ) Derivative instruments (1.7 ) (14.7 ) Utility environmental liabilities (22.2 ) (22.8 ) Other (27.8 ) (28.3 ) Gross deferred tax assets (321.1 ) (359.1 ) Deferred tax assets valuation allowance 107.1 114.3 Net deferred tax liabilities $ 1,330.7 $ 1,199.6 In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively the “Finance Bills”). The Finance Bills, among other things, will reduce the French corporate income tax rate from the current 34.43% to 28.92% , effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of the future income tax rate reduction, during Fiscal 2017 the Company reduced its net deferred income tax labilities and recognized a deferred tax benefit of $29.0 . At September 30, 2017 , foreign net operating loss carryforwards principally relating to Flaga, UGI International Holdings BV and certain subsidiaries of France SAS totaled $24.5 , $2.5 and $22.6 , respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $187.9 and expire through 2037 . We also have operating loss carryforwards of $19.7 for certain operations of AmeriGas Propane that expire through 2037 . At September 30, 2017 , deferred tax assets relating to operating loss carryforwards include $5.6 for Flaga, $7.8 for certain subsidiaries of France SAS, $0.7 for UGI International Holdings BV, $6.8 for AmeriGas Propane and $10.0 for certain other subsidiaries. The valuation allowance for all deferred tax assets decreased by $7.2 in Fiscal 2017 due to the reversal of $7.6 of valuation allowances associated with future utilization of foreign tax credits and a decrease in foreign operating loss carryforwards of $1.5 , partially offset by an increase in foreign tax credits of $1.1 , and an increase in state capital loss carryforwards of $0.8 . A valuation allowance of $0.2 remains for deferred tax assets related to other 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 $7.5 also exists for deferred tax assets related to certain subsidiaries of France SAS, and certain subsidiaries of Flaga and UGI International Holdings BV. In Fiscal 2017, the Company reversed $7.6 in valuation allowances associated with foreign tax credit carryforwards whose utilization before expiration had previously not met a more-likely-than-not threshold. In Fiscal 2016, the Company reversed valuation allowances associated with certain state tax net operating loss carryforwards of approximately $5.5 as a result of certain tax planning strategies that were related to legal entity classification. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. Prior to the adoption of ASU 2016-09, we would 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, related to non-qualified stock option deductions, the resulting benefits were credited to UGI Corporation stockholders’ equity. The Fiscal 2016 table of deferred tax assets and liabilities does not include $7.7 of deferred tax assets and a corresponding valuation allowance for unrealized state tax benefits for share-based compensation deductions. We have foreign tax credit carryforwards of approximately $106.1 expiring through 2027 resulting from the actual and planned repatriation of France SAS’s accumulated earnings since acquisition which are includable in U.S. taxable income. Prior to Fiscal 2017, we expected that these credits would expire unused and a valuation allowance had been provided for the entire foreign tax credit carryforward amount. The Company continuously monitors the potential utilization of these credits and performs the appropriate weighing of positive and negative evidence in reaching a conclusion of whether utilization reaches a level of more likely than not. In Fiscal 2017, the Company concluded it was more likely than not that $98.5 of the credits will expire before utilization and therefore reversed $7.6 of the prior year valuation allowance against these credits. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased. 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 2013 tax year, our French tax returns are settled through the 2013 tax year, our Austrian tax returns are settled through 2014 and our other European tax returns are effectively settled for various years from 2008 to 2015. 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, 2017 , we have unrecognized income tax benefits totaling $12.2 including related accrued interest of $0.5 . If these unrecognized tax benefits were subsequently recognized, $8.1 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 no material change expected in unrecognized tax benefits and related interest in the next twelve months. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2017 2016 2015 Unrecognized tax benefits — beginning of year $ 7.2 $ 3.2 $ 2.4 Additions for tax positions of the current year 1.9 2.2 0.9 Additions for tax positions taken in prior years 4.6 2.3 0.5 Settlements with tax authorities/statute lapses (1.5 ) (0.5 ) (0.6 ) Unrecognized tax benefits — end of year $ 12.2 $ 7.2 $ 3.2 |
Employee Retirement Plans
Employee Retirement Plans | 12 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
Employee Retirement Plans | Note 7 — 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 postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, certain UGI International employees in France, Belgium and the Netherlands are covered by defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI International 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 UGI International 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, 2017 and 2016 . 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 2017 2016 2017 2016 Change in benefit obligations: Benefit obligations — beginning of year $ 707.7 $ 614.7 $ 30.9 $ 25.4 Service cost 11.9 10.1 1.0 0.7 Interest cost 25.0 26.8 0.8 0.9 Actuarial (gain) loss (19.6 ) 83.3 (4.8 ) 6.6 Plan amendments 1.2 — — (1.5 ) Curtailment (3.6 ) (1.4 ) (0.4 ) (0.3 ) Foreign currency 2.9 0.1 0.4 — Benefits paid (27.7 ) (25.9 ) (0.9 ) (0.9 ) Benefit obligations — end of year $ 697.8 $ 707.7 $ 27.0 $ 30.9 Change in plan assets: Fair value of plan assets — beginning of year $ 493.7 $ 453.8 $ 13.7 $ 12.5 Actual gain on plan assets 47.0 53.4 1.3 1.3 Foreign currency 1.6 0.1 — — Employer contributions 14.6 11.4 0.6 0.6 Benefits paid (27.7 ) (25.0 ) (0.8 ) (0.7 ) Fair value of plan assets — end of year $ 529.2 $ 493.7 $ 14.8 $ 13.7 Funded status of the plans — end of year $ (168.6 ) $ (214.0 ) $ (12.2 ) $ (17.2 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 5.4 $ 4.1 Unfunded liabilities — included in other noncurrent liabilities (168.6 ) (214.0 ) (17.6 ) (21.3 ) Net amount recognized $ (168.6 ) $ (214.0 ) $ (12.2 ) $ (17.2 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service cost (credit) $ 0.7 $ (0.6 ) $ (1.5 ) $ (1.5 ) Net actuarial loss (gain) 21.3 31.4 (0.6 ) 3.8 Total $ 22.0 $ 30.8 $ (2.1 ) $ 2.3 Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 1.0 $ 1.2 $ (1.6 ) $ (2.2 ) Net actuarial loss 139.5 181.0 1.2 2.4 Total $ 140.5 $ 182.2 $ (0.4 ) $ 0.2 In Fiscal 2018 , we estimate that we will amortize approximately $13.5 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.5 of net 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 UGI International 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 2017 2016 2015 2017 2016 2015 Weighted-average assumptions: Discount rate – benefit obligations 4.00 % 3.80 % 4.60 % 4.00 % 3.80 % 4.70 % Discount rate – benefit cost 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Expected return on plan assets 7.50 % 7.55 % 7.75 % 5.00 % 5.00 % 5.00 % 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 $605.2 and $601.3 as of September 30, 2017 and 2016 , respectively. Net periodic pension expense and other postretirement benefit cost include the following components: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Service cost $ 11.9 $ 10.1 $ 10.0 $ 1.0 $ 0.7 $ 0.7 Interest cost 25.0 26.8 25.5 0.8 0.9 0.8 Expected return on assets (33.6 ) (32.4 ) (32.2 ) (0.7 ) (0.6 ) (0.6 ) Curtailment gain (1.4 ) (1.2 ) (0.8 ) — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.6 ) (0.6 ) (0.5 ) Actuarial loss 16.7 10.9 10.0 0.3 — 0.1 Net benefit cost 18.9 14.5 12.8 0.8 0.4 0.5 Change in associated regulatory liabilities — — — (0.5 ) 1.0 3.7 Net benefit cost after change in regulatory liabilities $ 18.9 $ 14.5 $ 12.8 $ 0.3 $ 1.4 $ 4.2 The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock and smallcap common stocks (prior to their liquidation during Fiscal 2017). 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 2017 , Fiscal 2016 and Fiscal 2015 , we made cash contributions to the U.S. Pension Plan of $11.4 , $9.9 and $11.1 respectively. The minimum required contributions in Fiscal 2018 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, if any, is deferred for future recovery from, or refund to, ratepayers. Any required contributions to the VEBA during Fiscal 2018 are not expected to be material. Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2018 $ 29.5 $ 1.1 Fiscal 2019 $ 29.9 $ 1.1 Fiscal 2020 $ 31.5 $ 1.1 Fiscal 2021 $ 39.0 $ 1.1 Fiscal 2022 $ 39.6 $ 1.0 Fiscal 2023 - 2027 $ 196.2 $ 4.9 The assumed domestic health care cost trend rates at September 30 are as follows: 2017 2016 Health care cost trend rate assumed for next year 7.00 % 7.25 % 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 2026 2026 A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2017 other postretirement benefit cost or September 30, 2017 , other postretirement benefit ABO. We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2017 and 2016 , the PBOs of these plans, including obligations for amounts held in grantor trusts, were $50.7 and $47.4 , respectively. We recorded pre-tax costs for these plans of $3.1 in Fiscal 2017 , $2.6 in Fiscal 2016 and $2.3 in Fiscal 2015 . These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $11.3 and $13.0 at September 30, 2017 and 2016 , respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $1.1 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2018 . During Fiscal 2017 and 2016 the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $1.3 and $0.4 , respectively. There were no such payments made in Fiscal 2015. 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 $31.8 and $28.4 at September 30, 2017 and 2016 , 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 (prior to their liquidation in Fiscal 2017) and UGI Common Stock. Assets associated with the UGI International plans are excluded from the disclosures in the tables below as such assets are not material. 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 2017 2016 Equity investments: Domestic 55.2 % 54.1 % 52.5 % 40.0% – 65.0% International 12.4 % 10.2 % 12.5 % 7.5% – 17.5% Total 67.6 % 64.3 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 32.4 % 35.7 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2017 2016 Domestic equity investments 63.1 % 69.9 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 36.9 % 30.1 % 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 separately managed account comprising small-cap common stocks (prior to their liquidation in Fiscal 2017). 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 7.7% and 8.0% of U.S. Pension Plan assets at September 30, 2017 and 2016 , 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, 2017 and 2016 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: Domestic equity investments: S&P 500 Index equity mutual funds $ 171.6 $ — $ — $ — $ 171.6 Small and midcap equity mutual funds 65.2 — — — 65.2 UGI Corporation Common Stock 38.1 — — — 38.1 Total domestic equity investments 274.9 — — — 274.9 International index equity mutual funds 61.6 — — — 61.6 Fixed income investments: Bond index mutual funds 156.2 — — — 156.2 Cash equivalents — — — 5.3 5.3 Total fixed income investments 156.2 — — 5.3 161.5 Total $ 492.7 $ — $ — $ 5.3 $ 498.0 September 30, 2016: Domestic equity investments: S&P 500 Index equity mutual funds $ 158.9 $ — $ — $ — $ 158.9 Small and midcap equity mutual funds 43.2 — — — 43.2 Smallcap common stocks 11.4 — — — 11.4 UGI Corporation Common Stock 37.0 — — — 37.0 Total domestic equity investments 250.5 — — — 250.5 International index equity mutual funds 47.3 — — — 47.3 Fixed income investments: Bond index mutual funds 147.8 — — — 147.8 Cash equivalents — — — 17.8 17.8 Total fixed income investments 147.8 — — 17.8 165.6 Total $ 445.6 $ — $ — $ 17.8 $ 463.4 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: S&P 500 Index equity mutual fund $ 9.3 $ — $ — $ — $ 9.3 Bond index mutual fund 5.1 — — — 5.1 Cash equivalents — — — 0.4 0.4 Total $ 14.4 $ — $ — $ 0.4 $ 14.8 September 30, 2016: S&P 500 Index equity mutual fund $ 9.6 $ — $ — $ — $ 9.6 Bond index mutual fund 4.0 — — — 4.0 Cash equivalents — — — 0.1 0.1 Total $ 13.6 $ — $ — $ 0.1 $ 13.7 (a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy. 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 $15.1 in Fiscal 2017 , $14.3 in Fiscal 2016 and $15.2 in Fiscal 2015 . 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 2017 , Fiscal 2016 and Fiscal 2015 were not material. At September 30, 2017 and 2016 , the total fair values of these grantor trust investment assets, which amounts are included in “ Other assets ” on the Consolidated Balance Sheets, were $3.6 and $4.6 , respectively. |
Utility Regulatory Assets and L
Utility Regulatory Assets and Liabilities and Regulatory Matters | 12 Months Ended |
Sep. 30, 2017 | |
Regulated Operations [Abstract] | |
Utility Regulatory Assets and Liabilities and Regulatory Matters | Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121.4 $ 115.7 Underfunded pension and postretirement plans 141.3 183.1 Environmental costs 61.6 59.4 Deferred fuel and power costs 7.7 0.2 Removal costs, net 31.0 27.9 Other 5.9 8.8 Total regulatory assets $ 368.9 $ 395.1 Regulatory liabilities (a): Postretirement benefit overcollections $ 17.5 $ 17.5 Deferred fuel and power refunds 10.6 22.3 State income tax benefits — distribution system repairs 18.4 15.1 Other 2.7 0.7 Total regulatory liabilities $ 49.2 $ 55.6 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above. 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 the tax benefit on 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. UGI 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 net actuarial losses and prior service costs (credits) 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 principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at MGP sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“DEP”). Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2017 , the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 15 . Removal costs, net . This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over five years . Postretirement benefit overcollections . This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, postretirement benefit overcollections are generally being refunded to customers over a ten -year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “Base Rate Filings” below). With respect to Electric Utility, the excess of the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers. Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that 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 gains on such contracts at September 30, 2017 and 2016 were $0.1 and $4.3 , respectively. 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, 2017 and 2016 , were not material. State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, 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 and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses. Other Regulatory Matters Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the Joint Petition and the increase became effective October 20, 2017. On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58.6 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27.0 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27.0 base distribution rate increase. The increase became effective on October 19, 2016. Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5.8 of such project costs ( $5.4 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ( $2.7 ) and regulatory assets ( $3.1 ). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities. |
Inventories
Inventories | 12 Months Ended |
Sep. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 9 — Inventories Inventories comprise the following at September 30: 2017 2016 Non-utility LPG and natural gas $ 188.4 $ 129.8 Gas Utility natural gas 39.5 29.2 Materials, supplies and other 50.7 51.3 Total inventories $ 278.6 $ 210.3 At September 30, 2017 , UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from 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 for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. As of September 30, 2017 , UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at September 30, 2017 and 2016 , comprising 2.3 billion cubic feet (“bcf”) and 3.5 bcf of natural gas, was $6.7 and $7.6 , respectively. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Note 10 — Property, Plant and Equipment Property, plant and equipment comprise the following at September 30: 2017 2016 Utilities: Distribution $ 2,835.3 $ 2,634.2 Transmission 96.4 93.5 Work in process 112.6 103.9 General and other 241.0 167.3 Total Utilities 3,285.3 2,998.9 Non-utility: Land 180.1 169.9 Buildings and improvements 351.2 382.2 Transportation equipment 289.3 301.7 Equipment, primarily cylinders and tanks 3,529.4 3,421.5 Electric generation 310.0 309.4 Pipeline and related assets 454.5 235.8 Work in process 95.3 201.6 Other 354.8 324.3 Total non-utility 5,564.6 5,346.4 Total property, plant and equipment $ 8,849.9 $ 8,345.3 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets | 12 Months Ended |
Sep. 30, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets | Note 11 — Goodwill and Intangible Assets Changes in the carrying amount of goodwill by reportable segment are as follows: AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Total Balance September 30, 2015 $ 1,956.0 $ 803.7 $ 11.6 $ 182.1 $ 2,953.4 Acquisitions 24.2 16.9 — — 41.1 Dispositions — (1.6 ) — — (1.6 ) Purchase accounting adjustments (1.9 ) (2.6 ) — — (4.5 ) Foreign currency translation — 0.6 — — 0.6 Balance September 30, 2016 1,978.3 817.0 11.6 182.1 2,989.0 Acquisitions 23.0 55.5 — — 78.5 Purchase accounting adjustments — (1.7 ) — — (1.7 ) Foreign currency translation — 41.4 — — 41.4 Balance September 30, 2017 $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ 3,107.2 Intangible assets comprise the following at September 30: 2017 2016 Customer relationships, noncompete agreements and other $ 817.8 $ 773.5 Trademarks and tradenames (not subject to amortization) 134.1 131.6 Gross carrying amount 951.9 905.1 Accumulated amortization (340.2 ) (324.8 ) Intangible assets, net $ 611.7 $ 580.3 Amortization expense of intangible assets was $50.8 , $54.3 and $52.0 for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2018 — $53.5 ; Fiscal 2019 — $51.6 ; Fiscal 2020 — $50.2 ; Fiscal 2021 — $48.3 ; Fiscal 2022 — $46.6 . |
Series Preferred Stock
Series Preferred Stock | 12 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Series Preferred Stock | Note 12 — 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, 2017 or 2016 . 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, 2017 and 2016 , there were no shares of UGI Utilities Series Preferred Stock outstanding. |
Common Stock and Equity-Based C
Common Stock and Equity-Based Compensation | 12 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Common Stock and Equity-Based Compensation | Note 13 — Common Stock and Equity-Based Compensation Common Stock On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 15,000,000 shares of UGI Corporation Common Stock over a four -year period. Pursuant to such authorization, during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the Company purchased and placed in treasury stock 900,000 , 1,250,000 and 1,000,000 shares at a total cost of $43.3 , $47.6 and $34.1 , respectively. UGI Common Stock share activity for Fiscal 2015 , Fiscal 2016 and Fiscal 2017 follows: Issued Treasury Outstanding Balance, September 30, 2014 173,770,641 (1,496,860 ) 172,273,781 Issued: Employee and director plans 36,350 1,155,376 1,191,726 Repurchases of common stock — (1,000,000 ) (1,000,000 ) Reacquired common stock – employee and director plans — (77,004 ) (77,004 ) Balance, September 30, 2015 173,806,991 (1,418,488 ) 172,388,503 Issued: Employee and director plans 87,150 2,355,202 2,442,352 Repurchases of common stock — (1,250,000 ) (1,250,000 ) Reacquired common stock – employee and director plans — (620,406 ) (620,406 ) Balance, September 30, 2016 173,894,141 (933,692 ) 172,960,449 Issued: Employee and director plans 93,550 1,051,704 1,145,254 Sale of reacquired common stock — 50,000 50,000 Repurchases of common stock — (900,000 ) (900,000 ) Reacquired common stock – employee and director plans — (111,966 ) (111,966 ) Balance, September 30, 2017 173,987,691 (843,954 ) 173,143,737 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 $19.3 ( $11.8 after-tax), $23.8 ( $15.4 after-tax) and $29.2 ( $18.9 after-tax) in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , 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 UGI 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 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 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 UGI Common Stock and cash. Substantially all UGI Unit awards granted to France SAS employees are settled in shares of UGI Common Stock and do not accrue dividend equivalents. 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. Stock options may be net exercised whereby shares equal to the option price and the 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 2015 , Fiscal 2016 and Fiscal 2017 follow: Shares Weighted Average Option Price Total Intrinsic Value Weighted Average Contract Term (Years) Shares under option — September 30, 2014 8,957,290 $ 21.44 $ 113.3 7.0 Granted 1,336,985 $ 37.70 Canceled (85,365 ) $ 30.45 Exercised (953,533 ) $ 19.10 $ 15.4 Shares under option — September 30, 2015 9,255,377 $ 23.97 $ 104.5 6.6 Granted 1,510,625 $ 34.67 Canceled (84,213 ) $ 34.13 Exercised (2,193,338 ) $ 20.38 $ 40.1 Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Granted 1,343,800 $ 46.51 Canceled (60,236 ) $ 41.86 Exercised (990,267 ) $ 21.40 $ 26.7 Shares under option — September 30, 2017 8,781,748 $ 30.20 $ 146.7 6.3 Options exercisable — September 30, 2015 6,050,946 $ 20.74 Options exercisable — September 30, 2016 5,522,370 $ 22.94 Options exercisable — September 30, 2017 5,973,668 $ 25.53 $ 127.4 5.3 Options not exercisable — September 30, 2017 2,808,080 $ 40.13 $ 19.3 7.8 Cash received from stock option exercises and associated tax benefits were $17.7 and $9.6 , $27.3 and $14.9 , and $16.2 and $5.8 in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , respectively. As of September 30, 2017 , there was $7.0 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years . The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2017 : Range of exercise prices Under $20.00 $20.00 – $25.00 $25.01 – $30.00 $30.01 – $35.00 Over $35.00 Options outstanding at September 30, 2017: Number of options 1,351,925 1,947,779 1,462,977 1,402,988 2,616,079 Weighted average remaining contractual life (in years) 3.3 4.6 6.1 8.1 8.3 Weighted average exercise price $ 18.26 $ 21.57 $ 27.43 $ 33.66 $ 42.93 Options exercisable at September 30, 2017: Number of options 1,351,925 1,947,779 1,342,377 499,351 832,236 Weighted average exercise price $ 18.26 $ 21.57 $ 27.42 $ 33.52 $ 38.81 UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $7.62 in Fiscal 2017 , $4.87 in Fiscal 2016 and $5.47 in Fiscal 2015 . 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 2017 , Fiscal 2016 and Fiscal 2015 are as follows: 2017 2016 2015 Expected life of option 5.75 years 5.75 years 5.75 years Weighted average volatility 19.8% 19.5% 19.5% Weighted average dividend yield 2.1% 2.6% 2.5% Expected volatility 19.8% 19.3% 19.1% -19.5% Expected dividend yield 2.1% 2.6% 2.5% Risk free rate 1.8% - 2.1% 1.2% - 1.9% 1.5% - 1.8% 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 the Russell Midcap Utility Index, excluding telecommunication companies (“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 Year 2017 2016 2015 Risk free rate 1.5% 1.3% 1.1% Expected life 3 years 3 years 3 years Expected volatility 18.9% 17.5% 15.9% Dividend yield 2.1% 2.7% 2.3% The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $50.91 for Units granted in Fiscal 2017 , $32.64 for Units granted in Fiscal 2016 and $38.43 for Units granted in Fiscal 2015 . The following table summarizes UGI Unit award activity for Fiscal 2017 : 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, 2016 999,083 $ 25.44 672,075 $ 21.17 327,008 $ 34.21 UGI Performance Units: Granted 143,300 $ 50.91 20,283 $ 50.94 123,017 $ 50.90 Forfeited (7,768 ) $ 41.33 — $ — (7,768 ) $ 41.33 Vested — $ — 131,409 $ 33.67 (131,409 ) $ 33.67 Unit awards paid (178,450 ) $ 32.47 (178,450 ) $ 32.47 — $ — UGI Stock Units: Granted (a) 42,079 $ 47.25 34,979 $ 46.44 7,100 $ 51.23 Unit awards paid (19,410 ) $ 18.69 (19,410 ) $ 18.69 — $ — September 30, 2017 978,834 $ 28.83 660,886 $ 23.93 317,948 $ 41.10 (a) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2016 and Fiscal 2015 were 52,493 and 39,801 , respectively. During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2017 2016 2015 UGI Performance Unit awards: Number of original awards granted 178,450 308,362 294,300 Fiscal year granted 2014 2013 2012 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 138,985 209,592 188,418 Cash paid $ 10.9 $ 13.9 $ 13.3 UGI Stock Unit awards: Number of original awards granted 43,699 51,037 67,419 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 15,990 39,422 44,034 Cash paid $ 0.3 $ 0.7 $ 0.8 During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , we granted UGI Unit awards representing 185,379 , 230,653 and 180,724 shares, respectively, having weighted-average grant date fair values per Unit of $50.08 , $33.04 and $38.20 , respectively. As of September 30, 2017 , there was a total of approximately $8.4 of unrecognized compensation cost associated with 978,834 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years . The total fair values of UGI Units that vested during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 were $7.1 , $9.7 and $15.3 , respectively. As of September 30, 2017 and 2016 , total liabilities of $13.1 and $18.5 , 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, 2017 , 10,851,819 shares of Common Stock were available for future grants under the 2013 OICP, and up to 4,116 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, phantom units, 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, and for certain awards granted on or after January 1, 2015, actual net customer acquisition and retention performance. 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. For that portion of Performance Unit awards whose ultimate payout is based upon market-based conditions (as further described below), the number of awards ultimately paid is 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 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”). For Performance Unit awards granted on or after January 1, 2015, the number of AmeriGas Performance Units ultimately paid is based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group as modified by AmeriGas Partners’ performance relative to the 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 such 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 %. The actual amount of the award is interpolated between these percentile rankings. For such grants issued on or after January 1, 2015, the amount ultimately paid shall be modified based upon AmeriGas Partners’ TUR ranking relative to the Propane MLP Group over the performance period (“MLP Modifier”). Such modification ranges from 70 % to 130 %, but in no event shall the amount ultimately paid, after such modification, exceed 200 % of the target award grant. With respect to AmeriGas Performance Unit awards granted in January 2014 subject to measurement compared with the Propane MLP Group, grantees were eligible to receive 150% of the target award if AmeriGas Partners’ TUR exceeded the TUR of all the other members in the Propane MLP Group. Otherwise there would be no payout of such AmeriGas Performance Units. If one of the other two members of the Propane MLP Group ceased to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued pursuant to the January 2014 grant, and the amount of distribution equivalents to be paid, would 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. For those performance awards granted on or after January 1, 2015, that are subject to the MLP Modifier, if an MLP Event were to occur during the performance period such MLP Modifier would be based upon AmeriGas Partners’ TUR rank as determined in (1),(2) or (3) above, as appropriate. With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0 % and 200 % of the target award based upon the annual actual net customer gain and retention performance as adjusted for the net customer gain and retention performance over the three -year performance period. With respect to AmeriGas Performance Unit awards granted in January 2016 and 2017 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target award based upon the actual net customer gain and retention performance over the entire three -year performance period. Common Unit distribution equivalents are paid in cash only on AmeriGas Performance Units that eventually vest. Generally, 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 GAAP, AmeriGas Performance Units awards that are subject to market-based conditions are equity awards that, if settled in Common Units, result 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 subject to market-based conditions are estimated using a Monte Carlo valuation model. The fair value associated with the target award, which 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. For purposes of valuing AmeriGas Performance Unit awards that are subject to market-based conditions, 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 entities in the peer group is based on historical volatility. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout is based upon net customer acquisition and retention performance measures are recorded as expense when it is probable all or a portion of the award will be paid. The fair value associated with the target award is the market price of the Common Units on the date of grant. 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 following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2017 2016 2015 Risk-free rate 1.5% 1.3% 0.9% Expected life 3 years 3 years 3 years Expected volatility 21.7% 20.6% 19.2% Dividend yield 7.8% 10.7% 6.8% The General Partner granted awards under the 2010 Propane Plan representing 67,563 , 73,080 and 80,336 Common Units in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , respectively, having weighted-average grant date fair values per Common Unit subject to award of $52.37 , $37.93 and $61.00 , respectively. At September 30, 2017 , 2,287,879 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 2017 : 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, 2016 210,549 $ 47.24 55,622 $ 45.67 154,927 $ 47.80 AmeriGas Performance Units: Granted 49,225 $ 54.24 633 $ 54.45 48,592 $ 54.24 Forfeited (9,151 ) $ 48.76 — $ — (9,151 ) $ 48.76 Vested — $ — 40,933 $ 42.55 (40,933 ) $ 42.55 Awards paid (44,732 ) $ 41.53 (44,732 ) $ 41.53 — $ — AmeriGas Stock Units: Granted 18,338 $ 47.33 12,738 $ 48.06 5,600 $ 45.66 Vested — $ — 6,800 $ 46.13 (6,800 ) $ 46.13 Awards paid (6,005 ) $ 43.64 (6,005 ) $ 43.64 — $ — September 30, 2017 218,224 $ 50.03 65,989 $ 47.31 152,235 $ 51.21 During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2017 2016 2015 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted 53,800 44,800 55,750 Fiscal year granted 2014 2013 2012 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 29,489 23,017 — Cash paid $ 2.9 $ 1.7 $ — AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted 32,658 20,336 42,532 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 3,932 9,272 21,509 Cash paid $ 0.1 $ 0.4 $ 0.8 As of September 30, 2017 , there was a total of approximately $1.7 of unrecognized compensation cost associated with 218,224 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 2017 , Fiscal 2016 and Fiscal 2015 were $2.1 , $2.0 and $2.6 , respectively. As of September 30, 2017 and 2016 , total liabilities of $2.5 and $3.5 associated with Common Unit-based awards are reflected in “ Employee compensation and benefits accrued ” and “ Other noncurrent liabilities ” in the Consolidated Balance Sheets. It is the Partnership’s practice to issue new AmeriGas Partners Common Units for the portion of any Common Unit-based awards paid in AmeriGas Partners Common Units. |
Partnership Distributions
Partnership Distributions | 12 Months Ended |
Sep. 30, 2017 | |
Distributions Made to Members or Limited Partners [Abstract] | |
Partnership Distributions | Note 14 — Partnership Distributions 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, plus 2. all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, less 3. 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 2017 , Fiscal 2016 and Fiscal 2015 , 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 2017 , Fiscal 2016 and Fiscal 2015 , the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $52.7 , $47.4 and $39.3 , respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 of $43.5 , $38.2 and $30.4 , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 15 — Commitments and Contingencies Commitments Leases 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 $99.5 in Fiscal 2017 , $102.0 in Fiscal 2016 and $86.1 in Fiscal 2015 . Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2018 2019 2020 2021 2022 After 2022 AmeriGas Propane $ 70.0 $ 61.7 $ 56.5 $ 48.9 $ 40.7 $ 110.3 UGI Utilities 7.5 6.0 4.4 2.7 0.8 0.2 UGI International 11.2 8.1 6.6 4.7 3.2 3.2 Other 2.3 2.0 1.9 0.9 0.5 0.6 Total $ 91.0 $ 77.8 $ 69.4 $ 57.2 $ 45.2 $ 114.3 UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20 -day volume-weighted average price of the Partnership’s common units (“Common Units”) prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points . The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership. At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one -for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one -for-one basis. Contingencies Environmental Matters UGI Utilities From the late 1800s through the mid-1900s, UGI Utilities and its current and 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. 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 also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG, and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5 , $1.8 and $1.1 , for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018 and 2019, respectively. At September 30, 2017 and 2016 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54.3 and $55.1 , respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8 ). We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. 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 a former subsidiary. 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 a former subsidiary 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. At September 30, 2017 and 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material. AmeriGas Propane AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that the DEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the DEC disclosed contamination related to a former MGP. At that time, AmeriGas OLP reviewed the study and researched the history of the site, including the extent of AmeriGas OLP’s ownership. In its written response to the DEC in early 2009, AmeriGas OLP disputed DEC’s contention it was a potentially responsible party (“PRP”) as it did not operate the MGP and appeared to only own a portion of the site. The DEC did not respond to the 2009 communication. In March 2017, the DEC communicated to AmeriGas OLP that the DEC had previously issued three Records of Decision (“RODs”) related to the site and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7 . To AmeriGas OLP’s knowledge, the DEC has not yet commenced implementation of the remediation plan but remediation is currently expected to commence in 2018. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing its challenge to designation as a PRP and identifying potential defenses. In October 2017, the DEC identified a third party PRP with respect to the site. Based on our evaluation of the available information, during Fiscal 2017, the Partnership accrued an environmental remediation liability of $7.5 related to the site, which amount is included in “ Operating and administrative expenses ” on the Consolidated Statements of Income. Our share of the actual remediation costs could be significantly more or less than the accrued amount. Other Matters Purported Class Action Lawsuits. Between May and October of 2014, more than 35 purported 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, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their 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 United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers. In June 2017, the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) ruled en banc to reverse the dismissal by the District Court, which had previously been affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. In July 2015, the District Court also dismissed all claims brought by the indirect customers other than those for injunctive relief. The indirect customers filed an amended complaint with the District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect customers appealed this decision to the Eighth Circuit; such appeal was subject to a stay pending the en banc review of the direct purchasers’ claims. In light of the Eighth Circuit decision with respect to the direct purchasers’ claims, the briefing schedule in respect of the indirect purchaser appeal will now resume. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal still pending in the Eighth Circuit. Now that the Eighth Circuit ruled on the direct purchasers’ claims, the stay has been lifted for the indirect claims and the parties submitted briefs in October 2017 to the Eighth Circuit and are waiting the court’s ruling. 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 financial statements. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 16 — Fair Value Measurements Recurring Fair Value Measurements 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, 2017 and 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2017: Derivative instruments: Assets: Commodity contracts $ 27.2 $ 76.9 $ — $ 104.1 Foreign currency contracts $ — $ 12.2 $ — $ 12.2 Liabilities: Commodity contracts $ (27.7 ) $ (11.4 ) $ — $ (39.1 ) Foreign currency contracts $ — $ (38.2 ) $ — $ (38.2 ) Cross-currency swaps $ — $ (2.9 ) $ — $ (2.9 ) Interest rate contracts $ — $ (2.3 ) $ — $ (2.3 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.6 $ — $ — $ 35.6 September 30, 2016 Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7 ). 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 that 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, foreign currency contracts and cross-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. 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). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016 were as follows: 2017 2016 Carrying amount $ 4,211.9 $ 3,832.3 Estimated fair value $ 4,346.8 $ 4,052.3 Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit 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 arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 17 . 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. See Note 2 for additional information on this investment. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 17 — 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. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For information on the accounting for our derivative instruments, see Note 2 . Commodity Price Risk Regulated Utility Operations Natural Gas 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 PGC. 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. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8 ). Electricity 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. At September 30, 2017 and 2016 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 8 ). Non-utility Operations LPG 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 businesses 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. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane. Natural Gas In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. 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. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers. Electricity In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, 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. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity. Interest Rate Risk France SAS’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor and LIBOR rates of interest on their variable-rate term loans. The France SAS swaps were originally executed in Fiscal 2015, at which time such swaps were designated in a cash flow hedging relationship associated with €600 notional amount of term loan debt issued in conjunction with the Totalgaz Acquisition. In March 2016, France SAS amended the terms of its pay-fixed, receive-variable interest rate swap agreements associated with the €600 term loan debt to purchase a 0% floor that is identical to the 0% floor embedded in France SAS’ term loan debt. In conjunction with the amendments, in March 2016, France SAS paid its interest rate swap counterparties €7.7 , which amount substantially equaled the interest rate swaps’ fair value. Concurrent with the amendments to the interest rate swaps, the swaps were simultaneously de-designated and re-designated as cash flow hedges of future anticipated interest payments associated with the €600 term loan debt. The amended swaps fix the underlying euribor rate on the €600 term loan at 0.18% . 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”). We account for interest rate swaps and IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $36.0 . Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and is being recognized in interest expense as the associated future interest expense impacts earnings. At September 30, 2017 and 2016 , we had no unsettled IRPAs. At September 30, 2017 , 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 $3.5 . Foreign Currency Exchange Rate Risk Forward Foreign Currency Exchange Contracts In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2017 , the amount of net losses associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $0.9 . Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the Consolidated Balance Sheets. Changes in the fair value of these foreign currency exchange contracts are recorded in “ Losses on foreign currency contracts, net ” on the Consolidated Statements of Income. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. At September 30, 2017 and 2016 , there were no unsettled net investment hedges outstanding. Cross-currency Swaps From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include 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. These cross-currency swaps also include interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At September 30, 2017 , the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material. Quantitative Disclosures Related to Derivative Instruments The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at September 30, 2017 and 2016 and the final settlement date of the Company's open derivative transactions as of September 30, 2017 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through 2017 2016 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2018 14.8 18.4 FTRs contracts Kilowatt hours May 2018 101.2 58.3 Non-utility Operations LPG swaps & options Gallons March 2020 325.5 396.9 Natural gas futures, forward and pipeline contracts (a) Dekatherms December 2021 75.9 71.1 Natural gas basis swap contracts Dekatherms March 2022 104.2 118.3 NYMEX natural gas storage Dekatherms March 2019 1.9 1.9 NYMEX propane storage Gallons March 2018 0.3 — Electricity long forward and futures contracts (a) Kilowatt hours May 2021 4,440.3 761.2 Electricity short forward and futures contracts Kilowatt hours May 2021 447.0 264.6 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2020 $ 424.8 $ 314.3 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1 (a) Amounts in 2017 include derivative contracts held by a natural gas and electricity marketing business in the Netherlands acquired in Fiscal 2017. 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 forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017 and 2016 , restricted cash in brokerage accounts totaled $10.3 and $15.6 , respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at September 30, 2017 . 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, 2017 , 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 the Consolidated Balance Sheets if the right of offset exists. We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty. 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 over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the 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 the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30, 2017 and 2016 : 2017 2016 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 3.2 $ 17.8 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.7 4.5 Derivatives not designated as hedging instruments: Commodity contracts 102.4 50.4 Foreign currency contracts 9.0 — 111.4 50.4 Total derivative assets – gross 116.3 72.7 Gross amounts offset in the balance sheet (35.7 ) (35.0 ) Cash collateral received (8.3 ) (0.3 ) Total derivative assets – net $ 72.3 $ 37.4 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (5.5 ) $ (2.4 ) Cross-currency contracts (2.9 ) (0.5 ) Interest rate contracts (2.3 ) (3.9 ) (10.7 ) (6.8 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (1.5 ) (0.5 ) Derivatives not designated as hedging instruments: Commodity contracts (37.6 ) (98.1 ) Foreign currency contracts (32.7 ) — (70.3 ) (98.1 ) Total derivative liabilities – gross (82.5 ) (105.4 ) Gross amounts offset in the balance sheet 35.7 35.0 Total derivative liabilities – net $ (46.8 ) $ (70.4 ) Effects of Derivative Instruments The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income Location of Gain (Loss) Reclassified from Interests into Income 2017 2016 2015 2017 2016 2015 Cash Flow Hedges: Commodity contracts $ — $ — $ — $ — $ — $ (2.2 ) Cost of sales Foreign currency contracts 0.2 3.6 26.0 17.8 17.2 9.7 Cost of sales Cross-currency contracts 0.5 0.1 5.4 (0.1 ) 0.4 8.5 Interest expense /other operating income, net Interest rate contracts 1.5 (32.5 ) (6.6 ) (3.9 ) (4.5 ) (20.4 ) Interest expense Total $ 2.2 $ (28.8 ) $ 24.8 $ 13.8 $ 13.1 $ (4.4 ) Gain (Loss) Recognized in Income Location of Recognized in Income 2017 2016 2015 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ 166.0 $ (65.0 ) $ (375.8 ) Cost of sales Commodity contracts (2.0 ) (2.2 ) 0.3 Revenues Commodity contracts 0.2 (0.1 ) (0.8 ) Operating and administrative expenses / other operating income, net Foreign currency contracts (23.8 ) — — Losses on foreign currency contracts, net Total $ 140.4 $ (67.3 ) $ (376.3 ) For Fiscal 2017 and Fiscal 2015 , 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 2016 the amounts of derivative gains or losses representing ineffectiveness were losses of $5.5 , which were recorded in “ Other operating income, net ,” on the Consolidated Statements of Income and are related to interest rate swap agreements at France SAS prior to their amendments in March 2016. In May 2015, the Company prepaid term loans outstanding under Antargaz’ 2011 Senior Facilities Agreement. In conjunction with the prepayment, the Company also settled associated pay-fixed, receive-variable interest rate swaps, and discontinued cash flow hedge accounting treatment for such swaps. During Fiscal 2015, the Company recorded a pre-tax loss of $9.0 associated with the discontinuance of cash flow hedge accounting for the swaps, which amount is included in “ Interest expense ” on the Consolidated Statements of Income. We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that 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 certain of these contracts have the requisite elements of a derivative instrument, 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. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Note 18 — Accumulated 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 long-term intra-company transaction adjustments. Changes in AOCI during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) (1.2 ) 16.8 (114.1 ) (98.5 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 2.2 4.4 — 6.6 Reclassification adjustments tax benefit (0.8 ) (2.8 ) — (3.6 ) Reclassification adjustments (after-tax) 1.4 1.6 — 3.0 Other comprehensive income (loss) 0.2 18.4 (114.1 ) (95.5 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 2.1 — 2.1 Other comprehensive income (loss) attributable to UGI 0.2 20.5 (114.1 ) (93.4 ) AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive loss before reclassification adjustments (after-tax) (10.9 ) (16.5 ) (6.8 ) (34.2 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.6 (13.1 ) — (10.5 ) Reclassification adjustments tax (benefit) expense (0.4 ) 5.0 — 4.6 Reclassification adjustments (after-tax) 2.2 (8.1 ) — (5.9 ) Other comprehensive loss attributable to UGI (8.7 ) (24.6 ) (6.8 ) (40.1 ) AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income before reclassification adjustments (after-tax) 6.5 1.7 59.4 67.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 5.5 (13.8 ) — (8.3 ) Reclassification adjustments tax (benefit) expense (2.1 ) 4.1 — 2.0 Reclassification adjustments (after-tax) 3.4 (9.7 ) — (6.3 ) Other comprehensive income (loss) attributable to UGI 9.9 (8.0 ) 59.4 61.3 AOCI - September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 17 . |
Other Operating Income, Net
Other Operating Income, Net | 12 Months Ended |
Sep. 30, 2017 | |
Component of Operating Income [Abstract] | |
Other Operating Income, Net | Note 19 — Other Operating Income, Net Other operating income, net, comprises the following: 2017 2016 2015 Finance charges $ 11.8 $ 15.2 $ 12.7 AFUDC associated with pipeline projects 5.5 3.3 — Interest and interest-related income 1.7 0.2 0.8 Utility non-tariff service income 1.5 2.6 4.8 Loss on private equity partnership investment (11.0 ) — — (Losses) gains on sales of fixed assets, net (3.9 ) 3.3 11.1 Other, net 4.9 (2.2 ) 15.0 Total other operating income, net $ 10.5 $ 22.4 $ 44.4 |
Quarterly Data (unaudited)
Quarterly Data (unaudited) | 12 Months Ended |
Sep. 30, 2017 | |
Quarterly Financial Data [Abstract] | |
Quarterly Data (unaudited) | Note 20 — 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 primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity and certain foreign currency derivative instruments (see Note 17). December 31, March 31, June 30, September 30, 2016 (a)(b) 2015 2017 (b)(c) 2016 2017 (b) 2016 (d) 2017 (a)(c) 2016 (d) Revenues $ 1,679.5 $ 1,606.6 $ 2,173.8 $ 1,972.1 $ 1,153.5 $ 1,130.8 $ 1,113.9 $ 976.2 Operating income (loss) $ 466.2 $ 305.5 $ 513.2 $ 615.4 $ (2.8 ) $ 155.7 $ 27.6 $ (88.6 ) (Loss) income from equity investees $ (0.2 ) $ (0.1 ) $ 2.3 $ — $ 0.9 $ — $ 1.3 $ (0.1 ) Loss on extinguishments of debt $ (33.2 ) $ — $ (22.1 ) $ — $ (4.4 ) $ (37.1 ) $ — $ (11.8 ) Net income (loss) including noncontrolling interests $ 290.9 $ 167.9 $ 311.8 $ 408.0 $ (62.2 ) $ 28.6 $ (16.7 ) $ (115.7 ) Net income (loss) attributable to UGI Corporation $ 230.7 $ 114.6 $ 219.9 $ 233.2 $ (19.0 ) $ 60.7 $ 5.0 $ (43.8 ) Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 1.33 $ 0.66 $ 1.27 $ 1.35 $ (0.11 ) $ 0.35 $ 0.03 $ (0.25 ) Diluted $ 1.30 $ 0.65 $ 1.24 $ 1.33 $ (0.11 ) $ 0.34 $ 0.03 $ (0.25 ) (a) The quarter ended December 31, 2016 includes beneficial impact of adjustments to net deferred income tax liabilities associated with a change in French income tax rate which increased net income attributable to UGI Corporation by $27.4 or $0.15 per diluted share, and the impact of an income tax settlement refund in France which increased net income attributable to UGI Corporation by $6.7 or $0.04 per diluted share. The quarter ended September 30, 2017 includes the release of a valuation allowance against future uses of foreign tax credit carryforwards, which increased net income attributable to UGI Corporation by $7.6 or $0.04 per diluted share. (b) The quarter ended December 31, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $5.3 or $0.03 per diluted share. The quarter ended March 31, 2017 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $3.6 or $0.02 . The quarter ended June 30, 2017 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $0.7 or $0.01 per diluted share (see Note 5). (c) The quarter ended March 31, 2017 includes impairment of a cost basis investment which decreased net income attributable to UGI Corporation by $4.5 or $0.03 per diluted share. The quarter ended September 30, 2017 includes impairment of a cost basis investment which decreased net income attributable to UGI Corporation by $2.6 or $0.02 per diluted share for the quarter ended September 30, 2017 (see Note 2). (d) The quarter ended June 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share. The quarter ended September 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5). |
Segment Information
Segment Information | 12 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Note 21 — Segment Information Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities. As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”), effective October 1, 2016, we combined (1) our UGI France reportable segment with our Flaga & Other reportable segment, collectively referred to as “UGI International,” and (2) our Energy Services reportable segment with our Electric Generation reportable segment, collectively referred to as “Midstream & Marketing.” In accordance with GAAP, prior-period amounts have been restated to reflect these changes. AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. UGI International derives its revenues principally from the distribution of LPG to retail customers in France and in northern, central and eastern European countries. In addition, UGI International operates natural gas marketing businesses in France, Belgium and the United Kingdom and markets natural gas and electricity in the Netherlands. Midstream & Marketing derives its revenues principally from the sale of natural gas and, to a lesser extent, electricity, LPG and fuel oil as well as revenues and fees from storage, pipeline transportation and natural gas production activities primarily in the Mid-Atlantic region of the U.S. Midstream & Marketing also derives revenues from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S., and, to a lesser extent, also from contracting services provided by HVAC to customers in portions of eastern and central Pennsylvania. UGI Utilities derives its revenues principally from the sale and distribution of natural gas to customers in eastern and central Pennsylvania and, to a lesser extent, from the sale and distribution of electricity in two northeastern Pennsylvania counties. Corporate & Other principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our CODM in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets. 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 as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted 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 Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned. 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. Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (b) 2017 Revenues from external customers $ 6,120.7 $ — $ 2,453.5 $ 1,877.5 $ 943.0 $ 847.5 $ (0.8 ) Intersegment revenues $ — $ (222.7 ) (c) $ — $ — $ 178.2 $ 40.1 $ 4.4 Cost of sales $ 2,837.3 $ (218.3 ) (c) $ 1,002.9 $ 935.3 $ 856.7 $ 367.3 $ (106.6 ) Operating income $ 1,004.2 $ 0.3 $ 355.3 $ 195.7 $ 139.2 $ 228.3 $ 85.4 Income from equity investees $ 4.3 $ — $ — $ — $ 4.3 (d) $ — $ — Losses on foreign currency contracts, net $ (23.9 ) $ — $ — $ (0.1 ) $ — $ — $ (23.8 ) Loss on extinguishments of debt $ (59.7 ) $ — $ (59.7 ) $ — $ — $ — $ — Interest expense $ (223.5 ) $ — $ (160.2 ) $ (20.6 ) $ (2.1 ) $ (40.2 ) $ (0.4 ) Income before income taxes $ 701.4 $ 0.3 $ 135.4 $ 175.0 $ 141.4 $ 188.1 $ 61.2 Net income attributable to UGI $ 436.6 $ 0.1 $ 44.6 $ 158.6 $ 86.9 $ 116.0 $ 30.4 Depreciation and amortization $ 416.3 $ (0.2 ) $ 190.5 $ 117.4 $ 35.4 $ 72.3 $ 0.9 Noncontrolling interests’ net income $ 87.2 $ — $ 64.4 $ 0.2 $ — $ — $ 22.6 Partnership Adjusted EBITDA (a) $ 551.3 Total assets $ 11,582.2 $ (51.5 ) $ 4,069.4 $ 3,132.0 $ 1,165.5 $ 2,994.0 $ 272.8 Short-term borrowings $ 366.9 $ — $ 140.0 $ 17.9 $ 39.0 $ 170.0 $ — Capital expenditures (including the effects of accruals) $ 624.3 $ — $ 98.1 $ 90.3 $ 117.5 $ 317.7 $ 0.7 Investments in equity investees $ 59.1 $ — $ — $ 8.1 $ 51.0 $ — $ — Goodwill $ 3,107.2 $ — $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ — 2016 (f) Revenues from external customers $ 5,685.7 $ — $ 2,311.8 $ 1,868.8 $ 752.3 $ 751.4 $ 1.4 Intersegment revenues $ — $ (133.9 ) (c) $ — $ — $ 114.3 $ 17.1 $ 2.5 Cost of sales $ 2,437.5 $ (131.5 ) (c) $ 864.8 $ 903.8 $ 602.2 $ 289.8 $ (91.6 ) Operating income $ 988.0 $ 0.2 $ 356.3 $ 206.6 $ 146.7 $ 200.9 $ 77.3 Loss from equity investees $ (0.2 ) $ — $ — $ (0.2 ) $ — $ — $ — Loss on extinguishments of debt $ (48.9 ) $ — $ (48.9 ) $ — $ — $ — $ — Interest expense $ (228.9 ) $ — $ (164.1 ) $ (24.4 ) $ (2.1 ) $ (37.6 ) $ (0.7 ) Income before income taxes $ 710.0 $ 0.2 $ 143.3 $ 182.0 $ 144.6 $ 163.3 $ 76.6 Net income attributable to UGI $ 364.7 $ 0.1 $ 43.2 $ 111.6 $ 87.1 $ 97.4 $ 25.3 Depreciation and amortization $ 400.9 $ (0.2 ) $ 190.0 $ 112.4 $ 30.6 $ 67.3 $ 0.8 Noncontrolling interests’ net income $ 124.1 $ — $ 75.9 $ — $ — $ — $ 48.2 Partnership Adjusted EBITDA (a) $ 543.0 Total assets $ 10,847.2 $ (136.6 ) $ 4,071.8 $ 2,865.1 $ 1,038.2 $ 2,743.1 $ 265.6 Short-term borrowings $ 291.7 $ — $ 153.2 $ 0.5 $ 25.5 $ 112.5 $ — Capital expenditures (including the effects of accruals) $ 604.6 $ — $ 101.7 $ 99.9 $ 140.4 $ 262.5 $ 0.1 Investments in equity investees $ 25.9 $ — $ — $ 8.5 $ 17.4 $ — $ — Goodwill $ 2,989.0 $ — $ 1,978.3 $ 817.0 $ 11.6 $ 182.1 $ — Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (b) 2015 (f) Revenues from external customers $ 6,691.1 $ — $ 2,885.3 $ 1,808.5 $ 1,012.3 $ 981.9 $ 3.1 Intersegment revenues $ — $ (213.6 ) (c) $ — $ — $ 151.3 $ 59.7 $ 2.6 Cost of sales $ 3,736.5 $ (209.8 ) (c) $ 1,340.0 $ 1,120.0 $ 854.6 $ 510.8 $ 120.9 Operating income (loss) $ 834.9 $ (0.9 ) $ 427.6 $ 112.8 $ 182.6 $ 241.7 $ (128.9 ) Loss from equity investees $ (1.2 ) $ — $ — $ (1.2 ) $ — $ — $ — Interest expense $ (241.9 ) $ — $ (162.8 ) $ (35.2 ) (e) $ (2.1 ) $ (41.1 ) $ (0.7 ) Income (loss) before income taxes $ 591.8 $ (0.9 ) $ 264.8 $ 76.4 $ 180.5 $ 200.6 $ (129.6 ) Net income (loss) attributable to UGI $ 281.0 $ (0.6 ) $ 61.0 $ 52.7 $ 107.5 $ 121.1 $ (60.7 ) Depreciation and amortization $ 374.1 $ — $ 194.9 $ 86.9 $ 28.0 $ 63.5 $ 0.8 Noncontrolling interests’ net income (loss) $ 133.0 $ — $ 167.9 $ (0.1 ) $ — $ — $ (34.8 ) Partnership Adjusted EBITDA (a) $ 619.2 Total assets $ 10,514.2 $ (90.4 ) $ 4,128.4 $ 2,860.9 $ 969.6 $ 2,506.0 $ 139.7 Short-term borrowings $ 189.9 $ — $ 68.1 $ 0.6 $ 49.5 $ 71.7 $ — Capital expenditures (including the effects of accruals) $ 475.4 $ — $ 102.0 $ 87.5 $ 88.0 $ 197.7 $ 0.2 Investments in equity investees $ 16.2 $ — $ — $ 9.8 $ 6.4 $ — $ — Goodwill $ 2,953.4 $ — $ 1,956.0 $ 803.7 $ 11.6 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: 2017 2016 2015 Partnership Adjusted EBITDA $ 551.3 $ 543.0 $ 619.2 Depreciation and amortization (190.5 ) (190.0 ) (194.9 ) Interest expense (160.2 ) (164.1 ) (162.8 ) Loss on extinguishments of debt (59.7 ) (48.9 ) — MGP environmental accrual (7.5 ) — — Noncontrolling interest (i) 2.0 3.3 3.3 Income before income taxes $ 135.4 $ 143.3 $ 264.8 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Includes net pre-tax gains (losses) on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $82.0 , $91.6 and $(119.1) in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , respectively. Fiscal 2017 also includes a pre-tax loss of $11.0 associated with the impairment of a cost basis investment (see Note 2 ). (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents AFUDC associated with PennEast (see Note 2 ). (e) Includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5 ). (f) Restated to reflect the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments. |
Condensed Financial Information
Condensed Financial Information of Registrant (Parent Company) | 12 Months Ended |
Sep. 30, 2017 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Financial Information of Registrant (Parent Company) | BALANCE SHEETS (Millions of dollars) September 30, 2017 2016 ASSETS Current assets: Cash and cash equivalents $ 15.8 $ 4.8 Accounts receivable – related parties 4.5 9.2 Prepaid expenses and other current assets 15.6 5.0 Total current assets 35.9 19.0 Property, plant and equipment, net 0.4 — Investments in subsidiaries 3,119.7 2,825.7 Other assets 82.0 69.8 Total assets $ 3,238.0 $ 2,914.5 LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY Current liabilities: Accounts and notes payable $ 12.3 $ 11.4 Accrued liabilities 5.9 4.4 Total current liabilities 18.2 15.8 Noncurrent liabilities 56.5 54.6 Commitments and contingencies (Note 1) Common stockholders’ equity: Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) 1,188.6 1,201.6 Retained earnings 2,106.7 1,834.1 Accumulated other comprehensive loss (93.4 ) (154.7 ) Treasury stock, at cost (38.6 ) (36.9 ) Total common stockholders’ equity 3,163.3 2,844.1 Total liabilities and common stockholders’ equity $ 3,238.0 $ 2,914.5 Note 1 — Commitments and Contingencies: In addition to the guarantees of Flaga’s debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2017 , UGI Corporation had agreed to indemnify the issuers of $88.9 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, LLC and subsidiaries of which $432.5 of such obligations were outstanding as of September 30, 2017 . UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga, which obligations totaled $0.6 at September 30, 2017 . STATEMENTS OF INCOME (Millions of dollars, except per share amounts) Year Ended September 30, 2017 2016 2015 Revenues $ — $ — $ — Costs and expenses: Operating and administrative expenses 46.3 45.7 48.7 Other operating income, net (a) (45.9 ) (45.3 ) (48.5 ) 0.4 0.4 0.2 Operating loss (0.4 ) (0.4 ) (0.2 ) Intercompany interest income — 0.1 0.1 Loss before income taxes (0.4 ) (0.3 ) (0.1 ) Income tax (benefit) expense (5.7 ) (4.0 ) 1.9 Income (loss) before equity in income of unconsolidated subsidiaries 5.3 3.7 (2.0 ) Equity in income of unconsolidated subsidiaries 431.3 361.0 283.0 Net income attributable to UGI Corporation $ 436.6 $ 364.7 $ 281.0 Other comprehensive income (loss) 1.3 (1.1 ) 0.1 Equity in other comprehensive income (loss) of unconsolidated subsidiaries 60.0 (39.0 ) (93.5 ) Comprehensive income attributable to UGI Corporation $ 497.9 $ 324.6 $ 187.6 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 2.51 $ 2.11 $ 1.62 Diluted $ 2.46 $ 2.08 $ 1.60 Weighted - average common shares outstanding (thousands): Basic 173,662 173,154 173,115 Diluted 177,159 175,572 175,667 (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 operating income, net” in the Statements of Income above. STATEMENTS OF CASH FLOWS (Millions of dollars) Year Ended September 30, 2017 2016 2015 NET CASH PROVIDED BY OPERATING ACTIVITIES (a) $ 253.2 $ 195.6 $ 277.2 CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for property, plant and equipment (0.4 ) — — Net investments in unconsolidated subsidiaries (40.7 ) (8.9 ) (104.8 ) Net cash used by investing activities (41.1 ) (8.9 ) (104.8 ) CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends on Common Stock (168.9 ) (160.7 ) (153.5 ) Repurchases of UGI Common Stock (43.3 ) (47.6 ) (34.1 ) Issuances of Common Stock 11.0 24.5 16.8 Other 0.1 — (0.5 ) Net cash used by financing activities (201.1 ) (183.8 ) (171.3 ) Cash and cash equivalents increase $ 11.0 $ 2.9 $ 1.1 Cash and cash equivalents: End of year $ 15.8 $ 4.8 $ 1.9 Beginning of year 4.8 1.9 0.8 Increase $ 11.0 $ 2.9 $ 1.1 (a) Includes dividends received from unconsolidated subsidiaries of $241.9 , $193.1 and $271.6 for the years ended September 30, 2017 , 2016 and 2015 , respectively. |
Valuation and Qualifying Accoun
Valuation and Qualifying Accounts | 12 Months Ended |
Sep. 30, 2017 | |
Valuation and Qualifying Accounts [Abstract] | |
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, 2017 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 27.3 $ 30.7 $ (31.1 ) (1) $ 26.9 Other reserves: Deferred tax assets valuation allowance $ 114.3 $ (7.6 ) $ 0.4 (3) $ 107.1 Year Ended September 30, 2016 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 29.7 $ 21.7 $ (24.1 ) (1) $ 27.3 Other reserves: Deferred tax assets valuation allowance $ 131.3 $ (5.8 ) $ (8.8 ) (3) $ 114.3 (2.4 ) (4) Year Ended September 30, 2015 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 39.1 $ 31.6 $ (39.6 ) (1) $ 29.7 (1.4 ) (2) Other reserves: Deferred tax assets valuation allowance $ 59.2 $ 5.1 $ 66.1 (3) $ 131.3 (2.6 ) (4) 3.5 (5) (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) Acquisitions |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Certain prior-year amounts have been reclassified to conform to the current-year presentation. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100% -owned subsidiaries, as noncontrolling interests. We eliminate 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. Investments in business entities that are not publicly traded and in which we do not have significant influence over operating and financial policies are accounted for using the cost method. |
Effects of Regulation | Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “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 and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. |
Fair Value Measurements | Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value 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 Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception 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 and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“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 occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “ Losses on foreign currency contracts, net ” on the Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flow from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flow from financing activities. |
Foreign Currency Translation | Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. |
Revenue Recognition | Revenue Recognition Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing and our UGI International energy marketing business record 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 rendered and commodities delivered 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 on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in “ Utility taxes other than income taxes ” on the Consolidated Statements of Income in accordance with regulatory practice. |
Accounts Receivable | Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. |
LPG Delivery Expenses | 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 | Income Taxes AmeriGas Partners and AmeriGas OLP 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. AmeriGas OLP 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. UGI Utilities records 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. UGI Utilities also records 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. We record interest on tax deficiencies and income tax penalties in “ Income taxes ” on the Consolidated Statements of Income. |
Earnings Per Common Share | Earnings Per Common Share Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards. |
Cash and Cash Equivalents | Cash and Cash Equivalents For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased. |
Restricted Cash | Restricted Cash Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. |
Inventories | Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for non-utility LPG and natural gas and Gas Utility natural gas; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories. |
Property, Plant and Equipment and Related Depreciation | Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, allowance for funds used during construction (“AFUDC”). 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. At September 30, 2017 , estimated useful lives by type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 40 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 12 Computer software 1 10 We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis based upon the projected service lives of the various classes of its depreciable property. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Gas Utility 2.2 % 2.2 % 2.2 % Electric Utility 2.4 % 2.5 % 2.5 % When UGI 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 and amortized over five years , consistent with prior ratemaking treatment. |
Goodwill and Intangible Assets | Goodwill and Intangible Assets We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames 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 for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. 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. 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. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3). For certain of our reporting units with goodwill, 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 bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including 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. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. |
Impairment of Long-Lived Assets | We evaluate long-lived assets for impairment 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. |
Cost Method Investments | We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. |
Deferred Debt Issuance Costs | Deferred Debt Issuance Costs We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities are classified as “ Other assets ” on our Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in loss on extinguishment of debt. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and amortized over the lives of the new issuances. |
Refundable Tank and Cylinder Deposits | Refundable Tank and Cylinder Deposits Included in “ Other noncurrent liabilities ” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders primarily owned by subsidiaries of France SAS of $279.9 and $267.2 at September 30, 2017 and 2016 , respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms. |
Environmental Matters | Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the 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 be reasonably 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, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. |
Employee Retirement Plans | Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our U.S. 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 |
Equity-Based Compensation | Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units” or “Unit awards”), 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 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. Prior to the adoption of new accounting guidance effective October 1, 2016, differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return were recorded in Common Stock (if the tax benefit exceeded the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeded the tax benefit and no tax windfall pool existed from previous awards). We calculated this tax windfall pool using the shortcut method. Effective October 1, 2016, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-Based Payments Accounting” (“ASU 2016-09”) issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding no longer include windfall tax benefits in the diluted shares calculation. In accordance with the required prospective method of transition relating to excess tax benefits, we recognized income tax benefits of $10.3 related to excess tax benefits for share-based awards that were exercised or vested during Fiscal 2017. This amount is reflected in “ Income taxes ” on the Consolidated Statements of Income. In addition, upon the adoption of ASU 2016-09, we recorded a $4.9 increase to retained earnings and decrease to deferred income tax liabilities for excess tax benefits related to prior period unrecognized state tax benefits. We elected to use the prospective method of transition for classifying excess tax benefits as cash flow from operating activities on the Consolidated Statements of Cash Flows and prior periods were not adjusted. We have historically presented employee taxes paid for net settled awards as a financing activity on the Consolidated Statements of Cash Flows and therefore there is no transition impact from this requirement. In addition, as provided by the new guidance, we elected to account for forfeitures of share-based payments when they occur. |
Accounting Changes | Adoption of New Accounting Standards Definition of a Business. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance which clarifies the definition of a business. The new guidance is intended to assist entities with evaluating whether a set of transferred assets and activities comprises a business. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements. Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Employee Share-based Payments. Effective October 1, 2016, the Company adopted ASU 2016-09 regarding share-based payments. See Note 2 for a detailed description of the impact of the new guidance. Equity Method Accounting. Effective October 1, 2016, the Company adopted new accounting guidance regarding the accounting for an investment that qualifies for use of the equity method as a result of an increase in an investor’s level of ownership or influence. The guidance requires that the equity method investor add the cost of acquiring an additional interest to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date such investment qualifies for equity method accounting. The new guidance eliminates the previous requirement in such circumstances to apply the effects of the equity method of accounting retrospectively. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Accounting Standards Not Yet Adopted Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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 entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements. |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Equity Method Investments | Our equity and cost method investments are included in “ Other assets ” on the Consolidated Balance Sheets and comprise the following amounts at September 30, 2017 and 2016: 2017 2016 Equity method investments $ 59.1 $ 25.9 Cost method investments (a) $ 61.3 $ 70.1 (a) Cost method investments at September 30, 2017 and 2016 include $7.0 and $18.0 , respectively, associated with our investment in a private equity partnership that invests in renewable energy companies. |
Cost Method Investments | Our equity and cost method investments are included in “ Other assets ” on the Consolidated Balance Sheets and comprise the following amounts at September 30, 2017 and 2016: 2017 2016 Equity method investments $ 59.1 $ 25.9 Cost method investments (a) $ 61.3 $ 70.1 (a) Cost method investments at September 30, 2017 and 2016 include $7.0 and $18.0 , respectively, associated with our investment in a private equity partnership that invests in renewable energy companies. |
Shares Used in Computing Basic and Diluted Earnings Per Share | In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 : (Thousands of shares) 2017 2016 2015 Weighted-average common shares outstanding for basic computation 173,662 173,154 173,115 Incremental shares issuable for stock options and common stock awards (a) 3,497 2,418 2,552 Weighted-average common shares outstanding for diluted computation 177,159 175,572 175,667 (a) For Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , there were 146 shares, 38 shares and 1 share, 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. See “ Equity-Based Compensation ” below for a description of the impact on the calculation of diluted shares for Fiscal 2017 , resulting from the adoption of new accounting guidance regarding share-based payments. |
Estimated Useful Lives by Type | September 30, 2017 , estimated useful lives by type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 40 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 12 Computer software 1 10 Property, plant and equipment comprise the following at September 30: 2017 2016 Utilities: Distribution $ 2,835.3 $ 2,634.2 Transmission 96.4 93.5 Work in process 112.6 103.9 General and other 241.0 167.3 Total Utilities 3,285.3 2,998.9 Non-utility: Land 180.1 169.9 Buildings and improvements 351.2 382.2 Transportation equipment 289.3 301.7 Equipment, primarily cylinders and tanks 3,529.4 3,421.5 Electric generation 310.0 309.4 Pipeline and related assets 454.5 235.8 Work in process 95.3 201.6 Other 354.8 324.3 Total non-utility 5,564.6 5,346.4 Total property, plant and equipment $ 8,849.9 $ 8,345.3 |
Average Composite Depreciation Rates | The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Gas Utility 2.2 % 2.2 % 2.2 % Electric Utility 2.4 % 2.5 % 2.5 % |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Components of Final Purchase Price Allocation | The components of the final Totalgaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 117.5 Other noncurrent liabilities 113.4 Total liabilities assumed $ 443.6 Goodwill 183.8 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Comprises $79.3 of customer relationships and $12.0 of tradenames ( $8.3 of which is subject to amortization), having average amortization periods of 15 years . |
Unaudited Pro Forma Revenues, Net Income, and Earnings Per Share Data | The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014. Amounts in the table below exclude costs associated with extinguishment of debt under Antargaz’ 2011 Senior Facilities Agreement (see Note 5 ): 2015 As Reported Pro Forma Adjusted Revenues $ 6,691.1 $ 7,065.8 Net income attributable to UGI Corporation $ 281.0 $ 341.2 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 1.62 $ 1.97 Diluted $ 1.60 $ 1.94 |
Total Cash Paid and Liabilities Incurred | Total cash paid and liabilities incurred in connection with these acquisitions were as follows: 2017 2016 2015 AmeriGas Propane UGI International AmeriGas Propane UGI International AmeriGas Propane UGI International Total cash paid $ 36.8 $ 99.7 $ 37.6 $ 24.1 $ 20.8 $ 17.6 Liabilities incurred (a) 10.8 20.6 11.8 — 4.2 — Total purchase price $ 47.6 $ 120.3 $ 49.4 $ 24.1 $ 25.0 $ 17.6 (a) Reflects notes payable to seller and liabilities associated with noncompete agreements. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Loss on Extinguishment of Debt | In connection with the early repayments of AmeriGas’ Senior Notes, during Fiscal 2017 and 2016 , the Partnership recognized pre-tax losses which are reflected in “ Loss on extinguishments of debt ” on the Consolidated Statements of Income and comprise the following: 2017 2016 Early redemption premiums $ 51.3 $ 39.6 Write-off of unamortized debt issuance costs 8.4 9.3 Loss on extinguishments of debt $ 59.7 $ 48.9 |
Schedule of Long-term Debt Instruments | Long-term debt comprises the following at September 30: 2017 2016 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.50% due May 2025 $ 700.0 $ — 5.875% due August 2026 675.0 675.0 5.625% due May 2024 675.0 675.0 5.75% due May 2027 525.0 — 7.00%, due May 2022 — 980.8 HOLP Senior Secured Notes, including unamortized premium of $0.4 and $0.7, respectively (a) 11.3 15.2 Other 17.3 14.2 Unamortized debt issuance costs (31.3 ) (26.6 ) Total AmeriGas Propane 2,572.3 2,333.6 UGI International: France SAS Senior Facilities term loan, due through April 2020 (b) 708.9 674.4 Flaga variable-rate term loan, due October 2020 (c) 54.1 51.4 Flaga U.S. dollar variable-rate term loan, due September 2018 (d) 59.1 59.1 Other 21.3 1.4 Unamortized debt issuance costs (4.6 ) (6.7 ) Total UGI International 838.8 779.6 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 200.0 4.98%, due March 2044 175.0 175.0 4.12%, due October 2046 100.0 — 6.21%, due September 2036 100.0 100.0 2.95%, due June 2026 100.0 100.0 Medium-Term Notes: 6.13%, due October 2034 20.0 20.0 6.50%, due August 2033 20.0 20.0 5.67%, due January 2018 20.0 20.0 7.25%, due November 2017 20.0 20.0 6.17%, due June 2017 — 20.0 Unamortized debt issuance costs (3.9 ) (3.5 ) Total UGI Utilities 751.1 671.5 Other 9.9 10.8 Total long-term debt 4,172.1 3,795.5 Less: current maturities (177.5 ) (29.5 ) Total long-term debt due after one year $ 3,994.6 $ 3,766.0 (a) At September 30, 2017 and 2016 , the effective interest rate on the HOLP Senior Secured Notes was 6.75% . These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. (b) Borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of 0.0% . The margin on term loan borrowings (which ranges from 1.60% to 2.70% ) is dependent upon the ratio of France SAS’ consolidated total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement. At September 30, 2017 and 2016 , such margin was 1.90% . France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to fix the underlying euribor rate on term loan borrowings at 0.18% . At September 30, 2017 and 2016 , the effective interest rate on the term loan was approximately 2.10% . Principal amounts outstanding under the term loan are due as follows: €60 due April 2018; €60 due April 2019; and €480 due April 2020. (c) Borrowings bear interest at three-month euribor rates, plus a margin and other fees. The margin and other fees range from 1.20% to 2.60% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined, as well as fees defined by the local jurisdiction. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying market rate at 0.23% , effective October 2016. The effective interest rate on this term loan at September 30, 2017 and 2016 , was 1.80% and 2.11% , respectively. (d) Borrowings bear interest at a one-month LIBOR rate plus a margin of 1.125% . Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments by entering into a cross-currency swap arrangement with a bank. At September 30, 2017 and 2016 , the effective interest rate on this term loan was 0.87% . |
Schedule of Maturities of Long-term Debt | Scheduled principal repayments of long-term debt due in fiscal years 2018 to 2022 follows: 2018 2019 2020 2021 2022 AmeriGas Propane $ 8.6 $ 8.2 $ 7.5 $ 3.2 $ 1.2 UGI International 130.3 71.5 567.1 54.1 20.4 UGI Utilities 40.0 — — — — Other 0.7 0.8 0.8 0.9 0.9 Total $ 179.6 $ 80.5 $ 575.4 $ 58.2 $ 22.5 |
Schedule of Short-term Debt | Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility which is discussed below) as of September 30, 2017 and 2016 , is presented in the following table. Borrowings outstanding under these agreements are classified as “Short-term borrowings” on the Consolidated Balance Sheets. Expiration Date Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity Weighted Average Interest Rate - End of Year September 30, 2017 AmeriGas OLP (a) June 2019 $ 525.0 $ 140.0 $ 67.2 $ 317.8 3.74 % France SAS (b) April 2020 € 60.0 — — € 60.0 N.A. Flaga (c) October 2020 € 55.0 — € 6.5 € 48.5 N.A. Energy Services, LLC (d) March 2021 $ 240.0 — — $ 240.0 N.A. UGI Utilities (e) March 2020 $ 300.0 $ 170.0 $ 2.0 $ 128.0 2.11 % September 30, 2016 AmeriGas OLP (a) June 2019 $ 525.0 $ 153.2 $ 67.2 $ 304.6 2.79 % France SAS (b) April 2020 € 60.0 — — € 60.0 N.A. Flaga (c) October 2020 € 55.0 — € 9.6 € 45.4 N.A. Energy Services, LLC (d) March 2021 $ 240.0 $ — — $ 240.0 N.A. UGI Utilities (e) March 2020 $ 300.0 $ 112.5 $ 2.0 $ 185.5 1.42 % (a) The AmeriGas OLP Credit Agreement includes a $125 sublimit for letters of credit and 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, or one-, two-, three-, or six-month Eurodollar Rate, as defined, plus a margin. 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 EBITDA, as defined. (b) Borrowings under the 2015 Senior Facilities Agreement revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor) plus a margin. The margin on credit facility borrowings ranges from 1.45% to 2.55% based upon France SAS’s ratio of consolidated total net debt to EBITDA, as defined. (c) The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility and a €25 guarantee facility. Revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65% , are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, each as defined. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. Guarantees outstanding reduce the available capacity on the €25 guarantee facility. (d) The Energy Services, LLC Credit Agreement (“Energy Services Credit Agreement”) includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services, LLC and its subsidiaries. Energy Services, LLC may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined, does not exceed 3.00 to 1.00 . Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% , and (c) Adjusted LIBOR plus 1.00% . The margin on such borrowings is currently 2.25% . The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services, LLC. (e) The UGI Utilities Credit Agreement includes a $100 sublimit for letters of credit. Borrowings bear interest at prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. |
Schedule of Receivables Facility | Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , as well as the balance of ESFC trade receivables at September 30, 2017 , 2016 and 2015 follows: 2017 2016 2015 Trade receivables transferred to ESFC during the year $ 1,017.3 $ 756.4 $ 1,037.8 ESFC trade receivables sold to the bank during the year 243.0 204.0 306.5 ESFC trade receivables - end of year (a) 44.8 35.7 44.1 (a) At September 30, 2017 and 2016 , the amounts of ESFC trade receivables sold to the bank were $39.0 and $25.5 , respectively, and are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Before Income Taxes | Income before income taxes comprises the following: 2017 2016 2015 Domestic $ 527.3 $ 518.9 $ 552.3 Foreign 174.1 191.1 39.5 Total income before income taxes $ 701.4 $ 710.0 $ 591.8 |
Provisions for Income Taxes | The provisions for income taxes consist of the following: 2017 2016 2015 Current expense (benefit): Federal $ (2.7 ) $ 44.2 $ 97.1 State 14.0 20.9 32.2 Foreign 56.2 78.7 36.0 Investment tax credit — — (1.2 ) Total current expense 67.5 143.8 164.1 Deferred expense (benefit): Federal 125.8 81.2 28.1 State 16.4 1.3 2.9 Foreign (31.8 ) (4.8 ) (17.0 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense 110.1 77.4 13.7 Total income tax expense $ 177.6 $ 221.2 $ 177.8 |
Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate | A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2017 2016 2015 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: Noncontrolling interests not subject to tax (4.3 ) (6.2 ) (7.9 ) State income taxes, net of federal benefit 2.9 3.0 3.3 Valuation allowance adjustments (1.1 ) (0.9 ) 0.8 Effects of foreign operations (1.1 ) 0.6 0.2 Deferred tax effects of French tax rate change (4.1 ) — — Excess tax benefits on share-based payments (1.3 ) — — Other, net (0.7 ) (0.3 ) (1.4 ) Effective tax rate 25.3 % 31.2 % 30.0 % |
Deferred Tax Liabilities (Assets) | Deferred tax liabilities (assets) comprise the following at September 30: 2017 2016 Excess book basis over tax basis of property, plant and equipment $ 975.8 $ 873.9 Investment in AmeriGas Partners 326.8 323.2 Intangible assets and goodwill 98.2 87.1 Utility regulatory assets 132.2 148.3 Other 11.7 11.9 Gross deferred tax liabilities 1,544.7 1,444.4 Pension plan liabilities (57.7 ) (79.7 ) Employee-related benefits (65.4 ) (63.1 ) Operating loss carryforwards (30.9 ) (31.5 ) Foreign tax credit carryforwards (106.1 ) (105.1 ) Utility regulatory liabilities (9.3 ) (13.9 ) Derivative instruments (1.7 ) (14.7 ) Utility environmental liabilities (22.2 ) (22.8 ) Other (27.8 ) (28.3 ) Gross deferred tax assets (321.1 ) (359.1 ) Deferred tax assets valuation allowance 107.1 114.3 Net deferred tax liabilities $ 1,330.7 $ 1,199.6 |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2017 2016 2015 Unrecognized tax benefits — beginning of year $ 7.2 $ 3.2 $ 2.4 Additions for tax positions of the current year 1.9 2.2 0.9 Additions for tax positions taken in prior years 4.6 2.3 0.5 Settlements with tax authorities/statute lapses (1.5 ) (0.5 ) (0.6 ) Unrecognized tax benefits — end of year $ 12.2 $ 7.2 $ 3.2 |
Employee Retirement Plans (Tabl
Employee Retirement Plans (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
Change in Pension Benefits and Other Postretirement Benefits Obligations | The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI International 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, 2017 and 2016 . 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 2017 2016 2017 2016 Change in benefit obligations: Benefit obligations — beginning of year $ 707.7 $ 614.7 $ 30.9 $ 25.4 Service cost 11.9 10.1 1.0 0.7 Interest cost 25.0 26.8 0.8 0.9 Actuarial (gain) loss (19.6 ) 83.3 (4.8 ) 6.6 Plan amendments 1.2 — — (1.5 ) Curtailment (3.6 ) (1.4 ) (0.4 ) (0.3 ) Foreign currency 2.9 0.1 0.4 — Benefits paid (27.7 ) (25.9 ) (0.9 ) (0.9 ) Benefit obligations — end of year $ 697.8 $ 707.7 $ 27.0 $ 30.9 Change in plan assets: Fair value of plan assets — beginning of year $ 493.7 $ 453.8 $ 13.7 $ 12.5 Actual gain on plan assets 47.0 53.4 1.3 1.3 Foreign currency 1.6 0.1 — — Employer contributions 14.6 11.4 0.6 0.6 Benefits paid (27.7 ) (25.0 ) (0.8 ) (0.7 ) Fair value of plan assets — end of year $ 529.2 $ 493.7 $ 14.8 $ 13.7 Funded status of the plans — end of year $ (168.6 ) $ (214.0 ) $ (12.2 ) $ (17.2 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 5.4 $ 4.1 Unfunded liabilities — included in other noncurrent liabilities (168.6 ) (214.0 ) (17.6 ) (21.3 ) Net amount recognized $ (168.6 ) $ (214.0 ) $ (12.2 ) $ (17.2 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service cost (credit) $ 0.7 $ (0.6 ) $ (1.5 ) $ (1.5 ) Net actuarial loss (gain) 21.3 31.4 (0.6 ) 3.8 Total $ 22.0 $ 30.8 $ (2.1 ) $ 2.3 Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 1.0 $ 1.2 $ (1.6 ) $ (2.2 ) Net actuarial loss 139.5 181.0 1.2 2.4 Total $ 140.5 $ 182.2 $ (0.4 ) $ 0.2 |
Actuarial Assumptions for Domestic Plans | 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 2017 2016 2015 2017 2016 2015 Weighted-average assumptions: Discount rate – benefit obligations 4.00 % 3.80 % 4.60 % 4.00 % 3.80 % 4.70 % Discount rate – benefit cost 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Expected return on plan assets 7.50 % 7.55 % 7.75 % 5.00 % 5.00 % 5.00 % 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 Costs | Net periodic pension expense and other postretirement benefit cost include the following components: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Service cost $ 11.9 $ 10.1 $ 10.0 $ 1.0 $ 0.7 $ 0.7 Interest cost 25.0 26.8 25.5 0.8 0.9 0.8 Expected return on assets (33.6 ) (32.4 ) (32.2 ) (0.7 ) (0.6 ) (0.6 ) Curtailment gain (1.4 ) (1.2 ) (0.8 ) — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.6 ) (0.6 ) (0.5 ) Actuarial loss 16.7 10.9 10.0 0.3 — 0.1 Net benefit cost 18.9 14.5 12.8 0.8 0.4 0.5 Change in associated regulatory liabilities — — — (0.5 ) 1.0 3.7 Net benefit cost after change in regulatory liabilities $ 18.9 $ 14.5 $ 12.8 $ 0.3 $ 1.4 $ 4.2 |
Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits | Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2018 $ 29.5 $ 1.1 Fiscal 2019 $ 29.9 $ 1.1 Fiscal 2020 $ 31.5 $ 1.1 Fiscal 2021 $ 39.0 $ 1.1 Fiscal 2022 $ 39.6 $ 1.0 Fiscal 2023 - 2027 $ 196.2 $ 4.9 |
Schedule of Health Care Cost Trend Rates | The assumed domestic health care cost trend rates at September 30 are as follows: 2017 2016 Health care cost trend rate assumed for next year 7.00 % 7.25 % 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 2026 2026 |
Pension Plans | The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows: U.S. Pension Plan Actual Target Asset Allocation Permitted Range 2017 2016 Equity investments: Domestic 55.2 % 54.1 % 52.5 % 40.0% – 65.0% International 12.4 % 10.2 % 12.5 % 7.5% – 17.5% Total 67.6 % 64.3 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 32.4 % 35.7 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2017 2016 Domestic equity investments 63.1 % 69.9 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 36.9 % 30.1 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % |
Fair Value of U.S. Pension Plan and VEBA Trust Assets | The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2017 and 2016 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: Domestic equity investments: S&P 500 Index equity mutual funds $ 171.6 $ — $ — $ — $ 171.6 Small and midcap equity mutual funds 65.2 — — — 65.2 UGI Corporation Common Stock 38.1 — — — 38.1 Total domestic equity investments 274.9 — — — 274.9 International index equity mutual funds 61.6 — — — 61.6 Fixed income investments: Bond index mutual funds 156.2 — — — 156.2 Cash equivalents — — — 5.3 5.3 Total fixed income investments 156.2 — — 5.3 161.5 Total $ 492.7 $ — $ — $ 5.3 $ 498.0 September 30, 2016: Domestic equity investments: S&P 500 Index equity mutual funds $ 158.9 $ — $ — $ — $ 158.9 Small and midcap equity mutual funds 43.2 — — — 43.2 Smallcap common stocks 11.4 — — — 11.4 UGI Corporation Common Stock 37.0 — — — 37.0 Total domestic equity investments 250.5 — — — 250.5 International index equity mutual funds 47.3 — — — 47.3 Fixed income investments: Bond index mutual funds 147.8 — — — 147.8 Cash equivalents — — — 17.8 17.8 Total fixed income investments 147.8 — — 17.8 165.6 Total $ 445.6 $ — $ — $ 17.8 $ 463.4 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: S&P 500 Index equity mutual fund $ 9.3 $ — $ — $ — $ 9.3 Bond index mutual fund 5.1 — — — 5.1 Cash equivalents — — — 0.4 0.4 Total $ 14.4 $ — $ — $ 0.4 $ 14.8 September 30, 2016: S&P 500 Index equity mutual fund $ 9.6 $ — $ — $ — $ 9.6 Bond index mutual fund 4.0 — — — 4.0 Cash equivalents — — — 0.1 0.1 Total $ 13.6 $ — $ — $ 0.1 $ 13.7 (a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy. |
Utility Regulatory Assets and38
Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121.4 $ 115.7 Underfunded pension and postretirement plans 141.3 183.1 Environmental costs 61.6 59.4 Deferred fuel and power costs 7.7 0.2 Removal costs, net 31.0 27.9 Other 5.9 8.8 Total regulatory assets $ 368.9 $ 395.1 Regulatory liabilities (a): Postretirement benefit overcollections $ 17.5 $ 17.5 Deferred fuel and power refunds 10.6 22.3 State income tax benefits — distribution system repairs 18.4 15.1 Other 2.7 0.7 Total regulatory liabilities $ 49.2 $ 55.6 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. |
Schedule of Regulatory Liabilities | The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121.4 $ 115.7 Underfunded pension and postretirement plans 141.3 183.1 Environmental costs 61.6 59.4 Deferred fuel and power costs 7.7 0.2 Removal costs, net 31.0 27.9 Other 5.9 8.8 Total regulatory assets $ 368.9 $ 395.1 Regulatory liabilities (a): Postretirement benefit overcollections $ 17.5 $ 17.5 Deferred fuel and power refunds 10.6 22.3 State income tax benefits — distribution system repairs 18.4 15.1 Other 2.7 0.7 Total regulatory liabilities $ 49.2 $ 55.6 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Inventories | Inventories comprise the following at September 30: 2017 2016 Non-utility LPG and natural gas $ 188.4 $ 129.8 Gas Utility natural gas 39.5 29.2 Materials, supplies and other 50.7 51.3 Total inventories $ 278.6 $ 210.3 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | September 30, 2017 , estimated useful lives by type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 40 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 12 Computer software 1 10 Property, plant and equipment comprise the following at September 30: 2017 2016 Utilities: Distribution $ 2,835.3 $ 2,634.2 Transmission 96.4 93.5 Work in process 112.6 103.9 General and other 241.0 167.3 Total Utilities 3,285.3 2,998.9 Non-utility: Land 180.1 169.9 Buildings and improvements 351.2 382.2 Transportation equipment 289.3 301.7 Equipment, primarily cylinders and tanks 3,529.4 3,421.5 Electric generation 310.0 309.4 Pipeline and related assets 454.5 235.8 Work in process 95.3 201.6 Other 354.8 324.3 Total non-utility 5,564.6 5,346.4 Total property, plant and equipment $ 8,849.9 $ 8,345.3 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Changes in the Carrying Amount of Goodwill | Changes in the carrying amount of goodwill by reportable segment are as follows: AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Total Balance September 30, 2015 $ 1,956.0 $ 803.7 $ 11.6 $ 182.1 $ 2,953.4 Acquisitions 24.2 16.9 — — 41.1 Dispositions — (1.6 ) — — (1.6 ) Purchase accounting adjustments (1.9 ) (2.6 ) — — (4.5 ) Foreign currency translation — 0.6 — — 0.6 Balance September 30, 2016 1,978.3 817.0 11.6 182.1 2,989.0 Acquisitions 23.0 55.5 — — 78.5 Purchase accounting adjustments — (1.7 ) — — (1.7 ) Foreign currency translation — 41.4 — — 41.4 Balance September 30, 2017 $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ 3,107.2 |
Schedule of Finite-Lived Intangible Assets | Intangible assets comprise the following at September 30: 2017 2016 Customer relationships, noncompete agreements and other $ 817.8 $ 773.5 Trademarks and tradenames (not subject to amortization) 134.1 131.6 Gross carrying amount 951.9 905.1 Accumulated amortization (340.2 ) (324.8 ) Intangible assets, net $ 611.7 $ 580.3 |
Schedule of Indefinite-Lived Intangible Assets | Intangible assets comprise the following at September 30: 2017 2016 Customer relationships, noncompete agreements and other $ 817.8 $ 773.5 Trademarks and tradenames (not subject to amortization) 134.1 131.6 Gross carrying amount 951.9 905.1 Accumulated amortization (340.2 ) (324.8 ) Intangible assets, net $ 611.7 $ 580.3 |
Common Stock and Equity-Based42
Common Stock and Equity-Based Compensation (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Common Stock Share Activity | UGI Common Stock share activity for Fiscal 2015 , Fiscal 2016 and Fiscal 2017 follows: Issued Treasury Outstanding Balance, September 30, 2014 173,770,641 (1,496,860 ) 172,273,781 Issued: Employee and director plans 36,350 1,155,376 1,191,726 Repurchases of common stock — (1,000,000 ) (1,000,000 ) Reacquired common stock – employee and director plans — (77,004 ) (77,004 ) Balance, September 30, 2015 173,806,991 (1,418,488 ) 172,388,503 Issued: Employee and director plans 87,150 2,355,202 2,442,352 Repurchases of common stock — (1,250,000 ) (1,250,000 ) Reacquired common stock – employee and director plans — (620,406 ) (620,406 ) Balance, September 30, 2016 173,894,141 (933,692 ) 172,960,449 Issued: Employee and director plans 93,550 1,051,704 1,145,254 Sale of reacquired common stock — 50,000 50,000 Repurchases of common stock — (900,000 ) (900,000 ) Reacquired common stock – employee and director plans — (111,966 ) (111,966 ) Balance, September 30, 2017 173,987,691 (843,954 ) 173,143,737 |
Stock Option Awards | Stock option transactions under equity-based compensation plans during Fiscal 2015 , Fiscal 2016 and Fiscal 2017 follow: Shares Weighted Average Option Price Total Intrinsic Value Weighted Average Contract Term (Years) Shares under option — September 30, 2014 8,957,290 $ 21.44 $ 113.3 7.0 Granted 1,336,985 $ 37.70 Canceled (85,365 ) $ 30.45 Exercised (953,533 ) $ 19.10 $ 15.4 Shares under option — September 30, 2015 9,255,377 $ 23.97 $ 104.5 6.6 Granted 1,510,625 $ 34.67 Canceled (84,213 ) $ 34.13 Exercised (2,193,338 ) $ 20.38 $ 40.1 Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Granted 1,343,800 $ 46.51 Canceled (60,236 ) $ 41.86 Exercised (990,267 ) $ 21.40 $ 26.7 Shares under option — September 30, 2017 8,781,748 $ 30.20 $ 146.7 6.3 Options exercisable — September 30, 2015 6,050,946 $ 20.74 Options exercisable — September 30, 2016 5,522,370 $ 22.94 Options exercisable — September 30, 2017 5,973,668 $ 25.53 $ 127.4 5.3 Options not exercisable — September 30, 2017 2,808,080 $ 40.13 $ 19.3 7.8 |
Additional Information Relating to Stock Options Outstanding and Exercisable | The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2017 : Range of exercise prices Under $20.00 $20.00 – $25.00 $25.01 – $30.00 $30.01 – $35.00 Over $35.00 Options outstanding at September 30, 2017: Number of options 1,351,925 1,947,779 1,462,977 1,402,988 2,616,079 Weighted average remaining contractual life (in years) 3.3 4.6 6.1 8.1 8.3 Weighted average exercise price $ 18.26 $ 21.57 $ 27.43 $ 33.66 $ 42.93 Options exercisable at September 30, 2017: Number of options 1,351,925 1,947,779 1,342,377 499,351 832,236 Weighted average exercise price $ 18.26 $ 21.57 $ 27.42 $ 33.52 $ 38.81 |
Assumptions Used for Valuing Option Grants | The assumptions we used for valuing option grants during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are as follows: 2017 2016 2015 Expected life of option 5.75 years 5.75 years 5.75 years Weighted average volatility 19.8% 19.5% 19.5% Weighted average dividend yield 2.1% 2.6% 2.5% Expected volatility 19.8% 19.3% 19.1% -19.5% Expected dividend yield 2.1% 2.6% 2.5% Risk free rate 1.8% - 2.1% 1.2% - 1.9% 1.5% - 1.8% |
Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs | The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs: Grants Awarded in Fiscal Year 2017 2016 2015 Risk free rate 1.5% 1.3% 1.1% Expected life 3 years 3 years 3 years Expected volatility 18.9% 17.5% 15.9% Dividend yield 2.1% 2.7% 2.3% |
UGI Performance Unit Award Activity | The following table summarizes UGI Unit award activity for Fiscal 2017 : 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, 2016 999,083 $ 25.44 672,075 $ 21.17 327,008 $ 34.21 UGI Performance Units: Granted 143,300 $ 50.91 20,283 $ 50.94 123,017 $ 50.90 Forfeited (7,768 ) $ 41.33 — $ — (7,768 ) $ 41.33 Vested — $ — 131,409 $ 33.67 (131,409 ) $ 33.67 Unit awards paid (178,450 ) $ 32.47 (178,450 ) $ 32.47 — $ — UGI Stock Units: Granted (a) 42,079 $ 47.25 34,979 $ 46.44 7,100 $ 51.23 Unit awards paid (19,410 ) $ 18.69 (19,410 ) $ 18.69 — $ — September 30, 2017 978,834 $ 28.83 660,886 $ 23.93 317,948 $ 41.10 (a) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2016 and Fiscal 2015 were 52,493 and 39,801 , respectively. |
Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash | During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2017 2016 2015 UGI Performance Unit awards: Number of original awards granted 178,450 308,362 294,300 Fiscal year granted 2014 2013 2012 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 138,985 209,592 188,418 Cash paid $ 10.9 $ 13.9 $ 13.3 UGI Stock Unit awards: Number of original awards granted 43,699 51,037 67,419 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 15,990 39,422 44,034 Cash paid $ 0.3 $ 0.7 $ 0.8 |
Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs | The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2017 2016 2015 Risk-free rate 1.5% 1.3% 0.9% Expected life 3 years 3 years 3 years Expected volatility 21.7% 20.6% 19.2% Dividend yield 7.8% 10.7% 6.8% |
AmeriGas Common Unit Based Award Activity | The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2017 : 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, 2016 210,549 $ 47.24 55,622 $ 45.67 154,927 $ 47.80 AmeriGas Performance Units: Granted 49,225 $ 54.24 633 $ 54.45 48,592 $ 54.24 Forfeited (9,151 ) $ 48.76 — $ — (9,151 ) $ 48.76 Vested — $ — 40,933 $ 42.55 (40,933 ) $ 42.55 Awards paid (44,732 ) $ 41.53 (44,732 ) $ 41.53 — $ — AmeriGas Stock Units: Granted 18,338 $ 47.33 12,738 $ 48.06 5,600 $ 45.66 Vested — $ — 6,800 $ 46.13 (6,800 ) $ 46.13 Awards paid (6,005 ) $ 43.64 (6,005 ) $ 43.64 — $ — September 30, 2017 218,224 $ 50.03 65,989 $ 47.31 152,235 $ 51.21 |
AmeriGas Common Unit Based Awards in Common Units and Cash | During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2017 2016 2015 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted 53,800 44,800 55,750 Fiscal year granted 2014 2013 2012 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 29,489 23,017 — Cash paid $ 2.9 $ 1.7 $ — AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted 32,658 20,336 42,532 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 3,932 9,272 21,509 Cash paid $ 0.1 $ 0.4 $ 0.8 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum Future Payments Under Operating Leases | Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2018 2019 2020 2021 2022 After 2022 AmeriGas Propane $ 70.0 $ 61.7 $ 56.5 $ 48.9 $ 40.7 $ 110.3 UGI Utilities 7.5 6.0 4.4 2.7 0.8 0.2 UGI International 11.2 8.1 6.6 4.7 3.2 3.2 Other 2.3 2.0 1.9 0.9 0.5 0.6 Total $ 91.0 $ 77.8 $ 69.4 $ 57.2 $ 45.2 $ 114.3 |
Fair Value Measurement (Tables)
Fair Value Measurement (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
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, 2017 and 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2017: Derivative instruments: Assets: Commodity contracts $ 27.2 $ 76.9 $ — $ 104.1 Foreign currency contracts $ — $ 12.2 $ — $ 12.2 Liabilities: Commodity contracts $ (27.7 ) $ (11.4 ) $ — $ (39.1 ) Foreign currency contracts $ — $ (38.2 ) $ — $ (38.2 ) Cross-currency swaps $ — $ (2.9 ) $ — $ (2.9 ) Interest rate contracts $ — $ (2.3 ) $ — $ (2.3 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.6 $ — $ — $ 35.6 September 30, 2016 Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7 ). |
Schedule of Carrying Amount and Estimated Fair Value of Long-term Debt | The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016 were as follows: 2017 2016 Carrying amount $ 4,211.9 $ 3,832.3 Estimated fair value $ 4,346.8 $ 4,052.3 |
Derivative Instruments and He45
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts Related to Open Derivative Contracts | The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at September 30, 2017 and 2016 and the final settlement date of the Company's open derivative transactions as of September 30, 2017 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through 2017 2016 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2018 14.8 18.4 FTRs contracts Kilowatt hours May 2018 101.2 58.3 Non-utility Operations LPG swaps & options Gallons March 2020 325.5 396.9 Natural gas futures, forward and pipeline contracts (a) Dekatherms December 2021 75.9 71.1 Natural gas basis swap contracts Dekatherms March 2022 104.2 118.3 NYMEX natural gas storage Dekatherms March 2019 1.9 1.9 NYMEX propane storage Gallons March 2018 0.3 — Electricity long forward and futures contracts (a) Kilowatt hours May 2021 4,440.3 761.2 Electricity short forward and futures contracts Kilowatt hours May 2021 447.0 264.6 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2020 $ 424.8 $ 314.3 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1 (a) Amounts in 2017 include derivative contracts held by a natural gas and electricity marketing business in the Netherlands acquired in Fiscal 2017. |
Schedule of Derivative Assets, Liabilities and the Effects of Offsetting | The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30, 2017 and 2016 : 2017 2016 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 3.2 $ 17.8 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.7 4.5 Derivatives not designated as hedging instruments: Commodity contracts 102.4 50.4 Foreign currency contracts 9.0 — 111.4 50.4 Total derivative assets – gross 116.3 72.7 Gross amounts offset in the balance sheet (35.7 ) (35.0 ) Cash collateral received (8.3 ) (0.3 ) Total derivative assets – net $ 72.3 $ 37.4 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (5.5 ) $ (2.4 ) Cross-currency contracts (2.9 ) (0.5 ) Interest rate contracts (2.3 ) (3.9 ) (10.7 ) (6.8 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (1.5 ) (0.5 ) Derivatives not designated as hedging instruments: Commodity contracts (37.6 ) (98.1 ) Foreign currency contracts (32.7 ) — (70.3 ) (98.1 ) Total derivative liabilities – gross (82.5 ) (105.4 ) Gross amounts offset in the balance sheet 35.7 35.0 Total derivative liabilities – net $ (46.8 ) $ (70.4 ) |
Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest | The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income Location of Gain (Loss) Reclassified from Interests into Income 2017 2016 2015 2017 2016 2015 Cash Flow Hedges: Commodity contracts $ — $ — $ — $ — $ — $ (2.2 ) Cost of sales Foreign currency contracts 0.2 3.6 26.0 17.8 17.2 9.7 Cost of sales Cross-currency contracts 0.5 0.1 5.4 (0.1 ) 0.4 8.5 Interest expense /other operating income, net Interest rate contracts 1.5 (32.5 ) (6.6 ) (3.9 ) (4.5 ) (20.4 ) Interest expense Total $ 2.2 $ (28.8 ) $ 24.8 $ 13.8 $ 13.1 $ (4.4 ) Gain (Loss) Recognized in Income Location of Recognized in Income 2017 2016 2015 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ 166.0 $ (65.0 ) $ (375.8 ) Cost of sales Commodity contracts (2.0 ) (2.2 ) 0.3 Revenues Commodity contracts 0.2 (0.1 ) (0.8 ) Operating and administrative expenses / other operating income, net Foreign currency contracts (23.8 ) — — Losses on foreign currency contracts, net Total $ 140.4 $ (67.3 ) $ (376.3 ) |
Accumulated Other Comprehensi46
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Changes in AOCI during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) (1.2 ) 16.8 (114.1 ) (98.5 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 2.2 4.4 — 6.6 Reclassification adjustments tax benefit (0.8 ) (2.8 ) — (3.6 ) Reclassification adjustments (after-tax) 1.4 1.6 — 3.0 Other comprehensive income (loss) 0.2 18.4 (114.1 ) (95.5 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 2.1 — 2.1 Other comprehensive income (loss) attributable to UGI 0.2 20.5 (114.1 ) (93.4 ) AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive loss before reclassification adjustments (after-tax) (10.9 ) (16.5 ) (6.8 ) (34.2 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.6 (13.1 ) — (10.5 ) Reclassification adjustments tax (benefit) expense (0.4 ) 5.0 — 4.6 Reclassification adjustments (after-tax) 2.2 (8.1 ) — (5.9 ) Other comprehensive loss attributable to UGI (8.7 ) (24.6 ) (6.8 ) (40.1 ) AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income before reclassification adjustments (after-tax) 6.5 1.7 59.4 67.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 5.5 (13.8 ) — (8.3 ) Reclassification adjustments tax (benefit) expense (2.1 ) 4.1 — 2.0 Reclassification adjustments (after-tax) 3.4 (9.7 ) — (6.3 ) Other comprehensive income (loss) attributable to UGI 9.9 (8.0 ) 59.4 61.3 AOCI - September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) |
Other Operating Income, Net (Ta
Other Operating Income, Net (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Component of Operating Income [Abstract] | |
Other Operating Income, Net | Other operating income, net, comprises the following: 2017 2016 2015 Finance charges $ 11.8 $ 15.2 $ 12.7 AFUDC associated with pipeline projects 5.5 3.3 — Interest and interest-related income 1.7 0.2 0.8 Utility non-tariff service income 1.5 2.6 4.8 Loss on private equity partnership investment (11.0 ) — — (Losses) gains on sales of fixed assets, net (3.9 ) 3.3 11.1 Other, net 4.9 (2.2 ) 15.0 Total other operating income, net $ 10.5 $ 22.4 $ 44.4 |
Quarterly Data (unaudited) (Tab
Quarterly Data (unaudited) (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Quarterly Financial Data [Abstract] | |
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 primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity and certain foreign currency derivative instruments (see Note 17). December 31, March 31, June 30, September 30, 2016 (a)(b) 2015 2017 (b)(c) 2016 2017 (b) 2016 (d) 2017 (a)(c) 2016 (d) Revenues $ 1,679.5 $ 1,606.6 $ 2,173.8 $ 1,972.1 $ 1,153.5 $ 1,130.8 $ 1,113.9 $ 976.2 Operating income (loss) $ 466.2 $ 305.5 $ 513.2 $ 615.4 $ (2.8 ) $ 155.7 $ 27.6 $ (88.6 ) (Loss) income from equity investees $ (0.2 ) $ (0.1 ) $ 2.3 $ — $ 0.9 $ — $ 1.3 $ (0.1 ) Loss on extinguishments of debt $ (33.2 ) $ — $ (22.1 ) $ — $ (4.4 ) $ (37.1 ) $ — $ (11.8 ) Net income (loss) including noncontrolling interests $ 290.9 $ 167.9 $ 311.8 $ 408.0 $ (62.2 ) $ 28.6 $ (16.7 ) $ (115.7 ) Net income (loss) attributable to UGI Corporation $ 230.7 $ 114.6 $ 219.9 $ 233.2 $ (19.0 ) $ 60.7 $ 5.0 $ (43.8 ) Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 1.33 $ 0.66 $ 1.27 $ 1.35 $ (0.11 ) $ 0.35 $ 0.03 $ (0.25 ) Diluted $ 1.30 $ 0.65 $ 1.24 $ 1.33 $ (0.11 ) $ 0.34 $ 0.03 $ (0.25 ) (a) The quarter ended December 31, 2016 includes beneficial impact of adjustments to net deferred income tax liabilities associated with a change in French income tax rate which increased net income attributable to UGI Corporation by $27.4 or $0.15 per diluted share, and the impact of an income tax settlement refund in France which increased net income attributable to UGI Corporation by $6.7 or $0.04 per diluted share. The quarter ended September 30, 2017 includes the release of a valuation allowance against future uses of foreign tax credit carryforwards, which increased net income attributable to UGI Corporation by $7.6 or $0.04 per diluted share. (b) The quarter ended December 31, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $5.3 or $0.03 per diluted share. The quarter ended March 31, 2017 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $3.6 or $0.02 . The quarter ended June 30, 2017 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $0.7 or $0.01 per diluted share (see Note 5). (c) The quarter ended March 31, 2017 includes impairment of a cost basis investment which decreased net income attributable to UGI Corporation by $4.5 or $0.03 per diluted share. The quarter ended September 30, 2017 includes impairment of a cost basis investment which decreased net income attributable to UGI Corporation by $2.6 or $0.02 per diluted share for the quarter ended September 30, 2017 (see Note 2). (d) The quarter ended June 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share. The quarter ended September 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5). |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (b) 2017 Revenues from external customers $ 6,120.7 $ — $ 2,453.5 $ 1,877.5 $ 943.0 $ 847.5 $ (0.8 ) Intersegment revenues $ — $ (222.7 ) (c) $ — $ — $ 178.2 $ 40.1 $ 4.4 Cost of sales $ 2,837.3 $ (218.3 ) (c) $ 1,002.9 $ 935.3 $ 856.7 $ 367.3 $ (106.6 ) Operating income $ 1,004.2 $ 0.3 $ 355.3 $ 195.7 $ 139.2 $ 228.3 $ 85.4 Income from equity investees $ 4.3 $ — $ — $ — $ 4.3 (d) $ — $ — Losses on foreign currency contracts, net $ (23.9 ) $ — $ — $ (0.1 ) $ — $ — $ (23.8 ) Loss on extinguishments of debt $ (59.7 ) $ — $ (59.7 ) $ — $ — $ — $ — Interest expense $ (223.5 ) $ — $ (160.2 ) $ (20.6 ) $ (2.1 ) $ (40.2 ) $ (0.4 ) Income before income taxes $ 701.4 $ 0.3 $ 135.4 $ 175.0 $ 141.4 $ 188.1 $ 61.2 Net income attributable to UGI $ 436.6 $ 0.1 $ 44.6 $ 158.6 $ 86.9 $ 116.0 $ 30.4 Depreciation and amortization $ 416.3 $ (0.2 ) $ 190.5 $ 117.4 $ 35.4 $ 72.3 $ 0.9 Noncontrolling interests’ net income $ 87.2 $ — $ 64.4 $ 0.2 $ — $ — $ 22.6 Partnership Adjusted EBITDA (a) $ 551.3 Total assets $ 11,582.2 $ (51.5 ) $ 4,069.4 $ 3,132.0 $ 1,165.5 $ 2,994.0 $ 272.8 Short-term borrowings $ 366.9 $ — $ 140.0 $ 17.9 $ 39.0 $ 170.0 $ — Capital expenditures (including the effects of accruals) $ 624.3 $ — $ 98.1 $ 90.3 $ 117.5 $ 317.7 $ 0.7 Investments in equity investees $ 59.1 $ — $ — $ 8.1 $ 51.0 $ — $ — Goodwill $ 3,107.2 $ — $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ — 2016 (f) Revenues from external customers $ 5,685.7 $ — $ 2,311.8 $ 1,868.8 $ 752.3 $ 751.4 $ 1.4 Intersegment revenues $ — $ (133.9 ) (c) $ — $ — $ 114.3 $ 17.1 $ 2.5 Cost of sales $ 2,437.5 $ (131.5 ) (c) $ 864.8 $ 903.8 $ 602.2 $ 289.8 $ (91.6 ) Operating income $ 988.0 $ 0.2 $ 356.3 $ 206.6 $ 146.7 $ 200.9 $ 77.3 Loss from equity investees $ (0.2 ) $ — $ — $ (0.2 ) $ — $ — $ — Loss on extinguishments of debt $ (48.9 ) $ — $ (48.9 ) $ — $ — $ — $ — Interest expense $ (228.9 ) $ — $ (164.1 ) $ (24.4 ) $ (2.1 ) $ (37.6 ) $ (0.7 ) Income before income taxes $ 710.0 $ 0.2 $ 143.3 $ 182.0 $ 144.6 $ 163.3 $ 76.6 Net income attributable to UGI $ 364.7 $ 0.1 $ 43.2 $ 111.6 $ 87.1 $ 97.4 $ 25.3 Depreciation and amortization $ 400.9 $ (0.2 ) $ 190.0 $ 112.4 $ 30.6 $ 67.3 $ 0.8 Noncontrolling interests’ net income $ 124.1 $ — $ 75.9 $ — $ — $ — $ 48.2 Partnership Adjusted EBITDA (a) $ 543.0 Total assets $ 10,847.2 $ (136.6 ) $ 4,071.8 $ 2,865.1 $ 1,038.2 $ 2,743.1 $ 265.6 Short-term borrowings $ 291.7 $ — $ 153.2 $ 0.5 $ 25.5 $ 112.5 $ — Capital expenditures (including the effects of accruals) $ 604.6 $ — $ 101.7 $ 99.9 $ 140.4 $ 262.5 $ 0.1 Investments in equity investees $ 25.9 $ — $ — $ 8.5 $ 17.4 $ — $ — Goodwill $ 2,989.0 $ — $ 1,978.3 $ 817.0 $ 11.6 $ 182.1 $ — Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (b) 2015 (f) Revenues from external customers $ 6,691.1 $ — $ 2,885.3 $ 1,808.5 $ 1,012.3 $ 981.9 $ 3.1 Intersegment revenues $ — $ (213.6 ) (c) $ — $ — $ 151.3 $ 59.7 $ 2.6 Cost of sales $ 3,736.5 $ (209.8 ) (c) $ 1,340.0 $ 1,120.0 $ 854.6 $ 510.8 $ 120.9 Operating income (loss) $ 834.9 $ (0.9 ) $ 427.6 $ 112.8 $ 182.6 $ 241.7 $ (128.9 ) Loss from equity investees $ (1.2 ) $ — $ — $ (1.2 ) $ — $ — $ — Interest expense $ (241.9 ) $ — $ (162.8 ) $ (35.2 ) (e) $ (2.1 ) $ (41.1 ) $ (0.7 ) Income (loss) before income taxes $ 591.8 $ (0.9 ) $ 264.8 $ 76.4 $ 180.5 $ 200.6 $ (129.6 ) Net income (loss) attributable to UGI $ 281.0 $ (0.6 ) $ 61.0 $ 52.7 $ 107.5 $ 121.1 $ (60.7 ) Depreciation and amortization $ 374.1 $ — $ 194.9 $ 86.9 $ 28.0 $ 63.5 $ 0.8 Noncontrolling interests’ net income (loss) $ 133.0 $ — $ 167.9 $ (0.1 ) $ — $ — $ (34.8 ) Partnership Adjusted EBITDA (a) $ 619.2 Total assets $ 10,514.2 $ (90.4 ) $ 4,128.4 $ 2,860.9 $ 969.6 $ 2,506.0 $ 139.7 Short-term borrowings $ 189.9 $ — $ 68.1 $ 0.6 $ 49.5 $ 71.7 $ — Capital expenditures (including the effects of accruals) $ 475.4 $ — $ 102.0 $ 87.5 $ 88.0 $ 197.7 $ 0.2 Investments in equity investees $ 16.2 $ — $ — $ 9.8 $ 6.4 $ — $ — Goodwill $ 2,953.4 $ — $ 1,956.0 $ 803.7 $ 11.6 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: 2017 2016 2015 Partnership Adjusted EBITDA $ 551.3 $ 543.0 $ 619.2 Depreciation and amortization (190.5 ) (190.0 ) (194.9 ) Interest expense (160.2 ) (164.1 ) (162.8 ) Loss on extinguishments of debt (59.7 ) (48.9 ) — MGP environmental accrual (7.5 ) — — Noncontrolling interest (i) 2.0 3.3 3.3 Income before income taxes $ 135.4 $ 143.3 $ 264.8 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Includes net pre-tax gains (losses) on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $82.0 , $91.6 and $(119.1) in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , respectively. Fiscal 2017 also includes a pre-tax loss of $11.0 associated with the impairment of a cost basis investment (see Note 2 ). (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents AFUDC associated with PennEast (see Note 2 ). (e) Includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5 ). (f) Restated to reflect the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments. |
Nature of Operations (Details)
Nature of Operations (Details) | 12 Months Ended |
Sep. 30, 2017county | |
Investment [Line Items] | |
General Partner held a general partner interest in AmeriGas Partners | 2.00% |
Percentage of limited partnership interest in AmeriGas Partners | 98.00% |
Number of counties of operation | 1 |
AmeriGas Partners | |
Investment [Line Items] | |
General Partner held a general partner interest in AmeriGas Partners | 1.00% |
AmeriGas OLP | |
Investment [Line Items] | |
General Partner held a general partner interest in AmeriGas Partners | 1.01% |
AmeriGas Propane | AmeriGas Partners | |
Investment [Line Items] | |
General Partner held a general partner interest in AmeriGas Partners | 1.00% |
Percentage of limited partnership interest in AmeriGas Partners | 25.30% |
General public as limited partner interests in AmeriGas Partners | 73.70% |
AmeriGas Propane | AmeriGas OLP | |
Investment [Line Items] | |
Effective ownership interest in AmeriGas OLP | 27.10% |
Summary of Significant Accoun51
Summary of Significant Accounting Policies - Basis of Presentation (Details) $ in Millions | 12 Months Ended | ||
Sep. 30, 2015USD ($)subsidiary | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Decrease in opening retained earnings | $ (2,106.7) | $ (1,834.1) | |
Increase in other noncurrent liabilities | 774.8 | 806.6 | |
Decrease in deferred income tax liabilities | $ (1,357) | $ (1,212.4) | |
UGI International | Error in Cylinder Deposit Liability | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Number of subsidiaries | subsidiary | 2 | ||
UGI International | Error in Cylinder Deposit Liability | Restatement Adjustment | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Decrease in opening retained earnings | $ 6.8 | ||
Decrease in opening retained earnings (as a percent) | 0.50% | ||
Increase in other noncurrent liabilities | $ 10.6 | ||
Decrease in deferred income tax liabilities | $ 3.8 |
Summary of Significant Accoun52
Summary of Significant Accounting Policies - Principles of Consolidation (Details) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017USD ($)mi | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | |
Accounting Policies [Abstract] | |||
Ownership interests in certain subsidiaries under equity method investment, maximum | 100.00% | ||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investments | $ 59.1 | $ 25.9 | $ 16.2 |
UGI PennEast, LLC | PennEast | |||
Schedule of Equity Method Investments [Line Items] | |||
Ownership percentage | 20.00% | ||
Equity method investments | $ 51 | $ 17.4 | |
PennEast | |||
Schedule of Equity Method Investments [Line Items] | |||
Area of natural gas pipeline to be constructed (in miles) | mi | 118 | ||
Pipeline contract term | 15 years |
Summary of Significant Accoun53
Summary of Significant Accounting Policies - Equity and Cost Method Investments (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 |
Accounting Policies [Abstract] | |||
Equity method investments | $ 59.1 | $ 25.9 | $ 16.2 |
Schedule of Cost-method Investments [Line Items] | |||
Cost method investments | 61.3 | 70.1 | |
Private Equity Partnership That Invests in Renewable Energy Companies | |||
Schedule of Cost-method Investments [Line Items] | |||
Cost method investments | $ 7 | $ 18 |
Summary of Significant Accoun54
Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares shares in Thousands | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Accounting Policies [Abstract] | |||
Weighted-average common shares outstanding for basic computation | 173,662 | 173,154 | 173,115 |
Incremental shares issuable for stock options and common stock awards | 3,497 | 2,418 | 2,552 |
Weighted-average common shares outstanding for diluted computation | 177,159 | 175,572 | 175,667 |
Antidilutive securities excluded from computation of earnings per share (in shares) | 146 | 38 | 1 |
Summary of Significant Accoun55
Summary of Significant Accounting Policies - Estimated Useful Lives by Type (Details) | 12 Months Ended |
Sep. 30, 2017 | |
Buildings and improvements | Minimum | |
Property, Plant and Equipment | |
Useful life (in years) | 10 years |
Buildings and improvements | Maximum | |
Property, Plant and Equipment | |
Useful life (in years) | 40 years |
Equipment, primarily cylinders and tanks | Minimum | |
Property, Plant and Equipment | |
Useful life (in years) | 5 years |
Equipment, primarily cylinders and tanks | 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 |
Transportation equipment and office furniture and fixtures | Minimum | |
Property, Plant and Equipment | |
Useful life (in years) | 3 years |
Transportation equipment and office furniture and fixtures | Maximum | |
Property, Plant and Equipment | |
Useful life (in years) | 12 years |
Computer software | Minimum | |
Property, Plant and Equipment | |
Useful life (in years) | 1 year |
Computer software | Maximum | |
Property, Plant and Equipment | |
Useful life (in years) | 10 years |
Summary of Significant Accoun56
Summary of Significant Accounting Policies - Average Composite Depreciation Rates (Details) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Amortization period | 5 years | ||
Gas Utility | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Average composite depreciation rates | 2.20% | 2.20% | 2.20% |
Electric Utility | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Average composite depreciation rates | 2.40% | 2.50% | 2.50% |
Summary of Significant Accoun57
Summary of Significant Accounting Policies - Goodwill and Intangible Assets (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Accounting Policies [Abstract] | |||
Estimated useful life of definite-lived intangible assets, maximum | 15 years | ||
Accumulated impairment losses | $ 0 | $ 0 | |
Provision for goodwill or other intangible asset impairments | $ 0 | $ 0 | $ 0 |
Summary of Significant Accoun58
Summary of Significant Accounting Policies - Impairment of Long-Lived Assets and Cost Basis Investments (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Accounting Policies [Abstract] | |||
Provisions for impairments | $ 0 | $ 0 | $ 0 |
Other-than-temporary impairment of an investment in a private equity partnership pre-tax loss | $ 11,000,000 | $ 0 | $ 0 |
Summary of Significant Accoun59
Summary of Significant Accounting Policies - Refundable Tank and Cylinder Deposits (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Accounting Policies [Abstract] | ||
Customer paid deposits primarily on owned tanks and cylinders | $ 279.9 | $ 267.2 |
Summary of Significant Accoun60
Summary of Significant Accounting Policies - Equity-Based Compensation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Income tax benefits related to excess tax benefits for share-based awards | $ 10.3 | |
Decrease to deferred income tax liabilities | $ (1,357) | $ (1,212.4) |
Retained earnings | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Increase to retained earnings | 4.9 | |
ASU 2016-09 | New Accounting Pronouncement, Early Adoption, Effect | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Decrease to deferred income tax liabilities | 4.9 | |
ASU 2016-09 | New Accounting Pronouncement, Early Adoption, Effect | Retained earnings | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Increase to retained earnings | $ 4.9 |
Acquisitions - Acquisition of T
Acquisitions - Acquisition of Totalgaz (Details) $ in Millions | May 29, 2015EUR (€) | May 29, 2015USD ($) | Nov. 30, 2015EUR (€) | Nov. 30, 2015USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) |
Business Acquisition [Line Items] | |||||||
Long-term debt | $ 4,172.1 | $ 3,795.5 | |||||
Totalgaz SAS | |||||||
Business Acquisition [Line Items] | |||||||
Transaction related costs | $ 16.1 | ||||||
Totalgaz SAS | France SAS | |||||||
Business Acquisition [Line Items] | |||||||
Total cash paid | € 451,800,000 | $ 496.6 | |||||
Estimated Acquisition Date working capital | 30,000,000 | $ 33 | |||||
Adjustment to working capital | € 1,100,000 | $ 1.2 | |||||
Totalgaz SAS | Term Loan | 2015 Senior Facilities Agreement | France SAS | |||||||
Business Acquisition [Line Items] | |||||||
Long-term debt | € | € 600,000,000 |
Acquisitions - Components of Fi
Acquisitions - Components of Final Purchase Price Allocation (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2015 | May 29, 2015 | |
Liabilities assumed: | ||||
Goodwill | $ 2,989 | $ 3,107.2 | $ 2,953.4 | |
Totalgaz SAS | ||||
Assets acquired: | ||||
Cash | $ 86.8 | |||
Accounts receivable | 170.3 | |||
Prepaid expenses and other current assets | 11 | |||
Property, plant & equipment | 375.6 | |||
Intangible assets | 91.3 | |||
Other assets | 21.4 | |||
Total assets acquired | 756.4 | |||
Liabilities assumed: | ||||
Accounts payable | 109.2 | |||
Other current liabilities | 103.5 | |||
Deferred income taxes | 117.5 | |||
Other noncurrent liabilities | 113.4 | |||
Total liabilities assumed | 443.6 | |||
Goodwill | 183.8 | |||
Net consideration transferred (including working capital adjustments) | 496.6 | |||
Intangible assets acquired, tradenames | 12 | |||
Average amortization period | 15 years | |||
Totalgaz SAS | Customer Relationships | ||||
Liabilities assumed: | ||||
Finite-lived intangible assets acquired | 79.3 | |||
Totalgaz SAS | Tradenames | ||||
Liabilities assumed: | ||||
Finite-lived intangible assets acquired | $ 8.3 |
Acquisitions - Unaudited Pro Fo
Acquisitions - Unaudited Pro Forma Revenues, Net Income, and Earnings Per Share Data (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Business Combinations [Abstract] | |||||||||||
Revenues | $ 1,113.9 | $ 1,153.5 | $ 2,173.8 | $ 1,679.5 | $ 976.2 | $ 1,130.8 | $ 1,972.1 | $ 1,606.6 | $ 6,120.7 | $ 5,685.7 | $ 6,691.1 |
Net income (loss) attributable to UGI Corporation | $ 5 | $ (19) | $ 219.9 | $ 230.7 | $ (43.8) | $ 60.7 | $ 233.2 | $ 114.6 | $ 436.6 | $ 364.7 | $ 281 |
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.27 | $ 1.33 | $ (0.25) | $ 0.35 | $ 1.35 | $ 0.66 | $ 2.51 | $ 2.11 | $ 1.62 |
Diluted (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.24 | $ 1.30 | $ (0.25) | $ 0.34 | $ 1.33 | $ 0.65 | $ 2.46 | $ 2.08 | $ 1.60 |
Totalgaz SAS | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenues | $ 7,065.8 | ||||||||||
Net income attributable to UGI Corporation | $ 341.2 | ||||||||||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic (in dollars per share) | $ 1.97 | ||||||||||
Diluted (in dollars per share) | $ 1.94 |
Acquisitions - Total Cash Paid
Acquisitions - Total Cash Paid and Liabilities Incurred (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
AmeriGas Propane | |||
Business Acquisition [Line Items] | |||
Total cash paid | $ 36.8 | $ 37.6 | $ 20.8 |
Liabilities incurred | 10.8 | 11.8 | 4.2 |
Total purchase price | 47.6 | 49.4 | 25 |
UGI International | |||
Business Acquisition [Line Items] | |||
Total cash paid | 99.7 | 24.1 | 17.6 |
Liabilities incurred | 20.6 | 0 | 0 |
Total purchase price | $ 120.3 | $ 24.1 | $ 17.6 |
Debt - AmeriGas Propane (Detail
Debt - AmeriGas Propane (Details) - AmeriGas Partners - USD ($) | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Debt Instrument | ||
Aggregate principal amount of tendered notes redeemed | $ 1,270,000,000 | |
Senior Notes | 5.50% due May 2025 | ||
Debt Instrument | ||
Aggregate principal amount | $ 700,000,000 | |
Stated interest rate | 5.50% | |
Senior Notes | 5.75% due May 2027 | ||
Debt Instrument | ||
Aggregate principal amount | $ 525,000,000 | |
Stated interest rate | 5.75% | |
Senior Notes | 7.00% Senior Notes | ||
Debt Instrument | ||
Stated interest rate | 7.00% | |
Aggregate principal balance repaid | $ 980,800,000 | |
Senior Notes | 5.625% due May 2024 | ||
Debt Instrument | ||
Aggregate principal amount | $ 675,000,000 | |
Stated interest rate | 5.625% | |
Senior Notes | 5.875% due August 2026 | ||
Debt Instrument | ||
Aggregate principal amount | $ 675,000,000 | |
Stated interest rate | 5.875% | |
Senior Notes | 6.50% Senior Notes, due 2021 | ||
Debt Instrument | ||
Stated interest rate | 6.50% | |
Senior Notes | 6.75% Senior Notes, due 2020 | ||
Debt Instrument | ||
Stated interest rate | 6.75% | |
Senior Notes | 6.25% Senior Notes, due 2019 | ||
Debt Instrument | ||
Stated interest rate | 6.25% |
Debt - Loss on Extinguishment o
Debt - Loss on Extinguishment of Debt (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Debt Instrument, Redemption [Line Items] | |||||||||||
Loss on extinguishments of debt | $ 0 | $ 4.4 | $ 22.1 | $ 33.2 | $ 11.8 | $ 37.1 | $ 0 | $ 0 | $ 59.7 | $ 48.9 | $ 0 |
AmeriGas Partners | |||||||||||
Debt Instrument, Redemption [Line Items] | |||||||||||
Early redemption premiums | 51.3 | 39.6 | |||||||||
Write-off of unamortized debt issuance costs | 8.4 | 9.3 | |||||||||
Loss on extinguishments of debt | $ 59.7 | $ 48.9 |
Debt - UGI International (Detai
Debt - UGI International (Details) $ in Millions | May 29, 2015EUR (€) | Oct. 31, 2015EUR (€) | Oct. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Apr. 30, 2015EUR (€) | Sep. 30, 2015USD ($) | Sep. 30, 2017EUR (€) | Sep. 30, 2017USD ($) | Sep. 30, 2016EUR (€) | Sep. 30, 2016USD ($) | May 29, 2015USD ($) |
Debt Instrument | |||||||||||
Long-term debt | $ | $ 4,172.1 | $ 3,795.5 | |||||||||
Interest rate swaps | Interest expense | |||||||||||
Debt Instrument | |||||||||||
Loss on interest rate swaps | $ | $ 9 | ||||||||||
France SAS | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | € 60,000,000 | € 60,000,000 | |||||||||
France SAS | 2015 Senior Facilities Agreement | |||||||||||
Debt Instrument | |||||||||||
Debt instrument term (in years) | 5 years | ||||||||||
France SAS | 2015 Senior Facilities Agreement | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Long-term debt | € 600,000,000 | € 600,000,000 | $ 659.6 | ||||||||
Long-term debt, gross | $ | 708.9 | 674.4 | |||||||||
France SAS | 2015 Senior Facilities Agreement | Line of Credit | Revolving Credit Facility | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | € 60,000,000 | ||||||||||
France SAS | 2011 Senior Facilities Agreement | Interest expense | |||||||||||
Debt Instrument | |||||||||||
Write-off of unamortized debt issuance costs | $ | 1.3 | ||||||||||
France SAS | 2011 Senior Facilities Agreement | Interest rate swaps | Interest expense | |||||||||||
Debt Instrument | |||||||||||
Loss on interest rate swaps | $ | 9 | ||||||||||
France SAS | 2011 Senior Facilities Agreement | AGZ Holding | |||||||||||
Debt Instrument | |||||||||||
Repayments of debt | € 342,000,000 | ||||||||||
France SAS | 2011 Senior Facilities Agreement | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Pretax loss on early extinguishment of debt | $ | 10.3 | ||||||||||
Flaga | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | 55,000,000 | € 55,000,000 | |||||||||
Flaga | Flaga Credit Facility Agreement | Line of Credit | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | € 100,800,000 | ||||||||||
Flaga | Flaga Credit Facility Agreement | Overdraft Facility | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | 5,000,000 | 5,000,000 | |||||||||
Flaga | Flaga Credit Facility Agreement | Guarantee Facility | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | 25,000,000 | 25,000,000 | |||||||||
Flaga | Flaga Credit Facility Agreement | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Long-term debt, gross | 45,800,000 | ||||||||||
Flaga | Flaga Credit Facility Agreement | Revolving Credit Facility | Line of Credit | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | 25,000,000 | € 25,000,000 | |||||||||
Flaga | Flaga Multi-Currency Working Capital Facility | Line of Credit | |||||||||||
Debt Instrument | |||||||||||
Total Capacity | 46,000,000 | ||||||||||
Flaga | Flaga Term Loan, due October 2016 | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Amount of debt extinguished | 19,100,000 | $ 21.4 | |||||||||
Flaga | Flaga Term Loan, due through August 2016 | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Amount of debt extinguished | € 26,700,000 | $ 29.8 | |||||||||
Flaga | Flaga Term Loan due through September 2016 | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Amount of debt extinguished | $ | $ 52 | ||||||||||
Flaga | Flaga Term Loan, due September 2018 | Term Loan | |||||||||||
Debt Instrument | |||||||||||
Long-term debt, gross | $ | $ 59.1 | $ 59.1 | $ 59.1 | $ 59.1 |
Debt - UGI Utilities (Details)
Debt - UGI Utilities (Details) - UGI Utilities - USD ($) | Oct. 31, 2017 | Sep. 30, 2017 | Oct. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 |
Senior Notes | 2.95%, due June 2026 | |||||
Debt Instrument | |||||
Aggregate principal amount | $ 100,000,000 | ||||
Stated interest rate | 2.95% | 2.95% | |||
Senior Notes | 4.12%, due September 2046 | |||||
Debt Instrument | |||||
Aggregate principal amount | $ 200,000,000 | ||||
Stated interest rate | 4.12% | 4.12% | |||
Senior Notes | 4.12%, due October 2046 | |||||
Debt Instrument | |||||
Aggregate principal amount | $ 100,000,000 | ||||
Stated interest rate | 4.12% | 4.12% | |||
Senior Notes | 5.75% Senior Notes, due 2016 | |||||
Debt Instrument | |||||
Stated interest rate | 5.75% | ||||
Medium-term Notes | 7.37% Medium-term Notes, due October 2015 | |||||
Debt Instrument | |||||
Stated interest rate | 7.37% | ||||
Medium-term Notes | 5.64% Medium-term Notes, due December 2015 | |||||
Debt Instrument | |||||
Stated interest rate | 5.64% | ||||
Term Loan | Subsequent Event | |||||
Debt Instrument | |||||
Aggregate principal amount | $ 125,000,000 | ||||
Principal repayment in equal quarterly installments | $ 1,600,000 | ||||
Term Loan | Subsequent Event | Minimum | |||||
Debt Instrument | |||||
Basis spread on variable rate (percentage) | 0.00% | ||||
Term Loan | Subsequent Event | Maximum | |||||
Debt Instrument | |||||
Basis spread on variable rate (percentage) | 1.875% |
Debt - Schedule of Long-term De
Debt - Schedule of Long-term Debt (Details) € in Millions, $ in Millions | Sep. 30, 2017USD ($) | Oct. 31, 2016 | Sep. 30, 2016USD ($) | Jun. 30, 2016 | Sep. 30, 2015USD ($) | May 29, 2015EUR (€) | May 29, 2015USD ($) | Apr. 30, 2015EUR (€) |
Debt Instrument | ||||||||
Total long-term debt | $ 4,172.1 | $ 3,795.5 | ||||||
Less: current maturities | (177.5) | (29.5) | ||||||
Total long-term debt due after one year | 3,994.6 | 3,766 | ||||||
AmeriGas Propane | ||||||||
Debt Instrument | ||||||||
Unamortized debt issuance costs | (31.3) | (26.6) | ||||||
Total long-term debt | 2,572.3 | 2,333.6 | ||||||
AmeriGas Propane | Other | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 17.3 | 14.2 | ||||||
AmeriGas Propane | Senior Notes | 5.50% due May 2025 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 700 | 0 | ||||||
Stated interest rate | 5.50% | |||||||
AmeriGas Propane | Senior Notes | 5.875% due August 2026 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 675 | 675 | ||||||
Stated interest rate | 5.875% | |||||||
AmeriGas Propane | Senior Notes | 5.625% due May 2024 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 675 | 675 | ||||||
Stated interest rate | 5.625% | |||||||
AmeriGas Propane | Senior Notes | 5.75% due May 2027 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 525 | 0 | ||||||
Stated interest rate | 5.75% | |||||||
AmeriGas Propane | Senior Notes | 7.00%, due May 2022 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 0 | $ 980.8 | ||||||
Stated interest rate | 7.00% | |||||||
AmeriGas Propane | Senior Secured Notes | HOLP Senior Secured Notes | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 11.3 | $ 15.2 | ||||||
Unamortized premium | 0.4 | 0.7 | ||||||
UGI International | ||||||||
Debt Instrument | ||||||||
Unamortized debt issuance costs | (4.6) | (6.7) | ||||||
Total long-term debt | 838.8 | 779.6 | ||||||
UGI International | Other | Other | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 21.3 | 1.4 | ||||||
France SAS | Term Loan | France SAS Senior Facilities term loan, due through April 2020 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 708.9 | 674.4 | ||||||
Total long-term debt | € 600 | $ 659.6 | € 600 | |||||
Flaga | Term Loan | Flaga variable-rate term loan, due October 2020 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 54.1 | 51.4 | ||||||
Flaga | Term Loan | Flaga U.S. dollar variable-rate term loan, due September 2018 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | 59.1 | 59.1 | $ 59.1 | |||||
UGI Utilities | ||||||||
Debt Instrument | ||||||||
Unamortized debt issuance costs | (3.9) | (3.5) | ||||||
Total long-term debt | 751.1 | 671.5 | ||||||
UGI Utilities | Senior Notes | 4.12%, due September 2046 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 200 | $ 200 | ||||||
Stated interest rate | 4.12% | 4.12% | ||||||
UGI Utilities | Senior Notes | 4.98%, due March 2044 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 175 | $ 175 | ||||||
Stated interest rate | 4.98% | |||||||
UGI Utilities | Senior Notes | 4.12%, due October 2046 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 100 | 0 | ||||||
Stated interest rate | 4.12% | 4.12% | ||||||
UGI Utilities | Senior Notes | 6.21%, due September 2036 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 100 | 100 | ||||||
Stated interest rate | 6.21% | |||||||
UGI Utilities | Senior Notes | 2.95%, due June 2026 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 100 | 100 | ||||||
Stated interest rate | 2.95% | 2.95% | ||||||
UGI Utilities | Medium-term Notes | 6.13%, due October 2034 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 20 | 20 | ||||||
Stated interest rate | 6.13% | |||||||
UGI Utilities | Medium-term Notes | 6.50%, due August 2033 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 20 | 20 | ||||||
Stated interest rate | 6.50% | |||||||
UGI Utilities | Medium-term Notes | 5.67%, due January 2018 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 20 | 20 | ||||||
Stated interest rate | 5.67% | |||||||
UGI Utilities | Medium-term Notes | 7.25%, due November 2017 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 20 | 20 | ||||||
Stated interest rate | 7.25% | |||||||
UGI Utilities | Medium-term Notes | 6.17%, due June 2017 | ||||||||
Debt Instrument | ||||||||
Long-term debt, gross | $ 0 | $ 20 | ||||||
Stated interest rate | 6.17% | |||||||
Other | ||||||||
Debt Instrument | ||||||||
Total long-term debt | $ 9.9 | $ 10.8 |
Debt - Schedule of Long-term 70
Debt - Schedule of Long-term Debt (Footnotes) (Details) € in Millions, $ in Millions | 12 Months Ended | ||
Sep. 30, 2017EUR (€) | Sep. 30, 2016 | Sep. 30, 2017USD ($) | |
Debt Instrument | |||
Principal repayments due April 30, 2018 | $ 575.4 | ||
Principal repayments due April 30, 2019 | 58.2 | ||
Principal repayments due April 30, 2020 | 22.5 | ||
AmeriGas Propane | |||
Debt Instrument | |||
Principal repayments due April 30, 2018 | 7.5 | ||
Principal repayments due April 30, 2019 | 3.2 | ||
Principal repayments due April 30, 2020 | $ 1.2 | ||
AmeriGas Propane | Senior Secured Notes | HOLP Senior Secured Notes | |||
Debt Instrument | |||
Effective interest rate | 6.75% | 6.75% | 6.75% |
France SAS | France SAS Senior Facilities term loan, due through April 2020 | EURIBOR | |||
Debt Instrument | |||
Variable interest rate floor (percentage) | 0.00% | ||
Basis spread on variable rate (percentage) | 1.90% | 1.90% | |
France SAS | France SAS Senior Facilities term loan, due through April 2020 | EURIBOR | Minimum | |||
Debt Instrument | |||
Basis spread on variable rate (percentage) | 1.60% | ||
France SAS | France SAS Senior Facilities term loan, due through April 2020 | EURIBOR | Maximum | |||
Debt Instrument | |||
Basis spread on variable rate (percentage) | 2.70% | ||
France SAS | France SAS Senior Facilities term loan, due through April 2020 | Interest rate swaps | EURIBOR | |||
Debt Instrument | |||
Underlying fixed interest rate (percentage) | 0.18% | 0.18% | |
France SAS | Term Loan | France SAS Senior Facilities term loan, due through April 2020 | |||
Debt Instrument | |||
Principal repayments due April 30, 2018 | € | € 60 | ||
Principal repayments due April 30, 2019 | € | 60 | ||
Principal repayments due April 30, 2020 | € | € 480 | ||
France SAS | Term Loan | France SAS Senior Facilities term loan, due through April 2020 | EURIBOR | |||
Debt Instrument | |||
Effective interest rate | 2.10% | 2.10% | 2.10% |
Flaga | Term Loan | Flaga Credit Facility Agreement | |||
Debt Instrument | |||
Effective interest rate | 1.80% | 2.11% | 1.80% |
Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR | Minimum | |||
Debt Instrument | |||
Basis spread on variable rate (percentage) | 1.20% | ||
Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR | Maximum | |||
Debt Instrument | |||
Basis spread on variable rate (percentage) | 2.60% | ||
Flaga | Term Loan | Flaga Credit Facility Agreement | Interest rate swaps | Three-Month EURIBOR | |||
Debt Instrument | |||
Underlying fixed interest rate (percentage) | 0.23% | 0.23% | |
Flaga | Term Loan | Flaga Term Loan, due September 2018 | One-Month LIBOR | |||
Debt Instrument | |||
Basis spread on variable rate (percentage) | 1.125% | ||
Flaga | Term Loan | Flaga Term Loan, due September 2018 | Cross-currency swaps | One-Month LIBOR | |||
Debt Instrument | |||
Effective interest rate | 0.87% | 0.87% | 0.87% |
Debt - Schedule of Principal Re
Debt - Schedule of Principal Repayments of Long-term Debt (Details) $ in Millions | Sep. 30, 2017USD ($) |
Debt Instrument | |
2,018 | $ 179.6 |
2,019 | 80.5 |
2,020 | 575.4 |
2,021 | 58.2 |
2,022 | 22.5 |
AmeriGas Propane | |
Debt Instrument | |
2,018 | 8.6 |
2,019 | 8.2 |
2,020 | 7.5 |
2,021 | 3.2 |
2,022 | 1.2 |
UGI International | |
Debt Instrument | |
2,018 | 130.3 |
2,019 | 71.5 |
2,020 | 567.1 |
2,021 | 54.1 |
2,022 | 20.4 |
UGI Utilities | |
Debt Instrument | |
2,018 | 40 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Other | |
Debt Instrument | |
2,018 | 0.7 |
2,019 | 0.8 |
2,020 | 0.8 |
2,021 | 0.9 |
2,022 | $ 0.9 |
Debt - Schedule of Short-term D
Debt - Schedule of Short-term Debt (Details) | Sep. 30, 2017EUR (€) | Sep. 30, 2017USD ($) | Sep. 30, 2016EUR (€) | Sep. 30, 2016USD ($) |
AmeriGas OLP | ||||
Short-term Debt | ||||
Total Capacity | $ 525,000,000 | $ 525,000,000 | ||
Borrowings Outstanding | 140,000,000 | 153,200,000 | ||
Letters of Credit and Guarantees Outstanding | 67,200,000 | 67,200,000 | ||
Available Borrowing Capacity | $ 317,800,000 | $ 304,600,000 | ||
Weighted Average Interest Rate - End of Year | 3.74% | 3.74% | 2.79% | 2.79% |
France SAS | ||||
Short-term Debt | ||||
Total Capacity | € | € 60,000,000 | € 60,000,000 | ||
Borrowings Outstanding | € | 0 | 0 | ||
Letters of Credit and Guarantees Outstanding | € | 0 | 0 | ||
Available Borrowing Capacity | € | 60,000,000 | 60,000,000 | ||
Flaga | ||||
Short-term Debt | ||||
Total Capacity | € | 55,000,000 | 55,000,000 | ||
Borrowings Outstanding | € | 0 | 0 | ||
Letters of Credit and Guarantees Outstanding | € | 6,500,000 | 9,600,000 | ||
Available Borrowing Capacity | € | € 48,500,000 | € 45,400,000 | ||
Energy Services, LLC | ||||
Short-term Debt | ||||
Total Capacity | $ 240,000,000 | $ 240,000,000 | ||
Borrowings Outstanding | 0 | 0 | ||
Letters of Credit and Guarantees Outstanding | 0 | 0 | ||
Available Borrowing Capacity | 240,000,000 | 240,000,000 | ||
UGI Utilities | ||||
Short-term Debt | ||||
Total Capacity | 300,000,000 | 300,000,000 | ||
Borrowings Outstanding | 170,000,000 | 112,500,000 | ||
Letters of Credit and Guarantees Outstanding | 2,000,000 | 2,000,000 | ||
Available Borrowing Capacity | $ 128,000,000 | $ 185,500,000 | ||
Weighted Average Interest Rate - End of Year | 2.11% | 2.11% | 1.42% | 1.42% |
Debt - Schedule of Short-term73
Debt - Schedule of Short-term Debt (Footnotes) (Details) | 12 Months Ended | |||||
Sep. 30, 2017EUR (€) | Sep. 30, 2016EUR (€) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Oct. 31, 2015EUR (€) | Apr. 30, 2015EUR (€) | |
AmeriGas OLP | ||||||
Short-term Debt | ||||||
Total Capacity | $ | $ 525,000,000 | $ 525,000,000 | ||||
AmeriGas OLP | Letter of Credit | AmeriGas Credit Agreement | ||||||
Short-term Debt | ||||||
Total Capacity | $ | 125,000,000 | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Minimum | ||||||
Short-term Debt | ||||||
Facility fee (percentage) | 0.30% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Maximum | ||||||
Short-term Debt | ||||||
Facility fee (percentage) | 0.45% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Federal Funds Effective Swap Rate | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 0.50% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Base Rate | Minimum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 0.50% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Base Rate | Maximum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.50% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Eurodollar | Minimum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.50% | |||||
AmeriGas OLP | Line of Credit | AmeriGas Credit Agreement | Eurodollar | Maximum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 2.50% | |||||
France SAS | ||||||
Short-term Debt | ||||||
Total Capacity | € 60,000,000 | € 60,000,000 | ||||
France SAS | 2015 Senior Facilities Agreement | EURIBOR | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.90% | 1.90% | ||||
France SAS | 2015 Senior Facilities Agreement | EURIBOR | Minimum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.60% | |||||
France SAS | 2015 Senior Facilities Agreement | EURIBOR | Maximum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 2.70% | |||||
France SAS | Revolving Credit Facility | 2015 Senior Facilities Agreement | Line of Credit | ||||||
Short-term Debt | ||||||
Total Capacity | € 60,000,000 | |||||
France SAS | Revolving Credit Facility | 2015 Senior Facilities Agreement | EURIBOR | Minimum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.45% | |||||
France SAS | Revolving Credit Facility | 2015 Senior Facilities Agreement | EURIBOR | Maximum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 2.55% | |||||
Flaga | ||||||
Short-term Debt | ||||||
Total Capacity | € 55,000,000 | € 55,000,000 | ||||
Flaga | Flaga Credit Facility Agreement | Line of Credit | ||||||
Short-term Debt | ||||||
Total Capacity | € 100,800,000 | |||||
Flaga | Flaga Credit Facility Agreement | Overdraft Facility | ||||||
Short-term Debt | ||||||
Total Capacity | 5,000,000 | 5,000,000 | ||||
Flaga | Flaga Credit Facility Agreement | Guarantee Facility | ||||||
Short-term Debt | ||||||
Total Capacity | 25,000,000 | 25,000,000 | ||||
Flaga | Revolving Credit Facility | Flaga Credit Facility Agreement | Line of Credit | ||||||
Short-term Debt | ||||||
Total Capacity | € 25,000,000 | € 25,000,000 | ||||
Facility fee (percentage) | 30.00% | |||||
Flaga | Revolving Credit Facility | Flaga Credit Facility Agreement | EURIBOR | Minimum | Line of Credit | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.45% | |||||
Flaga | Revolving Credit Facility | Flaga Credit Facility Agreement | EURIBOR | Maximum | Line of Credit | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 3.65% | |||||
Energy Services | ||||||
Short-term Debt | ||||||
Total Capacity | $ | $ 240,000,000 | 240,000,000 | ||||
Energy Services | Energy Services Credit Agreement | ||||||
Short-term Debt | ||||||
Maximum ratio of Total Indebtedness to EBITDA, after dividend payment | 3 | 3 | ||||
Energy Services | Energy Services Credit Agreement | Line of Credit | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 2.25% | |||||
Energy Services | Energy Services Credit Agreement | Federal Funds Rate | Line of Credit | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 0.50% | |||||
Energy Services | Energy Services Credit Agreement | LIBOR | Line of Credit | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.00% | |||||
Energy Services | Letter of Credit | Energy Services Credit Agreement | Line of Credit | ||||||
Short-term Debt | ||||||
Total Capacity | $ | $ 50,000,000 | |||||
UGI Utilities | ||||||
Short-term Debt | ||||||
Total Capacity | $ | 300,000,000 | $ 300,000,000 | ||||
UGI Utilities | Letter of Credit | 2015 UGI Utilities Credit Agreement | ||||||
Short-term Debt | ||||||
Total Capacity | $ | $ 100,000,000 | |||||
UGI Utilities | Line of Credit | 2015 UGI Utilities Credit Agreement | LIBOR | Minimum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 0.00% | |||||
UGI Utilities | Line of Credit | 2015 UGI Utilities Credit Agreement | LIBOR | Maximum | ||||||
Short-term Debt | ||||||
Basis spread on variable rate (percentage) | 1.75% |
Debt - Accounts Receivable Secu
Debt - Accounts Receivable Securitization Facility (Details) - USD ($) | 6 Months Ended | |
Oct. 31, 2016 | Apr. 30, 2016 | |
Energy Services | Receivables Facility | Energy Services Receivables Facility | ||
Short-term Debt | ||
Maximum borrowing capacity | $ 75,000,000 | $ 150,000,000 |
Debt - Schedule of Receivables
Debt - Schedule of Receivables Facility (Details) - Energy Services - Receivables Facility - Energy Services Receivables Facility - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Short-term Debt | |||
Trade receivables transferred to ESFC during the year | $ 1,017.3 | $ 756.4 | $ 1,037.8 |
ESFC trade receivables sold to the bank during the year | 243 | 204 | 306.5 |
ESFC trade receivables - end of year | 44.8 | 35.7 | $ 44.1 |
Outstanding balance of trade receivables sold | $ 39 | $ 25.5 |
Debt - Restrictive Covenants (D
Debt - Restrictive Covenants (Details) | 12 Months Ended |
Sep. 30, 2017 | |
Energy Services | Energy Services Credit Agreement | |
Debt Instrument | |
Maximum ratio of Total Indebtedness to EBITDA | 3.50 |
Minimum ratio of EBITDA to interest expense | 3.50 |
UGI Utilities | 2015 UGI Utilities Credit Agreement | |
Debt Instrument | |
Ratio of Consolidated Debt to Consolidated Total Capital | 0.65 |
UGI Utilities | Senior Notes | |
Debt Instrument | |
Ratio of Consolidated Debt to Consolidated Total Capital | 0.65 |
Debt - Restricted Net Assets (D
Debt - Restricted Net Assets (Details) $ in Millions | Sep. 30, 2017USD ($) |
Senior Notes | 4.98% Senior Notes, due March 2044 | |
Debt Instrument | |
Amount of net assets restricted from transfer to parent company under different agreements | $ 1,500 |
Income Taxes - Income Before In
Income Taxes - Income Before Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |||
Domestic | $ 527.3 | $ 518.9 | $ 552.3 |
Foreign | 174.1 | 191.1 | 39.5 |
Income before income taxes | $ 701.4 | $ 710 | $ 591.8 |
Income Taxes - Provisions for I
Income Taxes - Provisions for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Current expense (benefit): | |||
Federal | $ (2.7) | $ 44.2 | $ 97.1 |
State | 14 | 20.9 | 32.2 |
Foreign | 56.2 | 78.7 | 36 |
Investment tax credit | 0 | 0 | (1.2) |
Total current expense | 67.5 | 143.8 | 164.1 |
Deferred expense (benefit): | |||
Federal | 125.8 | 81.2 | 28.1 |
State | 16.4 | 1.3 | 2.9 |
Foreign | (31.8) | (4.8) | (17) |
Investment tax credit amortization | (0.3) | (0.3) | (0.3) |
Total deferred expense | 110.1 | 77.4 | 13.7 |
Total income tax expense | $ 177.6 | $ 221.2 | $ 177.8 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017 | Sep. 30, 2021 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Income Tax Disclosure [Abstract] | ||||||
Foreign tax credits | $ 40.9 | $ 25.6 | $ 63 | |||
Undistributed earnings of foreign subsidiaries | $ 119.7 | $ 119.7 | ||||
Income Taxes | ||||||
Corporate income tax rate | 25.30% | 31.20% | 30.00% | |||
Deferred tax assets relating to operating loss carryforwards | 30.9 | $ 30.9 | $ 31.5 | |||
Increase (decrease) in valuation allowance | 7.6 | (7.2) | ||||
Valuation allowance provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries | 0.2 | 0.2 | ||||
Credits to expire before utilization | 98.5 | 98.5 | ||||
Unrecognized income tax benefits | 12.2 | 12.2 | 7.2 | $ 3.2 | $ 2.4 | |
Accrued interest included in unrecognized income tax benefits | 0.5 | 0.5 | ||||
Unrecognized tax benefits if recognized would impact the reported effective tax rate | 8.1 | 8.1 | ||||
Accrued Interest Included | ||||||
Income Taxes | ||||||
Unrecognized income tax benefits | 12.2 | 12.2 | ||||
Future Utilization of Foreign Tax Credits | ||||||
Income Taxes | ||||||
Increase (decrease) in valuation allowance | (7.6) | |||||
Foreign Operating Loss Carryforwards | ||||||
Income Taxes | ||||||
Increase (decrease) in valuation allowance | (1.5) | |||||
Foreign Tax Credits | ||||||
Income Taxes | ||||||
Increase (decrease) in valuation allowance | 1.1 | |||||
State Capital Loss Carryforwards | ||||||
Income Taxes | ||||||
Increase (decrease) in valuation allowance | 0.8 | |||||
State Operating Loss Carryforwards | ||||||
Income Taxes | ||||||
Increase (decrease) in valuation allowance | (5.5) | |||||
Flaga | ||||||
Income Taxes | ||||||
Deferred tax assets relating to operating loss carryforwards | 5.6 | 5.6 | ||||
UGI International Holdings BV | ||||||
Income Taxes | ||||||
Deferred tax assets relating to operating loss carryforwards | 0.7 | 0.7 | ||||
UGI France | ||||||
Income Taxes | ||||||
Deferred tax assets relating to operating loss carryforwards | 7.8 | 7.8 | ||||
AmeriGas Propane | ||||||
Income Taxes | ||||||
Operating loss carryforwards | 19.7 | 19.7 | ||||
Deferred tax assets relating to operating loss carryforwards | 6.8 | 6.8 | ||||
Other Subsidiaries | ||||||
Income Taxes | ||||||
Deferred tax assets relating to operating loss carryforwards | 10 | 10 | ||||
UGI International | ||||||
Income Taxes | ||||||
Valuation allowance operating loss carryforwards | 7.5 | $ 7.5 | ||||
French Parliament | ||||||
Income Taxes | ||||||
Corporate income tax rate | 34.43% | |||||
Deferred tax benefit | $ 29 | |||||
French Parliament | Forecast | ||||||
Income Taxes | ||||||
Corporate income tax rate | 28.92% | |||||
State | ||||||
Income Taxes | ||||||
Operating loss carryforwards | 187.9 | 187.9 | ||||
Decrease in income tax expense due to state tax flow through of accelerated depreciation | 2.5 | 1.3 | $ 1.5 | |||
Deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions | $ 7.7 | |||||
Foreign | ||||||
Income Taxes | ||||||
Foreign tax credit carryforwards | 106.1 | 106.1 | ||||
Foreign | Flaga | ||||||
Income Taxes | ||||||
Operating loss carryforwards | 24.5 | 24.5 | ||||
Foreign | UGI International Holdings BV | ||||||
Income Taxes | ||||||
Operating loss carryforwards | 2.5 | 2.5 | ||||
Foreign | UGI France | ||||||
Income Taxes | ||||||
Operating loss carryforwards | $ 22.6 | $ 22.6 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate (Details) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
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 | (4.30%) | (6.20%) | (7.90%) |
State income taxes, net of federal benefit | 2.90% | 3.00% | 3.30% |
Valuation allowance adjustments | (1.10%) | (0.90%) | 0.80% |
Effects of foreign operations | (1.10%) | 0.60% | 0.20% |
Deferred tax effects of French tax rate change | (4.10%) | 0.00% | 0.00% |
Excess tax benefits on share-based payments | (1.30%) | 0.00% | 0.00% |
Other, net | (0.70%) | (0.30%) | (1.40%) |
Effective tax rate | 25.30% | 31.20% | 30.00% |
Income Taxes - Deferred Tax Lia
Income Taxes - Deferred Tax Liabilities (Assets) (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Income Tax Disclosure [Abstract] | ||
Excess book basis over tax basis of property, plant and equipment | $ 975.8 | $ 873.9 |
Investment in AmeriGas Partners | 326.8 | 323.2 |
Intangible assets and goodwill | 98.2 | 87.1 |
Utility regulatory assets | 132.2 | 148.3 |
Other | 11.7 | 11.9 |
Gross deferred tax liabilities | 1,544.7 | 1,444.4 |
Pension plan liabilities | (57.7) | (79.7) |
Employee-related benefits | (65.4) | (63.1) |
Operating loss carryforwards | (30.9) | (31.5) |
Foreign tax credit carryforwards | (106.1) | (105.1) |
Utility regulatory liabilities | (9.3) | (13.9) |
Derivative instruments | (1.7) | (14.7) |
Utility environmental liabilities | (22.2) | (22.8) |
Other | (27.8) | (28.3) |
Gross deferred tax assets | (321.1) | (359.1) |
Deferred tax assets valuation allowance | 107.1 | 114.3 |
Net deferred tax liabilities | $ 1,330.7 | $ 1,199.6 |
Income Taxes - Reconciliation83
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Reconciliation of Unrecognized Tax Benefits | |||
Unrecognized tax benefits — beginning of year | $ 7.2 | $ 3.2 | $ 2.4 |
Additions for tax positions of the current year | 1.9 | 2.2 | 0.9 |
Additions for tax positions taken in prior years | 4.6 | 2.3 | 0.5 |
Settlements with tax authorities/statute lapses | (1.5) | (0.5) | (0.6) |
Unrecognized tax benefits — end of year | $ 12.2 | $ 7.2 | $ 3.2 |
Employee Retirement Plans - Cha
Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefits Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Pension Benefits | |||
Change in benefit obligations: | |||
Benefit obligations — beginning of year | $ 707.7 | $ 614.7 | |
Service cost | 11.9 | 10.1 | $ 10 |
Interest cost | 25 | 26.8 | 25.5 |
Actuarial (gain) loss | (19.6) | 83.3 | |
Plan amendments | 1.2 | 0 | |
Curtailment | (3.6) | (1.4) | |
Foreign currency | 2.9 | 0.1 | |
Benefits paid | (27.7) | (25.9) | |
Benefit obligations — end of year | 697.8 | 707.7 | 614.7 |
Change in plan assets: | |||
Fair value of plan assets — beginning of year | 493.7 | 453.8 | |
Actual gain on plan assets | 47 | 53.4 | |
Foreign currency | 1.6 | 0.1 | |
Employer contributions | 14.6 | 11.4 | |
Benefits paid | (27.7) | (25) | |
Fair value of plan assets — end of year | 529.2 | 493.7 | 453.8 |
Funded status of the plans — end of year | (168.6) | (214) | |
Assets (liabilities) recorded in the balance sheet: | |||
Assets in excess of liabilities — included in other noncurrent assets | 0 | 0 | |
Unfunded liabilities — included in other noncurrent liabilities | (168.6) | (214) | |
Net amount recognized | (168.6) | (214) | |
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): | |||
Prior service cost (credit) | 0.7 | (0.6) | |
Net actuarial loss (gain) | 21.3 | 31.4 | |
Total | 22 | 30.8 | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | |||
Prior service cost (credit) | 1 | 1.2 | |
Net actuarial loss | 139.5 | 181 | |
Total | 140.5 | 182.2 | |
Other Postretirement Benefits | |||
Change in benefit obligations: | |||
Benefit obligations — beginning of year | 30.9 | 25.4 | |
Service cost | 1 | 0.7 | 0.7 |
Interest cost | 0.8 | 0.9 | 0.8 |
Actuarial (gain) loss | (4.8) | 6.6 | |
Plan amendments | 0 | (1.5) | |
Curtailment | (0.4) | (0.3) | |
Foreign currency | 0.4 | 0 | |
Benefits paid | (0.9) | (0.9) | |
Benefit obligations — end of year | 27 | 30.9 | 25.4 |
Change in plan assets: | |||
Fair value of plan assets — beginning of year | 13.7 | 12.5 | |
Actual gain on plan assets | 1.3 | 1.3 | |
Foreign currency | 0 | 0 | |
Employer contributions | 0.6 | 0.6 | |
Benefits paid | (0.8) | (0.7) | |
Fair value of plan assets — end of year | 14.8 | 13.7 | $ 12.5 |
Funded status of the plans — end of year | (12.2) | (17.2) | |
Assets (liabilities) recorded in the balance sheet: | |||
Assets in excess of liabilities — included in other noncurrent assets | 5.4 | 4.1 | |
Unfunded liabilities — included in other noncurrent liabilities | (17.6) | (21.3) | |
Net amount recognized | (12.2) | (17.2) | |
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): | |||
Prior service cost (credit) | (1.5) | (1.5) | |
Net actuarial loss (gain) | (0.6) | 3.8 | |
Total | (2.1) | 2.3 | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | |||
Prior service cost (credit) | (1.6) | (2.2) | |
Net actuarial loss | 1.2 | 2.4 | |
Total | $ (0.4) | $ 0.2 |
Employee Retirement Plans - Nar
Employee Retirement Plans - Narrative (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Defined Benefit Plan Disclosure | |||
Amortization of prior service credits | $ 500,000 | ||
Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Contribution made to Pension Plan | 14,600,000 | $ 11,400,000 | |
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans | 697,800,000 | 707,700,000 | $ 614,700,000 |
Pre-tax cost to sponsor unfunded and non-qualified supplemental executive retirement plans | 18,900,000 | 14,500,000 | 12,800,000 |
Net actuarial loss | 21,300,000 | 31,400,000 | |
Fair value of pension and other postretirement benefit contributions | 0 | 0 | |
Supplemental Employee Retirement Plans | |||
Defined Benefit Plan Disclosure | |||
Expected amortization of net actuarial losses | 1,100,000 | ||
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans | 50,700,000 | 47,400,000 | |
Pre-tax cost to sponsor unfunded and non-qualified supplemental executive retirement plans | 3,100,000 | 2,600,000 | 2,300,000 |
Net actuarial loss | 11,300,000 | 13,000,000 | |
Pension and other postretirement benefit contributions | 1,300,000 | 400,000 | 0 |
Fair value of pension and other postretirement benefit contributions | 31,800,000 | 28,400,000 | |
U.S. Pension Plan | Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Expected amortization of net actuarial losses | 13,500,000 | ||
ABO for the pension plans | 605,200,000 | 601,300,000 | |
Contribution made to Pension Plan | $ 11,400,000 | $ 9,900,000 | $ 11,100,000 |
Employee Retirement Plans - Act
Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details) | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Pension Benefits | |||
Weighted-average assumptions: | |||
Discount rate – benefit obligations | 4.00% | 3.80% | 4.60% |
Discount rate – benefit cost | 3.80% | 4.60% | 4.60% |
Expected return on plan assets | 7.50% | 7.55% | 7.75% |
Rate of increase in salary levels | 3.25% | 3.25% | 3.25% |
Other Postretirement Benefits | |||
Weighted-average assumptions: | |||
Discount rate – benefit obligations | 4.00% | 3.80% | 4.70% |
Discount rate – benefit cost | 3.80% | 4.70% | 4.60% |
Expected return on plan assets | 5.00% | 5.00% | 5.00% |
Rate of increase in salary levels | 3.25% | 3.25% | 3.25% |
Employee Retirement Plans - Net
Employee Retirement Plans - Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | $ 11.9 | $ 10.1 | $ 10 |
Interest cost | 25 | 26.8 | 25.5 |
Expected return on assets | (33.6) | (32.4) | (32.2) |
Curtailment gain | (1.4) | (1.2) | (0.8) |
Amortization of: | |||
Prior service cost (benefit) | 0.3 | 0.3 | 0.3 |
Actuarial loss | 16.7 | 10.9 | 10 |
Net benefit cost | 18.9 | 14.5 | 12.8 |
Change in associated regulatory liabilities | 0 | 0 | 0 |
Net benefit cost after change in regulatory liabilities | 18.9 | 14.5 | 12.8 |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | 1 | 0.7 | 0.7 |
Interest cost | 0.8 | 0.9 | 0.8 |
Expected return on assets | (0.7) | (0.6) | (0.6) |
Curtailment gain | 0 | 0 | 0 |
Amortization of: | |||
Prior service cost (benefit) | (0.6) | (0.6) | (0.5) |
Actuarial loss | 0.3 | 0 | 0.1 |
Net benefit cost | 0.8 | 0.4 | 0.5 |
Change in associated regulatory liabilities | (0.5) | 1 | 3.7 |
Net benefit cost after change in regulatory liabilities | $ 0.3 | $ 1.4 | $ 4.2 |
Employee Retirement Plans - Exp
Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Millions | Sep. 30, 2017USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure | |
Fiscal 2,018 | $ 29.5 |
Fiscal 2,019 | 29.9 |
Fiscal 2,020 | 31.5 |
Fiscal 2,021 | 39 |
Fiscal 2,022 | 39.6 |
Fiscal 2023 - 2027 | 196.2 |
Other Postretirement Benefits | |
Defined Benefit Plan Disclosure | |
Fiscal 2,018 | 1.1 |
Fiscal 2,019 | 1.1 |
Fiscal 2,020 | 1.1 |
Fiscal 2,021 | 1.1 |
Fiscal 2,022 | 1 |
Fiscal 2023 - 2027 | $ 4.9 |
Employee Retirement Plans - Sch
Employee Retirement Plans - Schedule of Health Care Cost Trend Rates (Details) | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Retirement Benefits [Abstract] | ||
Health care cost trend rate assumed for next year | 7.00% | 7.25% |
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 5.00% | 5.00% |
Fiscal year that the rate reaches the ultimate trend rate | 2,026 | 2,026 |
Employee Retirement Plans - Pen
Employee Retirement Plans - Pension Plans (Details) | Sep. 30, 2017 | Sep. 30, 2016 |
U.S. Pension Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Percentage of common stock represented pension plan assets | 7.70% | 8.00% |
Pension Benefits | U.S. Pension Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 100.00% | 100.00% |
Target Asset Allocation | 100.00% | |
Pension Benefits | U.S. Pension Plan | Equity investments | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 67.60% | 64.30% |
Target Asset Allocation | 65.00% | |
Pension Benefits | U.S. Pension Plan | Equity investments | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 60.00% | |
Pension Benefits | U.S. Pension Plan | Equity investments | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 70.00% | |
Pension Benefits | U.S. Pension Plan | Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 55.20% | 54.10% |
Target Asset Allocation | 52.50% | |
Pension Benefits | U.S. Pension Plan | Domestic | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 40.00% | |
Pension Benefits | U.S. Pension Plan | Domestic | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 65.00% | |
Pension Benefits | U.S. Pension Plan | International | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 12.40% | 10.20% |
Target Asset Allocation | 12.50% | |
Pension Benefits | U.S. Pension Plan | International | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 7.50% | |
Pension Benefits | U.S. Pension Plan | International | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 17.50% | |
Pension Benefits | U.S. Pension Plan | Fixed income funds & cash equivalents | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 32.40% | 35.70% |
Target Asset Allocation | 35.00% | |
Pension Benefits | U.S. Pension Plan | Fixed income funds & cash equivalents | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 30.00% | |
Pension Benefits | U.S. Pension Plan | Fixed income funds & cash equivalents | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 40.00% | |
VEBA | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 100.00% | 100.00% |
Target Asset Allocation | 100.00% | |
VEBA | Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 63.10% | 69.90% |
Target Asset Allocation | 65.00% | |
VEBA | Domestic | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 60.00% | |
VEBA | Domestic | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 70.00% | |
VEBA | Fixed income funds & cash equivalents | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Actual | 36.90% | 30.10% |
Target Asset Allocation | 35.00% | |
VEBA | Fixed income funds & cash equivalents | Minimum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 30.00% | |
VEBA | Fixed income funds & cash equivalents | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans | ||
Target Asset Allocation | 40.00% |
Employee Retirement Plans - Fai
Employee Retirement Plans - Fair Value of U.S. Pension Plan and VEBA Trust Assets (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 |
Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | $ 529.2 | $ 493.7 | $ 453.8 |
Pension Benefits | U.S. Pension Plan | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 498 | 463.4 | |
Other | 5.3 | 17.8 | |
Pension Benefits | U.S. Pension Plan | Domestic equity investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 274.9 | 250.5 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 171.6 | 158.9 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Small and midcap equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 65.2 | 43.2 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Smallcap common stocks | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 11.4 | ||
Other | 0 | ||
Pension Benefits | U.S. Pension Plan | UGI Corporation Common Stock | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 38.1 | 37 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | International index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 61.6 | 47.3 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Fixed income investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 161.5 | 165.6 | |
Other | 5.3 | 17.8 | |
Pension Benefits | U.S. Pension Plan | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 156.2 | 147.8 | |
Other | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 5.3 | 17.8 | |
Other | 5.3 | 17.8 | |
Pension Benefits | U.S. Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 492.7 | 445.6 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Domestic equity investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 274.9 | 250.5 | |
Pension Benefits | U.S. Pension Plan | Level 1 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 171.6 | 158.9 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Small and midcap equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 65.2 | 43.2 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Smallcap common stocks | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 11.4 | ||
Pension Benefits | U.S. Pension Plan | Level 1 | UGI Corporation Common Stock | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 38.1 | 37 | |
Pension Benefits | U.S. Pension Plan | Level 1 | International index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 61.6 | 47.3 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Fixed income investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 156.2 | 147.8 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 156.2 | 147.8 | |
Pension Benefits | U.S. Pension Plan | Level 1 | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | Domestic equity investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | Small and midcap equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | Smallcap common stocks | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | ||
Pension Benefits | U.S. Pension Plan | Level 2 | UGI Corporation Common Stock | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | International index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 2 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Domestic equity investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Small and midcap equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Smallcap common stocks | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | ||
Pension Benefits | U.S. Pension Plan | Level 3 | UGI Corporation Common Stock | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | International index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Fixed income investments: | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | U.S. Pension Plan | Level 3 | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 14.8 | 13.7 | |
Other | 0.4 | 0.1 | |
VEBA | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 9.3 | 9.6 | |
Other | 0 | 0 | |
VEBA | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 5.1 | 4 | |
Other | 0 | 0 | |
VEBA | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0.4 | 0.1 | |
Other | 0.4 | 0.1 | |
VEBA | Level 1 | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 14.4 | 13.6 | |
VEBA | Level 1 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 9.3 | 9.6 | |
VEBA | Level 1 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 5.1 | 4 | |
VEBA | Level 1 | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 2 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 2 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 3 | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 3 | S&P 500 Index equity mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 3 | Bond index mutual funds | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | 0 | 0 | |
VEBA | Level 3 | Cash equivalents | |||
Defined Benefit Plan Disclosure | |||
Fair value of plan assets | $ 0 | $ 0 |
Employee Retirement Plans - Def
Employee Retirement Plans - Defined Contribution Plans (Details) - Other Pension, Postretirement and Supplemental Plans - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Defined Contribution Plan Disclosure [Line Items] | |||
Costs of benefits under savings plans | $ 15.1 | $ 14.3 | $ 15.2 |
Total fair values of grantor trust investment assets | $ 3.6 | $ 4.6 |
Utility Regulatory Assets and93
Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Utilities (Details) - UGI Utilities - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 368.9 | $ 395.1 |
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 49.2 | 55.6 |
Postretirement benefit overcollections | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 17.5 | 17.5 |
Deferred fuel and power refunds | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 10.6 | 22.3 |
State income tax benefits — distribution system repairs | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 18.4 | 15.1 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 2.7 | 0.7 |
Income taxes recoverable | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 121.4 | 115.7 |
Underfunded pension and postretirement plans | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 141.3 | 183.1 |
Environmental costs | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 61.6 | 59.4 |
Deferred fuel and power costs | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 7.7 | 0.2 |
Removal costs, net | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 31 | 27.9 |
Other | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 5.9 | $ 8.8 |
Utility Regulatory Assets and94
Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions | Oct. 20, 2017 | Jul. 01, 2017 | Jan. 19, 2017 | Jan. 01, 2017 | Oct. 19, 2016 | Oct. 14, 2016 | Jun. 30, 2016 | Apr. 01, 2016 | Jan. 19, 2016 | Apr. 01, 2015 | Mar. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2016 |
Regulatory Assets [Line Items] | |||||||||||||||
Associated increase to utility property, plant and equipment | $ 5,564.6 | $ 5,346.4 | |||||||||||||
UGI Utilities | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Capitalized project costs | 5.8 | ||||||||||||||
Project costs expensed in prior periods | $ 5.4 | ||||||||||||||
UGI Utilities | Information Technology | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Associated increase to utility property, plant and equipment | 2.7 | ||||||||||||||
Pennsylvania Public Utility Commission | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Maximum period since petition to file a general rate filing | 5 years | ||||||||||||||
DSIC, percent of amount billed to customers | 0.00% | ||||||||||||||
Pennsylvania Public Utility Commission | PNG | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Requested operating revenue increase | $ 21.7 | ||||||||||||||
DSIC, percent of amount billed to customers | 7.50% | 0.00% | |||||||||||||
Pennsylvania Public Utility Commission | PNG | Subsequent Event | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Approved operating revenue increase | $ 11.3 | ||||||||||||||
Pennsylvania Public Utility Commission | UGI Gas | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Approved operating revenue increase | $ 27 | ||||||||||||||
Pennsylvania Public Utility Commission | CPG | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
DSIC, percent of amount billed to customers | 7.50% | 0.00% | |||||||||||||
Pennsylvania Public Utility Commission | UGI Utilities | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Requested operating revenue increase | $ 58.6 | ||||||||||||||
Amount of operating revenue increase | $ 27 | ||||||||||||||
Gas Utility | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Fair value of unrealized gains (losses) | $ 0.1 | 4.3 | |||||||||||||
Deferred Project Costs | UGI Utilities | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Associated increase to utility regulatory assets | $ 3.1 | ||||||||||||||
Minimum | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Average remaining depreciable lives of the associated property | 1 year | ||||||||||||||
Maximum | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Average remaining depreciable lives of the associated property | 65 years | ||||||||||||||
Maximum | Pennsylvania Public Utility Commission | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
DSIC, percent of amount billed to customers | 5.00% | 5.00% | |||||||||||||
Maximum | Pennsylvania Public Utility Commission | PNG | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
DSIC, percent of amount billed to customers | 10.00% | ||||||||||||||
Maximum | Pennsylvania Public Utility Commission | CPG | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
DSIC, percent of amount billed to customers | 10.00% | ||||||||||||||
Maximum | Postretirement benefit overcollections | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Regulatory liability, period overcollections will be refunded to customers | 10 years | ||||||||||||||
Maximum | Removal Costs, Net | |||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||
Regulatory asset, amortization period | 5 years |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Public Utilities, Inventory | ||
Total inventories | $ 278.6 | $ 210.3 |
Non-utility LPG and natural gas | ||
Public Utilities, Inventory | ||
Total inventories | 188.4 | 129.8 |
Gas Utility natural gas | ||
Public Utilities, Inventory | ||
Total inventories | 39.5 | 29.2 |
Materials, supplies and other | ||
Public Utilities, Inventory | ||
Total inventories | $ 50.7 | $ 51.3 |
Inventories - Narrative (Detail
Inventories - Narrative (Details) - UGI Utilities $ in Millions | 12 Months Ended | |
Sep. 30, 2017USD ($)storage_agreementBcf | Sep. 30, 2016USD ($)Bcf | |
Public Utilities, Inventory | ||
Number of storage agreements | storage_agreement | 5 | |
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet) | Bcf | 2.3 | 3.5 |
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $ | $ 6.7 | $ 7.6 |
Minimum | ||
Public Utilities, Inventory | ||
Storage agreement term (in years) | 1 year | |
Maximum | ||
Public Utilities, Inventory | ||
Storage agreement term (in years) | 3 years |
Property, Plant and Equipment97
Property, Plant and Equipment (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Property, Plant and Equipment | ||
Utility | $ 3,285.3 | $ 2,998.9 |
Non-utility | 5,564.6 | 5,346.4 |
Total property, plant and equipment | 8,849.9 | 8,345.3 |
Distribution | ||
Property, Plant and Equipment | ||
Utility | 2,835.3 | 2,634.2 |
Transmission | ||
Property, Plant and Equipment | ||
Utility | 96.4 | 93.5 |
General and other | ||
Property, Plant and Equipment | ||
Utility | 241 | 167.3 |
Land | ||
Property, Plant and Equipment | ||
Non-utility | 180.1 | 169.9 |
Buildings and improvements | ||
Property, Plant and Equipment | ||
Non-utility | 351.2 | 382.2 |
Transportation equipment | ||
Property, Plant and Equipment | ||
Non-utility | 289.3 | 301.7 |
Equipment, primarily cylinders and tanks | ||
Property, Plant and Equipment | ||
Non-utility | 3,529.4 | 3,421.5 |
Electric generation | ||
Property, Plant and Equipment | ||
Non-utility | 310 | 309.4 |
Pipeline and related assets | ||
Property, Plant and Equipment | ||
Non-utility | 454.5 | 235.8 |
Work in process | ||
Property, Plant and Equipment | ||
Utility | 112.6 | 103.9 |
Non-utility | 95.3 | 201.6 |
Other | ||
Property, Plant and Equipment | ||
Non-utility | $ 354.8 | $ 324.3 |
Goodwill and Intangible Asset98
Goodwill and Intangible Assets - Changes in the Carrying Amount of Goodwill (Details) - USD ($) $ in Millions | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Goodwill | ||
Balance at beginning of period | $ 2,989 | $ 2,953.4 |
Acquisitions | 78.5 | 41.1 |
Dispositions | (1.6) | |
Purchase accounting adjustments | (1.7) | (4.5) |
Foreign currency translation | 41.4 | 0.6 |
Balance at end of period | 3,107.2 | 2,989 |
AmeriGas Propane | ||
Goodwill | ||
Balance at beginning of period | 1,978.3 | 1,956 |
Acquisitions | 23 | 24.2 |
Dispositions | 0 | |
Purchase accounting adjustments | 0 | (1.9) |
Foreign currency translation | 0 | 0 |
Balance at end of period | 2,001.3 | 1,978.3 |
UGI International | ||
Goodwill | ||
Balance at beginning of period | 817 | 803.7 |
Acquisitions | 55.5 | 16.9 |
Dispositions | (1.6) | |
Purchase accounting adjustments | (1.7) | (2.6) |
Foreign currency translation | 41.4 | 0.6 |
Balance at end of period | 912.2 | 817 |
Midstream & Marketing | ||
Goodwill | ||
Balance at beginning of period | 11.6 | 11.6 |
Acquisitions | 0 | 0 |
Dispositions | 0 | |
Purchase accounting adjustments | 0 | 0 |
Foreign currency translation | 0 | 0 |
Balance at end of period | 11.6 | 11.6 |
UGI Utilities | ||
Goodwill | ||
Balance at beginning of period | 182.1 | 182.1 |
Acquisitions | 0 | 0 |
Dispositions | 0 | |
Purchase accounting adjustments | 0 | 0 |
Foreign currency translation | 0 | 0 |
Balance at end of period | $ 182.1 | $ 182.1 |
Goodwill and Intangible Asset99
Goodwill and Intangible Assets - Components of Intangible Assets (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Customer relationships, noncompete agreements and other | $ 817.8 | $ 773.5 |
Trademarks and tradenames (not subject to amortization) | 134.1 | 131.6 |
Gross carrying amount | 951.9 | 905.1 |
Accumulated amortization | (340.2) | (324.8) |
Intangible assets, net | $ 611.7 | $ 580.3 |
Goodwill and Intangible Asse100
Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Amortization expense of intangible assets | $ 50.8 | $ 54.3 | $ 52 |
Expected aggregate amortization expense of intangible assets for the next five fiscal years: | |||
Fiscal 2,018 | 53.5 | ||
Fiscal 2,019 | 51.6 | ||
Fiscal 2,020 | 50.2 | ||
Fiscal 2,021 | 48.3 | ||
Fiscal 2,022 | $ 46.6 |
Series Preferred Stock (Details
Series Preferred Stock (Details) - shares | Sep. 30, 2017 | Sep. 30, 2016 |
Class of Stock [Line Items] | ||
Preferred Stock, shares authorized | 10,000,000 | |
Preferred Stock, shares outstanding | 0 | 0 |
UGI Utilities | ||
Class of Stock [Line Items] | ||
Preferred Stock, shares authorized | 2,000,000 | |
Preferred Stock, shares outstanding | 0 | 0 |
Common Stock and Equity-Base102
Common Stock and Equity-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 30, 2014 | Jan. 24, 2013 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Treasury stock acquired | $ 38.6 | $ 36.9 | |||
Pre-tax equity-based compensation expense | 19.3 | 23.8 | $ 29.2 | ||
After tax equity-based compensation expense | 11.8 | 15.4 | 18.9 | ||
Cash received from stock option exercises | 17.7 | 27.3 | 16.2 | ||
Associated tax benefits | 9.6 | $ 14.9 | $ 5.8 | ||
Unrecognized compensation cost associated with unvested unit awards | $ 7 | ||||
Weighted-average period of recognition for unvested unit awards | 1 year 11 months | ||||
UGI Stock Option Awards | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ 7.62 | $ 4.87 | $ 5.47 | ||
Amerigas Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Unrecognized compensation cost associated with unvested unit awards | $ 1.7 | ||||
Weighted-average period of recognition for unvested unit awards | 1 year 8 months 24 days | ||||
UGI Unit awards outstanding (in shares) | 218,224 | 210,549 | |||
Fair value of unit awards vested | $ 2.1 | $ 2 | $ 2.6 | ||
Liabilities associated with share based compensation | $ 2.5 | $ 3.5 | |||
AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Expected term of Performance Unit awards | 3 years | ||||
Expected volatility measurement period (in years) | 3 years | ||||
UGI Units awarded (in shares) | 49,225 | ||||
Weighted average grant date fair value unit awards (in dollars per share) | $ 54.24 | ||||
AmeriGas Performance Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 0.00% | ||||
AmeriGas Performance Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
AmeriGas Partners Common Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
UGI Units awarded (in shares) | 18,338 | ||||
Weighted average grant date fair value unit awards (in dollars per share) | $ 47.33 | ||||
UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Unrecognized compensation cost associated with unvested unit awards | $ 8.4 | ||||
Weighted-average period of recognition for unvested unit awards | 1 year 10 months 24 days | ||||
Award performance period | 3 years | ||||
UGI Units awarded (in shares) | 185,379 | 230,653 | 180,724 | ||
Weighted average grant date fair value unit awards (in dollars per share) | $ 50.08 | $ 33.04 | $ 38.20 | ||
UGI Unit awards outstanding (in shares) | 978,834 | 999,083 | |||
Fair value of unit awards vested | $ 7.1 | $ 9.7 | $ 15.3 | ||
Liabilities associated with share based compensation | $ 13.1 | $ 18.5 | |||
UGI Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
UGI Units awarded (in shares) | 42,079 | 52,493 | 39,801 | ||
Weighted average grant date fair value unit awards (in dollars per share) | $ 47.25 | ||||
UGI Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ 50.91 | $ 32.64 | $ 38.43 | ||
Expected term of Performance Unit awards | 3 years | ||||
Expected volatility measurement period (in years) | 3 years | ||||
UGI Units awarded (in shares) | 143,300 | ||||
Weighted average grant date fair value unit awards (in dollars per share) | $ 50.91 | ||||
Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 0.00% | ||||
Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 0.00% | ||||
Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Issued on or after January 1, 2015 | AmeriGas Performance Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Modification range for grants issued in January 2015 | 70.00% | ||||
Issued on or after January 1, 2015 | AmeriGas Performance Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Modification range for grants issued in January 2015 | 130.00% | ||||
Grants Issued in January 2015 | AmeriGas Performance Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 0.00% | ||||
Grants Issued in January 2015 | AmeriGas Performance Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Grants Issued in January 2016 | AmeriGas Performance Units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 0.00% | ||||
Grants Issued in January 2016 | AmeriGas Performance Units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Total Unitholder Return at 25th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 25.00% | ||||
Total Unitholder Return at 25th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 25.00% | ||||
Total Unitholder Return at 40th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 70.00% | ||||
Total Unitholder Return at 40th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 70.00% | ||||
Total Unitholder Return at 40th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 50.00% | ||||
Total Unitholder Return at 50th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 100.00% | ||||
Total Unitholder Return at 50th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 100.00% | ||||
Total Unitholder Return at 50th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 100.00% | ||||
Total Unitholder Return at 100th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Total Unitholder Return at 60th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 125.00% | ||||
Total Unitholder Return at 75th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 162.50% | ||||
Total Unitholder Return at 90th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Total Unitholder Return at 90th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 200.00% | ||||
Total Unitholder Return Highest of Propane MLP Group | Certain Grants Issued on or After January 1, 2014 | AmeriGas Performance Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Percentage of target award to be granted | 150.00% | ||||
2010 Propane Plan | Amerigas Performance Units and Stock Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Expiration period | 10 years | ||||
Common Stock awards granted (in shares) | 2,800,000 | ||||
Award performance period | 3 years | ||||
2010 Propane Plan | AmeriGas Partners Common Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ 52.37 | $ 37.93 | $ 61 | ||
UGI Units awarded (in shares) | 67,563 | 73,080 | 80,336 | ||
Number of common unit awards available for future grant (in shares) | 2,287,879 | ||||
UGI Corporation Common Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Maximum number of shares authorized for repurchase (in shares) | 15,000,000 | ||||
Duration of stock repurchase program | 4 years | ||||
Treasury stock acquired | $ 43.3 | $ 47.6 | $ 34.1 | ||
UGI Corporation Common Stock | 2013 Omnibus Incentive Compensation Plan (OICP) | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Expiration period | 10 years | ||||
Common Stock awards granted (in shares) | 21,750,000 | ||||
Number of common unit awards available for future grant (in shares) | 10,851,819 | ||||
UGI Corporation Common Stock | 2004 Omnibus Equity Compensation Plan (OECP) | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Expiration period | 10 years | ||||
Number of common unit awards available for future grant (in shares) | 4,116 | ||||
UGI Corporation Common Stock | Treasury Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Treasury stock acquired (in shares) | 900,000 | 1,250,000 | 1,000,000 |
Common Stock and Equity-Base103
Common Stock and Equity-Based Compensation - Common Stock Share Activity (Details) - UGI Corporation Common Stock - shares | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Common Stock Share Activity | |||
Beginning balance - shares issued (in shares) | 173,894,141 | 173,806,991 | 173,770,641 |
Beginning balance - shares outstanding (in shares) | 172,960,449 | 172,388,503 | 172,273,781 |
Employee and director plans - shares issued (in shares) | 93,550 | 87,150 | 36,350 |
Employee and director plans - shares outstanding (in shares) | 1,145,254 | 2,442,352 | 1,191,726 |
Sal of reacquired common stock - shares outstanding (in shares) | 50,000 | ||
Repurchases of common stock - shares outstanding (in shares) | (900,000) | (1,250,000) | (1,000,000) |
Reacquired common stock, employee and director plans - shares outstanding (in shares) | (111,966) | (620,406) | (77,004) |
Ending balance - shares issued (in shares) | 173,987,691 | 173,894,141 | 173,806,991 |
Ending balance - shares outstanding (in shares) | 173,143,737 | 172,960,449 | 172,388,503 |
Treasury | |||
Common Stock Share Activity | |||
Beginning balance - shares issued (in shares) | (933,692) | (1,418,488) | (1,496,860) |
Employee and director plans - shares issued (in shares) | 1,051,704 | 2,355,202 | 1,155,376 |
Sale of reacquired common stock - shares held in treasury (in shares) | 50,000 | ||
Repurchases of common stock - held in treasury (in shares) | (900,000) | (1,250,000) | (1,000,000) |
Reacquired common stock, employee and director plans - held in treasury (in shares) | (111,966) | (620,406) | (77,004) |
Ending balance - shares issued (in shares) | (843,954) | (933,692) | (1,418,488) |
Common Stock and Equity-Base104
Common Stock and Equity-Based Compensation - Stock Option Awards (Details) - UGI Stock Option Awards - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Shares | ||||
Shares under option - beginning balance (in shares) | 8,488,451 | 9,255,377 | 8,957,290 | |
Granted (in shares) | 1,343,800 | 1,510,625 | 1,336,985 | |
Canceled (in shares) | (60,236) | (84,213) | (85,365) | |
Exercised (in shares) | (990,267) | (2,193,338) | (953,533) | |
Shares under option - ending balance (in shares) | 8,781,748 | 8,488,451 | 9,255,377 | 8,957,290 |
Weighted Average Option Price | ||||
Shares under option - beginning balance (in dollars per share) | $ 26.68 | $ 23.97 | $ 21.44 | |
Granted (in dollars per share) | 46.51 | 34.67 | 37.70 | |
Canceled (in dollars per share) | 41.86 | 34.13 | 30.45 | |
Exercised (in dollars per share) | 21.40 | 20.38 | 19.10 | |
Shares under option - ending balance (in dollars per share) | $ 30.20 | $ 26.68 | $ 23.97 | $ 21.44 |
Total Intrinsic Value | ||||
Shares under option - beginning balance | $ 157.6 | $ 104.5 | $ 113.3 | |
Exercised | 26.7 | 40.1 | 15.4 | |
Shares under option - beginning balance | $ 146.7 | $ 157.6 | $ 104.5 | $ 113.3 |
Weighted Average Contract Term (Years) | ||||
Weighted average contract term (in years) | 6 years 3 months 18 days | 6 years 7 months | 6 years 7 months 18 days | 7 years |
Options Exercisable | ||||
Options exercisable (in shares) | 5,973,668 | 5,522,370 | 6,050,946 | |
Option exercisable (in dollars per share) | $ 25.53 | $ 22.94 | $ 20.74 | |
Option exercisable | $ 127.4 | |||
Option exercisable (in years) | 5 years 3 months 18 days | |||
Options Not Exercisable | ||||
Options not exercisable (in shares) | 2,808,080 | |||
Options not exercisable (in dollars per share) | $ 40.13 | |||
Options not exercisable | $ 19.3 | |||
Options not exercisable (in years) | 7 years 9 months 18 days |
Common Stock and Equity-Base105
Common Stock and Equity-Based Compensation - Additional Information Relating to Stock Options Outstanding and Exercisable (Details) - UGI Stock Option Awards | 12 Months Ended |
Sep. 30, 2017$ / sharesshares | |
$20.00 | |
Share-based Compensation Arrangement by Share-based Payment Award | |
Range of exercise prices, lower limit (in dollars per share) | $ 0 |
Range of exercise prices, upper limit (in dollars per share) | $ 20 |
Number of options (in shares) | shares | 1,351,925 |
Weighted average remaining contractual life (in years) | 3 years 3 months 18 days |
Weighted average exercise price (in dollars per share) | $ 18.26 |
Number of options (in shares) | shares | 1,351,925 |
Weighted average exercise price (in dollars per share) | $ 18.26 |
$20.00 – $25.00 | |
Share-based Compensation Arrangement by Share-based Payment Award | |
Range of exercise prices, lower limit (in dollars per share) | 20 |
Range of exercise prices, upper limit (in dollars per share) | $ 25 |
Number of options (in shares) | shares | 1,947,779 |
Weighted average remaining contractual life (in years) | 4 years 7 months 6 days |
Weighted average exercise price (in dollars per share) | $ 21.57 |
Number of options (in shares) | shares | 1,947,779 |
Weighted average exercise price (in dollars per share) | $ 21.57 |
$25.01 – $30.00 | |
Share-based Compensation Arrangement by Share-based Payment Award | |
Range of exercise prices, lower limit (in dollars per share) | 25.01 |
Range of exercise prices, upper limit (in dollars per share) | $ 30 |
Number of options (in shares) | shares | 1,462,977 |
Weighted average remaining contractual life (in years) | 6 years 1 month 6 days |
Weighted average exercise price (in dollars per share) | $ 27.43 |
Number of options (in shares) | shares | 1,342,377 |
Weighted average exercise price (in dollars per share) | $ 27.42 |
$30.01 – $35.00 | |
Share-based Compensation Arrangement by Share-based Payment Award | |
Range of exercise prices, lower limit (in dollars per share) | 30.01 |
Range of exercise prices, upper limit (in dollars per share) | $ 35 |
Number of options (in shares) | shares | 1,402,988 |
Weighted average remaining contractual life (in years) | 8 years 1 month 6 days |
Weighted average exercise price (in dollars per share) | $ 33.66 |
Number of options (in shares) | shares | 499,351 |
Weighted average exercise price (in dollars per share) | $ 33.52 |
$35.00 | |
Share-based Compensation Arrangement by Share-based Payment Award | |
Range of exercise prices, lower limit (in dollars per share) | $ 35.01 |
Number of options (in shares) | shares | 2,616,079 |
Weighted average remaining contractual life (in years) | 8 years 3 months 18 days |
Weighted average exercise price (in dollars per share) | $ 42.93 |
Number of options (in shares) | shares | 832,236 |
Weighted average exercise price (in dollars per share) | $ 38.81 |
Common Stock and Equity-Base106
Common Stock and Equity-Based Compensation - Assumptions Used for Valuing Option Grants (Details) - UGI Stock Option Awards | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
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 (as a percent) | 19.80% | 19.50% | 19.50% |
Weighted average dividend yield (as a percent) | 2.10% | 2.60% | 2.50% |
Expected volatility (as a percent) | 19.80% | 19.30% | |
Expected dividend yield (as a percent) | 2.10% | 2.60% | 2.50% |
Minimum | |||
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs | |||
Expected volatility (as a percent) | 19.10% | ||
Risk-free rate | 1.80% | 1.20% | 1.50% |
Maximum | |||
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs | |||
Expected volatility (as a percent) | 19.50% | ||
Risk-free rate | 2.10% | 1.90% | 1.80% |
Common Stock and Equity-Base107
Common Stock and Equity-Based Compensation - Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs (Details) - UGI Performance Units | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award | |||
Risk-free rate | 1.50% | 1.30% | 1.10% |
Expected life | 3 years | 3 years | 3 years |
Expected volatility (as a percent) | 18.90% | 17.50% | 15.90% |
Dividend yield (as a percent) | 2.10% | 2.70% | 2.30% |
Common Stock and Equity-Base108
Common Stock and Equity-Based Compensation - UGI Performance Unit Award Activity (Details) - $ / shares | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
UGI Performance Units and Stock Units | |||
Number of UGI Units | |||
Number of units - beginning balance (in shares) | 999,083 | ||
Granted (in shares) | 185,379 | 230,653 | 180,724 |
Number of units - ending balance (in shares) | 978,834 | 999,083 | |
Weighted Average Grant Date Fair Value (per Unit) | |||
Weighted average grant date fair value - beginning balance (in dollars per share) | $ 25.44 | ||
Granted (in dollars per share) | 50.08 | $ 33.04 | $ 38.20 |
Weighted average grant date fair value - ending balance (in dollars per share) | $ 28.83 | $ 25.44 | |
UGI Performance Units | |||
Number of UGI Units | |||
Granted (in shares) | 143,300 | ||
Forfeited (in shares) | (7,768) | ||
Vested (in shares) | 0 | ||
Awards paid (in shares) | (178,450) | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 50.91 | ||
Forfeited (in dollars per share) | 41.33 | ||
Vested (in dollars per share) | 0 | ||
Awards paid (in dollars per share) | $ 32.47 | ||
UGI Stock Units | |||
Number of UGI Units | |||
Granted (in shares) | 42,079 | 52,493 | 39,801 |
Awards paid (in shares) | (19,410) | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 47.25 | ||
Awards paid (in dollars per share) | $ 18.69 | ||
Shares granted under stock awards (percentage) | 70.00% | ||
Vested | UGI Performance Units and Stock Units | |||
Number of UGI Units | |||
Number of units - beginning balance (in shares) | 672,075 | ||
Number of units - ending balance (in shares) | 660,886 | 672,075 | |
Weighted Average Grant Date Fair Value (per Unit) | |||
Weighted average grant date fair value - beginning balance (in dollars per share) | $ 21.17 | ||
Weighted average grant date fair value - ending balance (in dollars per share) | $ 23.93 | $ 21.17 | |
Vested | UGI Performance Units | |||
Number of UGI Units | |||
Granted (in shares) | 20,283 | ||
Forfeited (in shares) | 0 | ||
Vested (in shares) | 131,409 | ||
Awards paid (in shares) | (178,450) | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 50.94 | ||
Forfeited (in dollars per share) | 0 | ||
Vested (in dollars per share) | 33.67 | ||
Awards paid (in dollars per share) | $ 32.47 | ||
Vested | UGI Stock Units | |||
Number of UGI Units | |||
Granted (in shares) | 34,979 | ||
Awards paid (in shares) | (19,410) | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 46.44 | ||
Awards paid (in dollars per share) | $ 18.69 | ||
Non-Vested | UGI Performance Units and Stock Units | |||
Number of UGI Units | |||
Number of units - beginning balance (in shares) | 327,008 | ||
Number of units - ending balance (in shares) | 317,948 | 327,008 | |
Weighted Average Grant Date Fair Value (per Unit) | |||
Weighted average grant date fair value - beginning balance (in dollars per share) | $ 34.21 | ||
Weighted average grant date fair value - ending balance (in dollars per share) | $ 41.10 | $ 34.21 | |
Non-Vested | UGI Performance Units | |||
Number of UGI Units | |||
Granted (in shares) | 123,017 | ||
Forfeited (in shares) | (7,768) | ||
Vested (in shares) | 131,409 | ||
Awards paid (in shares) | 0 | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 50.90 | ||
Forfeited (in dollars per share) | 41.33 | ||
Vested (in dollars per share) | 33.67 | ||
Awards paid (in dollars per share) | $ 0 | ||
Non-Vested | UGI Stock Units | |||
Number of UGI Units | |||
Granted (in shares) | 7,100 | ||
Awards paid (in shares) | 0 | ||
Weighted Average Grant Date Fair Value (per Unit) | |||
Granted (in dollars per share) | $ 51.23 | ||
Awards paid (in dollars per share) | $ 0 |
Common Stock and Equity-Base109
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 | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
UGI Performance Units | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Number of original awards granted (in shares) | 178,450 | 308,362 | 294,300 |
Fiscal year granted | 2,014 | 2,013 | 2,012 |
Payment of awards: | |||
Shares of UGI Common Stock issued, net of shares withheld for taxes | 138,985 | 209,592 | 188,418 |
Cash paid | $ 10.9 | $ 13.9 | $ 13.3 |
UGI Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Number of original awards granted (in shares) | 43,699 | 51,037 | 67,419 |
Payment of awards: | |||
Shares of UGI Common Stock issued, net of shares withheld for taxes | 15,990 | 39,422 | 44,034 |
Cash paid | $ 0.3 | $ 0.7 | $ 0.8 |
Common Stock and Equity-Base110
Common Stock and Equity-Based Compensation - Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs (Details) - AmeriGas Performance Units | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award | |||
Risk-free rate | 1.50% | 1.30% | 0.90% |
Expected life | 3 years | 3 years | 3 years |
Expected volatility (as a percent) | 21.70% | 20.60% | 19.20% |
Dividend yield (as a percent) | 7.80% | 10.70% | 6.80% |
Common Stock and Equity-Base111
Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Award Activity (Details) | 12 Months Ended |
Sep. 30, 2017$ / sharesshares | |
Amerigas Performance Units and Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Number of units - beginning balance (in shares) | shares | 210,549 |
Number of units - ending balance (in shares) | shares | 218,224 |
Weighted Average Grant Date Fair Value (per Unit) | |
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares | $ 47.24 |
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares | $ 50.03 |
AmeriGas Performance Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 49,225 |
Forfeited (in shares) | shares | (9,151) |
Vested (in shares) | shares | 0 |
Awards paid (in shares) | shares | (44,732) |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 54.24 |
Forfeited (in dollars per share) | $ / shares | 48.76 |
Vested (in dollars per share) | $ / shares | 0 |
Awards paid (in dollars per share) | $ / shares | $ 41.53 |
AmeriGas Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 18,338 |
Vested (in shares) | shares | 0 |
Awards paid (in shares) | shares | (6,005) |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 47.33 |
Vested (in dollars per share) | $ / shares | 0 |
Awards paid (in dollars per share) | $ / shares | $ 43.64 |
Vested | Amerigas Performance Units and Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Number of units - beginning balance (in shares) | shares | 55,622 |
Number of units - ending balance (in shares) | shares | 65,989 |
Weighted Average Grant Date Fair Value (per Unit) | |
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares | $ 45.67 |
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares | $ 47.31 |
Vested | AmeriGas Performance Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 633 |
Forfeited (in shares) | shares | 0 |
Vested (in shares) | shares | 40,933 |
Awards paid (in shares) | shares | (44,732) |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 54.45 |
Forfeited (in dollars per share) | $ / shares | 0 |
Vested (in dollars per share) | $ / shares | 42.55 |
Awards paid (in dollars per share) | $ / shares | $ 41.53 |
Vested | AmeriGas Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 12,738 |
Vested (in shares) | shares | 6,800 |
Awards paid (in shares) | shares | (6,005) |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 48.06 |
Vested (in dollars per share) | $ / shares | 46.13 |
Awards paid (in dollars per share) | $ / shares | $ 43.64 |
Non-Vested | Amerigas Performance Units and Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Number of units - beginning balance (in shares) | shares | 154,927 |
Number of units - ending balance (in shares) | shares | 152,235 |
Weighted Average Grant Date Fair Value (per Unit) | |
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares | $ 47.80 |
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares | $ 51.21 |
Non-Vested | AmeriGas Performance Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 48,592 |
Forfeited (in shares) | shares | (9,151) |
Vested (in shares) | shares | 40,933 |
Awards paid (in shares) | shares | 0 |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 54.24 |
Forfeited (in dollars per share) | $ / shares | 48.76 |
Vested (in dollars per share) | $ / shares | 42.55 |
Awards paid (in dollars per share) | $ / shares | $ 0 |
Non-Vested | AmeriGas Stock Units | |
Number of AmeriGas Partners Common Units Subject to Award | |
Granted (in shares) | shares | 5,600 |
Vested (in shares) | shares | 6,800 |
Awards paid (in shares) | shares | 0 |
Weighted Average Grant Date Fair Value (per Unit) | |
Granted (in dollars per share) | $ / shares | $ 45.66 |
Vested (in dollars per share) | $ / shares | 46.13 |
Awards paid (in dollars per share) | $ / shares | $ 0 |
Common Stock and Equity-Base112
Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Awards in Common Units and Cash (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
AmeriGas Performance Unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Number of Common Units subject to original awards granted (in shares) | 53,800 | 44,800 | 55,750 |
Fiscal year granted | 2,014 | 2,013 | 2,012 |
Payment of awards: | |||
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares) | 29,489 | 23,017 | 0 |
Cash paid | $ 2.9 | $ 1.7 | $ 0 |
AmeriGas Stock Unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Number of Common Units subject to original awards granted (in shares) | 32,658 | 20,336 | 42,532 |
Payment of awards: | |||
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares) | 3,932 | 9,272 | 21,509 |
Cash paid | $ 0.1 | $ 0.4 | $ 0.8 |
Partnership Distributions (Deta
Partnership Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Distribution Made to Limited Partner | |||
Partnership distributions to partners (days following quarter end) | 45 days | ||
Percentage of limited partnership interest (as a percent) | 98.00% | ||
General Partner held a general partner interest (as a percent) | 2.00% | ||
First target distribution (in dollars per share) | $ 0.055 | ||
Threshold for increased distribution to General Partner (in dollars per share) | $ 0.605 | ||
Pre-Incentive distribution of available cash to General Partners | 2.00% | 2.00% | 2.00% |
General Partners distribution based on ownership interest | $ 52.7 | $ 47.4 | $ 39.3 |
Incentive distributions received by the General Partner | $ 43.5 | $ 38.2 | $ 30.4 |
Minimum | |||
Distribution Made to Limited Partner | |||
Quarterly distribution (in dollars per share) | $ 0.55 | ||
Available cash for per common unit (more than) (in dollars per share) | $ 0.605 | $ 0.605 | $ 0.605 |
AmeriGas Partners | |||
Distribution Made to Limited Partner | |||
General Partner held a general partner interest (as a percent) | 1.00% | ||
AmeriGas OLP | |||
Distribution Made to Limited Partner | |||
General Partner held a general partner interest (as a percent) | 1.01% |
Commitments and Contingencies -
Commitments and Contingencies - Minimum Future Payments Under Operating Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Aggregate rental expense for leases | $ 99.5 | $ 102 | $ 86.1 |
Operating Leased Assets [Line Items] | |||
2,018 | 91 | ||
2,019 | 77.8 | ||
2,020 | 69.4 | ||
2,021 | 57.2 | ||
2,022 | 45.2 | ||
After 2,022 | 114.3 | ||
AmeriGas Propane | |||
Operating Leased Assets [Line Items] | |||
2,018 | 70 | ||
2,019 | 61.7 | ||
2,020 | 56.5 | ||
2,021 | 48.9 | ||
2,022 | 40.7 | ||
After 2,022 | 110.3 | ||
UGI Utilities | |||
Operating Leased Assets [Line Items] | |||
2,018 | 7.5 | ||
2,019 | 6 | ||
2,020 | 4.4 | ||
2,021 | 2.7 | ||
2,022 | 0.8 | ||
After 2,022 | 0.2 | ||
UGI International | |||
Operating Leased Assets [Line Items] | |||
2,018 | 11.2 | ||
2,019 | 8.1 | ||
2,020 | 6.6 | ||
2,021 | 4.7 | ||
2,022 | 3.2 | ||
After 2,022 | 3.2 | ||
Other | |||
Operating Leased Assets [Line Items] | |||
2,018 | 2.3 | ||
2,019 | 2 | ||
2,020 | 1.9 | ||
2,021 | 0.9 | ||
2,022 | 0.5 | ||
After 2,022 | $ 0.6 |
Commitments and Contingencie115
Commitments and Contingencies - UGI Standby Commitment to Purchase Class B Common Units (Details) - USD ($) $ in Millions | Nov. 07, 2017 | Jul. 01, 2019 |
Subsequent Event | Capital B Units | ||
Other Commitments [Line Items] | ||
Number of volume days of weighted average price of Partnership's common units | 20 days | |
Basis points on annualized yield | 1.30% | |
Period from initial issuance, holders may elect to convert units | 5 years | |
Conversion ratio | 1 | |
Period from initial issuance, holders may elect to convert subject to certain conditions | 6 years | |
Subsequent Event | Capital B Units | Minimum | ||
Other Commitments [Line Items] | ||
Trading price (as a percent) | 110.00% | |
Forecast | ||
Other Commitments [Line Items] | ||
Amount of capital contribution | $ 225 |
Commitments and Contingencie116
Commitments and Contingencies - Contingencies (Details) $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | |
Mar. 31, 2017USD ($)record_of_decision | Oct. 31, 2014lawsuit | Sep. 30, 2017USD ($)subsidiarylb | Sep. 30, 2016USD ($) | |
Loss Contingencies [Line Items] | ||||
Class action lawsuits (more than) | lawsuit | 35 | |||
Amount of propane in cylinders being sold | lb | 17 | |||
Reduced amount of propane in cylinders being sold | lb | 15 | |||
UGI Utilities | Environmental Issue | ||||
Loss Contingencies [Line Items] | ||||
Environmental expenditures cap during calendar year | $ 2.5 | |||
CPG MPG | Environmental Issue | ||||
Loss Contingencies [Line Items] | ||||
Environmental expenditures cap during calendar year | 1.8 | |||
PNG MPG | Environmental Issue | ||||
Loss Contingencies [Line Items] | ||||
Environmental expenditures cap during calendar year | 1.1 | |||
CPG, PNG and UGI Gas COAs | ||||
Loss Contingencies [Line Items] | ||||
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA | $ 54.3 | $ 55.1 | ||
UGI Utilities | CPG and PNG | ||||
Loss Contingencies [Line Items] | ||||
Number of subsidiaries acquired with similar histories | subsidiary | 2 | |||
AmeriGas OLP | Saranac Lake, New York | New York State Department of Environment Conservation Remediation Plan | ||||
Loss Contingencies [Line Items] | ||||
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA | $ 7.5 | |||
Number of records of decisions drafted | record_of_decision | 3 | |||
Estimated remediation plan cost | $ 27.7 |
Fair Value Measurement - Financ
Fair Value Measurement - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | $ 116.3 | $ 72.7 |
Derivative financial instruments, liabilities | (82.5) | (105.4) |
Recurring Basis | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Non-qualified supplemental postretirement grantor trust investments | 35.6 | 33 |
Recurring Basis | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Non-qualified supplemental postretirement grantor trust investments | 35.6 | 33 |
Recurring Basis | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Non-qualified supplemental postretirement grantor trust investments | 0 | 0 |
Recurring Basis | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Non-qualified supplemental postretirement grantor trust investments | 0 | 0 |
Recurring Basis | Commodity contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 104.1 | 54.9 |
Derivative financial instruments, liabilities | (39.1) | (98.6) |
Recurring Basis | Commodity contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 27.2 | 28.9 |
Derivative financial instruments, liabilities | (27.7) | (76.8) |
Recurring Basis | Commodity contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 76.9 | 26 |
Derivative financial instruments, liabilities | (11.4) | (21.8) |
Recurring Basis | Commodity contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 0 | 0 |
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Foreign currency contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 12.2 | 17.8 |
Derivative financial instruments, liabilities | (38.2) | (2.4) |
Recurring Basis | Foreign currency contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 0 | 0 |
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Foreign currency contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 12.2 | 17.8 |
Derivative financial instruments, liabilities | (38.2) | (2.4) |
Recurring Basis | Foreign currency contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, assets | 0 | 0 |
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Interest rate contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | (2.3) | (3.9) |
Recurring Basis | Interest rate contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Interest rate contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | (2.3) | (3.9) |
Recurring Basis | Interest rate contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Cross-currency swaps | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | (2.9) | (0.5) |
Recurring Basis | Cross-currency swaps | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | 0 | 0 |
Recurring Basis | Cross-currency swaps | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | (2.9) | (0.5) |
Recurring Basis | Cross-currency swaps | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative financial instruments, liabilities | $ 0 | $ 0 |
Fair Value Measurement - Long-t
Fair Value Measurement - Long-term Debt (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Carrying amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | $ 4,211.9 | $ 3,832.3 |
Estimated fair value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | $ 4,346.8 | $ 4,052.3 |
Derivative Instruments and H119
Derivative Instruments and Hedging Activities - Narrative (Details) € in Millions | Mar. 31, 2016USD ($) | Mar. 31, 2016EUR (€) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2017EUR (€) | Sep. 30, 2017USD ($) | Sep. 30, 2016EUR (€) | Sep. 30, 2016USD ($) | Sep. 30, 2015EUR (€) |
Derivative | ||||||||||
Settlement of UGI Utilities interest rate protection agreements | $ 0 | $ (36,000,000) | $ 0 | |||||||
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months | $ 3,500,000 | |||||||||
Amount of net losses associated with currency rate risk to be reclassified into earnings during the next 12 months | 900,000 | |||||||||
Restricted cash in brokerage accounts | 10,300,000 | $ 15,600,000 | ||||||||
Amounts of derivative losses representing ineffectiveness | $ 5,500,000 | |||||||||
Interest Rate Swaps | ||||||||||
Derivative | ||||||||||
Notional amount | € | € 645.8 | € 645.8 | ||||||||
Interest Rate Swaps | Interest Expense | ||||||||||
Derivative | ||||||||||
Loss on interest rate swaps | $ 9,000,000 | |||||||||
IRPA | ||||||||||
Derivative | ||||||||||
Notional amount | 0 | 0 | ||||||||
Foreign Currency Contracts | ||||||||||
Derivative | ||||||||||
Notional amount | 424,800,000 | 314,300,000 | ||||||||
Foreign Currency Contracts | Net Investment Hedging | ||||||||||
Derivative | ||||||||||
Notional amount | $ 0 | $ 0 | ||||||||
UGI France | ||||||||||
Derivative | ||||||||||
Derivative interest rate floor | 0.00% | |||||||||
UGI France | Interest Rate Swaps | ||||||||||
Derivative | ||||||||||
Payment to interest rate swap counterparties | € | € 7.7 | |||||||||
UGI France | Interest Rate Swaps | EURIBOR | ||||||||||
Derivative | ||||||||||
Underlying fixed interest rate (percentage) | 0.18% | |||||||||
UGI France | Interest Rate Swaps | Term Loan | ||||||||||
Derivative | ||||||||||
Notional amount | € | € 600 | € 600 | ||||||||
UGI Utilities | IRPA | ||||||||||
Derivative | ||||||||||
Settlement of UGI Utilities interest rate protection agreements | $ 36,000,000 |
Derivative Instruments and H120
Derivative Instruments and Hedging Activities - Schedule of Notional Amounts (Details) € in Millions, kWh in Millions, gal in Millions, MMBTU in Millions, $ in Millions | Sep. 30, 2017EUR (€)kWhgalMMBTU | Sep. 30, 2017USD ($)kWhgalMMBTU | Sep. 30, 2016EUR (€)kWhgalMMBTU | Sep. 30, 2016USD ($)kWhgalMMBTU |
Commodity contracts | Electricity | Long | ||||
Derivative | ||||
Notional amount (in units) | kWh | 4,440.3 | 4,440.3 | 761.2 | 761.2 |
Commodity contracts | Electricity | Short | ||||
Derivative | ||||
Notional amount (in units) | kWh | 447 | 447 | 264.6 | 264.6 |
Commodity contracts | Propane | ||||
Derivative | ||||
Notional amount (in units) | gal | 325.5 | 325.5 | 396.9 | 396.9 |
Natural gas futures, forward and pipeline contracts | Natural Gas | ||||
Derivative | ||||
Notional amount (in units) | 75.9 | 75.9 | 71.1 | 71.1 |
Natural gas basis swap contracts | Natural Gas | ||||
Derivative | ||||
Notional amount (in units) | 104.2 | 104.2 | 118.3 | 118.3 |
NYMEX natural gas storage | Natural Gas | ||||
Derivative | ||||
Notional amount (in units) | 1.9 | 1.9 | 1.9 | 1.9 |
NYMEX propane storage | Propane | ||||
Derivative | ||||
Notional amount (in units) | gal | 0.3 | 0.3 | 0 | 0 |
Interest rate swaps | ||||
Derivative | ||||
Notional amount | € | € 645.8 | € 645.8 | ||
Forward foreign currency exchange contracts | ||||
Derivative | ||||
Notional amount | $ | $ 424.8 | $ 314.3 | ||
Cross-currency swaps | ||||
Derivative | ||||
Notional amount | $ | $ 59.1 | $ 59.1 | ||
Regulated Utility Operations | Commodity contracts | Natural Gas | ||||
Derivative | ||||
Notional amount (in units) | 14.8 | 14.8 | 18.4 | 18.4 |
Regulated Utility Operations | FTRs contracts | Electricity | ||||
Derivative | ||||
Notional amount (in units) | kWh | 101.2 | 101.2 | 58.3 | 58.3 |
Derivative Instruments and H121
Derivative Instruments and Hedging Activities - Schedule of Derivative Assets, Liabilities and the Effects of Offsetting (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 |
Derivative assets: | ||
Total derivative assets – gross | $ 116.3 | $ 72.7 |
Gross amounts offset in the balance sheet | (35.7) | (35) |
Cash collateral received | (8.3) | (0.3) |
Total derivative assets – net | 72.3 | 37.4 |
Derivative liabilities: | ||
Total derivative liabilities – gross | (82.5) | (105.4) |
Gross amounts offset in the balance sheet | 35.7 | 35 |
Total derivative liabilities – net | (46.8) | (70.4) |
Derivatives designated as hedging instruments | ||
Derivative liabilities: | ||
Total derivative liabilities – gross | (10.7) | (6.8) |
Derivatives designated as hedging instruments | Foreign currency contracts | ||
Derivative assets: | ||
Total derivative assets – gross | 3.2 | 17.8 |
Derivative liabilities: | ||
Total derivative liabilities – gross | (5.5) | (2.4) |
Derivatives designated as hedging instruments | Cross-currency swaps | ||
Derivative liabilities: | ||
Total derivative liabilities – gross | (2.9) | (0.5) |
Derivatives designated as hedging instruments | Interest rate contracts | ||
Derivative liabilities: | ||
Total derivative liabilities – gross | (2.3) | (3.9) |
Derivatives subject to PGC and DS mechanisms | Commodity contracts | ||
Derivative assets: | ||
Total derivative assets – gross | 1.7 | 4.5 |
Derivative liabilities: | ||
Total derivative liabilities – gross | (1.5) | (0.5) |
Derivatives not designated as hedging instruments | ||
Derivative assets: | ||
Total derivative assets – gross | 111.4 | 50.4 |
Derivative liabilities: | ||
Total derivative liabilities – gross | (70.3) | (98.1) |
Derivatives not designated as hedging instruments | Commodity contracts | ||
Derivative assets: | ||
Total derivative assets – gross | 102.4 | 50.4 |
Derivative liabilities: | ||
Total derivative liabilities – gross | (37.6) | (98.1) |
Derivatives not designated as hedging instruments | Foreign currency contracts | ||
Derivative assets: | ||
Total derivative assets – gross | 9 | 0 |
Derivative liabilities: | ||
Total derivative liabilities – gross | $ (32.7) | $ 0 |
Derivative Instruments and H122
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 | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Not Designated as Hedging Instruments | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in Income | $ 140.4 | $ (67.3) | $ (376.3) |
Not Designated as Hedging Instruments | Commodity contracts | Cost of sales | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in Income | 166 | (65) | (375.8) |
Not Designated as Hedging Instruments | Commodity contracts | Revenues | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in Income | (2) | (2.2) | 0.3 |
Not Designated as Hedging Instruments | Commodity contracts | Operating and administrative expenses / other operating income, net | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in Income | 0.2 | (0.1) | (0.8) |
Not Designated as Hedging Instruments | Foreign currency contracts | Losses on foreign currency contracts, net | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in Income | (23.8) | 0 | 0 |
Cash Flow Hedges | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in AOCI | 2.2 | (28.8) | 24.8 |
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | 13.8 | 13.1 | (4.4) |
Cash Flow Hedges | Commodity contracts | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in AOCI | 0 | 0 | 0 |
Cash Flow Hedges | Commodity contracts | Cost of sales | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | 0 | 0 | (2.2) |
Cash Flow Hedges | Foreign currency contracts | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in AOCI | 0.2 | 3.6 | 26 |
Cash Flow Hedges | Foreign currency contracts | Cost of sales | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | 17.8 | 17.2 | 9.7 |
Cash Flow Hedges | Cross-currency swaps | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in AOCI | 0.5 | 0.1 | 5.4 |
Cash Flow Hedges | Cross-currency swaps | Interest expense /other operating income, net | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | (0.1) | 0.4 | 8.5 |
Cash Flow Hedges | Interest rate contracts | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Recognized in AOCI | 1.5 | (32.5) | (6.6) |
Cash Flow Hedges | Interest rate contracts | Interest expense | |||
Derivative Instruments, Gain (Loss) | |||
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | $ (3.9) | $ (4.5) | $ (20.4) |
Accumulated Other Comprehens123
Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
AOCI Including Portion Attributable to NCI [Roll Forward]: | |||
Balance, beginning of year | $ 3,595 | $ 3,565.6 | |
Other comprehensive (loss) income before reclassification adjustments (after-tax) | 67.6 | (34.2) | $ (98.5) |
Amounts reclassified from AOCI and noncontrolling interests: | |||
Reclassification adjustments (pre-tax) | (8.3) | (10.5) | 6.6 |
Reclassification adjustments tax (benefit) expense | 2 | 4.6 | (3.6) |
Reclassification adjustments (after-tax) | 6.3 | 5.9 | (3) |
Other comprehensive income (loss) | 61.3 | (40.1) | (95.5) |
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | 2.1 | ||
Other comprehensive loss attributable to UGI | 61.3 | (40.1) | (93.4) |
Balance, end of year | 3,740.9 | 3,595 | 3,565.6 |
Postretirement Benefit Plans | |||
AOCI Including Portion Attributable to NCI [Roll Forward]: | |||
Balance, beginning of year | (29.1) | (20.4) | (20.6) |
Other comprehensive (loss) income before reclassification adjustments (after-tax) | 6.5 | (10.9) | (1.2) |
Amounts reclassified from AOCI and noncontrolling interests: | |||
Reclassification adjustments (pre-tax) | 5.5 | 2.6 | 2.2 |
Reclassification adjustments tax (benefit) expense | (2.1) | (0.4) | (0.8) |
Reclassification adjustments (after-tax) | (3.4) | (2.2) | (1.4) |
Other comprehensive income (loss) | 0.2 | ||
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | 0 | ||
Other comprehensive loss attributable to UGI | 9.9 | (8.7) | 0.2 |
Balance, end of year | (19.2) | (29.1) | (20.4) |
Derivative Instruments | |||
AOCI Including Portion Attributable to NCI [Roll Forward]: | |||
Balance, beginning of year | (13.4) | 11.2 | (9.3) |
Other comprehensive (loss) income before reclassification adjustments (after-tax) | 1.7 | (16.5) | 16.8 |
Amounts reclassified from AOCI and noncontrolling interests: | |||
Reclassification adjustments (pre-tax) | (13.8) | (13.1) | 4.4 |
Reclassification adjustments tax (benefit) expense | 4.1 | 5 | (2.8) |
Reclassification adjustments (after-tax) | 9.7 | 8.1 | (1.6) |
Other comprehensive income (loss) | 18.4 | ||
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | 2.1 | ||
Other comprehensive loss attributable to UGI | (8) | (24.6) | 20.5 |
Balance, end of year | (21.4) | (13.4) | 11.2 |
Foreign Currency | |||
AOCI Including Portion Attributable to NCI [Roll Forward]: | |||
Balance, beginning of year | (112.2) | (105.4) | 8.7 |
Other comprehensive (loss) income before reclassification adjustments (after-tax) | 59.4 | (6.8) | (114.1) |
Amounts reclassified from AOCI and noncontrolling interests: | |||
Reclassification adjustments (pre-tax) | 0 | 0 | 0 |
Reclassification adjustments tax (benefit) expense | 0 | 0 | 0 |
Reclassification adjustments (after-tax) | 0 | 0 | 0 |
Other comprehensive income (loss) | (114.1) | ||
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | 0 | ||
Other comprehensive loss attributable to UGI | 59.4 | (6.8) | (114.1) |
Balance, end of year | (52.8) | (112.2) | (105.4) |
Accumulated Other Comprehensive Income (Loss) | |||
AOCI Including Portion Attributable to NCI [Roll Forward]: | |||
Balance, beginning of year | (154.7) | (114.6) | (21.2) |
Amounts reclassified from AOCI and noncontrolling interests: | |||
Balance, end of year | $ (93.4) | $ (154.7) | $ (114.6) |
Other Operating Income, Net (De
Other Operating Income, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Component of Operating Income [Abstract] | |||
Finance charges | $ 11.8 | $ 15.2 | $ 12.7 |
AFUDC associated with pipeline projects | 5.5 | 3.3 | 0 |
Interest and interest-related income | 1.7 | 0.2 | 0.8 |
Utility non-tariff service income | 1.5 | 2.6 | 4.8 |
Loss on private equity partnership investment | (11) | 0 | 0 |
(Losses) gains on sales of fixed assets, net | (3.9) | 3.3 | 11.1 |
Other, net | 4.9 | (2.2) | 15 |
Total other operating income, net | $ 10.5 | $ 22.4 | $ 44.4 |
Quarterly Data (unaudited) (Det
Quarterly Data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 1,113.9 | $ 1,153.5 | $ 2,173.8 | $ 1,679.5 | $ 976.2 | $ 1,130.8 | $ 1,972.1 | $ 1,606.6 | $ 6,120.7 | $ 5,685.7 | $ 6,691.1 |
Operating income (loss) | 27.6 | (2.8) | 513.2 | 466.2 | (88.6) | 155.7 | 615.4 | 305.5 | 1,004.2 | 988 | 834.9 |
(Loss) income from equity investees | 1.3 | 0.9 | 2.3 | (0.2) | (0.1) | 0 | 0 | (0.1) | 4.3 | (0.2) | (1.2) |
Loss on extinguishments of debt | 0 | (4.4) | (22.1) | (33.2) | (11.8) | (37.1) | 0 | 0 | (59.7) | (48.9) | 0 |
Net income (loss) including noncontrolling interests | (16.7) | (62.2) | 311.8 | 290.9 | (115.7) | 28.6 | 408 | 167.9 | 523.8 | 488.8 | 414 |
Net income (loss) attributable to UGI Corporation | $ 5 | $ (19) | $ 219.9 | $ 230.7 | $ (43.8) | $ 60.7 | $ 233.2 | $ 114.6 | $ 436.6 | $ 364.7 | $ 281 |
Earnings (loss) per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.27 | $ 1.33 | $ (0.25) | $ 0.35 | $ 1.35 | $ 0.66 | $ 2.51 | $ 2.11 | $ 1.62 |
Diluted (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.24 | $ 1.30 | $ (0.25) | $ 0.34 | $ 1.33 | $ 0.65 | $ 2.46 | $ 2.08 | $ 1.60 |
Effect of Fourth Quarter Events [Line Items] | |||||||||||
Increase in net income attributable to UGI Corporation, income tax settlement refund | $ 6.7 | ||||||||||
Increase in net income attributable to UGI Corporation, income tax settlement refund (in dollars per share) | $ 0.04 | ||||||||||
Increase in net income attributable to UGI Corporation due to release of valuation allowance against future uses of foreign tax credit carryforwards | $ 7.6 | $ (7.2) | |||||||||
Increase in net income per diluted share due to release of valuation allowance against future uses of foreign tax credit carryforwards (in dollars per share) | $ 0.04 | ||||||||||
Increase (decrease) in net income (loss) attributable to UGI Corporation, loss on extinguishments of debt | $ (0.7) | $ (3.6) | $ (5.3) | $ (1.8) | $ (6.1) | ||||||
Increase (decrease) in net income (loss) attributable to UGI Corporation, loss on extinguishments of debt (in dollars per share) | $ (0.01) | $ (0.02) | $ (0.03) | $ (0.01) | $ (0.03) | ||||||
Decrease in net income attributable to UGI Corporation, impairment of cost basis investment | $ 2.6 | $ 4.5 | |||||||||
Decrease in net income attributable to UGI Corporation, impairment of cost basis investment (in dollars per share) | $ 0.02 | $ 0.03 | |||||||||
UGI France | |||||||||||
Effect of Fourth Quarter Events [Line Items] | |||||||||||
Increase in net income attributable to UGI Corporation, adjustments to net deferred income tax liabilities | $ 27.4 | ||||||||||
Increase in net income attributable to UGI Corporation, adjustments to net deferred income tax liabilities (in dollars per share) | $ 0.15 |
Segment Information - Narrative
Segment Information - Narrative (Details) | 12 Months Ended |
Sep. 30, 2017countystatesegment | |
Segment Reporting [Abstract] | |
Number of reportable segments | segment | 4 |
Number of states to which product sale with propane revenue | state | 50 |
Segment Reporting Information | |
Number of counties | 1 |
UGI Utilities | |
Segment Reporting Information | |
Number of counties | 2 |
Segment Information - Schedule
Segment Information - Schedule of Segment Reporting (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Segment Reporting Information | |||||||||||
Revenues | $ 1,113.9 | $ 1,153.5 | $ 2,173.8 | $ 1,679.5 | $ 976.2 | $ 1,130.8 | $ 1,972.1 | $ 1,606.6 | $ 6,120.7 | $ 5,685.7 | $ 6,691.1 |
Cost of sales | 2,837.3 | 2,437.5 | 3,736.5 | ||||||||
Operating income | 27.6 | (2.8) | 513.2 | 466.2 | (88.6) | 155.7 | 615.4 | 305.5 | 1,004.2 | 988 | 834.9 |
Income (loss) from equity investees | 1.3 | 0.9 | 2.3 | (0.2) | (0.1) | 0 | 0 | (0.1) | 4.3 | (0.2) | (1.2) |
Losses on foreign currency contracts, net | (23.9) | 0 | 0 | ||||||||
Loss on extinguishments of debt | 0 | (4.4) | (22.1) | (33.2) | (11.8) | (37.1) | 0 | 0 | (59.7) | (48.9) | 0 |
Interest expense | (223.5) | (228.9) | (241.9) | ||||||||
Income before income taxes | 701.4 | 710 | 591.8 | ||||||||
Net income (loss) attributable to UGI | 5 | $ (19) | $ 219.9 | $ 230.7 | (43.8) | $ 60.7 | $ 233.2 | $ 114.6 | 436.6 | 364.7 | 281 |
Depreciation and amortization | 416.3 | 400.9 | 374.1 | ||||||||
Noncontrolling interests’ net income (loss) | 87.2 | 124.1 | 133 | ||||||||
Total assets | 11,582.2 | 10,847.2 | 11,582.2 | 10,847.2 | 10,514.2 | ||||||
Short-term borrowings | 366.9 | 291.7 | 366.9 | 291.7 | 189.9 | ||||||
Capital expenditures (including the effects of accruals) | 624.3 | 604.6 | 475.4 | ||||||||
Investments in equity investees | 59.1 | 25.9 | 59.1 | 25.9 | 16.2 | ||||||
Goodwill | 3,107.2 | 2,989 | 3,107.2 | 2,989 | 2,953.4 | ||||||
AmeriGas Propane | |||||||||||
Segment Reporting Information | |||||||||||
Goodwill | 2,001.3 | 1,978.3 | 2,001.3 | 1,978.3 | 1,956 | ||||||
UGI International | |||||||||||
Segment Reporting Information | |||||||||||
Goodwill | 912.2 | 817 | 912.2 | 817 | 803.7 | ||||||
Midstream & Marketing | |||||||||||
Segment Reporting Information | |||||||||||
Goodwill | 11.6 | 11.6 | 11.6 | 11.6 | 11.6 | ||||||
Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | (222.7) | (133.9) | (213.6) | ||||||||
Cost of sales | (218.3) | (131.5) | (209.8) | ||||||||
Operating income | 0.3 | 0.2 | (0.9) | ||||||||
Income (loss) from equity investees | 0 | 0 | 0 | ||||||||
Losses on foreign currency contracts, net | 0 | ||||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Income before income taxes | 0.3 | 0.2 | (0.9) | ||||||||
Net income (loss) attributable to UGI | 0.1 | 0.1 | (0.6) | ||||||||
Depreciation and amortization | (0.2) | (0.2) | 0 | ||||||||
Noncontrolling interests’ net income (loss) | 0 | 0 | 0 | ||||||||
Total assets | (51.5) | (136.6) | (51.5) | (136.6) | (90.4) | ||||||
Short-term borrowings | 0 | 0 | 0 | 0 | 0 | ||||||
Capital expenditures (including the effects of accruals) | 0 | 0 | 0 | ||||||||
Investments in equity investees | 0 | 0 | 0 | 0 | 0 | ||||||
Goodwill | 0 | 0 | 0 | 0 | 0 | ||||||
Eliminations | AmeriGas Propane | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Eliminations | UGI International | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Eliminations | Midstream & Marketing | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 178.2 | 114.3 | 151.3 | ||||||||
Eliminations | UGI Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 40.1 | 17.1 | 59.7 | ||||||||
Operating Segments | AmeriGas Propane | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 2,453.5 | 2,311.8 | 2,885.3 | ||||||||
Cost of sales | 1,002.9 | 864.8 | 1,340 | ||||||||
Operating income | 355.3 | 356.3 | 427.6 | ||||||||
Income (loss) from equity investees | 0 | 0 | 0 | ||||||||
Losses on foreign currency contracts, net | 0 | ||||||||||
Loss on extinguishments of debt | (59.7) | (48.9) | 0 | ||||||||
Interest expense | (160.2) | (164.1) | (162.8) | ||||||||
Income before income taxes | 135.4 | 143.3 | 264.8 | ||||||||
Net income (loss) attributable to UGI | 44.6 | 43.2 | 61 | ||||||||
Depreciation and amortization | 190.5 | 190 | 194.9 | ||||||||
Noncontrolling interests’ net income (loss) | 64.4 | 75.9 | 167.9 | ||||||||
Partnership Adjusted EBITDA | 551.3 | 543 | 619.2 | ||||||||
Total assets | 4,069.4 | 4,071.8 | 4,069.4 | 4,071.8 | 4,128.4 | ||||||
Short-term borrowings | 140 | 153.2 | 140 | 153.2 | 68.1 | ||||||
Capital expenditures (including the effects of accruals) | 98.1 | 101.7 | 102 | ||||||||
Investments in equity investees | 0 | 0 | 0 | 0 | 0 | ||||||
Goodwill | 2,001.3 | 1,978.3 | 2,001.3 | 1,978.3 | 1,956 | ||||||
Operating Segments | UGI International | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 1,877.5 | 1,868.8 | 1,808.5 | ||||||||
Cost of sales | 935.3 | 903.8 | 1,120 | ||||||||
Operating income | 195.7 | 206.6 | 112.8 | ||||||||
Income (loss) from equity investees | 0 | (0.2) | (1.2) | ||||||||
Losses on foreign currency contracts, net | (0.1) | ||||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Interest expense | (20.6) | (24.4) | (35.2) | ||||||||
Income before income taxes | 175 | 182 | 76.4 | ||||||||
Net income (loss) attributable to UGI | 158.6 | 111.6 | 52.7 | ||||||||
Depreciation and amortization | 117.4 | 112.4 | 86.9 | ||||||||
Noncontrolling interests’ net income (loss) | 0.2 | 0 | (0.1) | ||||||||
Total assets | 3,132 | 2,865.1 | 3,132 | 2,865.1 | 2,860.9 | ||||||
Short-term borrowings | 17.9 | 0.5 | 17.9 | 0.5 | 0.6 | ||||||
Capital expenditures (including the effects of accruals) | 90.3 | 99.9 | 87.5 | ||||||||
Investments in equity investees | 8.1 | 8.5 | 8.1 | 8.5 | 9.8 | ||||||
Goodwill | 912.2 | 817 | 912.2 | 817 | 803.7 | ||||||
Operating Segments | Midstream & Marketing | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 943 | 752.3 | 1,012.3 | ||||||||
Cost of sales | 856.7 | 602.2 | 854.6 | ||||||||
Operating income | 139.2 | 146.7 | 182.6 | ||||||||
Income (loss) from equity investees | 4.3 | 0 | 0 | ||||||||
Losses on foreign currency contracts, net | 0 | ||||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Interest expense | (2.1) | (2.1) | (2.1) | ||||||||
Income before income taxes | 141.4 | 144.6 | 180.5 | ||||||||
Net income (loss) attributable to UGI | 86.9 | 87.1 | 107.5 | ||||||||
Depreciation and amortization | 35.4 | 30.6 | 28 | ||||||||
Noncontrolling interests’ net income (loss) | 0 | 0 | 0 | ||||||||
Total assets | 1,165.5 | 1,038.2 | 1,165.5 | 1,038.2 | 969.6 | ||||||
Short-term borrowings | 39 | 25.5 | 39 | 25.5 | 49.5 | ||||||
Capital expenditures (including the effects of accruals) | 117.5 | 140.4 | 88 | ||||||||
Investments in equity investees | 51 | 17.4 | 51 | 17.4 | 6.4 | ||||||
Goodwill | 11.6 | 11.6 | 11.6 | 11.6 | 11.6 | ||||||
Operating Segments | UGI Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | 847.5 | 751.4 | 981.9 | ||||||||
Cost of sales | 367.3 | 289.8 | 510.8 | ||||||||
Operating income | 228.3 | 200.9 | 241.7 | ||||||||
Income (loss) from equity investees | 0 | 0 | 0 | ||||||||
Losses on foreign currency contracts, net | 0 | ||||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Interest expense | (40.2) | (37.6) | (41.1) | ||||||||
Income before income taxes | 188.1 | 163.3 | 200.6 | ||||||||
Net income (loss) attributable to UGI | 116 | 97.4 | 121.1 | ||||||||
Depreciation and amortization | 72.3 | 67.3 | 63.5 | ||||||||
Noncontrolling interests’ net income (loss) | 0 | 0 | 0 | ||||||||
Total assets | 2,994 | 2,743.1 | 2,994 | 2,743.1 | 2,506 | ||||||
Short-term borrowings | 170 | 112.5 | 170 | 112.5 | 71.7 | ||||||
Capital expenditures (including the effects of accruals) | 317.7 | 262.5 | 197.7 | ||||||||
Investments in equity investees | 0 | 0 | 0 | 0 | 0 | ||||||
Goodwill | 182.1 | 182.1 | 182.1 | 182.1 | 182.1 | ||||||
Corporate & Other | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | (0.8) | 1.4 | 3.1 | ||||||||
Cost of sales | (106.6) | (91.6) | 120.9 | ||||||||
Operating income | 85.4 | 77.3 | (128.9) | ||||||||
Income (loss) from equity investees | 0 | 0 | 0 | ||||||||
Losses on foreign currency contracts, net | (23.8) | ||||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Interest expense | (0.4) | (0.7) | (0.7) | ||||||||
Income before income taxes | 61.2 | 76.6 | (129.6) | ||||||||
Net income (loss) attributable to UGI | 30.4 | 25.3 | (60.7) | ||||||||
Depreciation and amortization | 0.9 | 0.8 | 0.8 | ||||||||
Noncontrolling interests’ net income (loss) | 22.6 | 48.2 | (34.8) | ||||||||
Total assets | 272.8 | 265.6 | 272.8 | 265.6 | 139.7 | ||||||
Short-term borrowings | 0 | 0 | 0 | 0 | 0 | ||||||
Capital expenditures (including the effects of accruals) | 0.7 | 0.1 | 0.2 | ||||||||
Investments in equity investees | 0 | 0 | 0 | 0 | 0 | ||||||
Goodwill | $ 0 | $ 0 | 0 | 0 | 0 | ||||||
Corporate, Intersegment Eliminations & Other | |||||||||||
Segment Reporting Information | |||||||||||
Revenues | $ 4.4 | $ 2.5 | $ 2.6 |
Segment Information - Reconcili
Segment Information - Reconciliation of Partnership EBITDA to AmeriGas Propane Operating Income and Footnotes (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Reconciliation of partnership EBITDA | |||||||||||
Depreciation and amortization | $ (416,300,000) | $ (400,900,000) | $ (374,100,000) | ||||||||
Interest expense | (223,500,000) | (228,900,000) | (241,900,000) | ||||||||
Loss on extinguishments of debt | $ 0 | $ (4,400,000) | $ (22,100,000) | $ (33,200,000) | $ (11,800,000) | $ (37,100,000) | $ 0 | $ 0 | (59,700,000) | (48,900,000) | 0 |
Income before income taxes | $ 701,400,000 | $ 710,000,000 | $ 591,800,000 | ||||||||
General Partner interest in AmeriGas OLP (percentage) | 1.01% | 1.01% | 1.01% | ||||||||
Pretax gains (losses) on unsettled commodity derivative instruments | $ 82,000,000 | $ 91,600,000 | $ (119,100,000) | ||||||||
Other-than-temporary impairment of an investment in a private equity partnership pre-tax loss | 11,000,000 | 0 | 0 | ||||||||
UGI International | Term Loan | |||||||||||
Reconciliation of partnership EBITDA | |||||||||||
Pretax loss on early extinguishment of debt | 10,300,000 | ||||||||||
Operating Segments | AmeriGas Propane | |||||||||||
Reconciliation of partnership EBITDA | |||||||||||
Partnership Adjusted EBITDA | 551,300,000 | 543,000,000 | 619,200,000 | ||||||||
Depreciation and amortization | (190,500,000) | (190,000,000) | (194,900,000) | ||||||||
Interest expense | (160,200,000) | (164,100,000) | (162,800,000) | ||||||||
Loss on extinguishments of debt | (59,700,000) | (48,900,000) | 0 | ||||||||
MGP environmental accrual | (7,500,000) | 0 | 0 | ||||||||
Noncontrolling interests | 2,000,000 | 3,300,000 | 3,300,000 | ||||||||
Income before income taxes | 135,400,000 | 143,300,000 | 264,800,000 | ||||||||
Operating Segments | UGI International | |||||||||||
Reconciliation of partnership EBITDA | |||||||||||
Depreciation and amortization | (117,400,000) | (112,400,000) | (86,900,000) | ||||||||
Interest expense | (20,600,000) | (24,400,000) | (35,200,000) | ||||||||
Loss on extinguishments of debt | 0 | 0 | |||||||||
Income before income taxes | $ 175,000,000 | $ 182,000,000 | $ 76,400,000 |
Condensed Financial Informat129
Condensed Financial Information of Registrant (Parent Company) - Balance Sheets (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 |
Current assets | ||||
Cash and cash equivalents | $ 558.4 | $ 502.8 | $ 369.7 | $ 419.5 |
Total current assets | 1,697.5 | 1,423.8 | ||
Property, plant and equipment, net | 5,537 | 5,238 | ||
Other assets | 259 | 217.7 | ||
Total assets | 11,582.2 | 10,847.2 | 10,514.2 | |
Current liabilities | ||||
Total current liabilities | 1,690.1 | 1,442 | ||
Commitments and contingencies | ||||
Common stockholders’ equity: | ||||
Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) | 1,188.6 | 1,201.6 | ||
Retained earnings | 2,106.7 | 1,834.1 | ||
Accumulated other comprehensive loss | (93.4) | (154.7) | ||
Treasury stock, at cost | (38.6) | (36.9) | ||
Total UGI Corporation stockholders’ equity | 3,163.3 | 2,844.1 | ||
Total liabilities and equity | $ 11,582.2 | $ 10,847.2 | ||
Condensed Financial Information of Registrant [Abstract] | ||||
Common stock, shares authorized | 450,000,000 | 450,000,000 | ||
Common stock, shares issued | 173,987,691 | 173,894,141 | ||
Parent Company | ||||
Current assets | ||||
Cash and cash equivalents | $ 15.8 | $ 4.8 | $ 1.9 | $ 0.8 |
Accounts receivable – related parties | 4.5 | 9.2 | ||
Prepaid expenses and other current assets | 15.6 | 5 | ||
Total current assets | 35.9 | 19 | ||
Property, plant and equipment, net | 0.4 | 0 | ||
Investments in subsidiaries | 3,119.7 | 2,825.7 | ||
Other assets | 82 | 69.8 | ||
Total assets | 3,238 | 2,914.5 | ||
Current liabilities | ||||
Accounts and notes payable | 12.3 | 11.4 | ||
Accrued liabilities | 5.9 | 4.4 | ||
Total current liabilities | 18.2 | 15.8 | ||
Noncurrent liabilities | 56.5 | 54.6 | ||
Commitments and contingencies | ||||
Common stockholders’ equity: | ||||
Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) | 1,188.6 | 1,201.6 | ||
Retained earnings | 2,106.7 | 1,834.1 | ||
Accumulated other comprehensive loss | (93.4) | (154.7) | ||
Treasury stock, at cost | (38.6) | (36.9) | ||
Total UGI Corporation stockholders’ equity | 3,163.3 | 2,844.1 | ||
Total liabilities and equity | $ 3,238 | $ 2,914.5 | ||
Condensed Financial Information of Registrant [Abstract] | ||||
Common stock, shares authorized | 450,000,000 | 450,000,000 | ||
Common stock, shares issued | 173,987,691 | 173,894,141 |
Condensed Financial Informat130
Condensed Financial Information of Registrant (Parent Company) - Narrative (Details) | 12 Months Ended |
Sep. 30, 2017USD ($) | |
Flaga | |
Guarantee Obligations | |
Amount of floating to fixed rate interest rate swaps at Flaga | $ 600,000 |
Parent Company | |
Guarantee Obligations | |
Surety bonds indemnified | 88,900,000 |
Maximum amount authorized to guarantee obligations to suppliers and customers | 500,000,000 |
Current carrying value | $ 432,500,000 |
Condensed Financial Informat131
Condensed Financial Information of Registrant (Parent Company) - Statements of Income (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Condensed Financial Statements, Captions | |||||||||||
Revenues | $ 1,113.9 | $ 1,153.5 | $ 2,173.8 | $ 1,679.5 | $ 976.2 | $ 1,130.8 | $ 1,972.1 | $ 1,606.6 | $ 6,120.7 | $ 5,685.7 | $ 6,691.1 |
Costs and Expenses | |||||||||||
Operating and administrative expenses | 1,857.8 | 1,865.9 | 1,773.9 | ||||||||
Other operating income, net | (10.5) | (22.4) | (44.4) | ||||||||
Total costs and expenses | 5,116.5 | 4,697.7 | 5,856.2 | ||||||||
Operating income | 27.6 | (2.8) | 513.2 | 466.2 | (88.6) | 155.7 | 615.4 | 305.5 | 1,004.2 | 988 | 834.9 |
Income tax (benefit) expense | 177.6 | 221.2 | 177.8 | ||||||||
Equity in income of unconsolidated subsidiaries | 1.3 | 0.9 | 2.3 | (0.2) | (0.1) | 0 | 0 | (0.1) | 4.3 | (0.2) | (1.2) |
Net income attributable to UGI Corporation | $ 5 | $ (19) | $ 219.9 | $ 230.7 | $ (43.8) | $ 60.7 | $ 233.2 | $ 114.6 | 436.6 | 364.7 | 281 |
Comprehensive income attributable to UGI Corporation | $ 497.9 | $ 324.6 | $ 187.6 | ||||||||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.27 | $ 1.33 | $ (0.25) | $ 0.35 | $ 1.35 | $ 0.66 | $ 2.51 | $ 2.11 | $ 1.62 |
Diluted (in dollars per share) | $ 0.03 | $ (0.11) | $ 1.24 | $ 1.30 | $ (0.25) | $ 0.34 | $ 1.33 | $ 0.65 | $ 2.46 | $ 2.08 | $ 1.60 |
Weighted - average common shares outstanding (thousands): | |||||||||||
Basic (in shares) | 173,662 | 173,154 | 173,115 | ||||||||
Diluted (in shares) | 177,159 | 175,572 | 175,667 | ||||||||
Parent Company | |||||||||||
Condensed Financial Statements, Captions | |||||||||||
Revenues | $ 0 | $ 0 | $ 0 | ||||||||
Costs and Expenses | |||||||||||
Operating and administrative expenses | 46.3 | 45.7 | 48.7 | ||||||||
Other operating income, net | (45.9) | (45.3) | (48.5) | ||||||||
Total costs and expenses | 0.4 | 0.4 | 0.2 | ||||||||
Operating income | (0.4) | (0.4) | (0.2) | ||||||||
Intercompany interest income | 0 | 0.1 | 0.1 | ||||||||
Loss before income taxes | (0.4) | (0.3) | (0.1) | ||||||||
Income tax (benefit) expense | (5.7) | (4) | 1.9 | ||||||||
Income (loss) before equity in income of unconsolidated subsidiaries | 5.3 | 3.7 | (2) | ||||||||
Equity in income of unconsolidated subsidiaries | 431.3 | 361 | 283 | ||||||||
Net income attributable to UGI Corporation | 436.6 | 364.7 | 281 | ||||||||
Other comprehensive income (loss) | 1.3 | (1.1) | 0.1 | ||||||||
Equity in other comprehensive income (loss) of unconsolidated subsidiaries | 60 | (39) | (93.5) | ||||||||
Comprehensive income attributable to UGI Corporation | $ 497.9 | $ 324.6 | $ 187.6 | ||||||||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic (in dollars per share) | $ 2.51 | $ 2.11 | $ 1.62 | ||||||||
Diluted (in dollars per share) | $ 2.46 | $ 2.08 | $ 1.60 | ||||||||
Weighted - average common shares outstanding (thousands): | |||||||||||
Basic (in shares) | 173,662 | 173,154 | 173,115 | ||||||||
Diluted (in shares) | 177,159 | 175,572 | 175,667 |
Condensed Financial Informat132
Condensed Financial Information of Registrant (Parent Company) - Statements of Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Condensed Financial Statements, Captions | |||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ 964.4 | $ 969.7 | $ 1,163.8 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Expenditures for property, plant and equipment | (638.9) | (563.8) | (490.6) |
Net cash used by investing activities | (763.4) | (558.6) | (976.3) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Payment of dividends on Common Stock | (168.9) | (160.7) | (153.5) |
Repurchases of UGI Common Stock | (43.3) | (47.6) | (34.1) |
Issuances of Common Stock | 11 | 13.7 | 11.9 |
Other | (0.8) | 15.5 | (3.5) |
Net cash used by financing activities | (146.6) | (275.1) | (217.1) |
Cash and cash equivalents increase (decrease) | 55.6 | 133.1 | (49.8) |
Cash and cash equivalents: | |||
End of year | 558.4 | 502.8 | 369.7 |
Beginning of year | 502.8 | 369.7 | 419.5 |
Increase (decrease) | 55.6 | 133.1 | (49.8) |
Parent Company | |||
Condensed Financial Statements, Captions | |||
NET CASH PROVIDED BY OPERATING ACTIVITIES | 253.2 | 195.6 | 277.2 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Expenditures for property, plant and equipment | (0.4) | 0 | 0 |
Net investments in unconsolidated subsidiaries | (40.7) | (8.9) | (104.8) |
Net cash used by investing activities | (41.1) | (8.9) | (104.8) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Payment of dividends on Common Stock | (168.9) | (160.7) | (153.5) |
Repurchases of UGI Common Stock | (43.3) | (47.6) | (34.1) |
Issuances of Common Stock | 11 | 24.5 | 16.8 |
Other | 0.1 | 0 | (0.5) |
Net cash used by financing activities | (201.1) | (183.8) | (171.3) |
Cash and cash equivalents increase (decrease) | 11 | 2.9 | 1.1 |
Cash and cash equivalents: | |||
End of year | 15.8 | 4.8 | 1.9 |
Beginning of year | 4.8 | 1.9 | 0.8 |
Increase (decrease) | 11 | 2.9 | 1.1 |
Dividends from unconsolidated subsidiaries | $ 241.9 | $ 193.1 | $ 271.6 |
Valuation and Qualifying Acc133
Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2015 | |
Allowance for doubtful accounts | |||
Valuation and Qualifying Account | |||
Balance at beginning of year | $ 27.3 | $ 29.7 | $ 39.1 |
Charged (credited) to costs and expenses | 30.7 | 21.7 | 31.6 |
Balance at end of year | 26.9 | 27.3 | 29.7 |
Uncollectible accounts written off, net of recoveries | |||
Valuation and Qualifying Account | |||
Other | (31.1) | (24.1) | (39.6) |
Effects of currency exchange | |||
Valuation and Qualifying Account | |||
Other | (1.4) | ||
Deferred tax assets valuation allowance | |||
Valuation and Qualifying Account | |||
Balance at beginning of year | 114.3 | 131.3 | 59.2 |
Charged (credited) to costs and expenses | (7.6) | (5.8) | 5.1 |
Balance at end of year | 107.1 | 114.3 | 131.3 |
Foreign tax credit valuation allowance adjustment | |||
Valuation and Qualifying Account | |||
Other | $ 0.4 | (8.8) | 66.1 |
Decrease in unusable foreign operating loss carryforwards | |||
Valuation and Qualifying Account | |||
Other | $ (2.4) | (2.6) | |
Acquisitions | |||
Valuation and Qualifying Account | |||
Other | $ 3.5 |