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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

☑ | ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2019

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________
Commission file number 1-11071
UGI CORP ORATION
(Exact name of registrant as specified in its charter)

Pennsylvania |  | 23-2668356
(State or Other Jurisdiction of Incorporation or Organization) |  | (I.R.S. Employer Identification No.)

460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class: | Trading Symbol(s): | Name of each exchange on which registered:
Common Stock, without par value | UGI | New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ☑ |  | Accelerated filer | ☐ |  | Non-accelerated filer | ☐
Smaller reporting company | ☐ |  | Emerging growth company | ☐ |  |  |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2019 was $9,601,543,818.
At November 19, 2019, there were 209,011,039 shares of UGI Corporation Common Stock issued and outstanding.
Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held on January 22, 2020 are incorporated by reference into Part III of this Form 10-K.

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TABLE OF CONTENTS

| Page
Glossary of Terms and Abbreviations | 2
Forward-Looking Information | 9
PART I: |
Items 1. and 2. Business and Properties | 9
Item 1A. Risk Factors | 28
Item 1B. Unresolved Staff Comments | 37
Item 3. Legal Proceedings | 37
Item 4. Mine Safety Disclosures | 37
PART II: |
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 38
Item 6. Selected Financial Data | 39
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 42
Item 7A. Quantitative and Qualitative Disclosures About Market Risk | 72
Item 8. Financial Statements and Supplementary Data | 72
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 72
Item 9A. Controls and Procedures | 72
Item 9B. Other Information | 72
PART III: |
Item 10. Directors, Executive Officers and Corporate Governance | 73
Item 11. Executive Compensation | 73
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 73
Item 13. Certain Relationships and Related Transactions and Director Independence | 73
Item 14. Principal Accounting Fees and Services | 73
PART IV: |
Item 15. Exhibits and Financial Statement Schedules | 76
Item 16. Form 10-K Summary | 85
Signatures | 87
Index to Financial Statements and Financial Statement Schedules | F-2

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GLOSSARY OF TERMS AND ABBREVIATIONS
Terms and abbreviations used in this Form 10-K are defined below:
UGI Corporation and Related Entities
AmeriGas OLP - AmeriGas Propane, L.P., the principal operating subsidiary of AmeriGas Partners
AmeriGas Partners - AmeriGas Partners, L.P., a Delaware limited partnership and an indirect wholly-owned subsidiary of UGI; also referred to as the “Partnership”
AmeriGas Propane - Reportable segment comprising AmeriGas Propane, Inc. and its subsidiaries, including AmeriGas Partners and AmeriGas OLP
AmeriGas Propane Holdings, Inc. - A Delaware corporation and an indirect wholly-owned subsidiary of UGI
AmeriGas Propane Holdings, LLC - A Delaware limited liability company and an indirect wholly-owned subsidiary of UGI; also referred to as the “Merger Sub”
AmeriGas Propane, Inc. - A wholly owned second-tier subsidiary of UGI and the general partner of AmeriGas Partners; also referred to as the “General Partner”
AvantiGas - AvantiGas Limited, an indirect wholly owned subsidiary of UGI International, LLC
Company - UGI and its consolidated subsidiaries collectively
CPG - UGI Central Penn Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to the Utility Merger
DVEP - DVEP Investeringen B.V., an indirect wholly owned subsidiary of UGI International, LLC
Electric Utility - UGI Utilities’ regulated electric distribution utility
Energy Services - UGI Energy Services, LLC, a wholly owned subsidiary of Enterprises
Enterprises - UGI Enterprises, LLC, a wholly owned subsidiary of UGI
ESFC - Energy Services Funding Corporation, a wholly owned subsidiary of Energy Services
Finagaz - The retail LPG distribution business of Totalgaz SAS acquired on May 29, 2015
Flaga - Flaga GmbH, an indirect wholly owned subsidiary of UGI International, LLC
Gas Utility - UGI Utilities’ regulated natural gas distribution business, comprising the natural gas utility businesses owned and operated by UGI Utilities and, prior to the Utility Merger, PNG and CPG
General Partner - AmeriGas Propane, Inc., the general partner of AmeriGas Partners
Heritage Propane - Retail propane businesses of Energy Transfer Partners, L.P. acquired by AmeriGas Partners, L.P. on January 12, 2012
HVAC - UGI HVAC Enterprises, Inc., a wholly owned subsidiary of Enterprises
Merger Sub - AmeriGas Propane Holdings, LLC, an indirect wholly owned subsidiary of UGI
Midstream & Marketing - Reportable segment comprising Energy Services, UGID and HVAC
Partnership - AmeriGas Partners and its consolidated subsidiaries, including AmeriGas OLP
Pennant - Pennant Midstream, LLC, a Delaware limited liability company
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PennEast - PennEast Pipeline Company, LLC
PNG - UGI Penn Natural Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to the Utility Merger
UGI - UGI Corporation
UGI Central - The natural gas rate district of CPG subsequent to the Utility Merger
UGI France - UGI France SAS (a Société par actions simplifiée), an indirect wholly owned subsidiary of UGI International, LLC
UGI Gas - UGI Utilities’ natural gas utility
UGI International - Reportable segment principally comprising UGI’s foreign operations
UGI International, LLC - UGI International, LLC, a wholly owned subsidiary of Enterprises
UGI North - The natural gas rate district of PNG subsequent to the Utility Merger
UGI PennEast, LLC - A wholly owned subsidiary of Energy Services that holds a 20% membership interest in PennEast
UGI South - The natural gas rate district of UGI Gas subsequent to the Utility Merger
UGI Utilities - UGI Utilities, Inc., a wholly owned subsidiary of UGI. Also a reportable segment of UGI
UGID - UGI Development Company, a wholly owned subsidiary of Energy Services
UniverGas - UniverGas Italia S.r.l, an indirect wholly owned subsidiary of UGI International, LLC
Other Terms and Abbreviations
2010 Propane Plan - The AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan
2013 OICP - UGI Corporation 2013 Omnibus Incentive Compensation Plan
2015 Senior Facilities Agreement - A five-year senior facilities agreement entered into in April 2015 between UGI France and a consortium of banks consisting of a variable-rate term loan and a revolving credit facility
2017 UGI International Credit Agreement - A secured multicurrency revolving facility agreement entered into in December 2017 by UGI International, LLC with a group of banks providing for borrowings up to €300 million that was terminated concurrent with 2018 UGI International Credit Facilities Agreement
2018 UGI International Credit Facilities Agreement - A five-year unsecured Senior Facilities Agreement entered into in October 2018, by UGI International, LLC comprising a €300 million term loan facility and a €300 million revolving credit facility maturing October 2023
ABO - Accumulated Benefit Obligation
ACE - AmeriGas Cylinder Exchange
Act 11 - Act 11 of 2012
Adjusted LIBOR - A rate derived from LIBOR
AEPS Act - Alternative Energy Portfolio Standards Act
AFUDC - Allowance for Funds Used During Construction
Alerian MLP Group - represents entities in the Alerian MLP Index
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AmeriGas 2017 Senior Notes - The underwritten senior facilities agreements issued by AmeriGas Partners comprising $700 million principal amount of 5.50% Senior Notes due May 2025 and $525 million principal amount of 5.75% Senior Notes due May 2027
AmeriGas Merger - The transaction contemplated by the Merger Agreement pursuant to which AmeriGas Propane Holdings, LLC merged with and into the Partnership, with the Partnership surviving as an indirect wholly owned subsidiary of UGI
AmeriGas OLP Credit Agreement - The second amended and restated credit agreement entered into by AmeriGas OLP providing for borrowings of up to $600 million, including a letter of credit subfacility of up to $150 million
AmeriGas Partners’ 7.00% Senior Notes - An underwritten public offering of $980.8 million aggregate principal amount of notes due 2022, issued by AmeriGas Finance Corp. and AmeriGas Finance LLC
AmeriGas Partners Units - AmeriGas Stock Units and AmeriGas Performance Stock Units that are awarded to employees and non-employee directors
AOCI - Accumulated Other Comprehensive Income (loss)
ASC - Accounting Standards Codification
ASC 605 - ASC 605, “Revenue Recognition”
ASC 606 - ASC 606, “Revenue from Contracts with Customers”
ASC 740 - ASC 740, “Income Taxes”
ASU - Accounting Standards Update
ASU 2014-09 - Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers”
Bcf - Billions of cubic feet
BIE - Pennsylvania Public Utility Commission Bureau of Investigation and Enforcement
Board of Directors - the board of directors of UGI
BRP - Balance Responsible Party providing electricity balancing services in the European electricity markets
Btu - British thermal unit
CERCLA - Comprehensive Environmental Response, Compensation and Liability Act
CFTC - Commodity Futures Trading Commission
CMG - Columbia Midstream Group, LLC
CMG Acquisition - Acquisition of CMG and Columbia Pennant, LLC on August 1, 2019 pursuant to the CMG Acquisition Agreements
CMG Acquisition Agreements - Agreements related to the CMG Acquisition comprising (1) a purchase and sale agreement related to the CMG acquisition, dated July 2, 2019, by and among Columbia Midstream & Minerals Group, LLC, Energy Services, UGI and TransCanada PipeLine USA Ltd., and (2) a purchase and sale agreement related to the Columbia Pennant, LLC acquisition, dated July 2, 2019, by and among Columbia Midstream & Minerals Group, LLC, Energy Services, and TransCanada PipeLine USA Ltd.
COA - Consent Order and Agreement
CODM - Chief Operating Decision Maker as defined in ASC 280, “Segment Reporting”
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Common Stock - shares of UGI common stock
Common Units - Limited partnership ownership interests in AmeriGas Partners
Conemaugh - Conemaugh generation station, a 1,711-megawatt, coal-fired electricity generation station located near Johnstown, Pennsylvania
Core market - Comprises (1) firm residential, commercial and industrial customers to whom UGI Utilities has a statutory obligation to provide service who purchase their natural gas or electricity from UGI Utilities; and (2) residential, commercial and industrial customers to whom UGI Utilities has a statutory obligation to provide service who purchase their natural gas or electricity from others
December 2016 French Finance Bills - The French Finance Bill for 2017 and the amendment of the French Finance Bill for 2016
December 2017 French Finance Bills - The French Finance Bill for 2018 and the second amendment to the French Finance Bill for 2017
DEP - Pennsylvania Department of Environmental Protection
DOT - U.S. Department of Transportation
DS - Default service
DSIC - Distribution System Improvement Charge
EBITDA - Earnings before interest expense, income taxes, depreciation, and amortization
Energy Services Credit Agreement - An unsecured revolving credit agreement entered into by Energy Services providing for borrowings up to $200 million, including a letter of credit subfacility of up to $50 million expiring March 2021
Energy Services Term Loan - A seven-year $700 million senior secured term loan agreement entered into on August 13, 2019, with a group of lenders
EPA - Environmental Protection Agency
EPACT 2005 - Energy Policy Act of 2005
EPS - Earnings Per Share
ERISA - Employee Retirement Income Security Act of 1974
ERO - Electric Reliability Organization
ERP - Enterprise Resource Planning
EU - European Union
Euribor - Euro Interbank Offered Rate
Exchange Act - Securities Exchange Act of 1934, as amended
FASB - Financial Accounting Standards Board
FDIC - Federal Deposit Insurance Corporation
FERC - Federal Energy Regulatory Commission
FIFO - First-in, first-out inventory valuation method
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Fiscal 2017 - The fiscal year ended September 30, 2017
Fiscal 2018 - The fiscal year ended September 30, 2018
Fiscal 2019 - The fiscal year ended September 30, 2019
Fiscal 2020 - The fiscal year ending September 30, 2020
Flaga Credit Facility Agreement - A credit facility agreement entered into in October 2015 between Flaga GmbH and a bank
Flaga U.S. Dollar Term Loan - The U.S. dollar denominated variable-rate term loan, as amended to extend the maturity date to April 2020
French Finance Bills - The December 2016 French Finance Bills and the December 2017 French Finance Bills
FTR - Financial transmission rights
GAAP - U.S. generally accepted accounting principles
GDE - Gas Delivery Enhancement Rider
GDE Charges - Costs associated with temporary mobile sources of gas supply and interstate pipeline demand charge enhancements
GDPR - General Data Protection Regulation
GET Gas - Growth Extension Tariff program
GHG - Greenhouse gas
GILTI - Global Intangible Low Taxed Income
Gwh - Millions of kilowatt hours
ICE - Intercontinental Exchange
IDR - Incentive distribution right
IRPA - Interest rate protection agreement
IT - Information technology
LIBOR - London Inter-bank Offered Rate
LNG - Liquefied natural gas
LPG - Liquefied petroleum gas
LTIIP - Long-term infrastructure improvement plans
MD&A - Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDPSC - Maryland Public Service Commission
Merger Agreement - Agreement and Plan of Merger, dated as of April 1, 2019, among UGI, AmeriGas Propane Holdings, Inc., AmeriGas Propane Holdings, LLC, AmeriGas Partners and AmeriGas Propane
MGP - Manufactured gas plant
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NAV - Net asset value
NOAA - National Oceanic and Atmospheric Administration
NPNS - Normal purchase and normal sale
NYDEC - New York State Department of Environmental Conservation
NYISO - New York Independent System Operator
NYMEX - New York Mercantile Exchange
OSHA - Occupational Safety and Health Act
PADEP - Pennsylvania Department of Environmental Protection
PAPUC - Pennsylvania Public Utility Commission
Partnership Agreement - Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009, as amended
PBO - Projected benefit obligation
PGC - Purchased gas costs
PJM - PJM Interconnection, LLC
Propane MLP Group - Ferrellgas Partners, L.P. and Suburban Propane, L.P.
PRP - Potentially Responsible Party
PUHCA 2005 - Public Utility Holding Company Act of 2005
Receivables Facility - A receivables purchase facility of Energy Services with an issuer of receivables-backed commercial paper
Retail core-market - Comprises firm residential, commercial and industrial customers to whom UGI Utilities has a statutory obligation to provide service that purchase their natural gas from Gas Utility
ROD - Record of Decision
SAR - Stock Appreciation Rights
SCAA - Storage Contract Administrative Agreements
SEC - U.S. Securities and Exchange Commission
Stock Unit - Unit awards that entitle the grantee to shares of UGI Common Stock or cash subject to service conditions
TCJA - Tax Cuts and Jobs Act
Temporary Rates Order - Order issued by the PAPUC on March 15, 2018, that converted PAPUC approved rates of a defined group of large Pennsylvania public utilities into temporary rates for a period of not more than 12 months while the PAPUC reviewed effects of the TCJA
Tortoise MLP Group - Represents the entities in the Tortoise MLP Index
TSR - Total Shareholder Return
TUR - Total Unitholder Return
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UGI comparator group - The Russell Midcap Utility Index, excluding telecommunications companies
UGI Corporation Senior Credit Facility - An unsecured senior facilities agreement entered into on August 1, 2019, by UGI comprising (1) a five-year $250 million term loan facility; (2) a three-year $300 million term loan facility; and (3) a five-year $300 million revolving credit facility (including a $10 million sublimit for letters of credit)
UGI International 3.25% Senior Notes - An underwritten private placement of €350 million principal amount of senior unsecured notes due November 1, 2025, issued by UGI International, LLC
UGI Performance Units - Unit awards that entitle the grantee to shares of UGI Common Stock or cash subject to service and market performance conditions
UGI Utilities 2019 Credit Agreement - A five-year unsecured revolving credit agreement entered into by UGI Utilities on June 27, 2019, providing for borrowings up to $350 million, including a letter of credit subfacility of up to $100 million
UGI Utilities 4.55% Senior Notes - A private placement of $150 million principal amount of senior notes issued by UGI Utilities due February 2049
Units or Unit Awards - UGI Corporation stock options, grants of UGI Corporation stock-based equity instruments and, prior to the AmeriGas Merger, grants of AmeriGas Partners, L.P. equity instruments (together with UGI Corporation stock-based equity instruments)
USD - U.S. dollar
U.S. Pension Plan - Defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities and certain of UGI’s other domestic wholly owned subsidiaries
Utilities Term Loan - A $125 million unsecured variable-rate term loan agreement entered into in September 2018 by UGI Utilities with a group of banks
Utility Merger - The merger, effective October 1, 2018, of CPG and PNG with and into UGI Utilities
VEBA - Voluntary Employees’ Beneficiary Association
Western Missouri District Court - The United States District Court for the Western District of Missouri
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FORWARD-LOOKING INFORMATION
Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind our Risk Factors included in Item 1A herein and the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) weather conditions resulting in reduced demand and the seasonal nature of our business; (2) cost volatility and availability of propane and other LPG, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection, data privacy, accounting matters, and environmental, including regulatory responses to climate change; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers or retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) customer, counterparty, supplier, or vendor defaults; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, natural disasters and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States, Europe and other foreign countries, including the current conflicts in the Middle East and the potential withdrawal of the United Kingdom from the EU, and foreign currency exchange rate fluctuations, particularly the euro; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; (17) reduced distributions from subsidiaries impacting the ability to pay dividends; (18) changes in Marcellus and Utica Shale gas production; (19) the availability, timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; (20) our ability to successfully integrate acquired businesses and achieve anticipated synergies, including certain integration risks relating to the CMG Acquisition; (21) the interruption, disruption, failure or malfunction of our information technology systems, including due to cyber attack; (22) the inability to complete pending or future energy infrastructure projects; and (23) our ability to achieve the operational benefits and cost efficiencies expected from the completion of pending and future transformation initiatives at our business units.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
UGI Corporation 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) own and operate 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 LPG and other energy products and services. Our subsidiaries and affiliates operate principally in the following four business segments:

• | AmeriGas Propane

• | UGI International

• | Midstream & Marketing

• | UGI Utilities

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The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners. In addition to distributing propane, the Partnership also sells, installs, and services propane appliances, including heating systems. The Partnership conducts its propane distribution business through its principal operating subsidiary, AmeriGas Propane, L.P., and is the nation’s largest retail propane distributor. The general partner of AmeriGas Partners is our wholly owned subsidiary, AmeriGas Propane, Inc. On August 21, 2019, UGI completed its acquisition of all of the outstanding Common Units representing limited partnership interests in AmeriGas Partners not already held by UGI or one of its subsidiaries. Following completion of the transaction, the Partnership’s Common Units are no longer publicly traded, and the Partnership is now an indirect, wholly owned subsidiary of UGI. See Note 5 to Consolidated Financial Statements.
The UGI International segment consists of LPG distribution businesses conducted by our subsidiaries and affiliates in France, Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg, the United Kingdom, Italy, Finland, Denmark, Norway and Sweden. In addition, UGI International conducts an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. Based on volumes distributed, UGI International believes that it is the largest distributor of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, the Netherlands and Sweden. These businesses are conducted principally through our subsidiaries, UGI France, Flaga, AvantiGas, UniverGas and DVEP.
The Midstream & Marketing segment consists of energy-related businesses conducted by our indirect, wholly owned subsidiary, UGI Energy Services, LLC. These businesses (i) conduct energy marketing in the Mid-Atlantic region of the United States, (ii) own and operate natural gas liquefaction, storage and vaporization facilities and propane-air mixing assets, (iii) manage natural gas pipeline and storage contracts, (iv) develop, own and operate pipelines, gathering infrastructure and gas storage facilities in the Marcellus and Utica Shale regions of Pennsylvania, eastern Ohio, and the panhandle of West Virginia, and (v) own all or portions of electricity generation facilities. The Midstream & Marketing segment also includes HVAC, which conducts a heating, ventilation, air conditioning, refrigeration, mechanical and electrical contracting, and project management service business in portions of eastern and central Pennsylvania.
The UGI Utilities segment consists of the regulated natural gas distribution businesses of our wholly owned subsidiary, UGI Utilities, Inc. The UGI Utilities segment also consists of UGI Utilities’ regulated electric distribution business in Pennsylvania. Gas Utility serves nearly 655,000 customers in eastern and central Pennsylvania and more than 500 customers in portions of one Maryland county. Electric Utility serves more than 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania. Gas Utility is regulated by the PAPUC and, with respect to its customers in Maryland, the MDPSC. Electric Utility is also regulated by the PAPUC and FERC.
Business Strategy
Our business strategy is to grow the Company by focusing on our core competencies of distributing, storing, transporting and marketing energy products and services. We are utilizing our core competencies from our existing businesses and our national scope, international experience, extensive asset base and access to customers to accelerate both organic growth and growth through acquisitions in our existing businesses, as well as in related and complementary businesses. During Fiscal 2019, we completed a number of transactions in pursuit of this strategy and made progress on larger internally generated capital projects, including infrastructure projects to further support the development of natural gas in the Marcellus and Utica Shale regions. A few of these transactions and projects are described below.
In October 2018, UGI International completed a significant refinancing transaction, whereby it issued €350 million of 3.25% bonds due November 2025 through an underwritten private placement, borrowed €300 million under a term loan facility, and entered into a €300 million multicurrency revolving credit facility. The proceeds from the term loan and the 3.25% bonds were used to repay UGI France’s and Flaga’s term loans ahead of schedule, which strengthened the Company’s balance sheet and helped position it for future growth. Additionally, in Fiscal 2019, UGI International continued to expand its footprint throughout Europe with the completion of acquisitions in the United Kingdom, the Netherlands and Belgium.
In Fiscal 2019, the Midstream & Marketing segment continued to enhance its natural gas infrastructure assets both organically and through significant acquisitions. In August 2019, Energy Services completed the CMG Acquisition for approximately $1.275 billion. The CMG Acquisition expands Energy Services’ natural gas gathering systems into southwestern Pennsylvania, eastern Ohio and the West Virginia panhandle. The assets acquired include a network of five natural gas gathering systems and one processing plant. The Midstream & Marketing segment also continued to focus on organic growth through infrastructure build-out projects in the Marcellus and Utica Shale regions, including (i) the commencement of construction on a large-scale LNG peak shaving facility in Bethlehem, Pennsylvania and (ii) the expansion of infield gathering capabilities through the buildout of our Texas Creek and other gathering assets located in northern Pennsylvania. In November 2019, we completed our Auburn IV pipeline
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expansion project in northern Pennsylvania. We expect the newly-acquired assets from the CMG Acquisition, along with our infrastructure investments, to enhance our existing Midstream & Marketing business as well as establish a full-scale midstream platform. Additionally, in early Fiscal 2019, Energy Services completed the acquisition of South Jersey Energy Company’s natural gas marketing business, expanding its customer base.
On August 21, 2019, UGI completed the AmeriGas Merger. Following completion of the transaction, the Partnership’s Common Units are no longer publicly traded, and the Partnership is now an indirect, wholly owned subsidiary of UGI. The transaction is expected to increase cash available for investments and growth opportunities across UGI’s businesses, particularly with respect to natural gas investments.
UGI Utilities continued to execute on its infrastructure replacement and system betterment program, with record capital expenditures in Fiscal 2019. UGI Utilities made progress toward its goal of replacing the cast iron portions of its gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. In addition, in January 2019, Gas Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial, and industrial customers and, on October 4, 2019, the PAPUC issued a final order permitting Gas Utility to increase its base distribution revenues by $30.0 million under a single tariff effective October 11, 2019. In Fiscal 2019, UGI Utilities also completed the construction of its new headquarters building located in Denver, Pennsylvania. The new headquarters is LEED Silver certified, uses natural gas to generate electricity, and utilizes combined heat and power, as well as solar to promote energy efficiency.
In addition, during Fiscal 2019, AmeriGas Propane and UGI International began executing on multi-year business transformation initiatives. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. For further information on these initiatives, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Global LPG Business Transformation Initiatives.”
Environmental, Social and Governance
UGI is committed to delivering safe, reliable and energy efficient solutions to our customers. We strive to deliver this fundamental need through best-in-class safety, operations, products and services while positively impacting the lives of our employees and the communities we serve. In May 2019, UGI released its inaugural Environmental, Social and Governance Report (the “ESG Report”). The ESG Report may be accessed on our website under the “Investors - Environmental, Social, and Governance (ESG) - ESG Report” caption. The information included in the ESG Report is not intended to be incorporated by reference into this Report. The following highlights some of our ongoing ESG efforts.
Safety
UGI believes that the safety and well-being of our employees, customers, and communities is of the utmost importance. Safety is the top priority for our business. Over the past five years, UGI and its businesses have invested in programs, technology, and training to improve safety throughout our operations.
Environmental
UGI emphasizes the importance of reducing our environmental impact and encouraging conservation and efficiency. This has actively shaped our three-step approach to addressing climate change by reducing both our emissions and our customers’ emissions and investing in energy alternatives. Some of our recent achievements and initiatives include:

• | partnering with the EPA’s Natural Gas STAR and Methane Challenge programs;

• | replacing cast iron and bare steel pipeline as part of our pipeline replacement and betterment program, which is projected to reduce current CO 2 equivalent emissions by at least 80% by 2041;

• | converting households to clean-burning natural gas, which reduces GHG emissions;

• | converting a portion of our fleet as well as the fleets of third parties (including school bus fleets) to cleaner, more efficient compressed natural gas and propane-powered engines;

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• | initiating natural gas service to three power generation facilities, which reduces CO 2 emissions by half when compared to coal-fired plants;

• | creating a dedicated Gas Energy Efficiency and Conservation program that provides rebates to program participants; and

• | investing in energy alternatives, such as solar, landfill gas recovery, combined heat and power, compressed natural gas, bio-LPG, renewable natural gas, and green energy marketing in Europe.

Community Engagement
A commitment to the community is a core value embraced by UGI and its employees. Our teams embrace a wide variety of causes, including literacy programs, first responders, STEM programs, cancer awareness events, food banks, opioid abuse, veteran affairs and hunger.
Corporate Governance
Our Board of Directors takes an active role in risk management and ESG efforts, fulfilling its oversight responsibilities directly and through delegation to the following committees: Audit, Corporate Governance, Compensation and Management Development, Safety, Environmental and Regulatory Compliance, and Executive. The Board of Directors also plays an important role in overseeing management’s performance in assessing and managing risk and ESG efforts. The Company’s Principles of Corporate Governance and Code of Business Conduct and Ethics are available on the Company’s website under the caption “Company - Leadership and Governance - Governance Documents.”
Corporate Information
UGI was incorporated in Pennsylvania in 1991. The Company is not subject to regulation by the PAPUC and it is a “holding company” under PUHCA 2005. PUHCA 2005 and the implementing regulations of FERC give FERC access to certain holding company books and records and impose certain accounting, record-keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the basis of UGI’s status as a single-state holding company system, UGI is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations.
Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania 19406, and our telephone number is (610) 337-1000. In this report, the terms “Company” and “UGI,” as well as the terms “our,” “we,” “us,” and “its” are sometimes used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. For further information on the meaning of certain terms used in this Report, see “Glossary of Terms and Abbreviations.”
The Company’s corporate website can be found at www.ugicorp.com. Information on our website, including the information published in our ESG Report, is not intended to be incorporated into this Report. The Company makes available free of charge at this website (under the “Investors - Financial Reports - SEC Filings and Proxies” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance and Code of Business Conduct and Ethics are available on the Company’s website under the caption “Company - Leadership and Governance - Governance Documents.” The charters of the Audit, Corporate Governance, Compensation and Management Development, and Safety, Environmental and Regulatory Compliance Committees of the Board of Directors are available on the Company’s website under the caption “Company - Committees & Charters.” All of these documents are also available free of charge by writing to Director, Investor Relations, UGI Corporation, P.O. Box 858, Valley Forge, PA 19482.
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AMERIGAS PROPANE
Products, Services and Marketing
Our domestic propane distribution business is conducted through AmeriGas Propane. AmeriGas Propane serves over 1.6 million customers in all 50 states from more than 1,800 propane distribution locations. In addition to distributing propane, AmeriGas Propane also sells, installs and services propane appliances, including heating systems and propane-powered generators. Typically, propane distribution locations are in suburban and rural areas where natural gas is not readily available. Our local offices generally consist of a business office and propane storage. As part of its overall transportation and distribution infrastructure, AmeriGas Propane operates as an interstate carrier in all states throughout the continental U.S.
AmeriGas Propane sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. AmeriGas Propane distributed over 1.1 billion gallons of propane in Fiscal 2019. Approximately 93% of AmeriGas Propane’s Fiscal 2019 sales (based on gallons sold) were to retail accounts and approximately 7% were to wholesale and supply customers. Sales to residential customers in Fiscal 2019 represented approximately 35% of retail gallons sold; commercial/industrial customers 39%; motor fuel customers 18%; and agricultural customers 4%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 4% of Fiscal 2019 retail gallons. No single customer represents, or is anticipated to represent, more than 5% of AmeriGas Propane’s consolidated revenues.
AmeriGas Propane continues to expand its ACE program. At September 30, 2019, ACE cylinders were available at over 62,000 retail locations throughout the U.S. Sales of our ACE cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase or exchange propane cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. In addition, in Fiscal 2019, our ACE program completed a roll-out of automated self-serve vending machines, which enable our customers to purchase and exchange ACE cylinders at various retail locations 24/7, and we introduced Cynch, our propane home delivery service for customers in select markets. Additionally, we supply retailers with large propane tanks to enable them to replenish customers’ propane cylinders directly at the retailer’s location.
Residential and commercial customers use propane primarily for home heating, water heating and cooking purposes. Commercial users include hotels, restaurants, churches, warehouses, and retail stores. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers that use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power school buses and other over-the-road vehicles, forklifts, and stationary engines. Agricultural uses include tobacco curing, chicken brooding, crop drying, and orchard heating. In its wholesale operations, AmeriGas Propane principally sells propane to large industrial end-users and other propane distributors.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. AmeriGas Propane owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. AmeriGas Propane also delivers propane in portable cylinders, including ACE and motor fuel cylinders. Some of these deliveries are made to the customer’s location, where cylinders are either picked up or replenished in place.
During Fiscal 2019, we continued to invest in technology to reduce operational costs while improving our customers’ experience. For example, (i) following the successful implementation of the AmeriMobile distribution platform to all district locations to more efficiently deploy our drivers in making deliveries to customers, we continued to roll out the platform to our service technicians for service scheduling, job routing, and billing, and (ii) we continue to promote a customer service culture through enhancements to our on-line customer experience, enabling customers to transact with us at any time through self-service account management, to sign up as a new customer and to seek customer support through live on-line chat.
Moreover, in Fiscal 2019, AmeriGas Propane began executing on multi-year business transformation initiatives designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. For further information on these initiatives, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Global LPG Business Transformation Initiatives.”
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Propane Supply and Storage
The U.S. propane market has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from AmeriGas Propane’s sources historically have been readily available. Volatility in the U.S. propane market stabilized in Fiscal 2017 and Fiscal 2018, following record high levels reached in Fiscal 2016 and Fiscal 2015, and the propane industry continued to experience normal inventory levels in Fiscal 2019. The availability and pricing of propane supply is dependent upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and crude oil, and the amount and availability of exported supply and, to a much lesser extent, imported supply. In recent years, there has been an increase in overseas demand for U.S. propane exports as the U.S. continues to have low cost reliable sources of propane. We utilized our extensive distribution and logistics channels to minimize disruption to our customers as a result of localized supply chain interruptions due to (i) refinery production interruptions in California during the 2018-2019 winter season and (ii) the effects of Hurricane Dorian in Florida in September 2019.
During Fiscal 2019, approximately 98% of AmeriGas Propane’s propane supply was purchased under supply agreements with terms of one to three years. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during Fiscal 2020. If supply from major sources were interrupted, however, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Enterprise Products Operating LLC supplied approximately 12% of AmeriGas Propane’s Fiscal 2019 propane supply. No other single supplier provided more than 10% of AmeriGas Propane’s total propane supply in Fiscal 2019. In certain geographic areas, however, a single supplier provides more than 50% of AmeriGas Propane’s requirements. Disruptions in supply in these areas could also have an adverse impact on the AmeriGas Propane’s margins.
AmeriGas Propane’s supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas, or (ii) posted prices at the time of delivery. In addition, some agreements provide maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and the amount of supply contracted for at fixed prices, will vary from year to year. AmeriGas Propane uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks and barges, to transport propane from suppliers to storage and distribution facilities. AmeriGas Propane stores propane at various storage facilities and terminals located in strategic areas across the U.S.
Because AmeriGas Propane’s profitability is sensitive to changes in wholesale propane costs, AmeriGas Propane generally seeks to pass on increases in the cost of propane to customers. There is no assurance, however, that AmeriGas Propane will always be able to pass on product cost increases fully, or keep pace with such increases, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. AmeriGas Propane has supply acquisition and product cost risk management practices to reduce the effect of volatility on selling prices. These practices currently include the use of summer storage, forward purchases and derivative commodity instruments, such as propane price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”
The following graph shows the average prices of propane on the propane spot market during the last five fiscal years at Mont Belvieu, Texas, and Conway, Kansas, both major storage areas.
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Average Propane Spot Market Prices
General Industry Information
Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow for its detection. Propane is considered a clean alternative fuel under the Clean Air Act Amendments of 1990, producing negligible amounts of pollutants when properly consumed.
Competition
Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Propane distributors compete for customers with suppliers of electricity, fuel oil and natural gas, principally on the basis of price, service, availability and portability. Electricity is generally more expensive than propane on a Btu equivalent basis, but the convenience and efficiency of electricity make it an attractive energy source for consumers and developers of new homes. Fuel oil is also a major competitor of propane and, although a less environmentally attractive energy source, is currently less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Natural gas is generally a significantly less expensive source of energy than propane, although in areas where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during interruptions in natural gas service. The gradual expansion of the nation’s natural gas distribution systems has resulted in the availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present in many areas of the country where propane is sold for heating and cooking purposes.
For motor fuel customers, propane competes with gasoline, diesel fuel, electric batteries, fuel cells and, in certain applications, LNG and compressed natural gas. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a competitive bidding process.
Retail propane industry volumes have been declining for several years and no or modest growth in total demand is foreseen in the next several years. Therefore, AmeriGas Propane’s ability to grow within the industry is dependent on the success of its sales and marketing programs designed to attract and retain customers, the success of business transformation initiatives, its ability to achieve internal growth, which includes expansion of the ACE and National Accounts programs (through which multi-location propane users enter into a single AmeriGas Propane supply agreement rather than agreements with multiple suppliers), and its ability to acquire other retail distributors. The failure of AmeriGas Propane to retain and grow its customer base would have an adverse effect on its long-term results.
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The domestic propane retail distribution business is highly competitive. AmeriGas Propane competes in this business with other large propane marketers, including other full-service marketers, and thousands of small independent operators. Some farm cooperatives, rural electric cooperatives and fuel oil distributors include propane distribution in their businesses and AmeriGas Propane competes with them as well. The ability to compete effectively depends on providing high quality customer service, maintaining competitive retail prices and controlling operating expenses. AmeriGas Propane also offers customers various payment and service options, including guaranteed price programs, fixed price arrangements and pricing arrangements based on published propane prices at specified terminals.
In Fiscal 2019, AmeriGas Propane’s retail propane sales totaled more than 1.0 billion gallons. Based on the most recent annual survey by the American Petroleum Institute, 2017 domestic retail propane sales (annual sales for other than chemical uses) in the U.S. totaled approximately 8.2 billion gallons. Based on LP-GAS magazine rankings, 2017 sales volume of the ten largest propane distribution companies (including AmeriGas Partners) represented approximately 36% of domestic retail propane sales.
Properties
As of September 30, 2019, the Partnership owned approximately 85% of its approximately 570 local offices throughout the country. The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2019, the Partnership operated a transportation fleet with the following assets:

Approximate Quantity & Equipment Type | % Owned | % Leased
900 | Trailers | 74% | 26%
330 | Tractors | 3% | 97%
500 | Railroad tank cars | 0% | 100%
2,910 | Bobtail trucks | 23% | 77%
390 | Rack trucks | 25% | 75%
3,710 | Service and delivery trucks | 30% | 70%

Other assets owned at September 30, 2019 included approximately 1 million stationary storage tanks with typical capacities of more than 120 gallons, approximately 4.3 million portable propane cylinders with typical capacities of 1 to 120 gallons, 22 terminals and 12 transflow units.
Trade Names, Trade and Service Marks
AmeriGas Propane markets propane and other services principally under the “AmeriGas®,” “America’s Propane Company®,” “Driving Every Day®,” “Heritage Propane®,” and “Relationships Matter®” trade names and related service marks. AmeriGas Propane also markets propane under various other trade names throughout the U.S. UGI owns, directly or indirectly, all the right, title and interest in the “AmeriGas” name and related trade and service marks. The General Partner owns all right, title and interest in the “America’s Propane Company” trade name and related service marks. The Partnership has an exclusive (except for use by UGI, AmeriGas, Inc., AmeriGas Polska Sp. z.o.o. and the General Partner), royalty-free license to use these trade names and related service marks. UGI and the General Partner each have the option to terminate its respective license agreement (except its licenses with permitted transferees and on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership for cause. If the General Partner ceases to serve as the general partner of the Partnership other than for cause, the General Partner has the option to terminate its license agreement upon payment of a fee to AmeriGas Propane, L.P. equal to the fair market value of the licensed trade names. UGI has a similar termination option; however, UGI must provide 12 months’ prior notice in addition to paying the fee to AmeriGas OLP. UGI and the General Partner each also have the right to terminate its respective license agreement in order to settle any claim of infringement, unfair competition or similar claim or if the agreement has been materially breached without appropriate cure.
Seasonality
Because many customers use propane for heating purposes, AmeriGas Propane’s retail sales volume is seasonal. During Fiscal 2019, approximately 66% of the Partnership’s retail sales volume occurred, and all of AmeriGas Propane’s operating income was earned, during the peak heating season from October through March. As a result of this seasonality, sales are typically higher in AmeriGas Propane’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season. As a result of the AmeriGas Merger, we expect that UGI will derive a greater percentage of its earnings during the peak heating season of October through March. For more information on the risks associated with the seasonality of our business, see “Risk Factors - Our business
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is seasonal and decreases in the demand for our energy products and services because of warmer-than-normal heating season weather or unfavorable weather conditions may adversely affect our results of operations.”
Sales volume for AmeriGas Propane traditionally fluctuates from year-to-year in response to variations in weather, prices, competition, customer mix and other factors, such as conservation efforts and general economic conditions. For information on national weather statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
AmeriGas Propane is subject to various federal, state and local environmental, health, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage propane terminals.
Environmental
Generally, applicable environmental laws impose limitations on the discharge of pollutants, establish standards for the handling of solid and hazardous substances, and require the investigation and cleanup of environmental contamination. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, the Clean Water Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, comparable state statutes and any applicable amendments. The Partnership incurs expenses associated with compliance with its obligations under federal and state environmental laws and regulations, and we believe that the Partnership is in material compliance with its obligations. The Partnership maintains various permits that are necessary to operate its facilities, some of which may be material to its operations. AmeriGas Propane continually monitors its operations with respect to potential environmental issues, including changes in legal requirements.
AmeriGas Propane is investigating and remediating contamination at a number of present and former operating sites in the U.S., including sites where its predecessor entities operated manufactured gas plants. CERCLA and similar state laws impose joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of CERCLA.
Health and Safety
AmeriGas Propane is subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of our workers. These laws require the Partnership, among other things, to maintain information about materials, some of which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this information must be provided to employees, federal and state and local governmental authorities and responders, commercial and industrial customers and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. AmeriGas Propane’s operations are also subject to federal safety hazard communication requirements and reporting obligations.
All states in which AmeriGas Propane operates have adopted fire safety codes that regulate the storage, distribution, and use of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. AmeriGas Propane conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, AmeriGas Propane is subject in all jurisdictions in which it operates to rules and procedures governing the safe handling of propane, including those established by National Fire Protection Association Pamphlets No. 54 and No. 58, various state, local and international codes (including international fire, building and fuel gas codes), and OSHA fall protection standards. Management believes that the policies and procedures currently in effect at all of its facilities for the handling, storage, distribution and use of propane, as well as its fall protection standards, are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.
With respect to the transportation of propane by truck, AmeriGas Propane is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act, the Hazardous Materials & Transportation Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials, including propane for purposes of these regulations, and are administered by the Pipeline and Hazardous Materials Safety Administration of the DOT. The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT's pipeline safety regulations apply to, among other things, a propane gas system that supplies 10 or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators of all gas systems to provide operator qualification standards and training and written instructions for employees and third party contractors working on covered pipelines and facilities, establish written procedures to minimize the hazards resulting from gas pipeline emergencies,
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and conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002. Management believes that the procedures currently in effect at all of AmeriGas Propane’s facilities for the handling, storage, transportation and distribution of propane are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.
Climate Change
There continues to be concern, both nationally and internationally, about climate change and the contribution of GHG emissions, most notably carbon dioxide, to global warming. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, the Partnership anticipates that this will provide it with a competitive advantage over other sources of energy, such as fuel oil and coal, to the extent new climate change regulations become effective. At the same time, increased regulation of GHG emissions, especially in the transportation sector, could impose significant additional costs on AmeriGas Propane, its suppliers, its vendors and its customers. In recent years, there has been an increase in state initiatives aimed at regulating GHG emissions. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane distribution companies, to purchase allowances to compensate for the GHG emissions created by their business operations. Compliance with these types of regulations may increase our operating costs if we are unable to pass on these costs to our customers.
Employees
The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2019, the General Partner had over 7,550 employees, including more than 300 part-time, seasonal and temporary employees, working on behalf of the Partnership. UGI also performs, and is reimbursed for, certain financial and administrative services on behalf of the Partnership and AmeriGas OLP.
UGI INTERNATIONAL
UGI International, through subsidiaries and affiliates, conducts (i) an LPG distribution business in 17 countries throughout Europe (France, Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg, the United Kingdom, Italy, Finland, Denmark, Norway and Sweden), and (ii) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. Based on Fiscal 2019 volumes, UGI International believes that it is the largest distributor of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, the Netherlands and Sweden.
Products, Services and Marketing
LPG Distribution Business
During Fiscal 2019, UGI International sold over 960 million gallons of LPG throughout Europe. UGI International operates under seven distinct LPG brands, and its customer base primarily consists of residential, commercial, industrial, agricultural, wholesale and automobile fuel (‘‘autogas’’) customers that use LPG for space heating, cooking, water heating, motor fuel, leisure activities, crop drying, irrigation, construction, power generation, manufacturing and as an aerosol propellant. For Fiscal 2019, approximately 47% of UGI International’s LPG volume was sold to commercial and industrial customers, approximately 19% was sold to residential, approximately 9% was sold to agricultural and approximately 25% was sold to wholesale and other customers (including autogas). UGI International supplies LPG to its customers in small, medium and large bulk tanks at their locations. In addition to bulk sales, UGI International sells LPG in cylinders through retail outlets, such as supermarkets, individually owned stores and gas stations. Sales of LPG are also made to service stations to fuel vehicles that run on LPG. Approximately 62% of Fiscal 2019 LPG sales (based on volumes) were attributed to bulk, 17% to cylinder, 13% to wholesale and 8% to autogas. For Fiscal 2019, no single customer represented more than 5% of UGI International’s revenues.
Bulk
UGI International classifies its bulk customers as small, medium or large bulk, depending on tank size at the customer locations. Small bulk customers are primarily residential and small business users such as restaurants that use LPG mainly for heating and cooking. Medium bulk customers consist mainly of large residential housing developments, hospitals, hotels, municipalities, medium-sized industrial enterprises and poultry brooders. Large bulk customers include agricultural customers (including crop drying) and companies that use LPG in their industrial processes. At September 30, 2019, UGI International had over 527,000 bulk LPG customers and sold approximately 600 million gallons of bulk LPG during Fiscal 2019.
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Cylinder
UGI International sells LPG in both steel and composite cylinders and typically owns the cylinders in which the LPG is sold. The principal end-users of cylinders are residential customers who use LPG for domestic applications, such as cooking and heating. Non-residential uses include fuel for forklift trucks, road construction and welding. At September 30, 2019, UGI International had over 19 million cylinders in circulation and sold approximately 160 million gallons of LPG in cylinders during Fiscal 2019. UGI International also delivers LPG to wholesale and retail customers in cylinders, including through the use of vending machines.
Wholesale, Autogas and Other Services
Approximately 17% of UGI International’s Fiscal 2019 LPG sales (based on volumes) were to wholesale customers (including small competitors, large industrial customers and aerosol customers), and approximately 8% of Fiscal 2019 LPG sales (based on volumes) were to autogas customers. UGI International also provides logistics, storage and other services to third-party LPG distributors.
Energy Marketing Business
UGI International markets and supplies natural gas and electricity to small and medium enterprises, schools and municipalities through third-party distribution systems. UGI International started developing its energy marketing business organically in 2012 and completed the acquisition of DVEP in the Netherlands in August 2017. UGI International sold approximately 26 Bcf of natural gas and over 3,450 Gwh of electricity during Fiscal 2019.
LPG Supply, Storage and Transportation
UGI International is typically party to term contracts, with approximately 60 different suppliers, including producers and international oil and gas trading companies, to meet LPG supply requirements throughout Europe. LPG supply is transported via rail and sea, and by road for shorter distances. Agreements are generally one- to two-year term agreements with pricing based on internationally quoted market prices. Additionally, LPG is purchased on the domestic spot markets to manage supply needs. In certain geographic areas (the United Kingdom and Italy), a single supplier may provide approximately 50% or more of UGI International’s requirements. Because UGI International’s profitability is sensitive to changes in wholesale LPG costs, UGI International generally seeks to pass on increases in the cost of LPG to its customers. There can be no assurance, however, that UGI International will always be able to pass on product cost increases fully, or keep pace with such increases, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events.
UGI International stores LPG at various storage facilities and terminals located across Europe and has interests in 10 primary storage facilities and more than 80 secondary storage facilities. LPG stored in primary storage facilities is transported to smaller storage facilities by rail and road. At secondary storage facilities, LPG is loaded into cylinders or trucks equipped with tanks and then delivered to customers. UGI International also manages an extensive logistics and transportation network and has access to seaborne import facilities.
UGI International transports LPG to customers primarily through outsourced transportation providers to serve both bulk and cylinder markets. UGI International has long-term relationships with many providers of logistics and transportation services in most of its markets and is not dependent on the services of any single transportation provider.
Competition and Seasonality
The LPG markets in western and northern Europe are mature, with modest declines in total demand due to competition with other fossil fuels and other energy sources, conservation and macroeconomic conditions. In the Eastern European countries in which UGI International operates, the demand for LPG is expected to grow in certain segments. Sales volumes are affected principally by the severity of the weather and customer migration to alternative energy forms, including natural gas, electricity, heating oil and wood. High LPG prices also may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. In addition, government policies and incentives that favor alternative energy sources, such as wind and solar, can result in customers migrating to energy sources other than LPG. In addition to price, UGI International competes for customers in its various markets based on contract terms. UGI International competes locally as well as regionally in many of its service territories. Additionally, particularly in France, although UGI International supplies certain supermarket chains, it also competes with some of these supermarket chains that affiliate with LPG distributors to offer their own brands of cylinders. UGI International seeks to increase demand for its LPG cylinders through marketing and product innovations.
In its energy marketing business, UGI International competes against small- and medium-sized enterprise providers of natural gas and electricity in four countries in Europe where the markets have been deregulated for at least ten years. The markets are generally stable, developed and growing and competition can be local, regional or pan-European.
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Because many of UGI International’s customers use LPG for heating, sales volume is affected principally by the severity of the temperatures during the heating season months and traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the economic environment. Demand for LPG is higher during the colder months of the year. For historical information on weather statistics for UGI International, see ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’
Government Regulation
UGI International’s business is subject to various laws and regulations at the country and local levels, as well as at the EU level, with respect to matters such as protection of the environment, the storage, transportation and handling of hazardous materials and flammable substances (including the Seveso II Directive), regulations specific to bulk tanks, cylinders and pipe networks, competition, pricing, regulation of contract terms, anti-corruption (including the U.S. Foreign Corrupt Practices Act, Sapin II and the U.K. Bribery Act), data privacy and protection, and the safety of persons and property.
Environmental
Environmental laws and regulations may require expenditures over a long timeframe to control environmental effects. Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following: (i) the complexity of the site; (ii) changes in environmental laws and regulations; (iii) the number of regulatory agencies or other parties involved; (iv) new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; (v) the level of remediation required; and (vi) variation between the estimated and actual period of time required to respond to an environmentally-contaminated site.
Data Privacy
The EU adopted the GDPR, which became effective in May of 2018. The GDPR expanded the EU data protection laws to all companies processing data of EU residents. It primarily focuses on unifying and strengthening the regulations dealing with the collection, processing, use and security of personal and sensitive data.
Properties
In addition to regional headquarter locations and sales offices throughout its service territory, UGI International has interests in 10 primary storage facilities and more than 80 secondary storage facilities.
Employees
At September 30, 2019, UGI International had over 2,700 employees.
MIDSTREAM & MARKETING
Retail Energy Marketing
Our retail energy marketing business is conducted through Energy Services and sells natural gas, liquid fuels and electricity to more than 13,000 residential, commercial and industrial customers at approximately 41,000 locations. We (i) serve customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Massachusetts, Virginia, North Carolina, South Carolina, Rhode Island and the District of Columbia, (ii) distribute natural gas through the use of the distribution systems of 42 local gas utilities, and (iii) supply power to customers through the use of the transmission lines of 20 utility systems.
Historically, a majority of Energy Services’ commodity sales have been made under fixed-price agreements, which typically contain a take-or-pay arrangement that permits customers to purchase a fixed amount of product for a fixed price during a specified period, and requires payment even if the customer does not take delivery of the product. However, a growing number of Energy Services’ commodity sales are currently being made under requirements contracts, under which Energy Services is typically an exclusive supplier and will supply as much product at a fixed price as the customer requires. Energy Services manages supply cost volatility related to these agreements by (i) entering into fixed-price supply arrangements with a diverse group of suppliers, (ii) holding its own interstate pipeline transportation and storage contracts to efficiently utilize gas supplies, (iii) entering into exchange-traded futures contracts on NYMEX and ICE, (iv) entering into over-the-counter derivative arrangements with major international banks and major suppliers, (v) utilizing supply assets that it owns or manages, and (vi) utilizing financial transmission rights to hedge price risk against certain transmission costs. Energy Services also bears the risk for balancing and delivering natural gas and power to its customers under various gas pipeline and utility company tariffs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”
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Midstream Assets
LNG
Our midstream assets, which are owned by Energy Services and its subsidiaries, comprise a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania, a natural gas liquefaction and storage facility in Mehoopany, Pennsylvania, and a natural gas vaporization and storage facility in Steelton, Pennsylvania.
In Fiscal 2019, our Midstream & Marketing segment continued making investments to expand its energy peaking and LNG business. Energy Services initiated construction of a large-scale LNG peak shaving facility in Bethlehem, Pennsylvania, which is designed to provide 70,000 dekatherms per day of peaking capacity and two million gallons of LNG storage. In addition, Energy Services purchased two portable LNG peak shaving systems, which include skid mounted LNG vaporizers, storage and LNG transport trailers, each designed to provide up to 5,000 dekatherms per day of peaking.
In addition, Energy Services sells LNG to customers for use by trucks, drilling rigs, other motor vehicles and facilities located off the natural gas grid. In Fiscal 2019, our Midstream & Marketing segment also managed natural gas pipeline and storage contracts for utility company customers, including UGI Utilities.
Storage
Energy Services and its subsidiaries also own mobile natural gas vaporization and storage facilities in Mount Carmel and Reading, Pennsylvania, and propane storage and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. Energy Services and its subsidiaries also operate propane storage, rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport, Pennsylvania. These assets are used in Midstream & Marketing’s energy peaking business that provides supplemental energy, primarily LNG and propane-air mixtures, to gas utilities at times of high demand (generally during periods of coldest winter weather).
A wholly owned subsidiary of Energy Services owns and operates underground natural gas storage and related high pressure pipeline facilities, which have FERC approval to sell storage services at market-based rates. The storage facilities are located in the Marcellus Shale region of north-central Pennsylvania and have a total storage capacity of 15 million dekatherms and a maximum daily withdrawal quantity of 224,000 dekatherms. In Fiscal 2019, Energy Services leased approximately 80% of the firm capacity at its underground natural gas facilities to third parties.
Gathering Systems and Pipelines
Energy Services also operates the Auburn gathering system in the Marcellus Shale region of northeastern Pennsylvania with a total system capacity of 635,000 dekatherms per day, including the expansion that was completed in November 2019. The gathering system delivers into both the Tennessee Gas and Transcontinental Gas pipelines. Energy Services owns and operates approximately 60 miles of natural gas gathering lines, dehydration and compression facilities located in Bradford, Tioga, Lycoming and Potter Counties, Pennsylvania, as well as 3.6 miles of natural gas gathering lines located in Clinton County, Pennsylvania.
Energy Services and its subsidiaries also own and operate a 35 mile, 20-inch pipeline, known as the Sunbury pipeline, with related facilities located in Snyder, Union, Northumberland, Montour, and Lycoming Counties, Pennsylvania, which has a design capacity of 200,000 dekatherms per day. In addition, Energy Services owns and operates the Mt. Bethel pipeline, which runs 12.5 miles in Northampton County, Pennsylvania and is designed to provide 72,000 dekatherms per day. The Union Dale pipeline is a 6 mile, 12-inch pipeline operated by Energy Services, located in Susquehanna County, Pennsylvania.
On August 1, 2019, Energy Services completed the CMG Acquisition for approximately $1.275 billion. The acquired assets consist of five natural gas gathering systems and one processing plant in southwestern Pennsylvania, eastern Ohio, and the panhandle of West Virginia. Energy Services also purchased a 47% ownership interest in Pennant, one of the acquired systems. The acquired assets provide natural gas gathering and processing services in the Appalachian Basin with gathering capacity of approximately 2,675,000 dekatherms per day and processing capacity of approximately 240,000 dekatherms per day.
In Fiscal 2019, our Midstream & Marketing segment continued to develop the PennEast Pipeline project, an approximately 120-mile pipeline from Luzerne County, Pennsylvania to the Transco pipeline interconnection in Mercer County, New Jersey. When completed, the pipeline will transport over 1 Bcf of low-cost natural gas to residential and commercial customers each day. In September 2019, a panel of the U.S. Court of Appeals for the Third Circuit ruled that New Jersey’s Eleventh Amendment immunity barred PennEast from bringing an eminent domain lawsuit in federal court, under the Natural Gas Act, against the State of New
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Jersey or its agencies. The Third Circuit subsequently denied PennEast’s petition for rehearing en banc. In addition, in October 2019, in reliance on the Third Circuit ruling, the New Jersey Department of Environmental Protection rejected PennEast’s application for certain project permits. PennEast has filed a petition for declaratory order with FERC regarding interpretation of the Natural Gas Act. PennEast also expects to file a petition for a writ of certiorari to seek U.S. Supreme Court review of the Third Circuit decision. The ultimate outcome of these matters cannot be determined at this time, and could result in delays, additional costs, or the inability to move forward with the project, resulting in an impairment of all or a portion of our investment in PennEast. See “Risk Factors - The expansion, construction and development of our energy infrastructure assets subjects us to risks.”
Electricity Generation Assets
Midstream & Marketing’s electricity generation assets consist of electric generation facilities conducted by Energy Services’ wholly owned subsidiary, UGID. UGID, through a wholly owned subsidiary, has an approximate 5.97% (approximately 102 megawatt) ownership interest in the Conemaugh generation station, a 1,711-megawatt, coal-fired electricity generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of GenOn Energy. UGID also owns and operates the Hunlock Station located near Wilkes-Barre, Pennsylvania, a 130-megawatt natural gas-fueled electricity generating station, and owns and operates a landfill gas-fueled generation plant near Hegins, Pennsylvania, with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits. Additionally, UGID owns and operates 13.5 megawatts of solar-powered generation capacity in Pennsylvania, Maryland and New Jersey. UGID, through another wholly owned subsidiary, owns and operates a 44-megawatt natural gas-fueled electricity generation station.
HVAC Business
Our Midstream & Marketing segment also conducts a heating, ventilation, air conditioning, mechanical & electrical contracting, and project management service business through its HVAC business unit, which serves portions of eastern and central Pennsylvania. This business serves customers in residential, commercial, industrial and new construction markets.
Competition
Our Midstream & Marketing segment competes with other midstream operators to sell gathering, compression, storage and pipeline transportation services. Our Midstream & Marketing segment competes in both the regulated and non-regulated environment against interstate and intrastate pipelines that gather, compress, process, transport and market natural gas. Our Midstream & Marketing segment sells midstream services primarily to producers, marketers and utilities on the basis of price, customer service, flexibility, reliability and operational experience. The competition in the midstream segment is significant and has grown recently in the northeast U.S. as more competitors seek opportunities offered by the development of the Marcellus and Utica Shales.
Our Midstream & Marketing segment also competes with other marketers, consultants and local utilities to sell natural gas, liquid fuels, electric power and related services to customers in its service area principally on the basis of price, customer service and reliability. Midstream & Marketing’s midstream asset business has faced an increase in competition in recent years with the consolidation of companies that have resulted in large, national competitors that can offer a suite of services across all customer segments.
Our electricity generation assets compete with other generation stations on the interface of PJM, a regional transmission organization that coordinates the movement of wholesale electricity in certain states, including the states in which we operate, and bases sales on bid pricing.
Government Regulation
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy, as well as the sales for resale of natural gas and related storage and transportation services. Energy Services has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates. Energy Services also has market-based rate authority for power sales to wholesale customers, to the extent that Energy Services purchases power in excess of its retail customer needs. Two subsidiaries of Energy Services currently operate natural gas storage facilities under FERC certificate approvals and offer services to wholesale customers at FERC-approved market-based rates. Two other Energy Services subsidiaries operate natural gas pipelines that are subject to FERC regulation. UGI Mt. Bethel Pipeline Company, LLC operates a 12.5-mile, 12-inch pipeline located in Northampton County, Pennsylvania, and UGI Sunbury, LLC operates the Sunbury Pipeline, a 35-mile, 20-inch diameter pipeline located in central Pennsylvania. Energy Services and its subsidiaries undertake various activities to maintain compliance with the FERC Standards of Conduct with respect to pipeline operations. Energy Services is also subject to
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FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers with respect to its wholesale commodity business.
Midstream & Marketing’s midstream assets include natural gas gathering pipelines and compression and processing in northeastern Pennsylvania, southwestern Pennsylvania, eastern Ohio and the panhandle of West Virginia that are regulated under the Pipeline Safety Improvement Act of 2002 and subject to operational oversight by both the Pipeline and Hazardous Materials Safety Administration and the PAPUC.
Certain of our Midstream & Marketing businesses are subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, OSHA, the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. With respect to the operation of natural gas gathering and transportation pipelines, Energy Services also is required to comply with the provisions of the Pipeline Safety Improvement Act of 2002 and the regulations of the DOT.
Our Midstream & Marketing’s electricity generation assets own electric generation facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. UGID receives certain revenues collected by PJM, determined under an approved rate schedule. Like Energy Services, UGID has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates, and FERC has approved UGID’s market-based rate authority through 2019. UGID is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers.
Employees
At September 30, 2019, Midstream & Marketing had over 700 employees, including nearly 300 employees in its HVAC business and 20 employees at UGID.
UGI UTILITIES
GAS UTILITY
Gas Utility consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities. Gas Utility serves nearly 655,000 customers in eastern and central Pennsylvania and more than 500 customers in portions of one Maryland county. Gas Utility is regulated by the PAPUC and, with respect to its customers in Maryland, the MDPSC.
Service Area; Revenue Analysis
Gas Utility provides natural gas distribution services to nearly 655,000 customers in certificated portions of 44 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 90% of Gas Utility’s more than 12,300 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron pipe comprising approximately 2% of Gas Utility’s gas mains. In accordance with Gas Utility’s agreement with the PAPUC, Gas Utility will replace the cast iron portion of its gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass, paper product manufacturing, and several power generation facilities. Gas Utility also distributes natural gas to more than 500 customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2019 was approximately 294 Bcf. System sales of gas accounted for approximately 21% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 79% of system throughput.
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Sources of Supply and Pipeline Capacity
Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 9 to Consolidated Financial Statements. Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase contracts with marketers and producers, along with storage and transportation service contracts. These arrangements enable Gas Utility to purchase gas from Marcellus, Gulf Coast, Mid-Continent, and Appalachian sources. For its transportation and storage functions, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., Tennessee Gas Pipeline Company, L.L.C., and Energy Services and its subsidiaries (including UGI Storage Company and UGI Sunbury, LLC).
Gas Supply Contracts
During Fiscal 2019, Gas Utility purchased approximately 83 Bcf of natural gas for sale to retail core-market customers (principally composed of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility) and off-system sales customers. Nearly 94% of the volumes purchased were supplied under agreements with 10 suppliers, with the remaining volumes supplied by 13 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 12 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. For Fiscal 2019, approximately 59% of Gas Utility’s sales volume was supplied, and approximately 92% of Gas Utility’s operating income was earned, during the peak heating season from October through March.
Competition
Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity and propane. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing and sales efforts designed to retain, expand, and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PAPUC or by law, to provide gas distribution services. All of Gas Utility’s customers, including core-market customers, have the right to purchase gas supplies from entities other than natural gas distribution utility companies.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates that are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, the frequency and duration of interruptions, and alternative firm service options. See “Gas Utility Regulation and Rates - PAPUC Jurisdiction and Gas Utility Rates.”
Approximately 47% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible customers with firm rates with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, nearly 15% of Gas Utility’s annual throughput volume for commercial and industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline. Gas Utility has 23 such customers, 21 of which have transportation contracts extending beyond Fiscal 2020. The majority of these customers are served under transportation contracts having 3- to 20-year terms and all are among the largest customers for Gas Utility in terms of annual volumes. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity, peaking services and other sources of supply available to it to meet the full requirements of all firm customers on its system through Fiscal 2020. Supply mix is diversified, market priced and delivered pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility’s larger customers.
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During Fiscal 2019, Gas Utility supplied transportation service to 10 electric generation facilities and installed new service to two co-generation facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2019, Gas Utility connected approximately 2,100 new commercial and industrial customers. In the residential market sector, Gas Utility added nearly 11,800 residential heating customers during Fiscal 2019. Approximately 51% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2019.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings that relate to (i) the pricing of pipeline services in a competitive energy marketplace, (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts, and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.
UGI Utilities’ objective in negotiations with providers of gas supply resources, and in proceedings before regulatory agencies, is to ensure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security with guaranteed deliverability and reliability of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.
Gas Utility Regulation and Rates
PAPUC Jurisdiction and Gas Utility Rates
Gas Utility is subject to regulation by the PAPUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, gas safety and various other matters. Rates that Gas Utility may charge for gas service come in two forms: (i) rates designed to recover PGCs; and (ii) rates designed to recover costs other than PGCs. Rates designed to recover PGCs are reviewed in PGC proceedings. Rates designed to recover costs other than PGCs are primarily established in general base rate proceedings.
In a PAPUC order dated September 20, 2018, the PAPUC granted authority for (i) the merger of PNG and CPG with and into UGI Gas, (ii) the adoption by UGI Utilities of the preexisting PNG and CPG tariffs, rates and terms and conditions of service for inclusion in the UGI Gas tariff, and (iii) operation as three separate rate districts, namely, UGI North, UGI South and UGI Central. The merger, which became effective October 1, 2018, was also separately approved by the MDPSC.
On October 4, 2019, the PAPUC issued a final order approving a settlement of a base rate proceeding by the merged Gas Utility that permits Gas Utility, effective October 11, 2019, to increase its base distribution revenues by $30.0 million under a single tariff, approves a plan for uniform class rates, and permits Gas Utility to extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by additional terms of 5 years.
Act 11 authorized the PAPUC to permit electric and gas distribution companies, between base rate cases and subject to certain conditions, to recover reasonable and prudent costs incurred to repair, improve or replace eligible property through a DSIC assessed to customers. Among other requirements, DSICs are subject to quarterly adjustment and are capped at five percent of total customer charges absent a PAPUC-granted exception. In addition, Act 11 requires affected utilities to obtain approval of LTIIPs from the PAPUC. Act 11 also authorized electric and gas distribution companies to utilize a fully forecasted future test year when establishing rates in base rate cases before the PAPUC.
Prior to the Utility Merger, the PAPUC approved LTIIPs and DSIC rate mechanisms for UGI Gas and its former CPG and PNG subsidiaries (now Gas Utility). The approved LTIIPs, in the aggregate, increased the projected spend on DSIC-eligible property for the 2016-2018 period from approximately $266.3 million to $402.8 million and have been extended through December 2019 for an additional $185.0 million of projected spend on DSIC-eligible property. The PAPUC also issued a series of orders approving DSIC rate mechanisms for UGI Gas, and the former PNG and CPG subsidiaries, which cap the Gas Utility DSIC charge in each of the pre-merger service territories to 5 percent, 7.5 percent, and 7.5 percent, respectively, of total base distribution revenue through the end of the 2019 LTIIP period.
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On August 21, 2019, Gas Utility filed a new consolidated LTIIP designed for the 2020-2024 calendar years (the “Gas LTIIP II”), during which Gas Utility projects spending $1.265 billion on DSIC-eligible property. This matter is currently pending before the PAPUC.
With the effective date of new base distribution rates on October 11, 2019, the DSIC-eligible property revenue requirement is included in base distribution revenue recovery and Gas Utility is no longer recovering any DSIC revenue. Gas Utility DSIC revenues will resume once the Gas LTIIP II is approved, the plant in-service targets provided in the base rate case settlement are reached, and UGI Utilities otherwise qualifies to place a new DSIC charge into effect. Unless Gas Utility seeks and receives a PAPUC waiver of the statutory 5 percent rate cap, any future DSIC charges will be capped at 5 percent of overall Gas Utility annual base revenue.
Gas Utility’s tariffs include a uniform PGC rate applicable to firm retail rate schedules for customers who do not obtain natural gas supply service from an alternative supplier. The PGC rate permits recovery of all prudently incurred costs of natural gas that UGI Gas sells to its retail customers. PGC rates are reviewed and approved annually by the PAPUC. Gas Utility may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on one day’s notice to the PAPUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PAPUC six months prior to its effective date. During this period, the PAPUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PAPUC issues an order permitting the collection of gas costs at levels that meet such standard. The PGC mechanism also provides for an annual reconciliation and for the payment or collection of interest on over and under collections. Gas Utility may release or sell to and recover from alternative natural gas suppliers the costs of gas supply contracts and transportation capacity acquired to serve the needs of smaller volume customers who elect to receive their natural gas supply service from an alternative supplier.
On April 28, 2017, UGI Gas, PNG and CPG filed the GDE with the PAPUC. The GDE provides a tariff mechanism to recover from certain non-choice transportation customers a portion of the GDE Charges that are incurred to achieve least-cost timely solutions to system reinforcement needs or for pipeline integrity management activities. GDE Charges exclude costs that are recovered through the PGC rate mechanism in Gas Utility’s annual 66 Pa.C.S. § 1307(f) PGC proceeding. On August 31, 2017, the PAPUC entered an order approving the GDE Rider for all three companies. This rider has been consolidated as part of the October 4, 2019 final PAPUC Order in Gas Utility’s base distribution rate proceeding.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
UGI Utilities is subject to Section 4A of the Natural Gas Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas or natural gas transportation subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of gas markets. UGI Utilities is also subject to Section 222 of the Federal Power Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of electric energy or transmission service subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of electric markets.
State Tax Surcharge Clauses
UGI Utilities’ gas service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.
Utility Franchises
Gas Utility holds certificates of public convenience issued by the PAPUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on its business in substantially all of the territories to which they now render gas service. Under applicable Pennsylvania law, Gas Utility also has certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.
Other Government Regulation
In addition to regulation by the PAPUC, MDPSC and FERC, Gas Utility is subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. Gas Utility is subject to the requirements
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of the Resource Conservation and Recovery Act, CERCLA and comparable state statutes with respect to the release of hazardous substances. See Note 16 to Consolidated Financial Statements.
Employees
At September 30, 2019, Gas Utility had approximately 1,620 employees.
ELECTRIC UTILITY
Electric Utility supplies electric service to more than 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,500 miles of transmission and distribution lines and 14 substations. For Fiscal 2019, approximately 56% of sales volume came from residential customers, 32% from commercial customers, and 12% from industrial and other customers. During Fiscal 2019, 15 retail electric generation suppliers provided energy for customers representing approximately 25% of Electric Utility’s sales volume. At September 30, 2019, UGI Utilities’ electric utility operations had approximately 60 employees.
Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with and approved by the PAPUC. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers.
On October 25, 2018, the PAPUC entered an Opinion and Order in Electric Utility’s base rate proceeding authorizing a $3.2 million increase in annual base distribution rates effective October 27, 2018. The PAPUC also authorized Electric Utility to establish a new reconcilable surcharge to permit the timely recovery of the costs of universal service programs designed to assist low income customers and required Electric Utility to refund approximately $0.2 million of tax benefits and associated interest relating to the TCJA through a one-time bill credit. Two issues arising in this matter relating to the use of a fully projected future test year and the treatment of tax benefits achieved through UGI’s consolidated federal tax filings have been appealed to the Pennsylvania Commonwealth Court by the Pennsylvania Office of Consumer Advocate. Electric Utility has intervened in support of the PAPUC’s decision adopting Electric Utility’s position on both issues.
Electric Utility’s tariff includes rates, applicable to so-called “default service” customers who do not obtain electric generation service from an alternative supplier, incurred pursuant to a PAPUC-approved supply plan. These default service rates are reconcilable, may be adjusted quarterly, and are designed to permit Electric Utility to recover the full costs of providing default service in a full and timely manner. Electric Utility has received PAPUC approval of its current default service rules and supply plan through May 31, 2021. Electric Utility’s default service rates include recovery of costs associated with compliance with the AEPS Act, which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources. Electric Utility’s LTIIP was approved by the PAPUC on December 21, 2017 for the 2018-2022 time period. Electric Utility’s projected annual investment in distribution infrastructure replacement was approximately $7.6 million in Fiscal 2018, and will increase to $8.3 million by the fiscal year ending September 30, 2022. On September 3, 2019, with eligibility established with the completion of its base rate case and the approval of its initial LTIIP, Electric Utility filed to establish a DSIC rate mechanism that will permit it to impose a DSIC surcharge to recover revenue requirement associated with DSIC-eligible plant once certain capital plant targets established in the rate case and other eligibility criteria are met. This filing is currently pending before the PAPUC.
FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties. FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.
Under provisions of the EPACT 2005, Electric Utility is subject to certain electric reliability standards established by FERC and administered by an ERO. Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.
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EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for Fiscal 2019, Fiscal 2018 and Fiscal 2017 appears in Note 22 to Consolidated Financial Statements included in Item 15 of this Report and is incorporated herein by reference.
EMPLOYEES
At September 30, 2019, UGI and its subsidiaries had approximately 12,800 employees.
ITEM 1A. RISK FACTORS
There are many factors that may affect our business and results of operations. Additional discussion regarding factors that may affect our business and operating results is included elsewhere in this Report.
Our business is seasonal and decreases in the demand for our energy products and services because of warmer-than-normal heating season weather or unfavorable weather conditions may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and businesses, and for agricultural purposes such as crop drying, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. For example, historically, approximately 60% to 70% of AmeriGas Propane’s annual retail propane volume, 60% to 70% of UGI International’s annual retail LPG volume, and 60% to 70% of Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) has typically been sold during these months. Additionally, as a result of the AmeriGas Merger, we expect that an even greater portion of our earnings will be derived during the peak heating season of October through March. There can be no assurance that normal winter weather in our market areas will occur in the future.
In addition, our agricultural customers use LPG for purposes other than heating, including for crop drying, and unfavorable weather conditions, such as lack of precipitation, may impact the demand for LPG. Moreover, harsh weather conditions may at times impede the transportation and delivery of LPG, or restrict our ability to obtain LPG from suppliers. Spikes in demand caused by weather or other factors can stress the supply chain and limit our ability to obtain additional quantities of LPG. Changes in LPG supply costs are normally passed through to customers, but time lags (between when we purchase the LPG and when the customer purchases the LPG) may result in significant gross margin fluctuations that could adversely affect our results of operations.
Our efforts to create operational benefits and cost efficiencies through business transformation initiatives at our business units may be disruptive and adversely affect our business, financial condition and results of operations.
We may make adjustments to our workforce in response to management changes, product changes, performance issues, changes in strategy, acquisitions or other internal and external considerations. These adjustments may result in increased costs and temporarily reduced productivity, as well as a disruption in our ability to perform functions critical to our strategy. The effects of such adjustments could recur in connection with any current or future business transformation initiatives or we may not achieve or sustain the expected growth or cost savings benefits of any such initiatives, or do so within the expected timeframe. As a result, our business, financial condition and results of operations could be negatively affected.
We are currently engaged in business transformation initiatives at our AmeriGas Propane and UGI International businesses designed to achieve operational benefits and cost efficiencies and to leverage technology to provide an enhanced customer experience. If we are unable to deliver the strategic and financial benefits that we anticipate, the achievement of these benefits is delayed, or the volume and nature of change overwhelms available resources, then our business operations and financial results could be materially and adversely impacted. Our ability to successfully manage and execute these initiatives and realize expected savings and benefits in the amounts and at the times anticipated is important to our business success. Any failure to do so, which could result from our inability to successfully execute organizational change and business transformation initiatives, unanticipated costs or charges, loss of key personnel and other factors described herein, could have a material adverse effect on our business, financial
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condition and results of operations. For further information on these initiatives, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Global LPG Business Transformation Initiatives.”
Our potential to increase revenues may be affected by the decline in retail volumes of LPG and our ability to retain and grow our customer base.
The retail LPG distribution industry in the U.S. and many of the European countries in which we operate is mature and has been declining over the past several years, with no or modest growth (or decline) in total demand foreseen in the next several years. Accordingly, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the domestic ACE and National Accounts programs in the U.S. and expansion in Europe, as well as the success of our sales and marketing programs designed to attract and retain customers. A failure to retain and grow our customer base would have an adverse effect on our results. Acquisitions in the U.S. and Europe may require merger control filings with the Federal Trade Commission and the European Commission, as applicable, and commitments or divestments of assets may be required to obtain clearance. Such commitments or divestments may influence the overall economics of the transaction.
Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have completed.
One of our strategies is to grow through acquisitions in the U.S. and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance an acquisition will not affect our ability to pay dividends. Moreover, acquisitions may require antitrust and other regulatory clearances. We may have to offer commitments (such as agreements not to compete for certain businesses) or divest assets to obtain clearance, which may adversely affect the overall economics of the transaction.
To the extent we are successful in making acquisitions, including the CMG Acquisition completed on August 1, 2019, such acquisitions involve a number of risks. These risks include, but are not limited to, the assumption of material liabilities, environmental liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices and internal controls, as well as in the assimilation of broad and geographically dispersed personnel and operations. Future acquisitions could also result in, among other things, the failure to identify material issues during due diligence, the risk of overpaying for assets, unanticipated capital expenditures, the failure to maintain effective internal control over financial reporting, recording goodwill and other intangible assets at values that ultimately may be subject to impairment charges and fluctuations in quarterly results. There can also be no assurance that our past and future acquisitions will deliver the strategic, financial and operational benefits that we anticipate. The failure to successfully integrate the CMG Acquisition and other acquisitions could have an adverse effect on our business, cash flows, financial condition and results of operations.
Energy efficiency and technology advances, as well as price induced customer conservation, may result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for LPG and natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase, which may lead to customer conservation and attrition. A reduction in demand could lower our revenues and, therefore, lower our net income and adversely affect our cash flows. State and/or federal regulation may require mandatory conservation measures, which would reduce the demand for our energy products. Additionally, at the international level, EU and local laws and regulations may require mandatory conservation measures, which would reduce the demand for our energy products. The EU revised the Energy Performance of Buildings Directive (“EPBD”) in 2018, with the goal to create a clear path towards a low and zero-emission and decarbonized building stock in the EU by 2050. EU countries have until March 2020 to adopt laws to implement the EPBD. The EU is also adopting further measures to decarbonize electricity generation in order to reduce dependence on fossil fuel imports and achieve its climate change objectives. Over time, these various measures will impact fossil fuel consumption in Europe. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.
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Our operations may be adversely affected by competition from other energy sources.
Our energy products and services face competition from other energy sources, some of which are less costly for equivalent energy value. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.
Our LPG distribution businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a major competitor of LPG but, except in France, is generally more expensive than LPG on a Btu equivalent basis for space heating, water heating and cooking. However, in Europe and elsewhere, climate change policies favoring electricity from renewable energy sources may cause changes in current relative price relationships. Moreover, notwithstanding cost, the convenience and efficiency of electricity make it an attractive energy source for consumers and developers of new homes. In addition, due to the prevalence of nuclear electric generation in France, the cost of electricity is generally less expensive than that of LPG, particularly when the cost to install new equipment to convert to LPG is considered. Fuel oil is also a major competitor of LPG and, although a less environmentally attractive energy source, is currently less expensive than propane. Furnaces and appliances that burn LPG will not operate on fuel oil and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less expensive than LPG. Except for certain industrial and commercial applications, LPG is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a significantly less expensive source of energy than LPG. The gradual expansion of natural gas distribution systems in our service areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon LPG. As long as natural gas remains a less expensive energy source than LPG, our LPG business will lose customers in each region into which natural gas distribution systems are expanded.
Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. There can be no assurance that our natural gas revenues will not be adversely affected by this competition.
If we are unable to protect our information technology systems against service interruption, misappropriation of data, or breaches of security resulting from cyber-security attacks or other events, or we encounter other unforeseen difficulties in the design, implementation or operation of our information technology systems, our operations could be disrupted, our business and reputation may suffer, and our internal controls could be adversely affected.
In the ordinary course of business, we rely on information technology systems, including the Internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) our proprietary business information and that of our suppliers and business partners, (iii) personally identifiable information of our customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. In addition, we rely on our information technology systems to process financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements. Despite our security measures, our information technology systems may be vulnerable to attacks by hackers or breached due to employee error, malfeasance, sabotage, or other disruptions. Similarly, our vendors or service providers could sustain the same risks and disruptions as described above. A loss of our information technology systems, or temporary interruptions in the operation of our information technology systems, or those of our vendors or service providers, or any other misappropriation of data, or breaches of security could have a material adverse effect on our business, financial condition, results of operations, and reputation. In addition, a cyber-security attack could provide a cyber-intruder with the ability to control or alter our pipeline operations. Such an act could result in critical pipeline failures.
Moreover, the efficient execution of the Company’s businesses is dependent upon the proper design, implementation and functioning of its current and future internal systems, such as the information technology systems that support the Company’s underlying business processes. Any significant failure or malfunction of such information technology systems may result in disruptions of our operations. In addition, the effectiveness of our internal controls could be adversely affected if we encounter unforeseen problems with respect to the operation of our information technology systems. While we have purchased cyber-security insurance, there are no assurances that the coverage would be adequate in relation to any incurred losses.
The expansion, construction and development of our energy infrastructure assets subjects us to risks.
We seek to grow our business through the expansion, construction and development of our energy infrastructure, including new pipelines, such as PennEast, gathering systems, facilities and other assets. These projects are subject to state and federal regulatory oversight and require certain property rights, such as easements and rights-of-way from public and private owners, as well as regulatory approvals, including environmental and other permits and licenses. There is no assurance that we or our project partners, as applicable, will be able to obtain the necessary property rights, permits and licenses in a timely and cost-efficient manner or at
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all, which may result in a delay or failure to complete a project. We may face opposition to the expansion, construction or development of new or existing pipelines, gathering systems, facilities or other assets from environmental groups, landowners, local groups and other advocates. This opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the development or operation of our assets and business. Failure to complete any pending or future infrastructure project may have a materially adverse impact on our financial condition and results of operations.
Even if we are able to successfully complete any pending or future infrastructure project, our revenues may not increase immediately upon the expenditure of funds on a particular project. We may expand, construct or develop energy infrastructure to capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize. As a result, there is the risk that new and expanded energy infrastructure may not be able to attract enough customers to achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Our utility transmission and distribution systems, our non-utility midstream assets, and the assets of upstream interstate pipelines and other midstream providers may not operate as planned, which may increase our expenses or decrease our revenues and, thus, have an adverse impact on our financial results.
Our ability to manage operational risk with respect to utility distribution and transmission and non-utility midstream assets, and the availability of natural gas delivered by interstate natural gas pipelines and midstream gathering assets is critical to our financial results. We obtain our supply from local Marcellus Shale sources, as well as other trading points in the U.S. If we experience physical capacity constraints on one or more of the interstate or intrastate natural gas pipelines that supply our businesses, we may not be able to supply our customers, which could have an adverse impact on our financial results. Our businesses also face several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors, including as a result of overpressurization of or damage to natural gas pipelines. Operation of our transmission and distribution systems or our midstream assets below our expectations may result in lost revenues or increased expenses, including higher maintenance costs, civil litigation and the risk of regulatory penalties.
Our international operations could be subject to increased risks, which may negatively affect our business results.
We operate LPG distribution and energy marketing businesses in Europe through our subsidiaries and we continue to explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:

• | costs and difficulties in staffing and managing international operations;

• | potentially adverse tax consequences, including restrictions on repatriating earnings, potential increases to corporate income taxes and the threat of “double taxation”;

• | fluctuations in currency exchange rates, which can affect demand for our products, increase our costs and adversely affect our profitability and reported results;

• | regulatory requirements and changes in regulatory requirements, including European competition laws that may adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter regulations applicable to the storage and handling of LPG;

• | economic and political uncertainty relating to the United Kingdom’s vote to withdraw from the EU, commonly known as “Brexit,” and the ongoing negotiations to determine the terms of such withdrawal, which may result in, among other things, increased regulatory costs and challenges, greater volatility in the British pound sterling and euro, business disruptions and increased tariffs;

• | new and inconsistently enforced industry regulatory requirements, which can have an adverse effect on our competitive position;

• | tariffs and other trade barriers;

• | difficulties in enforcing contractual rights;

• | longer payment cycles;

• | local political and economic conditions; and

• | potential violations of federal regulatory requirements, including anti-bribery, anti-corruption, and anti-money laundering law, economic sanctions, the Foreign Corrupt Practices Act of 1977, as amended, and EU regulatory requirements, including the GDPR and Sapin II.

In particular, certain legal and regulatory risks are associated with international business operations. We are subject to various anti-corruption, economic sanctions and trade compliance laws, rules and regulations. For example, the U.S. government imposes restrictions and prohibitions on transactions in certain foreign countries, including restrictions directed at oil and gas activities in
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Russia. U.S. laws also prohibit the improper offer, payment, promise to pay, or authorization of the payment of money or anything of value to any foreign official or political party, or to any person, knowing that all or a portion of it will be used to influence a foreign official in his or her official duties or to secure an improper advantage. Ensuring compliance with all relevant laws, rules and regulations is a complex task. Violation of one or more of these laws, rules or regulations could lead to loss of import or export privileges, civil or criminal penalties for us or our employees, or potential reputational harm, which could have a material adverse impact on earnings, cash flows and financial condition.
We are dependent on our principal LPG suppliers, which increases the risks from an interruption in supply and transportation.
During Fiscal 2019, AmeriGas Propane purchased approximately 84% of its propane needs from 20 suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain geographic areas, a single supplier may provide more than 50% of AmeriGas Propane’s propane requirements. Disruptions in supply in these geographic areas could also have an adverse impact on our earnings. Our international businesses are similarly dependent upon their LPG suppliers. For example, during Fiscal 2019, UGI International’s business in the United Kingdom purchased approximately 88% of its LPG needs from two suppliers and, in Italy, approximately 50% of its supply was sourced from a single supplier. If supplies from UGI International’s principal LPG sources are interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and our earnings could be adversely affected. There is no assurance that our international businesses will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow them to remain competitive.
Our ability to obtain sufficient quantities of LPG is dependent on transportation facilities and providers.
Spikes in demand caused by weather or other factors can limit our access to port terminals and other transportation and storage facilities, disrupt transportation and limit our ability to obtain sufficient quantities of LPG. A significant increase in port and similar fees and fuel prices may also adversely affect our transportation costs and business. Transportation providers (rail and truck) in some circumstances have limited ability to provide additional resources in times of peak demand. Moreover, our transportation providers maintaining a staff of qualified truck drivers is critical to the success of our business. Regulatory requirements and an improvement in the economy could reduce the number of eligible drivers or require us to pay higher transportation fees as our transportation providers seek to pass on additional labor costs associated with attracting and retaining drivers.
We may not be able to collect on the accounts of our customers.
We depend on the viability of our customers for collections of accounts receivable and notes receivable. Moreover, our businesses serve numerous retail customers, and as we grow our businesses organically and through acquisitions, our retail customer base is expected to significantly expand. There can be no assurance that our customers will not experience financial difficulties in the future or that we will be able to collect all of our outstanding accounts receivable or notes receivable and any such nonpayment by our customers could adversely affect our business.
Our profitability is subject to LPG pricing and inventory risk.
The retail LPG business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to fluctuations in response to changes in supply or other market conditions. We have no control over supplies, commodity prices or market conditions. Consequently, the unit price of the LPG that our subsidiaries and other distributors and marketers purchase can change rapidly over a short period of time. Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG supply contracts are based on internationally quoted market prices. We also purchase a portion of our supplies in the spot market. Because our subsidiaries’ profitability is sensitive to changes in wholesale LPG supply costs, it will be adversely affected if we cannot pass on increases in the cost of LPG to our customers, or if there is a delay in passing on such cost increases. Due to competitive pricing in the industry, our subsidiaries may not fully be able to pass on product cost increases to our customers when product costs rise, or when our competitors do not raise their product prices in a timely manner. Finally, market volatility may cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating results.
We offer our customers various fixed-price LPG programs, and a significant number of our customers utilize our fixed-price programs. In order to manage the price risk from offering these services, we utilize our physical inventory position, supplemented by forward commodity transactions with various third parties having terms and volumes substantially the same as our customer’s contracts, but there can be no assurance that such measures will be effective. In periods of high LPG price volatility, the fixed-
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price programs create exposure to over or under-supply positions as the demand from customers may significantly exceed or fall short of supply procured. In addition, if LPG prices decline significantly subsequent to customers signing up for a fixed-price program, there is a risk that customers will default on their commitments, adversely affecting our results of operations.
Changes in commodity market prices may have a significant negative effect on our liquidity.
Depending on the terms of our contracts with suppliers as well as our use of financial instruments to reduce volatility in the cost of LPG and natural gas, changes in the market price of LPG and natural gas can create margin payment obligations for us and expose us to increased liquidity risk. In addition, increased demand for domestically produced LPG and natural gas overseas may, depending on production volumes in the U.S., result in higher domestic LPG prices and expose us to additional liquidity risks.
Supplier defaults may have a negative effect on our operating results.
When we enter into fixed-price sales contracts with customers, we typically enter into fixed-price purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our contracts with suppliers of LPG, natural gas and electricity, a default of or force majeure by one or more of our suppliers under such contracts could cause us to purchase those commodities at higher prices, which would have a negative impact on our operating results.
We are subject to operating and litigation risks that may not be covered by insurance.
Our business operations are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as LPG, propane and natural gas, and the generation of electricity. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As a result of these and other incidents, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business, including regulatory investigations, claims, lawsuits and other proceedings. Additionally, environmental contamination could result in future legal proceedings. There can be no assurance that our insurance coverage will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance would be available in the future at economical prices. Moreover, defense and settlement costs may be substantial, even with respect to claims and investigations that have no merit. If we cannot resolve these matters favorably, our business, financial condition, results of operations and future prospects may be materially adversely affected.
The risk of natural disasters and catastrophic events, including terrorism, may adversely affect the economy and the price and availability of LPG, other refined fuels and natural gas.
Natural disasters and catastrophic events, such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, terrorist attacks, political unrest and other similar occurrences, may adversely impact the price and availability of LPG (including propane), other refined fuels and natural gas, which could adversely impact our financial condition and results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industries in general, and on us in particular, is not known at this time. A natural disaster or an act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of LPG), cause price volatility in the cost of LPG, fuel oil and natural gas, and our infrastructure facilities could be direct or indirect targets. A natural disaster or terrorist activity may also hinder our ability to transport LPG and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of a natural disaster or terrorism could also affect our ability to raise capital. We have opted to purchase insurance coverage for natural disasters and terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage would be adequate to fully compensate us for any losses to our business or property resulting from natural disasters or terrorist acts.
Our holding company structure could limit our ability to pay dividends or service debt.
We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, and Enterprises (including Energy Services and UGI International’s subsidiaries in Europe, which may be subject to complexities regarding the repatriation of funds to the U.S.). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows. The operations of our subsidiaries are affected by conditions beyond our control, including weather, regulations, competition in national and international markets we serve, the costs and availability of propane, butane, natural gas, electricity, and other energy sources and capital market conditions. The ability of our subsidiaries to make payments to us is also affected by the level of indebtedness of our subsidiaries, which is
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substantial, and the restrictions on payments to us imposed under the terms of such indebtedness.
Regulators may not approve the rates we request and existing rates may be challenged, which may adversely affect our results of operations.
In our UGI Utilities segment, our distribution operations are subject to regulation by the PAPUC. The PAPUC, among other things, approves the rates that UGI Utilities may charge its utility customers, thus impacting the returns that UGI Utilities may earn on the assets that are dedicated to its operations. We expect that UGI Utilities will periodically file requests with the PAPUC to increase base rates charged to customers. If UGI Utilities is required in a rate proceeding to reduce the rates it charges its utility customers, or is unable to obtain approval for timely rate increases from the PAPUC, particularly when necessary to cover increased costs, UGI Utilities’ revenue growth will be limited and earnings may decrease.
Our need to comply with, and respond to industry-wide changes resulting from, comprehensive, complex, and sometimes unpredictable governmental regulations, including regulatory initiatives aimed at increasing competition within our industry, may increase our costs and limit our revenue growth, which may adversely affect our operating results.
While we generally refer to our UGI Utilities segment as our “regulated segment,” there are many governmental regulations that have an impact on all of our businesses. Currently, we are subject to extensive and changing international, federal, state, and local safety, health, transportation, tax, and environmental laws and regulations governing the marketing, storage, distribution, and transportation of our energy products. Moreover, existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company that may affect our businesses in ways that we cannot predict.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities and, in some cases, such regulatory permits could subject our operations to additional regulations and standards of conduct. Failure to obtain or comply with these permits or applicable regulations and standards of conduct could result in civil and criminal fines or the cessation of the operations in violation. Governmental regulations and policies in the U.S. and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. The EU has committed to cut CO 2 emissions by at least 40% by 2030 and EU member states have implemented a range of subsidies and incentives to achieve the EU’s climate change goals. These subsidies and incentives may result in reduced demand for our energy products and services.
We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Most of the costs we incur to remediate sites outside of Pennsylvania cannot currently be recovered in PAPUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:

• | the discovery of presently unknown conditions;

• | changes in environmental laws and regulations;

• | judicial rejection of our legal defenses to third-party claims; or

• | the insolvency of other responsible parties at the sites at which we are involved.

Moreover, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.
We also may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to grow their business or enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.
Our operations, financial results and cash flows may be adversely affected by existing and future global climate change laws and regulations, including with respect to GHG emission restrictions, as well as market responses thereto.
Climate change continues to attract considerable public and scientific attention in the U.S. and in foreign countries. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit GHG emissions. These efforts have included consideration of cap-and-trade programs, carbon
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taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Increased regulation of GHG emissions could impose significant additional costs on us, our suppliers, our vendors, and our customers.
In September 2009, the EPA issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries, which include certain facilities of our natural gas distribution business. These subject facilities have been required to monitor emissions since January 2011 and to submit detailed annual reports beginning in March 2012. In addition, some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors. Examples include (i) the California cap-and-trade program that requires certain covered entities, including propane companies, to purchase GHG emission allowances, and (ii) the Regional Northeast Gas Initiative, in which a number of states in the northeastern U.S. participate and have agreed to establish cap and trade programs to reduce power plant emissions.
In the EU, there is a commitment to cut CO 2 emissions by at least 40% by 2030 and EU member states have implemented a range of subsidies and incentives to achieve the EU’s climate change goals. Further, emissions are regulated via a number of means, including the European Union Emissions Trading System (‘‘EU ETS’’). The EU ETS is a trading system across the EU for industrial emissions. The EU ETS is expected to become progressively more stringent over time, including by reducing the number of allowances to emit GHGs.
The adoption and implementation of any U.S. federal, state or local laws or regulations or foreign laws or regulations imposing obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for our energy products. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and/or administer and manage a GHG emissions program. We may not be able to pass on such increased costs to customers. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our results of operations, financial results and cash flows.
Changes in data privacy and data protection laws and regulations, particularly in Europe, or any failure to comply with such laws and regulations, could adversely affect our business and financial results.
There has been increased public attention regarding the use of personal information and data transfers, accompanied by legislation and regulations intended to strengthen data protection, information security and consumer and personal privacy. The law in these areas continues to develop and the changing nature of privacy laws in the U.S., the EU and elsewhere could impact our processing of the personal information of our employees, vendors and customers. The EU adopted the GDPR, which became effective in May of 2018 and expanded EU data protections, in certain circumstances, to companies outside of the EU processing data of EU residents, regardless of whether the processing occurs in the EU. Similarly, the State of California legislature passed the California Consumer Privacy Act of 2018 (“CCPA”), effective January 1, 2020, which grants certain rights to California residents with respect to their personal information. We expect that there will continue to be new laws, regulations and industry standards concerning data privacy and data protection in the U.S., the EU and other jurisdictions, and we cannot yet determine the impact such laws, regulations, interpretations and standards may have on our business.
The GDPR requires companies to satisfy strict new requirements regarding the handling of personal information, including its use, protection and the ability of persons whose data is processed to exercise a number of rights with respect to their personal information, such as correcting or requiring deletion of data about themselves. Supervisory authorities from different EU member states may interpret and apply the GDPR somewhat differently, and the GDPR also permits EU member states to create supplemental national laws, which increases the complexity of compliance. Failure to comply with GDPR requirements could result in penalties of up to €20 million or 4% of worldwide revenue, whichever is greater, for serious breaches. The CCPA requires companies to make new disclosures to consumers about such companies’ data collection, use, and sharing practices and inform consumers of their personal information rights such as deletion rights, allows consumers to opt out of certain data sharing with third parties, and provides a new cause of action for data breaches. The State of Nevada recently amended its online privacy law to allow consumers to submit requests to prevent websites and online service providers from selling personal information that is collected through a website or online service. Additionally, the Federal Trade Commission and many state attorneys general are interpreting federal and state consumer protection laws to impose standards for the online collection, use, dissemination, and security of data as well as requiring disclosures about these practices.
While we have invested significant time and resources in our GDPR compliance program, emerging and changing data privacy and data protection requirements, including CCPA, may cause us to incur additional substantial costs or require us to change our business practices. Any failure or perceived failure to comply may result in proceedings or actions against us by government entities or individuals. Moreover, any inquiries or investigations, any other government actions, or any actions by individuals,
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may be costly to comply with, result in negative publicity, increase our operating costs, require significant management time and attention, and subject us to remedies that may harm our business, including fines, demands or orders that we modify or cease existing business practices.
The provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), related regulations, and the rules adopted thereunder and other regulations, including the European Market Infrastructure Regulation (“EMIR”), may have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
Our derivative hedging activities are subject to Title VII of the Dodd-Frank Act, which regulates the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the CFTC and the federal banking regulators to implement the Dodd-Frank Act’s provisions through rulemaking, including rules regarding mandatory clearing, trade execution and margin requirements. We expect to qualify for and rely upon an exception from mandatory clearing and trade execution requirements for swaps entered into by commercial end-users to hedge commercial risks. In addition to relief from the clearing mandate, we also expect to qualify for an exception for non-financial end-users from the margin requirements on uncleared swaps. If we are not able to do so and have to post margin as to our uncleared swaps in the future, our costs of entering into and maintaining swaps would be increased.
While most of the CFTC’s rules and regulations under the Dodd-Frank Act have been finalized, some additional rules and regulations have yet to be adopted. It is possible that additional rules and regulations under the Dodd-Frank Act (including position limits as described below) may increase our cost of using derivative instruments to hedge risks associated with our business or may reduce the availability of such instruments to protect against risks we encounter. While costs imposed directly on us due to regulatory requirements for derivatives under the Dodd-Frank Act, such as reporting, recordkeeping and electing the end-user exception from mandatory clearing, are relatively minor, costs imposed upon our counterparties may increase the cost of our doing business in the derivatives markets to the extent such costs are passed on to us.
If we become subject to position limits, our ability to hedge risks would be further limited and we would be subject to additional compliance and reporting obligations. The CFTC has re-proposed position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits. The CFTC has also finalized a rule that requires market participants to aggregate their positions with those of certain other persons under common ownership or control for purposes of determining compliance with applicable position limits. If adopted, the revised position limit rule and its finalized companion rule on aggregation may adversely impact our ability to hedge exposure to price fluctuation of certain commodities. In addition to the CFTC federal position limit regime, designated contract markets also have established position limits and accountability regimes. We may have to modify trading decisions or liquidate positions to avoid exceeding such limits or at the direction of the relevant exchange to comply with accountability levels. Further, any such position limit regime, whether imposed at the federal level or by a designated contract market, may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
EMIR may result in increased costs for over-the-counter derivative counterparties trading in the EU and may also lead to an increase in the costs of, and demand for, the liquid collateral that EMIR requires central counterparties to accept. Although we expect to qualify as a non-financial counterparty under EMIR, and thus not be required to post margin under EMIR, we may still be subject to increased regulatory requirements, including recordkeeping, marking to market, timely confirmations, derivatives reporting, portfolio reconciliation and dispute resolution procedures. Regulations under EMIR could significantly increase the cost of derivatives contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter. The increased trading costs and collateral costs may have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Accordingly, our business and operating results may be adversely affected if we are forced to reduce or modify our current use of derivatives as a result of the Dodd-Frank Act and the rules and regulations promulgated thereunder as a result of EMIR.
Volatility in credit and capital markets may restrict our ability to grow, increase the likelihood of defaults by our customers and counterparties and adversely affect our operating results.
Volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Developments in the credit markets during the past few years increase our possible exposure to the liquidity, default and credit risks of our suppliers and vendors, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, less favorable market conditions could restrict our
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ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.
We depend on our intellectual property and failure to protect that intellectual property could have an adverse effect on us.
We seek trademark protection for our brands in each of our businesses, and we invest significant resources in developing our business brands. Failure to maintain our trademarks and brands could adversely affect our customer-facing businesses and our operational results.
Declines in the stock market and a low interest rate environment may negatively impact our pension liability.
Declines in the stock market and a low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 16 to Consolidated Financial Statements included in Item 15 of this Report, no material legal proceedings are pending involving the Company, any of its subsidiaries, or any of their properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.
ITEM 4. MINE SAFETY DISCLOSURES
None.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
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PART II:

ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Dividend Policy
Our Common Stock is traded on the New York Stock Exchange under the symbol “UGI.” On November 19, 2019, we had 6,523 holders of record of Common Stock.
Payment of dividends is subject to declaration by the Board of Directors. Factors considered in determining dividends include our profitability and expected capital needs. Subject to these qualifications, we presently expect to continue to pay dividends on a quarterly basis.
Equity Compensation Plan Information
Information regarding the securities authorized for issuance under our equity compensation plans can be found under Part III of this Report.
Issuer Purchases of Equity Securities
The Company did not repurchase any shares of its Common Stock during the quarter ended September 30, 2019. As of September 30, 2019, the Company had 6.8 million shares of Common Stock available for repurchase under an extension of a previous share repurchase program announced by the Company on January 25, 2018. The Board of Directors authorized the repurchase of up to 8 million shares of Common Stock over a four-year period expiring January 2022.
Recent Sale of Unregistered Securities
The Company did not sell any unregistered securities during Fiscal 2019.
Performance Graph
The following graph compares the cumulative total shareholder return (stock price appreciation and the reinvestment of dividends) on an investment of $100 in UGI Common Stock, the S&P 500 Index, and the S&P 500 Utilities Index over the five years from September 30, 2014, through September 30, 2019.
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ITEM 6. | SELECTED FINANCIAL DATA

|  | Year Ended September 30,
(Millions of dollars, except per share amounts) |  | 2019 |  | 2018 (a) |  | 2017 |  | 2016 |  | 2015
FOR THE PERIOD: |  |  |  |  |  |  |  |  |  |
Income statement data: |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 7,320.4 |  |  | $ | 7,651.2 |  |  | $ | 6,120.7 |  |  | $ | 5,685.7 |  |  | $ | 6,691.1 |
Net income including noncontrolling interests |  | $ | 307.9 |  |  | $ | 822.4 |  |  | $ | 523.8 |  |  | $ | 488.8 |  |  | $ | 414.0 |
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners |  | (51.7 | ) |  | (103.7 | ) |  | (87.2 | ) |  | (124.1 | ) |  | (133.0 | )
Net income attributable to UGI Corporation |  | $ | 256.2 |  |  | $ | 718.7 |  |  | $ | 436.6 |  |  | $ | 364.7 |  |  | $ | 281.0 |
Earnings per common share attributable to UGI Corporation stockholders: |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 1.44 |  |  | $ | 4.13 |  |  | $ | 2.51 |  |  | $ | 2.11 |  |  | $ | 1.62 |
Diluted |  | $ | 1.41 |  |  | $ | 4.06 |  |  | $ | 2.46 |  |  | $ | 2.08 |  |  | $ | 1.60 |
Cash dividends declared per common share |  | $ | 1.145 |  |  | $ | 1.020 |  |  | $ | 0.975 |  |  | $ | 0.930 |  |  | $ | 0.890 |
AT PERIOD END: |  |  |  |  |  |  |  |  |  |
Balance sheet data: |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 13,346.6 |  |  | $ | 11,980.9 |  |  | $ | 11,582.2 |  |  | $ | 10,847.2 |  |  | $ | 10,514.2 |
Capitalization: |  |  |  |  |  |  |  |  |  |
Debt: |  |  |  |  |  |  |  |  |  |
Short-term debt: |  |  |  |  |  |  |  |  |  |
AmeriGas Propane |  | $ | 328.0 |  |  | $ | 232.0 |  |  | $ | 140.0 |  |  | $ | 153.2 |  |  | $ | 68.1 |
UGI International |  | 210.9 |  |  | 1.4 |  |  | 17.9 |  |  | 0.5 |  |  | 0.6 |
Midstream & Marketing |  | 91.4 |  |  | 2.0 |  |  | 39.0 |  |  | 25.5 |  |  | 49.5 |
UGI Utilities |  | 166.0 |  |  | 189.5 |  |  | 170.0 |  |  | 112.5 |  |  | 71.7 |
Long-term debt (including current maturities): |  |  |  |  |  |  |  |  |  |
AmeriGas Propane |  | 2,564.6 |  |  | 2,569.6 |  |  | 2,572.3 |  |  | 2,333.6 |  |  | 2,261.9 |
UGI International |  | 719.5 |  |  | 748.5 |  |  | 838.8 |  |  | 779.6 |  |  | 774.2 |
Midstream & Marketing |  | 686.6 |  |  | 0.4 |  |  | 0.5 |  |  | 0.8 |  |  | 0.8 |
UGI Utilities |  | 979.2 |  |  | 838.0 |  |  | 751.1 |  |  | 671.5 |  |  | 619.8 |
UGI Corporation & Other |  | 854.1 |  |  | 8.8 |  |  | 9.4 |  |  | 10.0 |  |  | 10.7 |
Total debt |  | 6,600.3 |  |  | 4,590.2 |  |  | 4,539.0 |  |  | 4,087.2 |  |  | 3,857.3 |
UGI Corporation stockholders’ equity |  | 3,817.5 |  |  | 3,681.4 |  |  | 3,163.3 |  |  | 2,844.1 |  |  | 2,685.2 |
Noncontrolling interests (b) |  | 9.7 |  |  | 418.6 |  |  | 577.6 |  |  | 750.9 |  |  | 880.4 |
Total capitalization |  | $ | 10,427.5 |  |  | $ | 8,690.2 |  |  | $ | 8,279.9 |  |  | $ | 7,682.2 |  |  | $ | 7,422.9 |
Ratio of capitalization: |  |  |  |  |  |  |  |  |  |
Total debt |  | 63.3 | % |  | 52.8 | % |  | 54.8 | % |  | 53.2 | % |  | 52.0 | %
UGI Corporation stockholders’ equity |  | 36.6 | % |  | 42.4 | % |  | 38.2 | % |  | 37.0 | % |  | 36.2 | %
Noncontrolling interests (b) |  | 0.1 | % |  | 4.8 | % |  | 7.0 | % |  | 9.8 | % |  | 11.8 | %
|  | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  | 100.0 | %

(a) | Fiscal 2018 results include remeasurement impacts from the TCJA in the U.S. See Notes 7 and 9 to Consolidated Financial Statements for additional information.

(b) | Noncontrolling interests from Fiscal 2015 to Fiscal 2018 include noncontrolling interests in AmeriGas Partners. See Note 5 to Consolidated Financial Statements regarding the effect of the AmeriGas Merger on noncontrolling interests.

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|  | Year Ended September 30,
(Millions of dollars, except per share amounts) |  | 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015
Non-GAAP Reconciliation: |  |  |  |  |  |  |  |  |  |
Adjusted net income attributable to UGI Corporation: |  |  |  |  |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 256.2 |  |  | $ | 718.7 |  |  | $ | 436.6 |  |  | $ | 364.7 |  |  | $ | 281.0 |
Net losses (gains) on commodity derivative instruments not associated with current-period transactions (net of tax of $(59.5), $26.7, $31.9, $13.5 and $(30.9), respectively) (a) (b) |  | 147.4 |  |  | (68.1 | ) |  | (51.2 | ) |  | (29.9 | ) |  | 53.3 |
Unrealized (gains) losses on foreign currency derivative instruments (net of tax of $9.3, $9.3, $(9.9), $0 and $0), respectively) (a) |  | (22.9 | ) |  | (19.6 | ) |  | 13.9 |  |  | — |  |  | — |
Loss on extinguishments of debt (net of tax of $(1.9), $0, $(6.1), $(5.0) and $0, respectively) (a) |  | 4.2 |  |  | — |  |  | 9.6 |  |  | 7.9 |  |  | — |
AmeriGas Merger expenses (net of tax of $(0.4), $0, $0, $0 and $0, respectively) (a) |  | 1.2 |  |  | — |  |  | — |  |  | — |  |  | — |
Acquisition and integration expenses associated with the CMG Acquisition (net of tax of $(4.5), $0, $0, $0 and $0, respectively) (a) |  | 11.2 |  |  | — |  |  | — |  |  | — |  |  | — |
LPG business transformation costs (net of tax of $(5.1), $0, $0, $0 and $0, respectively) (a) |  | 15.6 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz (net of tax of $0, $(12.0), $(13.7), $(10.6) and $(7.7), respectively) (a) |  | — |  |  | 18.5 |  |  | 26.2 |  |  | 17.3 |  |  | 14.9 |
Impairment of Partnership tradenames and trademarks (net of tax of $0, $(5.8), $0, $0 and $0, respectively) (a) |  | — |  |  | 14.5 |  |  | — |  |  | — |  |  | — |
Impact from change in French tax rate |  | — |  |  | (12.1 | ) |  | (29.0 | ) |  | — |  |  | — |
Remeasurement impact from TCJA |  | — |  |  | (166.3 | ) |  | — |  |  | — |  |  | — |
Costs associated with extinguishment of debt (net of tax of $0, $0, $0, $0 and $(5.7), respectively) (a) (c) |  | — |  |  | — |  |  | — |  |  | — |  |  | 4.6 |
Adjusted net income attributable to UGI Corporation (d) |  | $ | 412.9 |  |  | $ | 485.6 |  |  | $ | 406.1 |  |  | $ | 360.0 |  |  | $ | 353.8 |
Adjusted diluted earnings per share: |  |  |  |  |  |  |  |  |  |
UGI Corporation earnings per share - diluted |  | $ | 1.41 |  |  | $ | 4.06 |  |  | $ | 2.46 |  |  | $ | 2.08 |  |  | $ | 1.60 |
Net losses (gains) on commodity derivative instruments not associated with current-period transactions (b) |  | 0.82 |  |  | (0.39 | ) |  | (0.29 | ) |  | (0.17 | ) |  | 0.30 |
Unrealized (gains) losses on foreign currency derivative instruments |  | (0.13 | ) |  | (0.11 | ) |  | 0.08 |  |  | — |  |  | — |
Loss on extinguishments of debt |  | 0.02 |  |  | — |  |  | 0.05 |  |  | 0.04 |  |  | — |
AmeriGas Merger expenses |  | 0.01 |  |  | — |  |  | — |  |  | — |  |  | — |
Acquisition and integration expenses associated with the CMG Acquisition |  | 0.06 |  |  | — |  |  | — |  |  | — |  |  | — |
LPG business transformation costs |  | 0.09 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz |  | — |  |  | 0.10 |  |  | 0.15 |  |  | 0.10 |  |  | 0.08 |
Impairment of Partnership tradenames and trademarks |  | — |  |  | 0.08 |  |  | — |  |  | — |  |  | — |
Impact from change in French tax rate |  | — |  |  | (0.07 | ) |  | (0.16 | ) |  | — |  |  | — |
Remeasurement impact from TCJA |  | — |  |  | (0.93 | ) |  | — |  |  | — |  |  | — |
Costs associated with extinguishment of debt |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.03 |
Adjusted diluted earnings per share (d) |  | $ | 2.28 |  |  | $ | 2.74 |  |  | $ | 2.29 |  |  | $ | 2.05 |  |  | $ | 2.01 |

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(a) | Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.

(b) | Includes the effects of rounding.

(c) | Costs associated with extinguishment of debt in Fiscal 2015 were included in “Interest expense” on the Consolidated Statement of Income.

(d) | Management uses "adjusted net income attributable to UGI Corporation" and "adjusted diluted earnings per share," both of which are financial measures not in accordance with GAAP, when evaluating UGI's overall performance. Adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding:

(1) | Net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments);

(2) | Losses on extinguishments of debt;

(3) | Merger expenses associated with the AmeriGas Merger;

(4) | Acquisition and integration expenses associated with the CMG and Finagaz acquisitions;

(5) | LPG business transformation costs;

(6) | Impairments of Partnership tradenames and trademarks; and

(7) | Remeasurement impacts on income tax assets and liabilities resulting from the enactments of the TCJA and French Finance Bills.

Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses our results of operations for Fiscal 2019, Fiscal 2018 and Fiscal 2017, and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors,” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 22 to Consolidated Financial Statements.
Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the peak heating-season months of October through March. Accordingly, our results of operations, after adjusting for the effects of gains and losses on derivative instruments not associated with current-period transactions as further discussed below under “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share,” are significantly higher in our first and second fiscal quarters.
UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are financial measures not in accordance with GAAP, when evaluating UGI’s overall performance. Management believes that these non-GAAP measures provide meaningful information to investors. Adjusted net income attributable to UGI Corporation excludes (1) net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results (as such items are further described below). UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under GAAP. Volatility in net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on these derivative instruments. However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities or, in the case of certain foreign currency derivatives, reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains and losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate the volatility in anticipated future earnings associated with our European operations. For further information, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below and Note 22 to Consolidated Financial Statements.
Executive Overview
Fiscal 2019 Financial Review
Net Income Attributable to UGI Corporation and Diluted EPS by Segment (GAAP)

|  | 2019 |  | 2018 |  | 2017
(Dollars in millions, except per share amounts) |  | Net Income (Loss) |  | Diluted EPS |  | Net Income |  | Diluted EPS |  | Net Income |  | Diluted EPS
AmeriGas Propane |  | $ | 68.2 |  |  | $ | 0.38 |  |  | $ | 76.3 |  |  | $ | 0.43 |  |  | $ | 54.2 |  |  | $ | 0.30 |
UGI International |  | 144.8 |  |  | 0.80 |  |  | 153.1 |  |  | 0.87 |  |  | 155.8 |  |  | 0.88 |
Midstream & Marketing |  | 78.0 |  |  | 0.43 |  |  | 126.7 |  |  | 0.72 |  |  | 86.9 |  |  | 0.49 |
UGI Utilities |  | 133.2 |  |  | 0.74 |  |  | 140.9 |  |  | 0.80 |  |  | 116.0 |  |  | 0.66 |
Total reportable segments |  | 424.2 |  |  | 2.35 |  |  | 497.0 |  |  | 2.82 |  |  | 412.9 |  |  | 2.33 |
Corporate & Other (a) (b) |  | (168.0 | ) |  | (0.94 | ) |  | 221.7 |  |  | 1.24 |  |  | 23.7 |  |  | 0.13 |
Net income attributable to UGI Corporation |  | $ | 256.2 |  |  | $ | 1.41 |  |  | $ | 718.7 |  |  | $ | 4.06 |  |  | $ | 436.6 |  |  | $ | 2.46 |

(a) | Fiscal 2018 net income attributable to UGI Corporation reflects the remeasurement of income tax assets and liabilities resulting from the TCJA in the U.S., and the remeasurement effects of the December 2017 French Finance Bills. Fiscal 2017 includes the remeasurement effects of the December 2016 French Finance Bills. See “Impact of Tax Reform” below and Notes 7 and 22 to Consolidated Financial Statements.

(b) | Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income attributable to UGI Corporation. These adjustments have been excluded from the segment results to align with the measure used by our CODM in assessing segment performance and allocating resources. See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below and Note 22 to Consolidated Financial Statements for additional information related to these adjustments, as well as other items included within Corporate & Other.

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From a financial performance perspective, the Company faced a number of operational challenges in Fiscal 2019, including average temperatures that were warmer than normal and slightly warmer than the prior year across three of our four business segments (with AmeriGas Propane being the exception). At our Midstream & Marketing segment, Fiscal 2019 results were significantly below the prior year due principally to the impact on capacity management margin of pipeline restrictions and limited weather volatility in the Marcellus region. UGI International faced a second consecutive year of significantly warmer than normal weather and the effects of a very warm and dry crop-drying season, which reduced LPG volumes. Despite these significant challenges, our adjusted diluted earnings per share (as further described below) of $2.28 demonstrate the resiliency of our business unit portfolio and our ability to manage expenses to adjust to these adverse conditions.
Our Fiscal 2019 net income attributable to UGI as determined in accordance with GAAP was $256.2 million, equal to $1.41 per diluted share, compared with $718.7 million, equal to $4.06 per diluted share, in Fiscal 2018. The significantly lower GAAP net income attributable to UGI and the lower associated GAAP diluted earnings per share reflects, among other things, significant year-over-year changes in unrealized gains and losses on derivative commodity instruments not associated with current-period transactions and the income tax remeasurement adjustments recorded in Fiscal 2018 resulting from the enactment of the TCJA and the 2017 French Finance Bills.
Our adjusted net income attributable to UGI for Fiscal 2019 was $412.9 million, equal to $2.28 per diluted share, a decrease from Fiscal 2018’s adjusted net income and adjusted diluted earnings per share of $485.6 million and $2.74, respectively. For further information on our non-GAAP financial measures “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” including reconciliations of these measures to the most directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below.
AmeriGas Propane net income attributable to UGI declined $8.1 million in Fiscal 2019 notwithstanding slightly colder average temperatures. The lower AmeriGas Propane results reflect the margin impact of lower retail propane volumes sold, particularly lower base business volumes. In addition, AmeriGas Propane operating and administrative expenses were slightly higher reflecting, in part, higher litigation-related and vehicle lease expenses.
UGI International net income attributable to UGI in Fiscal 2019 was $8.3 million lower than in Fiscal 2018 reflecting lower volumes sold for crop drying due to a very dry and warm 2018 summer and early fall in Europe and the negative volume and associated margin effects of warmer weather during the peak heating season on heating-related bulk sales. We were able to offset a portion of the effects of the decrease in volumes through effective price management and cost control initiatives. Although the euro and the British pound sterling were approximately 5% weaker during Fiscal 2019 compared to Fiscal 2018, which reduced translated local currency results, UGI International’s Fiscal 2019 net income was favorably impacted by significantly higher realized gains on foreign currency contracts used to reduce volatility in our foreign earnings.
Midstream & Marketing net income attributable to UGI in Fiscal 2019 was $48.7 million lower than in Fiscal 2018. The lower results reflect substantially lower prices for pipeline capacity principally due to the absence of cold and volatile temperatures that occurred in late December and January of Fiscal 2018, increased pipeline restrictions experienced during Fiscal 2019 and the effects on capacity values of new pipeline capacity. Midstream & Marketing’s Fiscal 2019 net income also reflects lower electric generation total margin and lower average natural gas marketing unit margins. These decreases were partially offset by the benefits of higher natural gas gathering and peaking total margin.
UGI Utilities net income attributable to UGI in Fiscal 2019 was $7.7 million lower than in Fiscal 2018. UGI Utilities’ Fiscal 2019 net income reflects the credit to customers under the PAPUC’s May 17, 2018 Order of tax savings resulting from the TCJA for the entire fiscal year. UGI Utilities’ Fiscal 2018 net income reflects the credit to customers for the nine-month period January 1, 2018 through September 30, 2018. The lower UGI Utilities’ Fiscal 2019 results also reflect the effects of temperatures that were warmer than in Fiscal 2018. The warmer temperatures reduced core market volumes but this reduction was partially offset by, among other things, the margin benefits of core market customer growth and higher use per customer.
Impact of Tax Reform
Our Fiscal 2019 and Fiscal 2018 GAAP results reflect the effects of two significant tax law changes: the December 2017 enactment of the TCJA in the U.S. and the December 2017 French Finance Bills. Among other things, the TCJA reduced the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018. The December 2017 French Finance Bills increased the corporate income tax rate in France to 39.4% from 34.4% for Fiscal 2018, but included measures to reduce the French corporate income tax rate, over time, to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the TCJA and the December 2017 French Finance Bills, during Fiscal 2018 we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. The net adjustment to our deferred income tax assets and liabilities resulting from the TCJA reduced our
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Fiscal 2018 income tax expense by $166.3 million (equal to $0.93 per diluted share). Due to the effects of utility ratemaking, most of the reduction in UGI Utilities’ deferred income tax assets and liabilities was not recognized immediately in income tax expense but has been reflected in regulatory assets and liabilities in accordance with utility ratemaking. The net adjustment to our deferred income tax assets and liabilities in France resulting from the December 2017 French Finance Bills reduced our Fiscal 2018 income tax expense by $12.1 million (equal to $0.07 per diluted share). Although these remeasurement adjustments decreased our income tax expense and increased our GAAP net income, we have eliminated these remeasurement adjustments from our non-GAAP adjusted results.
In addition to the Fiscal 2018 remeasurement adjustments related to our U.S. and French income tax assets and liabilities described above, our income tax expense for Fiscal 2018 was further impacted by a net reduction of approximately $35.0 million (equal to $0.20 per diluted share) principally as a result of a lower Fiscal 2018 blended U.S. income tax rate of 24.5% compared to 35% previously, partially offset by an after-tax reduction in UGI Utilities’ revenues resulting from a May 2018 PAPUC Order. In accordance with this PAPUC Order, UGI Utilities reduced its revenues by $24.1 million, and established an associated regulatory liability, related to $17.1 million of tax benefits resulting from the change in the federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. In addition to the requirement to establish this regulatory liability, the May 2018 PAPUC Order also directed each regulated utility that was not currently in a general base rate case proceeding to reduce their rates through a reconcilable negative surcharge applied to bills rendered on or after July 1, 2018 until the effective date of new rates was established in the next general base rate proceeding. This ratemaking effectively offset the effects of the TCJA on income taxes at UGI Utilities until the TCJA’s effects were considered in rate proceedings.
For further information on the TCJA, the December 2017 French Finance Bills, the regulatory impacts on UGI Utilities resulting from the TCJA and the actions of the PAPUC, see Notes 7 and 9 to Consolidated Financial Statements.
Strategic Initiatives
Fiscal 2019 was defined by two significant strategic transactions that we believe will have a transformational impact on our future performance and strategic direction. The larger of these transactions was the purchase of all of the public’s ownership interest in AmeriGas Partners for 34.6 million UGI shares and $529 million in cash. This transaction resulted in UGI owning 100% of the Partnership effective August 21, 2019. We will use the enhanced cash flow from our full ownership of the Partnership to reduce debt over time and help fund future major capital investments in our natural gas businesses. The second significant strategic transaction in Fiscal 2019 was the acquisition of Columbia Midstream Group from TC Energy on August 1, 2019. The CMG Acquisition resulted in a four-fold increase in our natural gas gathering assets as well as the acquisition of important gas processing assets in the Marcellus and Utica Shale formations. We anticipate executing on a number of system expansion projects associated with these assets over the next several years.
In addition to the AmeriGas Merger and the CMG Acquisition, during Fiscal 2019 we continued to focus on executing critical elements of our long-term strategy at each of our business segments. We believe these initiatives will provide a platform for sustainable future growth. Some of these initiatives are described below.
At our Midstream & Marketing business, we continued to focus on organic growth associated with infrastructure build-out projects in the Marcellus and Utica Shale. One such project is our Auburn IV pipeline expansion project in northern Pennsylvania, which was completed in November 2019 and is supported by a ten-year take or pay contract. We continued to expand our infield gathering capabilities including the build-out of our Texas Creek and other gathering assets located in northern Pennsylvania, and are continuing to expand our portfolio of LNG assets. Our largest LNG project currently underway is the construction of an LNG storage and vaporization facility located in Bethlehem, Pennsylvania. We expect this facility to be operational in early Fiscal 2021. Our existing portfolio of LNG assets and assets under construction, such as the Bethlehem LNG project, are vital to filling the gap between available pipeline capacity and peak day demand for natural gas. Early in Fiscal 2019, we also expanded our energy marketing customer base with the acquisition of South Jersey Energy Company’s natural gas marketing business, adding several thousand customers to our portfolio.
UGI Utilities had a busy and productive Fiscal 2019. We continue to see strong natural gas demand across our Gas Utility service territory. UGI Utilities added approximately 14,000 new residential and commercial heating customers during Fiscal 2019 with conversions accounting for the majority of the additions. UGI Utilities’ Electric Utility base rate case, filed in January 2018, went into effect in late October 2018. In January 2019, UGI Utilities filed its first combined Gas Utility rate case and successfully concluded the base rate case with an approved settlement that increases base rate revenue by approximately $30 million. The new base rates went into effect on October 11, 2019. UGI Utilities continues to invest in its distribution system and in Fiscal 2019 spent over $355 million in capital expenditures, including approximately $201 million in replacement and betterment capital. We expect this high level of capital expenditures at UGI Utilities to continue for the foreseeable future.
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AmeriGas Propane continued to experience the successful expansions of its ACE cylinder and National Accounts programs. Through both of these programs, AmeriGas Propane distinguishes itself by providing exceptional service to key customer groups, leveraging upon its national footprint to serve these customers efficiently and effectively. Fiscal 2019 was another year of strong growth in both programs, with ACE volumes up 8% and National Accounts volumes up more than 5%. During Fiscal 2019, we continued to deliver value-added technologies such as our second generation ACE vending solution for our largest cylinder exchange customers, and we introduced Cynch, our propane home delivery service for customers in select markets. We plan to continue to expand this start-up business to additional major metropolitan markets in Fiscal 2020 and beyond. During Fiscal 2019, AmeriGas Propane continued to focus on cost reduction through operating efficiencies, the application of technology solutions, and organizational management initiatives, including the development of our business transformation initiative further described below.
During Fiscal 2019, UGI International integrated four smaller-sized LPG businesses including LPG distribution businesses in Belgium, the Netherlands and the United Kingdom. After successfully completing the integration of Finagaz and centralizing its European supply and commodity hedging functions in France, UGI International management turned its attention in Fiscal 2019 to starting the process of centralizing certain operating and administrative functions and continued its efforts to incorporate new technology to ensure excellent customer service and improved profitability. UGI International continued to build out its cylinder distribution model including vending machines and expansion of retail chain customers.
Global LPG Business Transformation Initiatives
Driving operational efficiencies across our global LPG businesses will be an important component of our global LPG strategy for the next several years. We have begun to implement significant strategic and sustainable programs at AmeriGas Propane and UGI International that will increase profitability and provide for an enhanced customer experience at both of these businesses. We have engaged strategic partners to assist us in the identification and execution of these strategic initiatives.
At AmeriGas Propane, we have identified annual savings opportunities that will result from business transformation activities expected to be implemented over the next two years. We are focused on efficiency and effectiveness initiatives in the following key areas: customer digital experience; customer relationship management; operating process redesign and specialization; distribution and routing optimization; sales and marketing effectiveness; purchasing and general and administrative efficiencies; and supply and logistics. We expect that our focus on these key AmeriGas Propane business activities over the next two years will, once completed, provide more than $120 million of annual savings that will allow us to improve profitability through operational efficiencies and expense reductions. In addition to improving earnings of the business, this lower cost structure will enable increased investment into base business customer retention and growth initiatives, including the reduction of margins in select segments of our base business. We estimate the total cost of executing on these initiatives, including approximately $100 million of related capital expenditures, to be approximately $175 million.
At our UGI International LPG business, we launched an initiative and have embarked on a process of identifying operational synergies across all 17 countries in which we currently do business. We call this initiative Project Alliance, the goal of which is to focus attention on enhanced customer service and safe and efficient operations through the establishment of two centers of excellence. One such center will be focused on commercial excellence to identify and execute projects that improve the customer’s experience. The second center will be focused on operational excellence across our distribution network and our filling centers. These efforts will be executed primarily over the next two years and once completed will generate over €30 million of annual savings. We estimate the total cumulative cost of executing on these Project Alliance initiatives, including approximately €20 million related to IT capital expenditures, to be approximately €55 million.
These efficiency-focused initiatives are being centrally led under the global LPG structure that we announced last year. We are confident that these global LPG business transformation activities at AmeriGas Propane and UGI International will position our global LPG businesses to be industry leaders in providing a superior customer experience with safe and efficient operations.
Financing Transactions and Liquidity
During Fiscal 2019, we completed a number of significant long-term and short-term financing and refinancing transactions including financing a portion of the CMG Acquisition and the cash portion of the AmeriGas Merger.
In August 2019, Energy Services entered into a $700 million variable-rate senior secured term loan agreement with a group of lenders that matures in August 2026. Proceeds were used principally to finance the CMG Acquisition. Loans under the agreement bear interest at a floating benchmark rate plus a margin. We have entered into interest rate swap agreements to effectively fix the floating benchmark rate on these borrowings.
Also in August 2019, UGI entered into the UGI Corporation Senior Credit Facility. The UGI Corporation Senior Credit Facility comprises (1) a five-year $250 million amortizing variable-rate term loan facility; (2) a three-year $300 million term loan facility;
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and (3) a five-year $300 million revolving credit facility (including a $10 million sublimit for letters of credit). Proceeds from $850 million of borrowings in August 2019 under the UGI Corporation Senior Credit Facility were used to finance the cash portion of the AmeriGas Merger and a portion of the CMG Acquisition. Loans under the UGI Corporation Senior Credit Facility bear interest at a floating benchmark rate plus a margin. We have entered into interest rate swap agreements to fix the floating benchmark rate on a portion of the outstanding principal and term of these variable-rate borrowings.
In October 2018, UGI International, LLC completed a significant refinancing transaction and (i) issued €350 million of 3.25% bonds due November 2025 through an underwritten private placement; (ii) borrowed €300 million under its 2018 UGI International Credit Facilities Agreement variable-rate term loan facility; and (iii) entered into a €300 million multicurrency revolving credit facility. The €300 million term loan is due, and the new multicurrency revolving facility expires, in October 2023. The proceeds from the term loan and the 3.25% bonds plus cash on hand were used in October 2018 to repay UGI France’s and Flaga’s term loans ahead of schedule. We have entered into interest rate swap agreements to fix the interest rate on the outstanding principal of the variable-rate term loan borrowings through October 2022.
In June 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350 million (including a $100 million sublimit for letters of credit) which also has an additional $150 million accordion feature. Concurrently with entering into the UGI Utilities 2019 Credit Agreement, UGI Utilities terminated its existing $450 million revolving credit agreement. In February 2019, UGI Utilities issued in a private placement $150 million of UGI Utilities 4.55% Senior Notes due February 1, 2049.
We believe each of our business units has sufficient liquidity to fund business operations during Fiscal 2020 (see “Financial Condition and Liquidity” below). For additional information on our Fiscal 2019 financing transactions, see “Financial Condition and Liquidity” below and Note 6 to Consolidated Financial Statements.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share
Adjusted Net Income Attributable to UGI Corporation and Adjusted Diluted EPS by Segment (Non-GAAP)

|  | 2019 |  | 2018 |  | 2017
(Dollars in millions, except per share amounts) |  | Adjusted Net Income (Loss) |  | Adjusted Diluted EPS |  | Adjusted Net Income (Loss) |  | Adjusted Diluted EPS |  | Adjusted Net Income (Loss) |  | Adjusted Diluted EPS
AmeriGas Propane |  | $ | 68.2 |  |  | $ | 0.38 |  |  | $ | 76.3 |  |  | $ | 0.43 |  |  | $ | 54.2 |  |  | $ | 0.30 |
UGI International |  | 144.8 |  |  | 0.80 |  |  | 153.1 |  |  | 0.87 |  |  | 155.8 |  |  | 0.88 |
Midstream & Marketing |  | 78.0 |  |  | 0.43 |  |  | 126.7 |  |  | 0.72 |  |  | 86.9 |  |  | 0.49 |
UGI Utilities |  | 133.2 |  |  | 0.74 |  |  | 140.9 |  |  | 0.80 |  |  | 116.0 |  |  | 0.66 |
Total reportable segments |  | 424.2 |  |  | 2.35 |  |  | 497.0 |  |  | 2.82 |  |  | 412.9 |  |  | 2.33 |
Corporate & Other |  | (11.3 | ) |  | (0.07 | ) |  | (11.4 | ) |  | (0.08 | ) |  | (6.8 | ) |  | (0.04 | )
Adjusted net income attributable to UGI Corporation |  | $ | 412.9 |  |  | $ | 2.28 |  |  | $ | 485.6 |  |  | $ | 2.74 |  |  | $ | 406.1 |  |  | $ | 2.29 |

As previously mentioned, UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding:

(1) | Net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments);

(2) | Losses on extinguishments of debt;

(3) | Merger expenses associated with the AmeriGas Merger;

(4) | Acquisition and integration expenses associated with the CMG and Finagaz acquisitions;

(5) | Expenses associated with AmeriGas Propane’s and UGI International’s LPG business transformation initiatives designed to reduce costs and create more efficient processes;

(6) | Impairments of Partnership tradenames and trademarks; and

(7) | Remeasurement impacts on income tax assets and liabilities resulting from the enactments of the TCJA and French Finance Bills.

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UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under GAAP. Volatility in net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on unsettled commodity and certain foreign currency derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions. However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities, or in the case of certain foreign currency derivatives reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains or losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate volatility in anticipated future earnings. For further information on the Company’s accounting for commodity and certain foreign currency derivative instruments, see Notes 2 and 18 to Consolidated Financial Statements.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.
The following table reconciles net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation and reconciles diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above for Fiscal 2019, Fiscal 2018 and Fiscal 2017.
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|  | Year Ended September 30,
(Millions of dollars, except per share amounts) |  | 2019 |  | 2018 |  | 2017
Adjusted net income attributable to UGI Corporation: |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 256.2 |  |  | $ | 718.7 |  |  | $ | 436.6 |
Net losses (gains) on commodity derivative instruments not associated with current-period transactions (net of tax of $(59.5), $26.7 and $31.9, respectively) (a) (b) |  | 147.4 |  |  | (68.1 | ) |  | (51.2 | )
Unrealized (gains) losses on foreign currency derivative instruments (net of tax of $9.3, $9.3 and $(9.9), respectively) (a) |  | (22.9 | ) |  | (19.6 | ) |  | 13.9 |
Loss on extinguishments of debt (net of tax of $(1.9), $0, and $(6.1), respectively) (a) |  | 4.2 |  |  | — |  |  | 9.6 |
AmeriGas Merger expenses (net of tax of $(0.4), $0 and $0, respectively) (a) |  | 1.2 |  |  | — |  |  | — |
Acquisition and integration expenses associated with the CMG Acquisition (net of tax of $(4.5), $0 and $0, respectively) (a) |  | 11.2 |  |  | — |  |  | — |
LPG business transformation costs (net of tax of $(5.1), $0 and $0, respectively) (a) |  | 15.6 |  |  | — |  |  | — |
Integration expenses associated with Finagaz (net of tax of $0, $(12.0) and $(13.7), respectively) (a) |  | — |  |  | 18.5 |  |  | 26.2 |
Impairment of Partnership tradenames and trademarks (net of tax of $0, $(5.8) and $0, respectively) (a) |  | — |  |  | 14.5 |  |  | — |
Impact from change in French tax rate |  | — |  |  | (12.1 | ) |  | (29.0 | )
Remeasurement impact from TCJA |  | — |  |  | (166.3 | ) |  | — |
Total adjustments |  | 156.7 |  |  | (233.1 | ) |  | (30.5 | )
Adjusted net income attributable to UGI Corporation |  | $ | 412.9 |  |  | $ | 485.6 |  |  | $ | 406.1 |
Adjusted diluted earnings per share: |  |  |  |  |  |
UGI Corporation earnings per share - diluted |  | $ | 1.41 |  |  | $ | 4.06 |  |  | $ | 2.46 |
Net losses (gains) on commodity derivative instruments not associated with current-period transactions |  | 0.82 |  |  | (0.39 | ) |  | (0.29 | )
Unrealized (gains) losses on foreign currency derivative instruments |  | (0.13 | ) |  | (0.11 | ) |  | 0.08 |
Loss on extinguishments of debt |  | 0.02 |  |  | — |  |  | 0.05 |
AmeriGas Merger expenses |  | 0.01 |  |  | — |  |  | — |
Acquisition and integration expenses associated with the CMG Acquisition |  | 0.06 |  |  | — |  |  | — |
LPG business transformation costs |  | 0.09 |  |  | — |  |  | — |
Integration expenses associated with Finagaz |  | — |  |  | 0.10 |  |  | 0.15 |
Impairment of Partnership tradenames and trademarks |  | — |  |  | 0.08 |  |  | — |
Impact from change in French tax rate |  | — |  |  | (0.07 | ) |  | (0.16 | )
Remeasurement impact from TCJA |  | — |  |  | (0.93 | ) |  | — |
Adjusted diluted earnings per share |  | $ | 2.28 |  |  | $ | 2.74 |  |  | $ | 2.29 |

(a) | Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.

(b) | Includes the effects of rounding.

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The following analyses compare the Company’s results of operations for (1) Fiscal 2019 with Fiscal 2018 and (2) Fiscal 2018 with Fiscal 2017.
Fiscal 2019 Compared with Fiscal 2018
Consolidated Results
Net Income Attributable to UGI Corporation by Segment:

|  | 2019 |  | 2018 |  | Variance - (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 68.2 |  |  | 26.6 | % |  | $ | 76.3 |  |  | 10.6 | % |  | $ | (8.1 | ) |  | (10.6 | )%
UGI International |  | 144.8 |  |  | 56.5 | % |  | 153.1 |  |  | 21.3 | % |  | (8.3 | ) |  | (5.4 | )%
Midstream & Marketing |  | 78.0 |  |  | 30.4 | % |  | 126.7 |  |  | 17.6 | % |  | (48.7 | ) |  | (38.4 | )%
UGI Utilities |  | 133.2 |  |  | 52.0 | % |  | 140.9 |  |  | 19.6 | % |  | (7.7 | ) |  | (5.5 | )%
Corporate & Other (a) |  | (168.0 | ) |  | (65.5 | )% |  | 221.7 |  |  | 30.9 | % |  | (389.7 | ) |  | N.M. |
Net income attributable to UGI Corporation |  | $ | 256.2 |  |  | 100.0 | % |  | $ | 718.7 |  |  | 100.0 | % |  | $ | (462.5 | ) |  | (64.4 | )%

(a) | Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income attributable to UGI Corporation. These adjustments have been excluded from the segment results to align with the measure used by our CODM in assessing segment performance and allocating resources. These items totaled $(156.7) million and $233.1 million in Fiscal 2019 and Fiscal 2018, respectively. See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” above and Note 22 to Consolidated Financial Statements for further information.

N.M. — Variance is not meaningful.

AmeriGas Propane |  | 2019 |  | 2018 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |  |
Revenues |  | $ | 2,682.0 |  |  | $ | 2,823.0 |  |  | $ | (141.0 | ) |  | (5.0 | )%
Total margin (a) |  | $ | 1,490.7 |  |  | $ | 1,508.3 |  |  | $ | (17.6 | ) |  | (1.2 | )%
Operating and administrative expenses |  | $ | 929.0 |  |  | $ | 924.7 |  |  | $ | 4.3 |  |  | 0.5 | %
Operating income / earnings before interest expense and income taxes |  | $ | 404.0 |  |  | $ | 422.2 |  |  | $ | (18.2 | ) |  | (4.3 | )%
Partnership Adjusted EBITDA (b) |  | $ | 580.3 |  |  | $ | 605.5 |  |  | $ | (25.2 | ) |  | (4.2 | )%
Retail gallons sold (millions) |  | 1,053.9 |  |  | 1,081.3 |  |  | (27.4 | ) |  | (2.5 | )%
Degree days – % colder than normal (c) |  | 3.6 | % |  | 0.3 | % |  | — |  |  | — |

(a) | Total margin represents revenues less cost of sales.

(b) | Partnership Adjusted EBITDA is a non-GAAP financial measure and is not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not a substitute for, the comparable GAAP measures. Management believes Partnership Adjusted EBITDA is a meaningful non-GAAP measure used by investors to (1) compare the Partnership’s operating performance with that of other companies within the propane industry and (2) assess the Partnership’s ability to meet loan covenants.

The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:

|  | 2019 |  | 2018
Income before income taxes |  | $ | 236.6 |  |  | $ | 259.1 |
Interest expense |  | 167.4 |  |  | 163.1 |
Depreciation and amortization |  | 179.4 |  |  | 185.8 |
Noncontrolling interest (i) |  | (3.1 | ) |  | (2.5 | )
Partnership Adjusted EBITDA |  | $ | 580.3 |  |  | $ | 605.5 |

(i) principally represents 1.01% noncontrolling interest in AmeriGas OLP.
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(c) | Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.

The Partnership’s retail gallons sold during Fiscal 2019 were 2.5% lower than Fiscal 2018. Average temperatures based upon heating degree days were 3.6% colder than normal and 3.3% colder than the prior year. Although average temperatures during Fiscal 2019 across our entire service territory were colder than normal and colder than Fiscal 2018, we experienced significantly warmer than normal temperatures in the southeastern U.S. during two of the peak heating season months, January and February.
Retail propane revenues decreased $139.8 million during Fiscal 2019 reflecting the effects of lower average retail selling prices ($76.9 million) and the lower retail volumes sold ($62.9 million). Wholesale propane revenues decreased $1.3 million reflecting lower average wholesale selling prices ($17.1 million) partially offset by higher wholesale volumes sold ($15.8 million). Average daily wholesale propane commodity prices during Fiscal 2019 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 33% lower than such prices during Fiscal 2018, reflecting declining prices through most of Fiscal 2019 compared to more stable prices in the prior year. Other revenues in Fiscal 2019 were approximately equal to the prior year. Total cost of sales decreased $123.4 million principally reflecting the effects of lower average propane product costs ($105.6 million) and lower retail propane volumes sold ($29.5 million) partially offset by higher wholesale propane volumes sold ($15.3 million).
Total margin in Fiscal 2019 was $17.6 million lower than in Fiscal 2018 principally reflecting lower retail propane total margin ($21.7 million) partially offset by higher wholesale and other margin including higher tank rent and service total margin. The decline in retail propane total margin reflects the lower retail volumes sold ($33.3 million) partially offset by slightly higher average retail propane unit margins ($11.6 million).
Operating income/earnings before interest expense and income taxes decreased $18.2 million in Fiscal 2019 principally reflecting the lower total margin ($17.6 million), slightly higher operating and administrative expenses ($4.3 million) and slightly lower other operating income ($2.8 million) principally related to lower income on asset sales. These decreases were partially offset by lower depreciation and amortization expense ($6.4 million). The slight increase in Partnership operating and administrative expenses reflects, among other things, higher required accruals for litigation ($10.0 million) and higher vehicle lease expense ($9.9 million), including $5.0 million to correct vehicle lease expense associated with prior periods, substantially offset by lower general insurance and self-insured casualty and liability expense, and lower travel and entertainment expenses, professional fees and advertising expenses.

UGI International |  | 2019 |  | 2018 |  | Decrease
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,372.2 |  |  | $ | 2,683.8 |  |  | $ | (311.6 | ) |  | (11.6 | )%
Total margin (a) |  | $ | 955.8 |  |  | $ | 1,043.2 |  |  | $ | (87.4 | ) |  | (8.4 | )%
Operating and administrative expenses |  | $ | 611.3 |  |  | $ | 657.9 |  |  | $ | (46.6 | ) |  | (7.1 | )%
Operating income |  | $ | 228.9 |  |  | $ | 247.9 |  |  | $ | (19.0 | ) |  | (7.7 | )%
Earnings before interest expense and income taxes |  | $ | 234.3 |  |  | $ | 240.4 |  |  | $ | (6.1 | ) |  | (2.5 | )%
LPG retail gallons sold (millions) (b) |  | 832.6 |  |  | 875.0 |  |  | (42.4 | ) |  | (4.8 | )%
Degree days - % (warmer) than normal (c) |  | (5.8 | )% |  | (5.3 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales and, in Fiscal 2018, French energy certificate costs of $20.5 million. For financial statement purposes, French energy certificate costs in Fiscal 2018 are included in “Operating and administrative expenses” on the Consolidated Statements of Income (but are excluded from operating expenses presented above). In Fiscal 2019, French energy certificate costs are included in cost of goods sold on the consolidated statements of income.

(b) | Prior-year amount adjusted to conform to current-year classification.

(c) | Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

Average temperatures during Fiscal 2019 were 5.8% warmer than normal and 0.5% warmer than the prior year. Although average temperatures for Fiscal 2019 were only 0.5% warmer than the prior year, temperatures during the six months ended March 31, 2019, which include the peak heating season months, were 8.5% warmer than the prior-year period. Total retail gallons sold during Fiscal 2019 were 4.8% lower reflecting lower volumes associated with crop drying as a result of a very warm and dry summer, the loss of a low-margin cylinder dealer in Poland and the effects of the warmer weather on heating-related bulk sales, primarily sales to residential heating customers, during the peak heating season months. Notwithstanding higher wholesale LPG prices at
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the beginning of the Fiscal 2019 heating season, average wholesale prices for propane and butane in northwest Europe were approximately 19% and 16% lower than in Fiscal 2018, respectively, reflecting a significant decline in LPG prices during Fiscal 2019.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. Differences in these translation rates affect the comparison of line item amounts presented in the table above. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During Fiscal 2019 and Fiscal 2018, the average unweighted euro-to-dollar translation rates were $1.13 and $1.19, respectively, and the average unweighted British pound sterling-to-dollar translation rates were $1.28 and $1.35, respectively. During Fiscal 2019 and Fiscal 2018, realized gains and losses on foreign currency exchange contracts used to reduce volatility in our foreign operations’ net income settled at average euro-to-dollar exchange rates of $1.18 and $1.09, respectively, and at average British pound sterling-to-dollar exchange rates of $1.31 and $1.27, respectively.
UGI International revenues decreased $311.6 million during Fiscal 2019 principally reflecting the lower retail and lower wholesale LPG volumes sold, and the translation effects of the weaker euro and British pound sterling (approximately $140 million). UGI International cost of sales decreased $238.4 million during Fiscal 2019 principally reflecting the effects of the lower LPG retail and wholesale volumes sold, the translation effects of the weaker euro and British pound sterling (approximately $80 million), and the effects of slightly lower average wholesale prices for LPG. Although the average unweighted wholesale price for LPG during Fiscal 2019 was lower than in Fiscal 2018, wholesale LPG prices during late Fiscal 2018 and early Fiscal 2019 were higher than the prior year resulting in higher LPG inventory costs entering the Fiscal 2019 heating season.
UGI International total margin decreased $87.4 million primarily reflecting the lower retail LPG volumes sold, and the translation effects of the weaker euro and British pound sterling (approximately $60 million). These decreases in total margin were partially offset by slightly higher average retail LPG unit margin reflecting margin management efforts including the recovery of energy conservation compliance costs.
The $19.0 million decrease in UGI International operating income principally reflects the $87.4 million decrease in total margin partially offset by lower operating and administrative expenses ($46.6 million), lower depreciation and amortization expense ($16.8 million), and higher other operating income including higher income on asset sales and income from a customer contract settlement. The decrease in operating and administrative expenses reflects, in large part, the impact of the weaker euro and British pound sterling (approximately $35 million) and lower local currency operating and administrative expenses. Local currency operating and administrative expenses were lower than the prior year principally reflecting lower expenses associated with operational safety requirements, and lower advertising, information technology and outside services expense. The lower depreciation and amortization expense principally reflects adjustments recorded in Fiscal 2018 resulting mainly from changes in depreciable lives of certain cylinders and tanks and, to a lesser extent, the translation effects in the current year of the weaker currencies. UGI International earnings before interest expense and income taxes in Fiscal 2019 was $6.1 million lower than in Fiscal 2018 principally reflecting the net effects of the $19.0 million decrease in UGI International operating income and the absence of a postretirement plan curtailment gain recorded in the prior year ($5.8 million) partially offset by higher pre-tax realized gains on foreign currency exchange contracts entered into in order to reduce volatility in UGI International net income resulting from changes in foreign exchange rates ($18.3 million).

Midstream & Marketing |  | 2019 |  | 2018 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 1,515.7 |  |  | $ | 1,421.7 |  |  | $ | 94.0 |  |  | 6.6 | %
Total margin (a) |  | $ | 274.5 |  |  | $ | 330.9 |  |  | $ | (56.4 | ) |  | (17.0 | )%
Operating and administrative expenses |  | $ | 119.5 |  |  | $ | 112.8 |  |  | $ | 6.7 |  |  | 5.9 | %
Operating income |  | $ | 105.0 |  |  | $ | 175.1 |  |  | $ | (70.1 | ) |  | (40.0 | )%
Earnings before interest expense and income taxes |  | $ | 114.1 |  |  | $ | 178.7 |  |  | $ | (64.6 | ) |  | (36.1 | )%

(a) | Total margin represents total revenues less total cost of sales.

Average temperatures across Midstream & Marketing’s energy marketing territory during Fiscal 2019 were approximately 1.6% warmer than normal and slightly warmer than the prior year. Although average temperatures in Fiscal 2019 were only slightly warmer than the prior year, the prior year experienced extremely cold and volatile weather in late December 2017 and early January 2018.
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Midstream & Marketing’s Fiscal 2019 revenues were $94.0 million higher than in Fiscal 2018 principally reflecting higher natural gas revenues ($143.9 million) and higher natural gas gathering revenues ($29.8 million) including incremental revenues from CMG, which was acquired on August 1, 2019. These increases in revenues were partially offset by lower capacity revenues ($68.5 million) and, to a much lesser extent, lower electric generation revenues. The significant increase in natural gas revenues principally reflects the effects of higher natural gas volumes principally resulting from customer growth including customers obtained through the acquisition of South Jersey Energy Company’s natural gas marketing business on December 1, 2018, and slightly higher average natural gas prices. The decrease in capacity management revenues reflects significantly lower capacity values during Fiscal 2019. The lower electric generation revenues reflect lower off-peak volumes at the Hunlock Station generating facility due to a decline in economic dispatch opportunities and, to a much lesser extent, lower volumes at the Conemaugh Station. Midstream & Marketing cost of sales was $1,241.2 million in Fiscal 2019 compared to $1,090.8 million in the prior year, an increase of $150.4 million, principally reflecting the higher natural gas volumes and higher natural gas costs offset in part by lower electricity generation cost of sales on lower volumes produced.
Midstream & Marketing total margin decreased $56.4 million in Fiscal 2019 principally reflecting lower capacity management total margin ($68.5 million), lower electric generation total margin ($9.6 million) and lower margin from natural gas marketing reflecting lower average unit margins. These decreases were partially offset by higher natural gas gathering total margin including incremental margin from CMG. The decrease in capacity management total margin reflects significantly lower baseload capacity values, and higher prior-year pricing spreads between Marcellus and non-Marcellus delivery points. The lower capacity pricing spreads during Fiscal 2019 are principally the result of the absence of extremely cold and volatile weather experienced in late December and early January of Fiscal 2018, the effects of increased pipeline restrictions during the Fiscal 2019 heating season, and the effects on capacity values from new pipeline capacity. The lower total margin from electric generation principally reflects lower electric generation volumes from our Hunlock Station generating facility due to a decline in off-peak economic dispatch opportunities.
Midstream & Marketing operating income and earnings before interest expense and income taxes decreased $70.1 million and $64.6 million, respectively. The decrease in operating income principally reflects the previously mentioned decrease in total margin ($56.4 million), higher depreciation and amortization expense ($7.9 million), and higher operating and administrative expenses ($6.7 million). The increase in depreciation and amortization expense principally reflects incremental depreciation from the expansion of our natural gas gathering assets including CMG and, to a much lesser extent, our peaking and LNG assets. The $6.7 million increase in operating and administrative expenses principally reflects higher expenses associated with greater natural gas gathering, LNG and peaking activities including incremental operating and administrative expenses associated with CMG, slightly higher compensation and benefits expense and higher operation and maintenance expenses associated with a planned outage at the Conemaugh generating unit. The $64.6 million decrease in earnings before interest expense and income taxes principally reflects the lower operating income ($70.1 million) partially offset by higher AFUDC income associated with the PennEast pipeline and equity income from Pennant, a natural gas gathering and processing joint venture acquired as part of the CMG Acquisition.

UGI Utilities |  | 2019 |  | 2018 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 1,048.6 |  |  | $ | 1,092.4 |  |  | $ | (43.8 | ) |  | (4.0 | )%
Total margin (a)(b) |  | $ | 562.6 |  |  | $ | 564.5 |  |  | $ | (1.9 | ) |  | (0.3 | )%
Operating and administrative expenses (b) |  | $ | 244.3 |  |  | $ | 242.2 |  |  | $ | 2.1 |  |  | 0.9 | %
Operating income |  | $ | 224.2 |  |  | $ | 239.9 |  |  | $ | (15.7 | ) |  | (6.5 | )%
Earnings before interest expense and income taxes |  | $ | 225.7 |  |  | $ | 237.5 |  |  | $ | (11.8 | ) |  | (5.0 | )%
Gas Utility system throughput – bcf |  |  |  |  |  |  |  |
Core market |  | 80.3 |  |  | 80.2 |  |  | 0.1 |  |  | 0.1 | %
Total |  | 293.9 |  |  | 264.0 |  |  | 29.9 |  |  | 11.3 | %
Electric Utility distribution sales - gwh |  | 983.4 |  |  | 1,005.9 |  |  | (22.5 | ) |  | (2.2 | )%
Gas Utility degree days – % (warmer) than normal (c) |  | (5.0 | )% |  | (2.1 | )% |  | — |  |  | — |

(a) | In accordance with the PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for Fiscal 2019 were reduced by $36.1 million to reflect the credit to customers of tax savings under the TCJA. Gas Utility’s revenues and total margin for Fiscal 2018 were reduced by $24.1 million and an associated regulatory liability established related to tax savings accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA.

(b) | Total margin represents total revenues less total cost of sales and revenue-related taxes (i.e. Electric Utility gross receipts taxes) of $4.7 million and $5.0 million during Fiscal 2019 and Fiscal 2018, respectively. For financial statement purposes,

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revenue-related taxes are included in “Operating and administrative expenses” on the Consolidated Statements of Income (but are excluded from operating expenses presented above).

(c) | Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory during Fiscal 2019 were 5.0% warmer than normal and 3.0% warmer than Fiscal 2018. Notwithstanding the warmer weather, Gas Utility core market volumes were about equal to the prior year reflecting, in large part, growth in the number of core market customers and higher use per customer. Total Gas Utility distribution system throughput increased 29.9 bcf reflecting higher large firm delivery service volumes (28.5 bcf) and slightly higher interruptible delivery service volumes (1.3 bcf). Electric Utility kilowatt-hour sales were 2.2% lower than the prior year principally reflecting the impact of the warmer winter weather on Electric Utility heating-related sales.
UGI Utilities revenues decreased $43.8 million reflecting a $41.7 million decrease in Gas Utility revenues and a $2.1 million decrease in Electric Utility revenues. Gas Utility revenues in both Fiscal 2019 and Fiscal 2018 reflect the effects of the May 17, 2018, PAPUC Order regarding the credit to customers of tax savings under the TCJA. Excluding the effects on revenues in both years as a result of the PAPUC Order, Gas Utility’s revenues decreased $29.9 million principally reflecting lower core market revenues ($37.8 million) due to lower Fiscal 2019 average PGC rates and lower large firm and interruptible delivery service revenues ($4.0 million) partially offset by an increase in off-system sales revenues ($9.5 million) and higher other revenues ($2.4 million). Fiscal 2019 off-system sales revenues include revenue from capacity releases due principally to the adoption of ASC 606 (which requires capacity release contracts be reflected on a gross, rather than net, basis). The decrease in Electric Utility revenues reflects the effects of the lower distribution system sales and lower default service rates partially offset by an increase in Electric Utility base rates effective October 27, 2018 ($2.3 million) and higher transmission revenue ($1.6 million).
UGI Utilities cost of sales was $481.3 million in Fiscal 2019 compared with $522.9 million in Fiscal 2018 reflecting lower Gas Utility cost of sales ($37.1 million) and lower Electric Utility cost of sales ($4.6 million) as a result of the lower distribution system sales and lower default service rates. The lower Gas Utility cost of sales principally reflects lower average retail core-market PGC rates ($41.9 million). Because Gas Utility and Electric Utility are subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in the actual cost of gas or electricity associated with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect on retail core-market margin (see Note 9 to Consolidated Financial Statements for a discussion of these recovery mechanisms).
UGI Utilities total margin decreased $1.9 million reflecting lower total margin from Gas Utility ($4.6 million) partially offset by higher total margin from Electric Utility ($2.8 million). Gas Utility total margin in both Fiscal 2019 and Fiscal 2018 reflects the effects of the May 17, 2018, PAPUC Order regarding the credit to customers of tax savings under the TCJA. Excluding the effects on margin in both periods as a result of the PAPUC Order, Gas Utility total margin increased $7.5 million. The increase in Gas Utility margin reflects higher off-system sales margin principally resulting from the previously mentioned presentation of certain revenues in accordance with the adoption of ASC 606, and higher total margin from core market customers reflecting, among other things, higher DSIC revenues. The increase in Electric Utility margin principally reflects higher transmission revenue and the increase in base rates partially offset by lower distribution system sales.
UGI Utilities operating income decreased $15.7 million principally reflecting the decrease in total margin ($1.9 million), higher operating and administrative expenses ($2.1 million), greater depreciation expense ($8.2 million), and higher other operating expense ($1.7 million). The increase in UGI Utilities operating and administrative expenses reflects, among other things, higher contractor and outside services expense ($5.3 million) and higher IT maintenance and consulting expenses ($3.0 million) partially offset by lower uncollectible accounts expense ($3.6 million). The increase in depreciation expense reflects increased distribution system and IT capital expenditure activity. UGI Utilities earnings before interest and income taxes decreased $11.8 million principally reflecting the decrease in UGI Utilities operating income ($15.7 million) partially offset by higher postretirement plan non-service income ($4.0 million).
Interest Expense and Income Taxes
Our consolidated interest expense during Fiscal 2019 was $257.8 million, $27.7 million higher than the interest expense recorded during Fiscal 2018. The higher interest expense principally reflects higher interest expense on long-term debt including debt incurred by UGI Corporation and Energy Services to fund a portion of the CMG Acquisition and the cash portion of the AmeriGas Merger, higher long-term debt at UGI Utilities, and higher interest on short-term borrowings.
Our effective income tax rate in Fiscal 2019 reflects a U.S. federal income tax rate of 21%. Our effective income tax rate in Fiscal 2018 reflects a blended U.S. federal income tax rate of 24.5%. As previously mentioned, our consolidated income taxes for Fiscal 2018 were significantly impacted by the enactment of the TCJA and the December 2017 French Finance Bills. As a result of the
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TCJA and the December 2017 French Finance Bills, during Fiscal 2018 we remeasured our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. Due to the effects of utility ratemaking, most of the reductions in UGI Utilities’ deferred income tax assets and liabilities were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities. Income tax expense for Fiscal 2018 was reduced by remeasurement adjustments totaling $166.3 million to tax-related accounts as a result of the enactment of the TCJA and was reduced by remeasurement adjustments totaling $12.1 million to net deferred income tax liabilities as a result of the December 2017 French Finance Bills. For further information on these tax law changes and the TCJA’s effects on regulatory assets and liabilities, see Notes 7 and 9 to Consolidated Financial Statements.
Fiscal 2018 Compared with Fiscal 2017
Consolidated Results
Net Income Attributable to UGI Corporation by Segment:

|  | 2018 |  | 2017 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 76.3 |  |  | 10.6 | % |  | $ | 54.2 |  |  | 12.4 | % |  | $ | 22.1 |  |  | 40.8 | %
UGI International |  | 153.1 |  |  | 21.3 | % |  | 155.8 |  |  | 35.7 | % |  | (2.7 | ) |  | (1.7 | )%
Midstream & Marketing |  | 126.7 |  |  | 17.6 | % |  | 86.9 |  |  | 19.9 | % |  | 39.8 |  |  | 45.8 | %
UGI Utilities |  | 140.9 |  |  | 19.6 | % |  | 116.0 |  |  | 26.6 | % |  | 24.9 |  |  | 21.5 | %
Corporate & Other (a) |  | 221.7 |  |  | 30.9 | % |  | 23.7 |  |  | 5.4 | % |  | 198.0 |  |  | N.M. |
Net income attributable to UGI Corporation |  | $ | 718.7 |  |  | 100.0 | % |  | $ | 436.6 |  |  | 100.0 | % |  | $ | 282.1 |  |  | 64.6 | %

(a) | Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income attributable to UGI Corporation. These adjustments have been excluded from the segment results to align with the measure used by our CODM in assessing segment performance and allocating resources. These items totaled $233.1 million and $30.5 million in Fiscal 2018 and Fiscal 2017, respectively. See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” above and Note 22 to Consolidated Financial Statements for further information.

N.M. — Variance is not meaningful.

AmeriGas Propane |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,823.0 |  |  | $ | 2,453.5 |  |  | $ | 369.5 |  |  | 15.1 | %
Total margin (a) |  | $ | 1,508.3 |  |  | $ | 1,450.6 |  |  | $ | 57.7 |  |  | 4.0 | %
Operating and administrative expenses (b) |  | $ | 924.7 |  |  | $ | 916.6 |  |  | $ | 8.1 |  |  | 0.9 | %
Operating income / earnings before interest expense and income taxes (c) (d) |  | $ | 422.2 |  |  | $ | 355.3 |  |  | $ | 66.9 |  |  | 18.8 | %
Partnership Adjusted EBITDA (e) |  | $ | 605.5 |  |  | $ | 551.3 |  |  | $ | 54.2 |  |  | 9.8 | %
Retail gallons sold (millions) |  | 1,081.3 |  |  | 1,046.9 |  |  | 34.4 |  |  | 3.3 | %
Degree days – % colder (warmer) than normal (f) |  | 0.3 | % |  | (11.3 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales.

(b) | Operating and administrative expenses in Fiscal 2017 include a $7.5 million environmental accrual associated with the site of a former MGP obtained in a prior-year acquisition. See Note 16 to Consolidated Financial Statements.

(c) | Fiscal 2017 reflects adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income / earnings before interest expense and income taxes by $7.7 million.

(d) | Amounts in Fiscal 2017 reflect an adjustment to correct depreciation expense associated with prior periods which reduced operating income / earnings before interest expense and income taxes by $7.5 million.

(e) | Partnership Adjusted EBITDA is a non-GAAP financial measure and is not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not a substitute for, the comparable GAAP measures. Management believes

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Partnership Adjusted EBITDA is a meaningful non-GAAP measure used by investors to (1) compare the Partnership’s operating performance with that of other companies within the propane industry and (2) assess the Partnership’s ability to meet loan covenants.
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:

|  | 2018 |  | 2017
Income before income taxes |  | $ | 259.1 |  |  | $ | 195.1 |
Interest expense |  | 163.1 |  |  | 160.2 |
Depreciation and amortization |  | 185.8 |  |  | 190.5 |
MGP environmental accrual |  | — |  |  | 7.5 |
Noncontrolling interest (i) |  | (2.5 | ) |  | (2.0 | )
Partnership Adjusted EBITDA |  | $ | 605.5 |  |  | $ | 551.3 |

(i) principally represents 1.01% noncontrolling interest in AmeriGas OLP.

(f) | Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by the NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.

AmeriGas Propane’s retail gallons sold during Fiscal 2018 were 3.3% higher than in Fiscal 2017. Average temperatures based upon heating degree days during Fiscal 2018 were 0.3% colder than normal and 13.0% colder than Fiscal 2017.
AmeriGas Propane retail propane revenues increased $337.9 million during Fiscal 2018 reflecting the effects of higher average retail selling prices ($267.5 million) and higher retail volumes sold ($70.4 million). Wholesale propane revenues increased $24.4 million reflecting the effects of higher average wholesale selling prices ($13.5 million) and higher wholesale volumes sold ($10.9 million). Average daily wholesale propane commodity prices during Fiscal 2018 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 36% higher than such prices during Fiscal 2017. Other revenues in Fiscal 2018 were slightly higher than in the prior year principally reflecting higher service and ancillary revenues. AmeriGas Propane cost of sales increased $311.8 million principally reflecting the effects on propane cost of sales of higher average propane product costs ($266.1 million) and, to a much lesser extent, the effects of the higher retail and wholesale propane volumes sold ($39.6 million).
AmeriGas Propane total margin increased $57.7 million principally reflecting slightly higher retail propane total margin ($56.6 million) and slightly higher non-propane total margin ($1.1 million). The increase in retail propane total margin reflects the higher retail volumes sold and, to a much lesser extent, slightly higher average retail propane unit margins.
AmeriGas Propane operating income / earnings before interest expense and income taxes increased $66.9 million in Fiscal 2018 as the $57.7 million increase in total margin, higher other operating income ($12.5 million) and a decrease in depreciation and amortization expense ($4.7 million) were partially offset by a $15.6 million increase in operating and administrative expenses (excluding the effects of the $7.5 million MGP accrual in the prior year). The increase in Partnership operating and administrative expenses reflects, among other things, higher total compensation and benefits cost ($20.4 million), principally higher labor, overtime and incentive compensation costs associated with the increased activity and improved performance; higher vehicle expenses ($10.6 million); and higher outside services expense ($6.3 million). These increases in operating expenses were partially offset by lower general insurance and self-insured casualty and liability expense and, to a lesser extent, lower provisions for uncollectible accounts and travel and entertainment expenses.
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UGI International |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,683.8 |  |  | $ | 1,877.5 |  |  | $ | 806.3 |  |  | 42.9 | %
Total margin (a) |  | $ | 1,043.2 |  |  | $ | 936.4 |  |  | $ | 106.8 |  |  | 11.4 | %
Operating and administrative expenses |  | $ | 657.9 |  |  | $ | 581.8 |  |  | $ | 76.1 |  |  | 13.1 | %
Operating income |  | $ | 247.9 |  |  | $ | 234.3 |  |  | $ | 13.6 |  |  | 5.8 | %
Earnings before interest expense and income taxes |  | $ | 240.4 |  |  | $ | 235.5 |  |  | $ | 4.9 |  |  | 2.1 | %
LPG retail gallons sold (millions) (b) |  | 875.0 |  |  | 817.9 |  |  | 57.1 |  |  | 7.0 | %
Degree days - % (warmer) colder than normal (c) |  | (5.3 | )% |  | 0.7 | % |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales and costs of French energy certificates in Fiscal 2018 and Fiscal 2017 of $20.5 million and $5.8 million, respectively. For financial statement purposes, these amounts are included in operating and administrative expenses on the Fiscal 2018 and Fiscal 2017 Consolidated Statements of Income (but are excluded from operating expenses above).

(b) | Amounts adjusted to conform to Fiscal 2019 classification.

(c) | Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

Average temperatures during Fiscal 2018 were approximately 5.3% warmer than normal and 5.9% warmer than Fiscal 2017. Total retail gallons sold during Fiscal 2018 were higher reflecting incremental LPG retail gallons sold from our October 2017 acquisition of UniverGas. Our existing businesses’ retail volumes were slightly lower than the prior year as slightly higher bulk sales late in the heating season were offset by the effects of warmer weather and lower crop-drying volumes early in Fiscal 2018. During Fiscal 2018, average wholesale prices for propane and butane in northwest Europe were approximately 23% and 19% higher than in Fiscal 2017, respectively.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During Fiscal 2018 and Fiscal 2017, the average unweighted euro-to-dollar translation rates were approximately $1.19 and $1.11, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.35 and $1.27, respectively. Although the euro and British pound sterling were stronger during Fiscal 2018 and affect the comparison of line item amounts presented in the table above, the beneficial impact of the stronger currencies on net income was substantially offset by net losses on foreign currency exchange contracts.
UGI International revenues increased $806.3 million during Fiscal 2018 reflecting approximately $439 million of combined incremental revenues from UniverGas and DVEP, higher LPG selling prices and the translation effects on our existing businesses’ revenues of the stronger euro and British pound sterling. The higher LPG selling prices reflect in large part the effects of higher LPG product costs. UGI International cost of sales increased $684.8 million during Fiscal 2018 reflecting approximately $381 million of incremental cost of sales associated with UniverGas and DVEP, the effects on cost of sales from the higher average LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.
The $106.8 million increase in total margin principally reflects the translation effects of the stronger euro and British pound sterling on margin (approximately $80 million), incremental margin from UniverGas and DVEP ($58 million), and slightly higher natural gas margin from our existing energy marketing business. These increases in margin were partially offset by slightly lower total margin from our existing retail LPG business reflecting in large part lower Fiscal 2018 income on foreign currency exchange contracts. Total margin from our existing natural gas business increased approximately $4.9 million reflecting higher subscription fee margin partially offset by lower average unit margins during Fiscal 2018.
The $13.6 million increase in UGI International operating income principally reflects the previously mentioned $106.8 million increase in total margin partially offset by a $76.1 million increase in operating and administrative expenses and a $23.2 million increase in depreciation and amortization expense. The increase in operating and administrative expenses principally reflects the translation effects of the stronger euro and British pound sterling on local currency expenses and approximately $39 million of incremental expenses from UniverGas and DVEP. Our existing businesses’ local currency operating and administrative expenses were lower than the prior year as lower tank and cylinder repair costs were partially offset by higher operational safety requirements and slightly higher distribution costs. The increase in depreciation and amortization expense principally reflects incremental amounts associated with UniverGas and DVEP ($9.9 million) and the translation effects of the stronger currencies. UGI International earnings before interest expense and income taxes increased $4.9 million principally reflecting the previously mentioned $13.6
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million increase in UGI International operating income and higher pension and other postretirement plan income ($4.4 million) partially offset by higher realized losses on foreign currency exchange contracts ($12.7 million) due to the effects of the stronger euro.

Midstream & Marketing |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 1,421.7 |  |  | $ | 1,121.2 |  |  | $ | 300.5 |  |  | 26.8 | %
Total margin |  | $ | 330.9 |  |  | $ | 264.5 |  |  | $ | 66.4 |  |  | 25.1 | %
Operating and administrative expenses |  | $ | 112.8 |  |  | $ | 95.4 |  |  | $ | 17.4 |  |  | 18.2 | %
Operating income |  | $ | 175.1 |  |  | $ | 139.4 |  |  | $ | 35.7 |  |  | 25.6 | %
Earnings before interest expense and income taxes |  | $ | 178.7 |  |  | $ | 143.5 |  |  | $ | 35.2 |  |  | 24.5 | %

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.5% warmer than normal during Fiscal 2018 but approximately 12.0% colder than Fiscal 2017. Midstream & Marketing’s Fiscal 2018 revenues were $300.5 million higher reflecting higher natural gas ($210.6 million) and retail power marketing ($15.0 million) revenues; higher revenues from midstream assets ($62.4 million), principally higher natural gas gathering, peaking, and capacity management revenues; and higher electric generation revenues ($13.1 million). The increase in natural gas revenues principally reflects the effects of higher natural gas volumes from colder Fiscal 2018 temperatures, customer growth and slightly higher average natural gas prices. The increase in capacity management and peaking revenues reflects the effects of colder weather in late December and January, higher capacity values, and with respect to peaking revenues, an increase in the number of peaking contracts. The higher natural gas gathering revenues principally reflects incremental revenues from the Sunbury Pipeline and from the Texas Creek natural gas gathering assets acquired on October 31, 2017. Electric generation revenues reflect higher volumes generated principally from the Hunlock natural-gas fired generation station and higher average selling prices. Midstream & Marketing cost of sales was $1,090.8 million in Fiscal 2018 compared to $856.7 million in Fiscal 2017, an increase of $234.1 million, principally reflecting higher natural gas and retail power cost of sales primarily a result of the higher natural gas and retail power volumes and higher average natural gas costs.
Midstream & Marketing total margin increased $66.4 million in Fiscal 2018 reflecting higher total margin from our midstream assets ($57.1 million), principally the result of higher natural gas gathering, capacity management and peaking total margin, and higher electricity generation total margin ($6.9 million). Fiscal 2018 total margin from natural gas marketing was about equal to Fiscal 2017 as slightly higher natural gas marketing volumes sold were offset by slightly lower average unit margins. The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, higher margin from the expansion of our natural gas gathering assets including the Texas Creek natural gas gathering assets. The increase in capacity management and peaking total margin reflects in large part the effects of extremely cold weather primarily in late December and in January, higher capacity values and, with respect to peaking margin, a year-over-year increase in the number of peaking contracts. The higher electricity generation total margin reflects higher electric generation volumes principally at our Hunlock Station generating facility and higher electricity unit margins.
The $35.7 million increase in Midstream & Marketing operating income principally reflects the previously mentioned increase in total margin ($66.4 million) partially offset by higher operating and administrative expenses ($17.4 million), higher depreciation expense ($8.1 million), and a decrease in other operating income primarily reflecting the absence of AFUDC income associated with the Sunbury Pipeline project recorded in Fiscal 2017 ($5.2 million). The $17.4 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The $35.2 million increase in earnings before interest expense and income taxes in Fiscal 2018 principally reflects the higher operating income ($35.7 million).
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UGI Utilities |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 1,092.4 |  |  | $ | 887.6 |  |  | $ | 204.8 |  |  | 23.1 | %
Total margin (a)(b) |  | $ | 564.5 |  |  | $ | 515.6 |  |  | $ | 48.9 |  |  | 9.5 | %
Operating and administrative expenses |  | $ | 242.2 |  |  | $ | 218.8 |  |  | $ | 23.4 |  |  | 10.7 | %
Operating income (a) |  | $ | 239.9 |  |  | $ | 232.7 |  |  | $ | 7.2 |  |  | 3.1 | %
Earnings before interest expense and income taxes (a) |  | $ | 237.5 |  |  | $ | 228.3 |  |  | $ | 9.2 |  |  | 4.0 | %
Net income attributable to UGI Corporation (a) |  | $ | 140.9 |  |  | $ | 116.0 |  |  | $ | 24.9 |  |  | 21.5 | %
Gas Utility system throughput – bcf |  |  |  |  |  |  |  |
Core market |  | 80.2 |  |  | 70.4 |  |  | 9.8 |  |  | 13.9 | %
Total |  | 264.0 |  |  | 243.1 |  |  | 20.9 |  |  | 8.6 | %
Electric Utility distribution sales - gwh |  | 1,005.9 |  |  | 950.6 |  |  | 55.3 |  |  | 5.8 | %
Gas Utility degree days – % (warmer) than normal (b) |  | (2.1 | )% |  | (11.1 | )% |  | — |  |  | — |

(a) | Gas Utility’s Fiscal 2018 revenues, total margin, operating income and income before income taxes were reduced by $24.1 million to record the effects of income tax savings that accrued during the period January 1, 2018 to June 30, 2018, in accordance with a PAPUC Order issued May 17, 2018, related to the TCJA (see Notes 7 and 9 to Consolidated Financial Statements). Although UGI Utilities’ income before income taxes for Fiscal 2018 was negatively impacted by this $24.1 million reduction in revenues, the impact on UGI Utilities’ net income was offset by a reduction in Fiscal 2018 income tax expense principally as a result of the lower federal income tax rate. The impact of the PAPUC Order on revenues for the period July 1, 2018 to September 30, 2018 was not material.

(b) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $5.0 million and $4.7 million during Fiscal 2018 and Fiscal 2017, respectively. For financial statement purposes, Electric Utility gross receipts taxes are included in “Operating and administrative expenses” on the Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above).

(c) | Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory during Fiscal 2018 were 2.1% warmer than normal but 10.1% colder than Fiscal 2017. Gas Utility core market volumes increased 9.8 bcf (13.9%) reflecting, among other things, the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 20.9 bcf principally reflecting higher large firm delivery service volumes and the higher core market volumes. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 5.8% higher than Fiscal 2017, principally reflecting the effects of colder heating-season weather on heating-related sales, and the effects of warmer summer weather on air-conditioning sales.
UGI Utilities revenues increased $204.8 million reflecting a $195.7 million increase in Gas Utility revenues and a $9.1 million increase in Electric Utility revenues. In accordance with a PAPUC Order issued May 17, 2018, during Fiscal 2018 Gas Utility’s revenues were reduced by $24.1 million, and an associated regulatory liability was established, to record the effects of tax savings that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact on revenues from the PAPUC Order, Gas Utility revenues increased $218.8 million principally reflecting an increase in core market revenues ($143.0 million), higher off-system sales revenues ($54.6 million), and higher large firm delivery service revenues ($21.2 million).
The $143.0 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput ($70.7 million), higher average retail core market PGC rates ($61.4 million) and the increase in PNG base rates effective October 20, 2017 ($10.9 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system sales ($6.1 million) and higher average DS rates ($2.6 million). UGI Utilities cost of sales was $522.9 million in Fiscal 2018 compared with $367.3 million in Fiscal 2017 principally reflecting higher Gas Utility cost of sales ($149.3 million) and higher Electric Utility cost of sales ($6.3 million). The higher Gas Utility cost of sales principally reflects higher average retail core market PGC rates ($61.4 million), higher cost of sales associated with Gas Utility off-system sales ($54.6 million), and higher retail core-market volumes ($26.8 million). The higher Electric Utility cost of sales reflects the higher electricity sales.
UGI Utilities total margin increased $48.9 million principally reflecting higher total margin from Gas Utility core market customers ($53.9 million) and higher large firm delivery service total margin ($15.8 million) partially offset by the reduction in margin resulting from the PAPUC’s May 17, 2018 Order regarding the effects of the TCJA. The increase in Gas Utility core market margin
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principally reflects the higher core market throughput ($44.6 million) and the increase in PNG base rates effective October 20, 2017 ($9.3 million). Electric Utility total margin increased $2.4 million principally reflecting the higher distribution system sales.
UGI Utilities operating income increased $7.2 million principally reflecting the increase in total margin ($48.9 million) partially offset by higher operating and administrative expenses ($23.4 million), greater depreciation expense ($12.3 million) associated with increased distribution system and IT capital expenditure activity, and lower other operating income ($6.1 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($9.9 million), higher contractor and outside services expenses ($5.0 million), higher IT maintenance and consulting expenses ($4.0 million) and higher compensation and benefits expenses ($4.6 million). The decrease in other operating income principally reflects the absence of $5.8 million of income from an environmental insurance settlement recorded in Fiscal 2017. UGI Utilities earnings before interest expense and income taxes increased $9.2 million reflecting the increase in UGI Utilities operating income ($7.2 million) and lower pension and other postretirement non-service expense ($2.0 million).
Although UGI Utilities earnings before interest expense and income taxes increased a modest $9.2 million (4.0%) in Fiscal 2018 due to the impact on revenues from the PAPUC Order regarding income tax savings for the period January 1, 2018 to June 30, 2018, UGI Utilities net income attributable to UGI increased $24.9 million (21.5%). UGI Utilities Fiscal 2018 net income reflects the benefits of a $23.4 million decrease in current-year income taxes principally as a result of the lower federal income tax rate in Fiscal 2018.
Interest Expense and Income Taxes
Our consolidated interest expense during Fiscal 2018 was $230.1 million, $6.6 million higher than the $223.5 million of interest expense recorded during Fiscal 2017. The higher interest expense principally reflects the effects of higher long-term debt outstanding at UGI Utilities, higher average short-term borrowings and higher short-term interest rates, and the effects of the stronger euro on UGI International interest expense. These increases were partially offset by lower average interest rates on long-term debt at AmeriGas Propane and lower average debt outstanding at UGI International.
As previously mentioned, our consolidated income taxes for Fiscal 2018 were significantly impacted by the enactment of the TCJA in the U.S. and the December 2017 French Finance Bills. Our effective tax rate for Fiscal 2018 reflects the effects of deferred income tax asset and liability remeasurement adjustments resulting from the TCJA and the December 2017 French Finance Bills, which adjustments reduced Fiscal 2018 income tax expense by $178.4 million, and the lower blended U.S. federal income tax rate of 24.5% compared with 35% in Fiscal 2017. The effective income tax rate in Fiscal 2017 reflects the impact of a December 2016 change in the French corporate income tax rate for future years which reduced consolidated income tax expense by $29.0 million and, to a much lesser extent, the effects of an income tax settlement refund of $6.7 million, plus interest, in France.
Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a Receivables Facility. Long-term cash requirements are generally met through the issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and Receivables Facility borrowing capacity; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents totaled $447.1 million at September 30, 2019, compared with $452.6 million at September 30, 2018. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2019 and 2018, our cash and cash equivalents totaled $224.9 million and $194.3 million, respectively, a substantial portion of which is located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
UGI receives cash distributions from the Partnership in accordance with the Partnership Agreement’s requirement to make quarterly distributions in a total amount equal to its Available Cash. Prior to the AmeriGas Merger, amounts paid to the General Partner included incentive distributions when AmeriGas Partners’ quarterly distribution exceeded $0.605 per limited partner unit. During Fiscal 2019, Fiscal 2018 and Fiscal 2017, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner interest in the Partnership totaled $54.9 million, $54.9 million and $52.7 million, respectively, including incentive distributions totaling $45.7 million, $45.3 million and $43.5 million, respectively. See Note 15 to Consolidated
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Financial Statements for the definition of Available Cash included in the Partnership Agreement and additional information related to Partnership distributions.
During Fiscal 2019, Fiscal 2018 and Fiscal 2017, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

Year Ended September 30, |  | 2019 |  | 2018 |  | 2017
(Millions of dollars) |  |  |  |  |  |
AmeriGas Propane |  | $ | 118.5 |  |  | $ | 128.0 |  |  | $ | 123.0 |
UGI International (a) |  | 64.1 |  |  | 19.0 |  |  | 118.3 |
Midstream & Marketing |  | 50.0 |  |  | — |  |  | — |
UGI Utilities |  | 20.0 |  |  | 50.0 |  |  | 57.7 |
Total |  | $ | 252.6 |  |  | $ | 197.0 |  |  | $ | 299.0 |

(a) | Represents cash payments to UGI International’s U.S. holding company subsidiary. Cash dividends and other cash payments received from UGI International in Fiscal 2018 were impacted by the use of cash for the acquisition of UniverGas.

Dividends and Distributions
On April 30, 2019, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.30 per Common Share, or $1.20 on an annual basis, from the previous quarterly rate of $0.26, effective with the dividend payable on July 1, 2019, to shareholders of record on June 14, 2019. On July 23, 2019, UGI’s Board of Directors approved an additional increase in the quarterly dividend rate on UGI Common Stock to $0.325 per Common Share, or $1.30 on an annual basis, effective with the dividend payable on October 1, 2019, to shareholders of record on August 9, 2019. On a combined basis, these dividend increases resulted in a 25% increase in UGI’s dividend rate during Fiscal 2019.
On November 22, 2019, UGI’s Board of Directors declared a cash dividend equal to $0.325 per common share. The dividend will be payable on January 1, 2020, to shareholders of record on December 16, 2019.
Prior to the AmeriGas Merger, the General Partner’s Board of Directors approved, and AmeriGas Partners paid, quarterly distributions on AmeriGas Partners Common Units at a rate of $0.95 per Common Unit with respect to the first three quarters of Fiscal 2019 and the quarter ended September 30, 2018.
Repurchases of Common Stock
In January 2018, UGI’s Board of Directors authorized an extension of a previous share repurchase program for up to 8 million shares of UGI Corporation Common Stock for an additional four-year period expiring in January 2022. Pursuant to such authorizations, during Fiscal 2019, Fiscal 2018 and Fiscal 2017, the Company purchased on the open market 0.3 million, 1.2 million and 0.9 million shares at a total purchase price of $16.9 million, $59.8 million and $43.3 million, respectively.
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Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2019 and 2018, comprises the following:

| 2019 |  | 2018
(millions of dollars) | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corp. & Other |  | Total |  | Total
Short-term borrowings | $ | 328.0 |  |  | $ | 210.9 |  |  | $ | 91.4 |  |  | $ | 166.0 |  |  | $ | — |  |  | $ | 796.3 |  |  | $ | 424.9 |
Long-term debt (including current maturities): |  |  |  |  |  |  |  |  |  |  |  |  |
Senior notes | $ | 2,575.0 |  |  | $ | 381.5 |  |  | $ | — |  |  | $ | 825.0 |  |  | $ | — |  |  | $ | 3,781.5 |  |  | $ | 3,250.0 |
Term loans | — |  |  | 327.0 |  |  | 698.3 |  |  | 154.1 |  |  | 550.0 |  |  | 1,729.4 |  |  | 890.4 |
Other long-term debt | 13.3 |  |  | 19.3 |  |  | 0.3 |  |  | 4.7 |  |  | 308.1 |  |  | 345.7 |  |  | 59.0 |
Unamortized debt issuance costs | (23.7 | ) |  | (8.3 | ) |  | (12.0 | ) |  | (4.6 | ) |  | (4.0 | ) |  | (52.6 | ) |  | (34.1 | )
Total long-term debt | $ | 2,564.6 |  |  | $ | 719.5 |  |  | $ | 686.6 |  |  | $ | 979.2 |  |  | $ | 854.1 |  |  | $ | 5,804.0 |  |  | $ | 4,165.3 |
Total debt | $ | 2,892.6 |  |  | $ | 930.4 |  |  | $ | 778.0 |  |  | $ | 1,145.2 |  |  | $ | 854.1 |  |  | $ | 6,600.3 |  |  | $ | 4,590.2 |

Significant Financing Activities
UGI International. On October 18, 2018, UGI International, LLC entered into the 2018 UGI International Credit Facilities Agreement, a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 million variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 million senior unsecured multicurrency revolving facility agreement. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin (as defined in the agreement) and the associated euribor rate. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swap agreements to fix the underlying euribor rate on term loan borrowings at 0.34% through October 18, 2022. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Such loans will bear interest at the applicable rate (euribor or LIBOR rate) plus a margin as defined in the agreement.
On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 million principal amount of 3.25% senior unsecured notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 million outstanding principal of UGI France’s variable-rate term loan under its 2015 Senior Facilities Agreement due April 2020; €45.8 million of outstanding principal of Flaga’s variable-rate term loan due October 2020; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable-rate term loan due April 2020, plus accrued and unpaid interest, and (2) for general corporate purposes. Upon entering into the 2018 UGI International Credit Facilities Agreement, we terminated (1) the 2017 UGI International Credit Agreement; (2) UGI France’s revolving credit facility under the 2015 Senior Facilities Agreement; and (3) Flaga’s credit facility agreement.
On July 31, 2019 and August 1, 2019, UGI International, LLC paid cash distributions to Enterprises totaling $332.5 million. These distributions were funded by $290 million of borrowings under the 2018 UGI International Credit Facilities Agreement’s multicurrency revolving facility agreement (of which $210 million remained outstanding at September 30, 2019) and cash on hand.
Energy Services. On August 13, 2019, Energy Services entered into a seven-year $700 million variable-rate senior secured term loan agreement with a group of lenders. The Energy Services Term Loan is payable in equal quarterly installments of $1.8 million, commencing in September 2019, with the balance of the principal being due and payable in full at maturity. Borrowings under the Energy Services Term Loan bear interest at rates per annum, comprising the aggregate of the applicable margin (as defined in the agreement) and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. Energy Services has entered into a pay-fixed, receive-variable interest rate swap agreement to fix the underlying LIBOR rate on a significant portion of the Energy Services Term Loan borrowings at 1.55% through July 2024. Proceeds from borrowings under the Energy Services Term Loan were used to finance a portion of the CMG Acquisition and for general corporate purposes.
On August 13, 2019, Energy Services amended the Energy Services Credit Agreement to, among other things, decrease the borrowing capacity from $240 million to $200 million. Additionally, the amendment granted credit agreement lenders a security
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interest in the collateral of the Energy Services Term Loan. All other material terms of the Energy Services Credit Agreement remained unchanged.
UGI Utilities. On June 27, 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350 million (including a $100 million sublimit for letters of credit). UGI Utilities may request an increase in the amount of loan commitments up to a maximum aggregate amount of $150 million. Under the UGI Utilities 2019 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. Concurrently with entering into the UGI Utilities 2019 Credit Agreement, UGI Utilities terminated its existing $450 million revolving credit agreement. The UGI Utilities 2019 Credit Agreement is currently scheduled to expire in June 2024.
On February 1, 2019, UGI Utilities issued in a private placement $150 million of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the issuance of the UGI Utilities 4.55% Senior Notes were used to reduce revolving credit agreement borrowings and for general corporate purposes.
UGI Corporation. On August 1, 2019, UGI entered into the UGI Corporation Senior Credit Facility. The UGI Corporation Senior Credit Facility comprises (1) a five-year $250 million amortizing variable-rate term loan which was drawn on August 21, 2019; (2) a three-year $300 million variable-rate term loan which was drawn on August 1, 2019; and (3) a five-year $300 million revolving credit facility (including a $10 million sublimit for letters of credit) which was drawn in full on August 1, 2019. The $250 million term loan commitment is payable in equal quarterly installments of $9.4 million, commencing in December 2022, with the balance of the principal being due and payable in full on August 1, 2024. Borrowings under the UGI Corporation Senior Credit Facility bear interest comprising the aggregate of the applicable margin and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. UGI has entered into pay-fixed, receive-variable interest rate swap agreements to fix the underlying LIBOR interest rates on all or a significant portion of the loans’ outstanding principal balance, and all or a significant portion of the term loans’ tenor. Proceeds from borrowings under the UGI Corporation Senior Credit Facility were used to finance the cash portion of the AmeriGas Merger; a portion of the CMG Acquisition; and for general corporate purposes. Because management currently intends to maintain a substantial portion of the amounts outstanding under the $300 million revolving credit facility beyond September 30, 2020, and has the ability to do so under the terms of the UGI Corporation Senior Credit Facility, such amounts have been classified as “Long-term debt” on the Consolidated Balance Sheets.
Credit Facilities
Information about the Company’s principal credit agreements (excluding Energy Services’ Receivables Facility, which is discussed below) as of September 30, 2019 and 2018, is presented in the tables below.

(Currency in millions) |  | Expiration Date |  | Total Capacity |  | Borrowings Outstanding |  | Letters of Credit and Guarantees Outstanding |  | Available Borrowing Capacity |  | Weighted Average Interest Rate - End of Year
September 30, 2019 |  |  |  |  |  |  |  |  |  |  |  |
AmeriGas OLP |  | December 2022 |  | $ | 600.0 |  |  | $ | 328.0 |  |  | $ | 62.7 |  |  | $ | 209.3 |  |  | 4.50 | %
UGI International, LLC (a) |  | October 2023 |  | € | 300.0 |  |  | € | 192.7 |  |  | € | — |  |  | € | 107.3 |  |  | 3.64 | %
Energy Services |  | March 2021 |  | $ | 200.0 |  |  | $ | 45.0 |  |  | $ | — |  |  | $ | 155.0 |  |  | 6.25 | %
UGI Utilities |  | June 2024 |  | $ | 350.0 |  |  | $ | 166.0 |  |  | $ | — |  |  | $ | 184.0 |  |  | 3.00 | %
UGI Corporation (b) |  | August 2024 |  | $ | 300.0 |  |  | $ | 300.0 |  |  | $ | — |  |  | $ | — |  |  | 4.55 | %
September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |
AmeriGas OLP |  | December 2022 |  | $ | 600.0 |  |  | $ | 232.0 |  |  | $ | 63.5 |  |  | $ | 304.5 |  |  | 4.58 | %
UGI International, LLC |  | April 2020 |  | € | 300.0 |  |  | € | — |  |  | € | — |  |  | € | 300.0 |  |  | N.A. |
UGI France |  | April 2020 |  | € | 60.0 |  |  | € | — |  |  | € | — |  |  | € | 60.0 |  |  | N.A. |
Flaga |  | October 2020 |  | € | 55.0 |  |  | € | — |  |  | € | 0.5 |  |  | € | 54.5 |  |  | N.A. |
Energy Services |  | March 2021 |  | $ | 240.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 240.0 |  |  | N.A. |
UGI Utilities |  | March 2020 |  | $ | 450.0 |  |  | $ | 189.5 |  |  | $ | 2.0 |  |  | $ | 258.5 |  |  | 3.03 | %

N.A. - Not applicable

(a) | The 2018 UGI International Credit Facilities Agreement permits UGI International, LLC to borrow in euros or dollars. At September 30, 2019, the amount borrowed was USD-denominated borrowings of $210.0 million, equal to €192.7 million.

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(b) | Borrowings outstanding have been classified as “Long-term debt” on the 2019 Consolidated Balance Sheet. See “Significant Financing Activities - UGI Corporation” above for further information.

The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2019 and Fiscal 2018 are as follows:

|  | 2019 |  | 2018
(Millions of dollars or euros) |  | Average |  | Peak |  | Average |  | Peak
AmeriGas OLP |  | $ | 280.0 |  |  | $ | 422.0 |  |  | $ | 191.2 |  |  | $ | 349.0 |
UGI International, LLC |  | € | 41.0 |  |  | € | 266.1 |  |  | € | — |  |  | € | — |
Energy Services |  | $ | 12.6 |  |  | $ | 220.0 |  |  | $ | 15.5 |  |  | $ | 79.0 |
UGI Utilities |  | $ | 153.6 |  |  | $ | 311.0 |  |  | $ | 150.4 |  |  | $ | 215.0 |
UGI Corporation |  | $ | 50.4 |  |  | $ | 300.0 |  |  | $ | — |  |  | $ | — |

Energy Services also has a Receivables Facility with an issuer of receivables-backed commercial paper. On October 25, 2019, the expiration date of the Receivables Facility was extended to October 23, 2020. The Receivables Facility provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November through April, and up to $75 million of eligible receivables during the period May through October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
At September 30, 2019, the outstanding balance of trade receivables was $54.5 million of which $46.4 million was sold to the bank. At September 30, 2018, the outstanding balance of trade receivables was $65.0 million of which $2.0 million was sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Consolidated Balance Sheet. During both Fiscal 2019 and Fiscal 2018, peak sales of receivables were $68.0 million. During Fiscal 2019 and Fiscal 2018, average daily amounts sold were $20.7 million and $11.3 million, respectively.
For further information on the Company’s long-term debt and credit facilities, see Note 6 to Consolidated Financial Statements.
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities:
Year-to-year variations in our cash flows from operating activities can be significantly affected by changes in operating working capital especially during periods with significant changes in energy commodity prices. Cash flows from operating activities in Fiscal 2019, Fiscal 2018 and Fiscal 2017 were $1,078.1 million, $1,085.3 million and $964.4 million, respectively. Cash flows from operating activities before changes in operating working capital were $1,025.7 million in Fiscal 2019, $1,215.8 million in Fiscal 2018 and $1,125.0 million in Fiscal 2017. The lower cash flow from operating activities before changes in operating working capital in Fiscal 2019 principally reflects the effects of the lower operating results. Changes in operating working capital provided (used) operating cash flow of $52.4 million in Fiscal 2019, $(130.5) million in Fiscal 2018 and $(160.6) million in Fiscal 2017. Cash flow from changes in operating working capital principally reflects the impact of energy commodity prices on changes in accounts receivable, inventories and accounts payable. The higher cash flow from changes in operating working capital in Fiscal 2019 reflects, in large part, the net impact of decreases in LPG and natural gas prices on accounts receivable, inventories and accounts payable. The beneficial impact from these operating working capital items in Fiscal 2019 was partially offset by higher cash collateral deposits paid to commodity derivative instrument counterparties due principally to decreases in LPG and natural gas prices, and net repayments to UGI Utilities’ customers of purchased gas and electricity costs totaling $29.5 million (compared to net overcollections of $31.1 million in Fiscal 2018). Fiscal 2018 cash used by operating working capital was also reduced by federal income tax overpayments due to the release in late Fiscal 2018 of TCJA regulations regarding bonus depreciation for utility assets.
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Investing Activities:
Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions of businesses and assets; investments in equity investees; and cash proceeds from sales and retirements of property, plant and equipment. Cash expenditures for property, plant and equipment totaled $704.6 million in Fiscal 2019, $574.4 million in Fiscal 2018 and $638.9 million in Fiscal 2017. Cash payments for property, plant and equipment were higher in Fiscal 2019 compared with Fiscal 2018 and Fiscal 2017 reflecting, in part, higher IT expenditures associated with Enterprise Resource Planning systems and higher UGI Utilities new business capital expenditures. The significant increase in cash used for acquisitions of businesses and assets in Fiscal 2019 principally comprises Midstream & Marketing’s $1.275 billion acquisition of CMG and its acquisition of South Jersey Energy Company’s natural gas marketing business, and UGI International’s acquisitions of several smaller LPG retail businesses in Belgium, the Netherlands and the United Kingdom.
Financing Activities:
Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; short-term borrowings; dividends on UGI Common Stock and, prior to the AmeriGas Merger, distributions on publicly held AmeriGas Partners Common Units; issuances or repurchases of equity instruments; and, in Fiscal 2019, the cash portion of the AmeriGas Merger.
On October 25, 2018, UGI International, LLC, pursuant to a new five-year unsecured Senior Facilities Agreement, borrowed €300 million under a variable-rate term loan facility and, in an underwritten private placement, issued €350 million principal amount of 3.25% senior unsecured notes due November 1, 2025. The net proceeds from these borrowings plus cash on hand were used principally to repay €540 million outstanding principal of UGI France’s variable-rate term loan; €45.8 million of outstanding principal of Flaga’s variable-rate term loan; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest. In addition, on February 1, 2019, UGI Utilities issued in a private placement $150 million of UGI Utilities 4.55% Senior Notes due February 1, 2049.
In August 2019, UGI Corporation borrowed a total of $850 million under the UGI Corporation Senior Credit Facility. Also, in August 2019, Energy Services borrowed $700 million under the Energy Services Term Loan. A portion of the proceeds from borrowings under the UGI Corporation Senior Credit Facility were used to finance the cash portion of the AmeriGas Merger. Proceeds from the Energy Services Term Loan as well as a portion of the borrowings under the UGI Corporation Senior Credit Agreement were used to finance the CMG Acquisition.
For further information on debt transactions, see Note 6 to Consolidated Financial Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions) for Fiscal 2019, Fiscal 2018 and Fiscal 2017. We also provide amounts we expect to spend in Fiscal 2020. We expect to finance a substantial portion of our Fiscal 2020 capital expenditures from cash generated by operations and cash on hand.

Year Ended September 30, |  | 2020 |  | 2019 |  | 2018 |  | 2017
(Millions of dollars) |  | (estimate) |  |  |  |  |  |
AmeriGas Propane |  | $ | 185.0 |  |  | $ | 107.3 |  |  | $ | 101.3 |  |  | $ | 98.1 |
UGI International |  | 115.0 |  |  | 106.4 |  |  | 111.4 |  |  | 90.3 |
Midstream & Marketing |  | 136.0 |  |  | 137.7 |  |  | 43.1 |  |  | 117.5 |
UGI Utilities |  | 404.0 |  |  | 355.3 |  |  | 338.5 |  |  | 317.7 |
Total |  | $ | 840.0 |  |  | $ | 706.7 |  |  | $ | 594.3 |  |  | $ | 623.6 |

In Fiscal 2019, higher levels of capital expenditures resulted from ERP projects at AmeriGas Propane and UGI Utilities as well as continued investments in midstream assets at Midstream & Marketing. Increased levels of capital expenditures estimated in Fiscal 2020 reflect business transformation expenditures associated with initiatives at AmeriGas Propane and UGI International of approximately $65 million and $15 million, respectively; natural gas infrastructure expansion projects at Midstream & Marketing; and replacement and betterment and IT projects at UGI Utilities.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2019. Such obligations include scheduled repayments of long-term debt, interest on long-term debt, operating lease payments, unconditional purchase obligations for pipeline capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity, and derivative
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instruments. The following table presents contractual cash obligations with non-affiliates under agreements existing as of September 30, 2019:

|  | Payments Due by Period
(Millions of dollars) |  | Total |  | Fiscal 2020 |  | Fiscal 2021 - 2022 |  | Fiscal 2023 - 2024 |  | Thereafter
Long-term debt (a) |  | $ | 5,856.6 |  |  | $ | 24.0 |  |  | $ | 355.2 |  |  | $ | 1,667.6 |  |  | $ | 3,809.8 |
Interest on long-term fixed-rate debt (a)(b)(c) |  | 2,250.8 |  |  | 273.2 |  |  | 533.1 |  |  | 475.3 |  |  | 969.2 |
Operating leases |  | 511.8 |  |  | 100.4 |  |  | 156.9 |  |  | 115.3 |  |  | 139.2 |
AmeriGas Propane supply contracts |  | 16.1 |  |  | 16.1 |  |  | — |  |  | — |  |  | — |
UGI International supply contracts |  | 449.5 |  |  | 449.5 |  |  | — |  |  | — |  |  | — |
Midstream & Marketing supply contracts |  | 845.4 |  |  | 337.6 |  |  | 366.8 |  |  | 111.4 |  |  | 29.6 |
UGI Utilities supply, storage and transportation contracts |  | 313.6 |  |  | 99.0 |  |  | 105.7 |  |  | 56.3 |  |  | 52.6 |
Derivative instruments (d) |  | 121.0 |  |  | 83.2 |  |  | 36.7 |  |  | 1.1 |  |  | — |
Total |  | $ | 10,364.8 |  |  | $ | 1,383.0 |  |  | $ | 1,554.4 |  |  | $ | 2,427.0 |  |  | $ | 5,000.4 |

(a) | Based upon stated maturity dates for debt outstanding at September 30, 2019.

(b) | Based upon stated interest rates adjusted for the effects of interest rate swaps.

(c) | Calculated using applicable interest rates or forward interest rate curves, and UGI’s and its subsidiaries’ leverage ratios, as of September 30, 2019.

(d) | Represents the sum of amounts due if derivative instrument liabilities were settled at the September 30, 2019 amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate and cross-currency swaps).

“Other noncurrent liabilities” included in our Consolidated Balance Sheet at September 30, 2019, principally comprise regulatory liabilities (see Note 9 to Consolidated Financial Statements); refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 16 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 8 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 14 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. Required minimum contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plan”) in Fiscal 2020 are not expected to be material. Required minimum contributions to the U.S. Pension Plan in years beyond Fiscal 2020 will depend, in large part, on the impacts of future returns on pension plan assets and interest rates on pension plan liabilities. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2019, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $60 million.
U.S. Pension Plan
The U.S. Pension Plan is a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities and certain of UGI’s other domestic wholly owned subsidiaries. The fair values of the U.S. Pension Plan’s assets totaled $529.1 million and $531.7 million at September 30, 2019 and 2018, respectively. At September 30, 2019 and 2018, the underfunded positions of the U.S. Pension Plan, defined as the excess of the PBO over the U.S. Pension Plan’s assets, were $176.1 million and $79.5 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including the ERISA rules and regulations. Required minimum contributions to the U.S. Pension Plan in Fiscal 2020 are not expected to be material. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2019 was $6.1 million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2020 is expected to be approximately $9.3 million.
GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. At September 30, 2019, we have recorded after-tax charges to UGI Corporation’s stockholders’ equity of $25.7 million and recorded regulatory assets totaling
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$178.6 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the U.S. Pension Plan and our other postretirement benefit plans, see Note 8 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2019, Fiscal 2018 and Fiscal 2017, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.
Off-Balance-Sheet Arrangements
UGI primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the recognition and measurement guidance relating to guarantees under GAAP.
We do not have any off-balance-sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Utility Regulatory Matters
Base Rate Filings. On January 28, 2019, the merged Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial and industrial customers throughout its Pennsylvania service territory by an aggregate $71.1 million. As part of this rate request, Gas Utility also proposed to create uniform class rates under a single tariff such that all members of each customer class, throughout a consolidated UGI Gas service territory, would be charged the same base distribution and purchased gas cost rates, and other surcharges, eliminating the need to maintain the former UGI North, UGI South, and UGI Central rate districts formed as part of the earlier merger. In its initial filing, Gas Utility proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return to ratepayers $24.0 million of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 Order. On October 4, 2019, the PAPUC issued a final Order approving a settlement that permits Gas Utility, effective October 11, 2019, to increase its base distribution revenues by $30.0 million under a single tariff, approved a plan for uniform class rates, and permits the Company to extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years. The PAPUC’s final Order approved the negative surcharge, mentioned above, which became effective for a twelve-month period beginning on October 11, 2019, the effective date of Gas Utility’s new base rates.
On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2 million, which was later reduced by Electric Utility to $7.7 million to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final Order providing for a $3.2 million annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final PAPUC Order, Electric Utility provided customers with a one-time $0.2 million billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. UGI Utilities cannot predict the ultimate outcome of this appeal.
On August 31, 2017, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 million base distribution rate increase for PNG (now part of the consolidated UGI Gas service territory). The increase became effective October 20, 2017.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one UGI Utilities employee and injuries to two UGI Utilities employees and one sewer authority employee, and destroyed two residences and damaged several other homes, BIE filed a formal complaint at the PAPUC in which BIE alleged that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order UGI Utilities to pay approximately $2.1 million in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC but is not expected to have a material impact on the Company’s consolidated financial statements.
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Market Risk Disclosures
Our primary market risk exposures 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 price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Commodity Price Risk
The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap contracts. Our UGI International operations use over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to economically hedge forecasted purchases of LPG are generally settled at expiration of the contract.
Gas Utility's tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the NYMEX, to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism.
Electric Utility's DS tariffs contain clauses that permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of forward electricity purchase contracts, associated with our Electric Utility operations. At September 30, 2019, all of Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Consolidated Statements of Income.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sale contracts for physical natural gas and electricity, Midstream & Marketing enters into NYMEX, ICE and over-the-counter natural gas and electricity futures and option contracts, and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. UGI International’s natural gas and electricity marketing businesses also use natural gas and electricity futures and forward contracts to economically hedge market risk associated with fixed-price sales and purchase contracts.
Midstream & Marketing also uses NYMEX and over-the-counter futures and options contracts to economically hedge price volatility associated with the gross margin derived from the purchase and anticipated later near-term sale of natural gas storage inventories.
Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.
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Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt at September 30, 2019, includes revolving credit facility borrowings and variable-rate term loans at UGI International, LLC, UGI Utilities, Energy Services and UGI Corporation. These debt agreements have interest rates that are generally indexed to short-term market interest rates. We have entered into pay-fixed, receive-variable interest rate swap agreements on all or a significant portion of the term loans’ principal balances and all or a significant portion of the term loans’ tenor. We have designated these interest rate swaps as cash flow hedges. At September 30, 2019, combined borrowings outstanding under variable-rate debt agreements, excluding the previously mentioned effectively fixed-rate debt, totaled $1,095.4 million. Based upon average borrowings outstanding under variable-rate borrowings (excluding effectively fixed-rate term loan debt), an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2019 interest expense by approximately $6.0 million. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $280 million at September 30, 2019. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $290 million at September 30, 2019.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed rate debt, from time to time we enter into IRPAs.
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro and, to a lesser extent, the U.S. dollar versus the British pound sterling. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries. Gains or losses on these net investment hedges remain in AOCI until such foreign operations are sold or liquidated. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at September 30, 2019, by approximately $105 million, which amount would be reflected in other comprehensive income. In October 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes, we designated borrowings under these agreements as net investment hedges.
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 enter into forward foreign currency exchange contracts. We layer in these foreign currency exchange contracts over a multi-year period to eventually equal approximately 90% of anticipated UGI International local currency earnings before income taxes.
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 derivative instrument 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. At September 30, 2019, we had posted collateral with derivative instrument counterparties totaling $29.3 million. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2019, restricted cash in brokerage accounts totaled $63.7 million. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2019. 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.
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At September 30, 2019, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
The following table summarizes the fair values of unsettled market risk sensitive derivative instrument assets (liabilities) held at September 30, 2019. The table also includes the changes in fair values of derivative instruments that would result if there were (1) a 10% adverse change in the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) a 50 basis point adverse change in prevailing market interest rates; and (3) a 10% change in the value of the euro and the British pound sterling versus the U.S. dollar. Gas Utility’s and Electric Utility’s commodity derivative instruments other than gasoline futures contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.

|  | Asset (Liability)
(Millions of dollars) |  | Fair Value |  | Change in Fair Value
September 30, 2019 |  |  |  |
Commodity price risk |  | $ | (130.6 | ) |  | $ | (100.5 | )
Interest rate risk |  | $ | (12.3 | ) |  | $ | (8.9 | )
Foreign currency exchange rate risk |  | $ | 54.7 |  |  | $ | (47.9 | )

Critical Accounting Policies and Estimates
The accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events. Changes in these policies and estimates could have a material effect on our financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. Also, see Note 2 to Consolidated Financial Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
Goodwill Impairment Evaluation. Our goodwill is the result of business acquisitions. Under GAAP, we do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired.
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. As of September 30, 2019, our goodwill totaled $3,456.4 million. We did not record any impairments of goodwill in Fiscal 2019, Fiscal 2018 or Fiscal 2017.
Impairment of Long-Lived Assets. Impairment testing for individual long-lived assets, or groups of long-lived assets, is required when circumstances indicate that such assets may be impaired. If it is determined that a triggering event has occurred, we prepare a quantitative evaluation based upon undiscounted cash flow projections expected to be realized over the remaining useful life of the asset or the primary asset of an asset group. A long-lived asset or group of assets is considered impaired when the carrying amount of such assets exceeds the associated undiscounted estimated future cash flows. When determining whether an asset or
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group of assets has been impaired, management groups assets at the lowest level that has identifiable cash flows. Performing an impairment test on long-lived assets involves judgment in areas such as identifying when a triggering event requiring evaluation occurs; identifying and grouping assets; and, if the asset or group of assets is determined to be impaired based upon an excess of carrying amount over estimated undiscounted future cash flows, determining the fair value of the asset or asset group. Although cash flow estimates are based upon relevant information at the time the estimates are made, estimates of future cash flows are by nature highly uncertain and contemplate factors that change over time such as the expected use of the asset including future production and sales volumes, expected fluctuations in prices of commodities and expected proceeds from disposition. No material provisions for impairments of long-lived assets were recorded during Fiscal 2019, Fiscal 2018 or Fiscal 2017.
Loss Contingencies and Environmental Remediation Liabilities. We are involved in litigation that arises in the normal course of business, and we are subject to risk of loss for general, automobile and product liability and workers’ compensation claims for which we obtain insurance coverage subject to self-insured retentions or deductibles. We are also 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.
In accordance with GAAP, we establish reserves for loss contingencies including pending litigation, and for pending and incurred but not reported claims associated with general and product liability, automobile and workers’ compensation when it is probable that a liability exists and the amount or range of amounts related to such liability can be reasonably estimated. When no amount within a range of possible loss is a better estimate than any other amount within the range, liabilities recorded are based upon the low end of the range. With respect to unasserted claims arising from unreported incidents, we may use the work of specialists to estimate the ultimate losses to be incurred using actuarially determined loss development factors applied to actual claims data.
The likelihood of a loss with respect to a particular loss contingency is often difficult to predict. In addition, a reasonable estimate of the loss, or a range of possible loss, may not be practicable based upon the information available and the potential effects of future events and decisions by third parties that will determine the ultimate resolution of the loss contingency. Reasonable estimates involve management judgments based on a broad range of information and prior experience. For litigation and pending claims including those covered by insurance policies, the analysis of probable loss is performed on a case by case basis and includes an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success in prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. These judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Our estimated reserves for loss contingencies and for pending and incurred but not reported claims associated with general and product liability, automobile and workers’ compensation may differ materially from the ultimate liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.
In accordance with GAAP, we accrue reserves for environmental remediation when assessments indicate that it is probable a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the Consolidated 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. These estimates are based upon a number of factors including whether the company will be responsible for such remediation, the scope and cost of the remediation work to be performed, the portion of costs that will be shared with other potentially responsible parties, the timing of the remediation and possible impact of changes in technology, and the regulations and requirements of local governmental authorities. Our estimated reserves for environmental remediation may differ materially from the ultimate liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted. UGI Utilities receives ratemaking recognition of environmental investigation and remediation costs associated with their in-state 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.
Regulatory Assets and Liabilities. The accounting for our rate regulated gas and electric utility operations differs from the accounting for nonregulated operations in that these operations are required to reflect the effects of rate regulation in the consolidated financial statements. Regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated businesses. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Similarly, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PAPUC, discussions with regulatory authorities and legal counsel. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash
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flows. As of September 30, 2019, our regulatory assets and regulatory liabilities totaled $395.6 million and $358.8 million, respectively. For additional information on regulatory assets and liabilities, see Notes 2 and 9 to Consolidated Financial Statements.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. The interpretation of tax laws, including the provisions of the TCJA, involves uncertainty, since tax authorities may interpret the laws differently. In addition, the states in which we operate may or may not conform to some or all of the provisions in the TCJA. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation thereof and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2019, our net deferred tax liabilities totaled $423.5 million.
Business Combination Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value as of the acquisition date with the residual of the purchase price allocated to goodwill. From time to time we engage third-party valuation experts to assist us in determining the fair values of certain assets acquired and liabilities assumed. Such valuations require management to make significant judgments, estimates and assumptions especially with respect to intangible assets. Management makes estimates of fair value based upon assumptions it believes to be reasonable. These estimates are based upon historical experience and information obtained from the management of the acquired companies and are inherently uncertain. Critical estimates in valuing certain of the intangible assets include, but are not limited to, discount rates and expected future cash flows from and the economic lives of customer relationships, trade names, existing technology, and other intangible assets. Unanticipated events and circumstances may occur, which may affect the accuracy or validity of such assumptions or estimates. The allocation of the purchase price may be modified up to one year after the acquisition date, under certain circumstances, as more information is obtained about the fair value of assets acquired and liabilities assumed.
Recently Issued Accounting Pronouncements
See Note 3 to the Consolidated Financial Statements for a discussion of the effects of recently issued accounting guidance.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated by reference.

ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.

ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. | CONTROLS AND PROCEDURES

(a) | The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures, as of September 30, 2019, were effective at the reasonable assurance level.

(b) | For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference).

(c) | Effective July 1, 2019, our wholly-owned subsidiary, UGI Utilities, implemented a new Enterprise Resource Planning system to replace its legacy system. The implementation resulted in greater automation of internal controls in the UGI Utilities supply chain, fixed asset and financial reporting cycles and, as such, we consider this system implementation to be material to UGI. As a result of the implementation, controls that were previously determined to be effective were replaced with new or modified controls that were also determined to be effective. Other than this system implementation, there were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. | OTHER INFORMATION

None.
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PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the SEC by December 31, 2019.

| Information |  | Captions of Proxy Statement Incorporated by Reference
Item 10. | Directors, Executive Officers and Corporate Governance |  | Election of Directors - Nominees; Corporate Governance Principles; Director Independence; Board Leadership Structure and Role in Risk Management; Board Meetings and Attendance; Board and Committee Structure; Communications with the Board; Securities Ownership of Certain Beneficial Owners - Security Ownership of Directors and Executive Officers; Report of the Audit Committee of the Board of Directors
| The Code of Business Conduct and Ethics is available without charge on the Company’s website, www.ugicorp.com, or by writing to Director, Investor Relations, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. |  |
Item 11. | Executive Compensation |  | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  | Securities Ownership of Certain Beneficial Owners; Security Ownership of Directors and Executive Officers.
Item 13. | Certain Relationships and Related Transactions, and Director Independence |  | Election of Directors - Director Independence and Board and Committee Structure; Policy for Approval of Related Person Transactions
Item 14. | Principal Accounting Fees and Services |  | Our Independent Registered Public Accounting Firm

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Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2019 with respect to compensation plans under which our equity securities are authorized for issuance.

Plan category |  | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |  | Weighted average exercise price of outstanding options, warrants and rights (b) |  | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
Equity compensation plans approved by security holders |  | 8,478,105 |  | (1) | $ | 37.18 |  |  | 8,700,734 |  | (2)
|  | 893,820 |  | (3) | $ | 0 |  |  |  |
Equity compensation plans not approved by security holders |  | 0 |  |  |  |  |  |
Total |  | 9,371,925 |  |  | $ | 37.18 |  | (4) |  |

(1) | Represents 8,478,105 stock options under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.

(2) | Represents 8,700,734 securities remaining for issuance from the UGI Corporation 2013 Omnibus Incentive Compensation Plan, which includes 1,420,949 AmeriGas Common Units that were available for grant under the AmeriGas Propane, Inc. Long-Term Incentive Plan and converted to UGI Corporation units in connection with the AmeriGas Merger. The UGI Corporation 2013 Omnibus Incentive Compensation Plan was approved by the shareholders on January 24, 2013.

(3) | Represents 893,820 restricted stock units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.

(4) | Weighted-average exercise price of outstanding options; excludes restricted stock units.

The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS

Name |  | Age |  | Position
John L. Walsh |  | 64 |  | President and Chief Executive Officer
Ted J. Jastrzebski |  | 58 |  | Chief Financial Officer
Robert F. Beard |  | 54 |  | Executive Vice President, Natural Gas and President and Chief Executive Officer, UGI Utilities, Inc.
Roger Perreault |  | 55 |  | Executive Vice President, Global LPG and President, UGI International, LLC
Hugh J. Gallagher |  | 56 |  | President and Chief Executive Officer, AmeriGas Propane, Inc.
Joseph L. Hartz |  | 56 |  | President, UGI Energy Services, LLC
Monica M. Gaudiosi |  | 57 |  | Vice President, General Counsel and Secretary
Laurie A. Bergman |  | 42 |  | Vice President - Chief Accounting Officer and Corporate Controller

All officers are elected for a one-year term at the organizational meeting of the Board of Directors held each year.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
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John L. Walsh
Mr. Walsh is a Director and President (since 2005) and Chief Executive Officer (since 2013) of UGI Corporation. In addition, Mr. Walsh serves as a Director and Vice Chairman of UGI Utilities, Inc. (since 2005), a subsidiary of UGI Corporation. He previously served as UGI Corporation’s Chief Operating Officer (2005 to 2013) and as the President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Previously, Mr. Walsh was the Chief Executive of the Industrial and Special Products division of the BOC Group plc, an industrial gases company, a position he assumed in 2001. He was an Executive Director of BOC (2001 to 2005) having joined BOC in 1986 as Vice President - Special Gases and having held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as Director at Main Line Health, Inc., the United Way of Greater Philadelphia and Southern New Jersey, the World Affairs Council of Philadelphia, the Greater Philadelphia Chamber of Commerce, the Mastery Charter School, the Satell Institute, and the Philadelphia Zoo, and as Trustee at the Saint Columbkille Partnership School. Mr. Walsh also served as a director (since 2005) and Chairman of the Board (since 2016) of AmeriGas Propane, Inc. until its merger into UGI Corporation in August 2019.
Ted J. Jastrzebski
Mr. Jastrzebski is Chief Financial Officer of UGI Corporation (since 2018). Mr. Jastrzebski previously served as Principal Financial Officer of AmeriGas Propane, Inc. (2018 to 2019). From 2013 until 2018, Mr. Jastrzebski served as Executive Vice President and Chief Financial Officer of Qurate Retail Group, which is comprised of QVC, HSN, Cornerstone Brands, and Zulily. Previously, Mr. Jastrzebski held various positions at The Hershey Company, including Senior Vice President and President, Hershey Americas (2011 to 2013), Senior Vice President and President, Hershey International (2007 to 2010) and Vice President, Finance, Hershey International (2004 to 2007). Mr. Jastrzebski also served as Senior Vice President, Finance, IT and Administration and Chief Financial Officer of CARE (2002 to 2004) and as Vice President and Chief Financial Officer of Project Hope (1999 to 2002).
Robert F. Beard
Mr. Beard is Executive Vice President, Natural Gas (since 2018) and President and Chief Executive Officer and a Director of UGI Utilities, Inc. (since 2011). He previously served as Vice President - Marketing, Rates and Gas Supply (2010 to 2011) and Vice President - Southern Region (2008 to 2010) of UGI Utilities, Inc. From 2006 until 2008, Mr. Beard served as Vice President - Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he served as Director - Operations and Engineering of PPL Gas Utilities Corporation.
Roger Perreault
Mr. Perreault is Executive Vice President, Global LPG of UGI Corporation (since 2018) and President - UGI International, LLC (since 2015). Prior to joining UGI Corporation, Mr. Perreault held various positions at Air Liquide, an industrial gases company he joined in 1994, and served in various leadership positions from 2008 to 2014, including in a global role as President, Large Industries with international responsibilities and, prior to that, in a role with responsibility for Air Liquide’s North American large industries business. Prior to joining Air Liquide, Mr. Perreault was a chemical engineer and operations manager with I.C.I. in Quebec, Canada. Mr. Perreault previously served as a director of AmeriGas Propane, Inc. (since 2018) until its merger into UGI Corporation in August 2019.
Hugh J. Gallagher
Mr. Gallagher is President and Chief Executive Officer of AmeriGas Propane, Inc. (since 2018). Previously he served as its Vice President - Finance and Chief Financial Officer (2013 to 2018). He has also served as Treasurer of both UGI Corporation and AmeriGas Propane, Inc. (2011 to 2014), Director - Treasury Services and Investor Relations of UGI Corporation (2009 to 2011) and Director - Treasury Services (2007 to 2009) of UGI Corporation. He has also served as Director - Business Development (2004 to 2007), Director of Financial Planning and Analysis (2000 to 2004), Financial Manager - Operations (1999 to 2000), Manager of Financial Reporting (1996 to 1999), and Team Leader - Financial Reporting (1995 to 1996) at AmeriGas Propane, Inc. Mr. Gallagher joined UGI Corporation in 1990, serving in various finance and accounting roles of increasing responsibility. Mr. Gallagher previously served as a director of AmeriGas Propane, Inc. (since 2018) until its merger into UGI Corporation in August 2019.
Joseph L. Hartz
Mr. Hartz is President of UGI Energy Services, LLC (since 2017). He previously served as Chief Operating Officer (2014 to 2017) and as Vice President - Supply and Operations (2010 to 2014) of UGI Energy Services, LLC. He joined UGI Utilities, Inc.
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in 1985 as an accountant and has held various positions of increasing responsibility at UGI Utilities and UGI Energy Services, including Vice President - Assets and Supply and Chief Financial Officer.
Monica M. Gaudiosi
Ms. Gaudiosi is the Vice President, General Counsel and Secretary of UGI Corporation and UGI Utilities, Inc. (since 2012). She is also Vice President (since 2012), General Counsel (since 2015) and Secretary (since 2012) of AmeriGas Propane, Inc. Prior to joining UGI Corporation, Ms. Gaudiosi served as Senior Vice President and General Counsel (2007 to 2012) and Senior Vice President and Associate General Counsel (2005 to 2007) of Southern Union Company. Prior to joining Southern Union Company in 2005, Ms. Gaudiosi held various positions with General Electric Capital Corporation (1997 to 2005). Before joining General Electric Capital Corporation, Ms. Gaudiosi was an associate at the law firms of Hunton & Williams (1994 to 1997) and Sutherland, Asbill & Brennan (1988 to 1994).
Laurie A. Bergman
Ms. Bergman is Vice President, Chief Accounting Officer and Corporate Controller of UGI Corporation (since February 2019). She previously served as the Chief Accounting Officer and Corporate Controller of AmeriGas Propane, Inc. (2016 to 2019) and as its Group Director – Financial Planning and Operations (2014 to 2016). Ms. Bergman joined AmeriGas Propane, Inc. in 2006 as Manager – Disbursements and served in various roles for AmeriGas Propane, Inc., including Assistant Controller (2011 to 2012), Director of Financial Analysis and Planning (2012 to 2013), and Group Director of Financial Planning and Revenue Management (2013 to 2014). Prior to that, she held positions of increasing responsibility at AmeriGas Propane, Inc. Previously, Ms. Bergman served as a Financial Analysis Specialist and a Disbursement Operations Manager at CIGNA Corporation, a leading employee benefits provider, positions in which she served from 2001 to 2005.
PART IV:

ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) | Documents filed as part of this report:

(1) | Financial Statements:

Included under Item 8 are the following financial statements and supplementary data:
Management’s Annual Report on Consolidated Financial Statements and Schedules
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting)
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedules)
Consolidated Balance Sheets as of September 30, 2019 and 2018
Consolidated Statements of Income for the years ended September 30, 2019, 2018 and 2017
Consolidated Statements of Comprehensive Income for the years ended September 30, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the years ended September 30, 2019, 2018 and 2017
Consolidated Statements of Changes in Equity for the years ended September 30, 2019, 2018 and 2017
Notes to Consolidated Financial Statements

(2) | Financial Statement Schedules:

I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts for the years ended September 30, 2019, 2018 and 2017
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We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.

(3) | List of Exhibits:

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
3.1 | (Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005. | UGI | Form 10-Q (6/30/05) | 3.1
3.2 | Articles of Amendment to the Amended and Restated Articles of Incorporation of UGI Corporation. | UGI | Form 8-K (7/29/14) | 3.1
3.3 | Bylaws of UGI Corporation, amended and restated as of July 25, 2017. | UGI | Form 8-K (7/31/17) | 3.1
4.1 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K). |  |  |
4.2 | The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended. | UGI | Form 8-B/A (4/17/96) | 3.(4)
4.3 | UGI Corporation’s (Second) Amended and Restated Articles of Incorporation, as amended, and Bylaws referred to in 3.1, 3.2, and 3.3 above. |  |  |
4.4 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994. | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4(c)
4.5 | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association. | Utilities | Form 8-K (9/12/06) | 4.2

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
4.6 | Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto. | Utilities | Form 8-K (10/30/13) | 4.1
4.7 | Note Purchase Agreement dated April 22, 2016 between the Company and the purchasers listed as signatories thereto. | Utilities | Form 8-K (4/28/16) | 4.1
4.8 | Indenture, dated as of June 27, 2016, among AmeriGas Partners, L.P., AmeriGas Finance Corp., and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (6/27/16) | 4.1
4.9 | First Supplemental Indenture, dated as of June 27, 2016, among AmeriGas Partners, L.P., AmeriGas Finance Corp., and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (6/27/16) | 4.2
4.10 | Second Supplemental Indenture, dated as of December 28, 2016, among AmeriGas Partners, L.P., AmeriGas Finance Corp., and U.S. Bank National Association, as trustee (including form of global note). | AmeriGas Partners, L.P. | Form 8-K (12/28/16) | 4.1
4.11 | Third Supplemental Indenture, dated as of February 13, 2017, among AmeriGas Partners, L.P., AmeriGas Finance Corp., and U.S. Bank National Association, as trustee (including form of global note). | AmeriGas Partners, L.P. | Form 8-K (2/13/17) | 4.1
4.12 | Indenture, dated as of October 25, 2018, by and among International, the guarantors named therein, U.S. Bank National Association, as trustee, Elavon Financial Services DAC, as registrar and transfer agent, and Elavon Financial Services DAC, UK Branch, as paying agent (including the form of Note). | UGI | Form 8-K (10/25/18) | 4.1
4.13 | Form of Note Purchase Agreement dated December 21, 2018 between the Company and the purchasers listed as signatories thereto. | UGI | Form 10-Q (12/31/18) | 4.1
10.1** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014. | UGI | Form 10-K (9/30/16) | 10.25

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.2** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014 - Terms and Conditions as effective January 1, 2016. | UGI | Form 10-K (9/30/16) | 10.26
10.3** | UGI Corporation 2009 Deferral Plan, as Amended and Restated effective June 15, 2017. | UGI | Form 10-Q (6/30/17) | 10.6
10.4** | UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated as of June 15, 2017. | UGI | Form 10-Q (6/30/17) | 10.1
10.5** | UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of September 5, 2014. | UGI | Form 10-K (9/30/16) | 10.30
10.6** | UGI Corporation 2013 Omnibus Incentive Compensation Plan, Terms and Conditions for Non-Employee Directors, effective January 1, 2019. | UGI | Form 10-Q (3/31/19) | 10.6
10.7** | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective April 1, 2015. | UGI | Form 10-K (9/30/17) | 10.26
10.8** | UGI Corporation Senior Executive Employee Severance Plan, as amended as of June 15, 2017. | UGI | Form 10-Q (6/30/17) | 10.7
10.9** | UGI Utilities, Inc. Executive Annual Bonus Plan as amended November 15, 2018. | UGI | Form 10-Q (3/31/19) | 10.11
10.10** | UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended as of July 10, 2017. | Utilities | Form 10-Q (6/30/17) | 10.1
10.11** | UGI Corporation Executive Annual Bonus Plan as amended November 15, 2018. | UGI | Form 10-Q (3/31/19) | 10.7
10.12** | AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as Amended and Restated effective November 22, 2013. | AmeriGas Partners, L.P. | Form 10-Q (3/31/14) | 10.4
10.13** | AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as amended as of June 15, 2017. | UGI | Form 10-K (9/30/17) | 10.14
10.14** | AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended and Restated effective June 15, 2017. | AmeriGas Partners, L.P. | Form 10-Q (6/30/17) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.15** | AmeriGas Propane, Inc. Executive Annual Bonus Plan as amended November 15, 2018. | UGI | Form 10-Q (3/31/19) | 10.10
10.16** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010. | AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.2
10.17** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P., Terms and Conditions, effective January 1, 2019. | UGI | Form 10-Q (3/31/19) | 10.9
10.18** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI and Utilities Employees. | UGI | Form 10-Q (3/31/19) | 10.2
10.19** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees. | UGI | Form 10-Q (3/31/19) | 10.3
10.20** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Stock Unit Grant Letter for Non-Employee Directors. | UGI | Form 10-Q (3/31/19) | 10.4
10.21** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non-Employee Directors. | UGI | Form 10-Q (3/31/19) | 10.5
10.22** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for AmeriGas Employees. | AmeriGas Partners, L.P. | Form 10-Q (3/31/19) | 10.13
10.23** | Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P. Performance Unit Grant Letter. | UGI | Form 10-Q (3/31/19) | 10.14
10.24** | Change in Control Agreement for Monica M. Gaudiosi dated as of April 23, 2012. | UGI | Form 10-Q (6/30/12) | 10.1
10.25** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Walsh. | UGI | Form 10-Q (6/30/08) | 10.3
10.26** | Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between UGI Corporation and Ted J. Jastrzebski. | UGI | Form 10-Q (6/30/18) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.27** | Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between UGI Corporation and Mr. Roger Perreault. | UGI | Form 10-Q (3/31/19) | 10.12
10.28** | Form of Change in Control Agreement between UGI Corporation and Mr. Roger Perreault. | UGI | Form 10-Q (3/31/19) | 10.13
10.29** | Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between AmeriGas Propane, Inc. and Mr. Hugh J. Gallagher. | AmeriGas Partners, L.P. | Form 10-Q (12/31/18) | 10.1
10.30** | Form of Change in Control Agreement, Amended and Restated, between AmeriGas Propane, Inc. and Mr. Hugh J. Gallagher. | AmeriGas Partners, L.P. | Form 10-Q (12/31/18) | 10.2
*10.31* | Description of oral compensation arrangement for Messrs. Walsh, Jastrzebski, Perreault and Gallagher and Ms. Gaudiosi. |  |  |
*10.32** | Summary of Director Compensation dated October 1, 2019. |  |  |
10.33 | Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | UGI | Form 10-K (9/30/10) | 10.37
10.34 | First Amendment, dated as of November 18, 2015, to Trademark License Agreement, dated April 19, 1995, by and among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P., and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-K (9/30/15) | 10.40
10.35 | Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.36 | Form of Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 18 thereto dated October 27, 2017, by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, and PNC Bank, National Association, as issuer and administrator. | UGI | Form 10-K (9/30/17) | 10.38
10.37 | Amendment No. 19, dated as of October 26, 2018, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, and PNC Bank, National Association, as issuer and administrator. | UGI | Form 8-K (10/26/18) | 10.1
10.38 | Amendment No. 20, dated as of October 25, 2019, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, and PNC Bank, National Association, as issuer and administrator. | UGI | Form 8-K (10/25/19) | 10.1
10.39 | Form of Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 4 thereto dated October 1, 2013, by and between UGI Energy Services, LLC and Energy Services Funding Corporation. | UGI | Form 10-K (9/30/17) | 10.39
*10.40 | FSS Service Agreement No. 79028 effective as of December 1, 2019 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc. |  |  |
*10.41 | SST Service Agreement No. 79133 effective as of December 1, 2019 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc. |  |  |

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.42 | Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, LLC, effective November 1, 2015. | Utilities | Form 10-K (9/30/16) | 10.19
10.43 | Second Amended and Restated Credit Agreement, dated February 29, 2016, by and among UGI Energy Services, LLC, as borrower, and JP Morgan Chase Bank, N.A., as administrative agent, and PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association, as documentation agent. | UGI | Form 8-K (2/29/16) | 10.1
10.44 | First Amendment to the Second Amended and Restated Credit Agreement, dated as of August 13, 2019, by and among UGI Energy Services, LLC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent and collateral agent, and the lenders party thereto. | UGI | Form 8-K (8/13/19) | 10.2
10.45 | Credit Agreement, dated October 31, 2017, by and among UGI Utilities, Inc., PNC Bank National Association, as administrative agent, The Bank of New York Mellon, as syndication agent, and certain other lenders named therein. | Utilities | Form 8-K (10/31/17) | 10.1
10.46 | Credit Agreement, dated as of June 27, 2019, by and among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank, N.A., as syndication agent, and the lenders party thereto. | UGI | Form 10-Q (6/30/19) | 10.1
10.47 | Second Amended and Restated Credit Agreement dated as of December 15, 2017 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender, and Issuing Lender, Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Bookrunner, and the other financial institutions from time to time party thereto. | AmeriGas Partners, L.P. | Form 8-K (12/15/17) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.48 | Multicurrency Facilities Agreement, effective October 25, 2018, among International, as borrower, Natixis, as agent, mandated lead arranger, bookrunner and coordinator, Barclays Bank Plc, BNP Paribas, Credit Agricole Corporate and Investment Bank, HSBC France, ING Bank N.V., French Branch, Mediobanca International (Luxembourg) S.A., Raiffeisen Bank International AG and Societe Generale Corporate and Investment Banking, as mandated lead arrangers, and certain other lenders. | UGI | Form 8-K (10/25/18) | 4.2
10.49 | Purchase and Sale Agreement, dated as of July 2, 2019, by and among UGI Energy Services, LLC, Columbia Midstream & Minerals Group, LLC, UGI Corporation and TransCanada PipeLine USA Ltd. | UGI | Form 8-K (7/2/19) | 2.1
10.50 | Credit Agreement, dated as of August 1, 2019, by and among UGI Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. | UGI | Form 8-K (8/1/19) | 10.1
10.51 | Credit Agreement, dated as of August 13, 2019, by and among UGI Energy Services, LLC, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, and the lenders party thereto. | UGI | Form 8-K (8/13/19) | 10.1
*14 | Code of Business Conduct and Ethics. |  |  |
*21 | Subsidiaries of the Registrant. |  |  |
*23 | Consent of Ernst & Young LLP |  |  |
*31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |  |
*31.2 | Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |  |

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
*32 | Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  |  |
*101.INS | XBRL Instance - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |  |  |
*101.SCH | XBRL Taxonomy Extension Schema |  |  |
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase |  |  |
*101.DEF | XBRL Taxonomy Extension Definition Linkbase |  |  |
*101.LAB | XBRL Taxonomy Extension Labels Linkbase |  |  |
*101.PRE | XBRL Taxonomy Extension Presentation Linkbase |  |  |

* | Filed herewith.

** | As required by Item 15(a)(3), this exhibit is identified as a compensatory plan or arrangement.

ITEM 16. FORM 10-K SUMMARY
None.
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EXHIBIT INDEX

Exhibit No. | Description
10.31 | Description of oral compensation arrangement for Messrs. Walsh, Jastrzebski, Perreault and Gallagher and Ms. Gaudiosi.
10.32 | Summary of Director Compensation as of October 1, 2019.
10.40 | FSS Service Agreement No. 79028 effective as of December 1, 2019 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.41 | SST Service Agreement No. 79133 effective as of December 1, 2019 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
14 | Code of Business Conduct and Ethics.
21 | Subsidiaries of the Registrant.
23 | Consent of Ernst & Young LLP.
31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 | Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 | Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2019, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS | XBRL Instance - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH | XBRL Taxonomy Extension Schema
101.CAL | XBRL Taxonomy Extension Calculation Linkbase
101.DEF | XBRL Taxonomy Extension Definition Linkbase
101.LAB | XBRL Taxonomy Extension Labels Linkbase
101.PRE | XBRL Taxonomy Extension Presentation Linkbase

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

|  | UGI CORPORATION
Date: | November 26, 2019 | By: | /s/ Ted J. Jastrzebski
|  |  | Ted J. Jastrzebski Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 26, 2019, by the following persons on behalf of the Registrant in the capacities indicated.

Signature |  | Title
/s/ John L. Walsh |  | President and Chief Executive Officer (Principal Executive Officer) and Director
John L. Walsh |
/s/ Ted J. Jastrzebski |  | Chief Financial Officer (Principal Financial Officer)
Ted J. Jastrzebski |
/s/ Laurie A. Bergman |  | Vice President, Chief Accounting Officer and Corporate Controller (Principal Accounting Officer)
Laurie A. Bergman |
/s/ Marvin O. Schlanger |  | Chairman and Director
Marvin O. Schlanger |
/s/ M. Shawn Bort |  | Director
M. Shawn Bort |
/s/ Theodore A. Dosch |  | Director
Theodore A. Dosch |
/s/ Richard W. Gochnauer |  | Director
Richard W. Gochnauer |
/s/ Alan N. Harris |  | Director
Alan N. Harris |
/s/ Frank S. Hermance |  | Director
Frank S. Hermance |
/s/ William J. Marrazzo |  | Director
William J. Marrazzo |
/s/ Anne Pol |  | Director
Anne Pol |
|  | Director
/s/ Kelly A. Romano |
Kelly A. Romano |
/s/ James B. Stallings, Jr. |  | Director
James B. Stallings, Jr. |
/s/ K. Richard Turner |  | Director
K. Richard Turner |

87

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2019
F-1

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

| Pages
Management’s Annual Report on Consolidated Financial Statements and Schedules | F-3
Management’s Annual Report on Internal Control Over Financial Reporting | F-4
Financial Statements: |
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting) | F-5
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedules) | F-6
Consolidated Balance Sheets as of September 30, 2019 and 2018 | F-8
Consolidated Statements of Income for the years ended September 30, 2019, 2018 and 2017 | F-9
Consolidated Statements of Comprehensive Income for the years ended September 30, 2019, 2018 and 2017 | F-10
Consolidated Statements of Cash Flows for the years ended September 30, 2019, 2018 and 2017 | F-11
Consolidated Statements of Changes in Equity for the years ended September 30, 2019, 2018 and 2017 | F-12
Notes to Consolidated Financial Statements | F-13
Financial Statement Schedules: |
For the years ended September 30, 2019, 2018 and 2017: |
I — Condensed Financial Information of Registrant (Parent Company) | S-1
II — Valuation and Qualifying Accounts | S-4

We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2

Table of Contents
Management’s Annual Report on Consolidated Financial Statements and Schedules
The Company’s consolidated financial statements and other financial information contained in this Annual Report were prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with GAAP and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors (the “Committee”) is composed of four members, each of whom is independent and a non-employee director of the Company. The Committee is responsible for monitoring and overseeing the financial reporting process, the adequacy of internal accounting controls, the independence and performance of the Company’s independent registered public accounting firm and internal auditors. The Committee meets regularly, with and without management present, with the independent registered public accounting firm and the internal auditors, both of which report directly to the Committee. In addition, the Committee provides regular reports to the Board of Directors.
/s/ John L. Walsh
Chief Executive Officer
/s/ Ted J. Jastrzebski
Chief Financial Officer
/s/ Laurie A. Bergman
Chief Accounting Officer
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Table of Contents
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The scope of that assessment excluded the CMG business acquired on August 1, 2019, by Energy Services. CMG’s total assets represented approximately 10% of the Company’s consolidated total assets as of September 30, 2019 and less than 1% of its consolidated revenues for the year then ended. Such exclusion is permitted based upon current guidance of the SEC.
Internal control over financial reporting refers to the process, designed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, and effected by the Company’s Board of Directors, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2019, based on the COSO criteria. Ernst & Young LLP, our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2019, as stated in their report, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Ted J. Jastrzebski
Chief Financial Officer
/s/ Laurie A. Bergman
Chief Accounting Officer
F-4

Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of UGI Corporation
Opinion on Internal Control over Financial Reporting
We have audited UGI Corporation and subsidiaries’ internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework (the COSO criteria). In our opinion, UGI Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2019, based on the COSO criteria.
As indicated in the accompanying “Management’s Annual Report on Internal Control Over Financial Reporting”, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Columbia Midstream Group, LLC (“CMG”) which is included in the 2019 consolidated financial statements of the Company and constituted approximately 10% of total assets as of September 30, 2019 and less than 1% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of CMG.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of September 30, 2019 and 2018, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended September 30, 2019, and the related notes and the financial statement schedules listed in the Index at Item 15(a) and our report dated November 26, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 26, 2019
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Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of UGI Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries (the Company) as of September 30, 2019 and 2018, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended September 30, 2019, and the related notes and the financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework and our report dated November 26, 2019, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

|  | Measurement of legal claims and environmental contingencies
Description of the Matter |  | As discussed in Note 16 to the consolidated financial statements, the Company is subject to legal claims and is potentially a responsible party in possible environmental liabilities (collectively, “loss contingencies”). The Company measures the amount of estimated loss once they determine that a loss contingency is probable and an amount can be reasonably estimated. Auditing the Company’s loss contingencies was complex and especially challenging due to the significant subjective judgment involved in determining the reserve amount when a range of possible losses exists. In particular, significant judgment is required to determine the expected losses based on the nature of the information available in the circumstances.
How We Addressed the Matter in Our Audit |  | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s measurement of probable loss contingencies. For example, we tested controls over management’s review of the measurement of the expected losses. To test the amount of the expected losses recorded by management, our audit procedures included, among others, assessing the methodologies used to measure the expected losses and, when applicable, testing the completeness and accuracy of the data underlying the calculations. We inspected correspondence from the Company’s internal counsel as to the status of existing loss contingencies and correspondence from external counsel to corroborate the information provided by management. We also performed a search for new or contrary evidence that would affect the estimate, including through review of minutes of meetings of the board of directors. When available, we considered other known precedents pertaining to the Company’s own legal matters as well as others within the Company’s industry, to evaluate the estimated loss contingencies recorded.

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|  | Valuation of general, automobile and product liability, and workers’ compensation reserves
Description of the Matter |  | As discussed in Note 2 to the consolidated financial statements, the Company is subject to risk of loss for general, automobile and product liability, and workers’ compensation claims for which it obtains coverage under insurance policies that are subject to self-insured retentions or deductibles. The Company establishes reserves for pending and incurred but not reported claims associated with general, automobile and product liability matters and workers’ compensation when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Auditing the Company’s general, automobile and product liability, and workers’ compensation reserves was complex and required us to involve our actuarial specialists due to the significant measurement uncertainty associated with the estimate and the use of actuarial methods. In addition, the reserve estimate is sensitive to significant management assumptions, including the loss development factors for reported claims.
How We Addressed the Matter in Our Audit |  | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s valuation of general, automobile and product liability, and workers’ compensation reserves. For example, we tested controls over management’s review of the appropriateness of the assumptions used in the calculations and the completeness and accuracy of the data underlying the reserves. To test the valuation of general, automobile and product liability, and workers’ compensation reserves, our audit procedures included, among others, assessing the methodologies used to estimate the reserves and testing the completeness and accuracy of the underlying data. We involved our actuarial specialists to assist in evaluating the significant assumptions and actuarial methodologies used by the Company to estimate the total expected losses for claims. We also performed a search for unrecorded claims reserves and accrued expenses related to claims incurred prior to the balance sheet date through examination of subsequent payments and other supporting documentation to determine if unrecorded claims affect the loss reserve estimation process or reserve balance.
|  | Accounting for the Acquisition of Columbia Gas
Description of the Matter |  | As discussed in Note 5 to the consolidated financial statements, the Company completed the acquisition of all of the equity interests in Columbia Midstream Group, LLC and its 47% interest in Columbia Pennant, LLC (“the CMG Acquisition”) on August 1, 2019 for total consideration of $1,284 million and accounted for this transaction using the acquisition method. Auditing the Company’s accounting for the CMG Acquisition was complex due to the significant estimation uncertainty inherent in determining the fair value of the property, plant and equipment and the identified customer relationship intangible asset. The significant assumptions used to estimate the fair value of the property, plant and equipment included depreciated replacement cost estimates. The significant assumptions used to derive the customer relationship intangible asset included discount rates and other assumptions that form the basis of the cash flow projections of sales to acquired customers (e.g., transportation volumes, customer renewal rates and profit margins). These assumptions relate to the future performance of the acquired businesses, are forward-looking and could be affected by future economic and market conditions.
How We Addressed the Matter in Our Audit |  | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s valuation of the property, plant and equipment and customer relationship intangible assets. For example, we tested controls over management’s review of the valuation models, the appropriateness of the assumptions used in the calculations and the completeness and accuracy of the data underlying the valuation models. To test the fair value of the property, plant, and equipment and customer relationship intangible asset, our audit procedures included, among others, evaluating the Company’s selection of a valuation method and testing the models and significant assumptions described above, as well as the completeness and accuracy of the underlying data. For example, for the customer relationship intangible asset, we evaluated the estimated cash flows based on volumes of contractual gas transportation commitments from the acquired customer base and future transportation volume expectations beyond contractual commitments by comparing them to historical experience and anticipated customer renewals. We also evaluated the replacement cost assumptions used to derive the fair value of property, plant and equipment. We involved our valuation specialists to assist in evaluating the significant assumptions and methodologies used in the Company’s valuation models.

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2014.
Philadelphia, Pennsylvania
November 26, 2019
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)

| September 30,
| 2019 |  | 2018
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 447.1 |  |  | $ | 452.6 |
Restricted cash | 63.7 |  |  | 9.6 |
Accounts receivable (less allowances for doubtful accounts of $31.6 and $35.1, respectively) | 640.7 |  |  | 751.9 |
Accrued utility revenues | 14.6 |  |  | 14.0 |
Inventories | 229.9 |  |  | 318.2 |
Utility regulatory assets | 9.1 |  |  | 7.5 |
Derivative instruments | 28.9 |  |  | 142.5 |
Prepaid expenses | 72.2 |  |  | 130.2 |
Other current assets | 60.0 |  |  | 61.6 |
Total current assets | 1,566.2 |  |  | 1,888.1 |
Property, plant and equipment |  |  |
Non-utility | 6,134.9 |  |  | 5,345.8 |
Utility | 3,938.1 |  |  | 3,616.3 |
| 10,073.0 |  |  | 8,962.1 |
Accumulated depreciation | (3,385.2 | ) |  | (3,153.9 | )
Net property, plant, and equipment | 6,687.8 |  |  | 5,808.2 |
Goodwill | 3,456.4 |  |  | 3,160.4 |
Intangible assets, net | 708.6 |  |  | 513.6 |
Utility regulatory assets | 386.5 |  |  | 293.5 |
Derivative instruments | 43.2 |  |  | 43.5 |
Other assets | 497.9 |  |  | 273.6 |
Total assets | $ | 13,346.6 |  |  | $ | 11,980.9 |
LIABILITIES AND EQUITY |  |  |
Current liabilities |  |  |
Current maturities of long-term debt | $ | 24.1 |  |  | $ | 18.8 |
Short-term borrowings | 796.3 |  |  | 424.9 |
Accounts payable | 438.8 |  |  | 561.8 |
Employee compensation and benefits accrued | 133.0 |  |  | 132.1 |
Deposits and advances | 167.6 |  |  | 191.2 |
Derivative instruments | 84.9 |  |  | 11.7 |
Accrued interest | 62.9 |  |  | 60.7 |
Other current liabilities | 319.3 |  |  | 330.9 |
Total current liabilities | 2,026.9 |  |  | 1,732.1 |
Noncurrent liabilities |  |  |
Long-term debt | 5,779.9 |  |  | 4,146.5 |
Deferred income taxes | 541.4 |  |  | 991.9 |
Derivative instruments | 48.4 |  |  | 12.8 |
Other noncurrent liabilities | 1,122.8 |  |  | 997.6 |
Total liabilities | 9,519.4 |  |  | 7,880.9 |
Commitments and contingencies (Note 16) |  |  |
Equity: |  |  |
UGI Corporation stockholders’ equity: |  |  |
UGI Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively) | 1,396.9 |  |  | 1,200.8 |
Retained earnings | 2,653.1 |  |  | 2,610.7 |
Accumulated other comprehensive loss | (216.6 | ) |  | (110.4 | )
Treasury stock, at cost | (15.9 | ) |  | (19.7 | )
Total UGI Corporation stockholders’ equity | 3,817.5 |  |  | 3,681.4 |
Noncontrolling interests | 9.7 |  |  | 418.6 |
Total equity | 3,827.2 |  |  | 4,100.0 |
Total liabilities and equity | $ | 13,346.6 |  |  | $ | 11,980.9 |

See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
Revenues | $ | 7,320.4 |  |  | $ | 7,651.2 |  |  | $ | 6,120.7 |
Costs and expenses: |  |  |  |  |
Cost of sales (excluding depreciation and amortization shown below) | 4,323.1 |  |  | 4,074.9 |  |  | 2,837.3 |
Operating and administrative expenses | 1,963.2 |  |  | 2,012.8 |  |  | 1,867.6 |
Impairment of Partnership tradenames and trademarks | — |  |  | 75.0 |  |  | — |
Depreciation and amortization | 448.1 |  |  | 455.1 |  |  | 416.3 |
Other operating income, net | (31.1 | ) |  | (31.3 | ) |  | (10.5 | )
| 6,703.3 |  |  | 6,586.5 |  |  | 5,110.7 |
Operating income | 617.1 |  |  | 1,064.7 |  |  | 1,010.0 |
Income from equity investees | 9.1 |  |  | 4.3 |  |  | 4.3 |
Loss on extinguishments of debt | (6.1 | ) |  | — |  |  | (59.7 | )
Other non-operating income (expense), net | 38.2 |  |  | 15.6 |  |  | (29.7 | )
Interest expense | (257.8 | ) |  | (230.1 | ) |  | (223.5 | )
Income before income taxes | 400.5 |  |  | 854.5 |  |  | 701.4 |
Income tax expense | (92.6 | ) |  | (32.1 | ) |  | (177.6 | )
Net income including noncontrolling interests | 307.9 |  |  | 822.4 |  |  | 523.8 |
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (51.7 | ) |  | (103.7 | ) |  | (87.2 | )
Net income attributable to UGI Corporation | $ | 256.2 |  |  | $ | 718.7 |  |  | $ | 436.6 |
Earnings per common share attributable to UGI Corporation stockholders: |  |  |  |  |
Basic | $ | 1.44 |  |  | $ | 4.13 |  |  | $ | 2.51 |
Diluted | $ | 1.41 |  |  | $ | 4.06 |  |  | $ | 2.46 |
Weighted-average common shares outstanding (thousands): |  |  |  |  |
Basic | 178,417 |  |  | 173,908 |  |  | 173,662 |
Diluted | 181,111 |  |  | 176,905 |  |  | 177,159 |
Dividends declared per common share | $ | 1.145 |  |  | $ | 1.02 |  |  | $ | 0.975 |

See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
Net income including noncontrolling interests | $ | 307.9 |  |  | $ | 822.4 |  |  | $ | 523.8 |
Net (losses) gains on derivative instruments (net of tax of $3.2, $(0.8), and $(0.5), respectively) | (7.3 | ) |  | 1.0 |  |  | 1.7 |
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.7), $(2.6), and $4.1, respectively) | 1.7 |  |  | 4.3 |  |  | (9.7 | )
Foreign currency translation adjustments (net of tax of $(13.3), $(0.5), and $(0.6), respectively) | (23.2 | ) |  | (21.4 | ) |  | 34.6 |
Foreign currency (losses) gains on long-term intra-company transactions | (59.0 | ) |  | (9.1 | ) |  | 24.8 |
Benefit plans, principally actuarial (losses) gains net of tax of $5.4, $(5.2), and $(3.8), respectively) | (13.0 | ) |  | 10.4 |  |  | 6.5 |
Reclassifications of benefit plans actuarial losses and net prior service benefit (net of tax of $(0.5), $1.1, and $(2.1), respectively) | 1.2 |  |  | (2.2 | ) |  | 3.4 |
Other comprehensive (loss) income | (99.6 | ) |  | (17.0 | ) |  | 61.3 |
Comprehensive income including noncontrolling interests | 208.3 |  |  | 805.4 |  |  | 585.1 |
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | (51.7 | ) |  | (103.7 | ) |  | (87.2 | )
Comprehensive income attributable to UGI Corporation | $ | 156.6 |  |  | $ | 701.7 |  |  | $ | 497.9 |

See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |
Net income including noncontrolling interests | $ | 307.9 |  |  | $ | 822.4 |  |  | $ | 523.8 |
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |  |  |  |  |
Depreciation and amortization | 448.1 |  |  | 455.1 |  |  | 416.3 |
Deferred income tax (benefit) expense, net | (42.7 | ) |  | (68.8 | ) |  | 110.1 |
Provision for uncollectible accounts | 28.6 |  |  | 35.6 |  |  | 30.7 |
Changes in unrealized gains and losses on derivative instruments | 258.1 |  |  | (132.8 | ) |  | (82.0 | )
Impairment of Partnership tradenames and trademarks | — |  |  | 75.0 |  |  | — |
Equity-based compensation expense | 18.1 |  |  | 22.5 |  |  | 19.3 |
Loss on extinguishments of debt | 6.1 |  |  | — |  |  | 59.7 |
Income from equity investees | (9.1 | ) |  | (4.3 | ) |  | (4.3 | )
Loss on private equity partnership investment | 1.5 |  |  | — |  |  | 11.0 |
Other, net | 9.1 |  |  | 11.1 |  |  | 40.4 |
Net change in: |  |  |  |  |
Accounts receivable and accrued utility revenues | 83.3 |  |  | (147.6 | ) |  | (103.6 | )
Inventories | 84.1 |  |  | (37.4 | ) |  | (64.7 | )
Utility deferred fuel costs, net of changes in unsettled derivatives | (29.5 | ) |  | 31.1 |  |  | (15.4 | )
Accounts payable | (97.2 | ) |  | 65.1 |  |  | 49.9 |
Derivative instruments collateral (paid) received | (41.5 | ) |  | 3.9 |  |  | 8.0 |
Other current assets | 44.6 |  |  | (26.6 | ) |  | (37.5 | )
Other current liabilities | 8.6 |  |  | (19.0 | ) |  | 2.7 |
Net cash provided by operating activities | 1,078.1 |  |  | 1,085.3 |  |  | 964.4 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |
Expenditures for property, plant and equipment | (704.6 | ) |  | (574.4 | ) |  | (638.9 | )
Acquisitions of businesses and assets, net of cash and restricted cash acquired | (1,362.2 | ) |  | (187.2 | ) |  | (100.8 | )
Other, net | 11.5 |  |  | 13.0 |  |  | (29.0 | )
Net cash used by investing activities | (2,055.3 | ) |  | (748.6 | ) |  | (768.7 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |
Dividends on UGI Common Stock | (199.5 | ) |  | (176.9 | ) |  | (168.9 | )
Distributions on AmeriGas Partners publicly held Common Units | (263.1 | ) |  | (263.0 | ) |  | (261.6 | )
Issuances of debt, net of issuance costs | 2,411.7 |  |  | 124.4 |  |  | 1,307.1 |
Repayments of debt, including redemption premiums | (737.8 | ) |  | (149.1 | ) |  | (1,064.8 | )
Receivables Facility net borrowings (repayments) | 44.4 |  |  | (37.0 | ) |  | 13.5 |
Increase in short-term borrowings | 327.0 |  |  | 93.5 |  |  | 61.2 |
Issuances of UGI Common Stock | 16.8 |  |  | 34.9 |  |  | 11.0 |
Repurchases of UGI Common Stock | (16.9 | ) |  | (59.8 | ) |  | (43.3 | )
Cash paid for AmeriGas Merger | (528.9 | ) |  | — |  |  | — |
Other | (11.5 | ) |  | (5.2 | ) |  | (0.8 | )
Net cash provided (used) by financing activities | 1,042.2 |  |  | (438.2 | ) |  | (146.6 | )
Effect of exchange rate changes on cash, cash equivalents and restricted cash | (16.4 | ) |  | (5.0 | ) |  | 1.2 |
Cash, cash equivalents and restricted cash increase (decrease) | $ | 48.6 |  |  | $ | (106.5 | ) |  | $ | 50.3 |
CASH, CASH EQUIVALENTS AND RESTRICTED CASH |  |  |  |  |
Cash, cash equivalents and restricted cash at end of period | $ | 510.8 |  |  | $ | 462.2 |  |  | $ | 568.7 |
Cash, cash equivalents and restricted cash at beginning of period | 462.2 |  |  | 568.7 |  |  | 518.4 |
Cash, cash equivalents and restricted cash increase (decrease) | $ | 48.6 |  |  | $ | (106.5 | ) |  | $ | 50.3 |
SUPPLEMENTAL CASH FLOW INFORMATION |  |  |  |  |
Cash paid for: |  |  |  |  |
Interest | $ | 248.4 |  |  | $ | 221.7 |  |  | $ | 202.1 |
Income taxes | $ | 74.1 |  |  | $ | 118.0 |  |  | $ | 98.0 |

See accompanying Notes to Consolidated Financial Statements.
F-11

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
Common stock, without par value |  |  |  |  |
Balance, beginning of year | $ | 1,200.8 |  |  | $ | 1,188.6 |  |  | $ | 1,201.6 |
Common stock issued: |  |  |  |  |
Employee and director plans (including losses on treasury stock transactions), net of tax withheld | 11.2 |  |  | (1.5 | ) |  | (28.2 | )
Equity-based compensation expense | 14.6 |  |  | 13.7 |  |  | 13.2 |
Gain on sale of treasury stock | — |  |  | — |  |  | 2.0 |
AmeriGas Merger-related adjustments | 170.3 |  |  | — |  |  | — |
Balance, end of year | $ | 1,396.9 |  |  | $ | 1,200.8 |  |  | $ | 1,188.6 |
Retained earnings |  |  |  |  |
Balance, beginning of year | $ | 2,610.7 |  |  | $ | 2,106.7 |  |  | $ | 1,834.1 |
Net income attributable to UGI Corporation | 256.2 |  |  | 718.7 |  |  | 436.6 |
Cash dividends on common stock ($1.145, $1.02, and $0.975 per share, respectively) | (199.5 | ) |  | (176.9 | ) |  | (168.9 | )
Cumulative effect of change in accounting principle - ASC 606 | (7.1 | ) |  | — |  |  | — |
Cumulative effect of change in accounting for employee share-based payments | — |  |  | — |  |  | 4.9 |
Reclassification of stranded income tax effects related to TCJA | 6.6 |  |  | — |  |  | — |
Losses on treasury stock transactions in connection with employee and director plans | (13.8 | ) |  | (37.8 | ) |  | — |
Balance, end of year | $ | 2,653.1 |  |  | $ | 2,610.7 |  |  | $ | 2,106.7 |
Accumulated other comprehensive income (loss) |  |  |  |  |
Balance, beginning of year | $ | (110.4 | ) |  | $ | (93.4 | ) |  | $ | (154.7 | )
Reclassification of stranded income tax effects related to TCJA | (6.6 | ) |  | — |  |  | — |
Net (losses) gains on derivative instruments | (7.3 | ) |  | 1.0 |  |  | 1.7 |
Reclassification of net losses (gains) on derivative instruments | 1.7 |  |  | 4.3 |  |  | (9.7 | )
Benefit plans, principally actuarial (losses) gains | (13.0 | ) |  | 10.4 |  |  | 6.5 |
Reclassification of benefit plans actuarial losses and net prior service benefits | 1.2 |  |  | (2.2 | ) |  | 3.4 |
Foreign currency (losses) gains on long-term intra-company transactions | (59.0 | ) |  | (9.1 | ) |  | 24.8 |
Foreign currency translation adjustments | (23.2 | ) |  | (21.4 | ) |  | 34.6 |
Balance, end of year | $ | (216.6 | ) |  | $ | (110.4 | ) |  | $ | (93.4 | )
Treasury stock |  |  |  |  |
Balance, beginning of year | $ | (19.7 | ) |  | $ | (38.6 | ) |  | $ | (36.9 | )
Common stock issued: |  |  |  |  |
Employee and director plans, net of tax withheld | 23.5 |  |  | 86.5 |  |  | 49.6 |
Repurchases of common stock | (16.9 | ) |  | (59.8 | ) |  | (43.3 | )
Reacquired common stock – employee and director plans | (2.8 | ) |  | (7.8 | ) |  | (8.2 | )
Sale of treasury stock | — |  |  | — |  |  | 0.2 |
Balance, end of year | $ | (15.9 | ) |  | $ | (19.7 | ) |  | $ | (38.6 | )
Total UGI Corporation stockholders’ equity | $ | 3,817.5 |  |  | $ | 3,681.4 |  |  | $ | 3,163.3 |
Noncontrolling interests |  |  |  |  |
Balance, beginning of year | $ | 418.6 |  |  | $ | 577.6 |  |  | $ | 750.9 |
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | 51.7 |  |  | 103.7 |  |  | 87.2 |
Dividends and distributions | (263.1 | ) |  | (263.3 | ) |  | (261.6 | )
AmeriGas Merger-related adjustments | (198.7 | ) |  | — |  |  | — |
Other | 1.2 |  |  | 0.6 |  |  | 1.1 |
Balance, end of year | $ | 9.7 |  |  | $ | 418.6 |  |  | $ | 577.6 |
Total equity | $ | 3,827.2 |  |  | $ | 4,100.0 |  |  | $ | 3,740.9 |

See accompanying Notes to Consolidated Financial Statements.
F-12

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations
Note 2 — Summary of Significant Accounting Policies
Note 3 — Accounting Changes
Note 4 — Revenue from Contracts with Customers
Note 5 — AmeriGas Merger and Acquisitions
Note 6 — Debt
Note 7 — Income Taxes
Note 8 — Employee Retirement Plans
Note 9 — Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 10 — Inventories
Note 11 — Property, Plant and Equipment
Note 12 — Goodwill and Intangible Assets
Note 13 — Series Preferred Stock
Note 14 — Common Stock and Equity-Based Compensation
Note 15 — Partnership Distributions
Note 16 — Commitments and Contingencies
Note 17 — Fair Value Measurements
Note 18 — Derivative Instruments and Hedging Activities
Note 19 — Accumulated Other Comprehensive Income (Loss)
Note 20 — Other Operating Income, Net
Note 21 — Quarterly Data (unaudited)
Note 22 — Segment Information
Note 23 — Global LPG Business Transformation Initiatives
Note 1 — Nature of Operations
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 own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; and (3) 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 LPG and market other energy products and services.
We conduct a domestic propane marketing and distribution business through AmeriGas Partners. AmeriGas Partners conducts a national propane distribution business through its principal operating subsidiary AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc., serves as the general partner of AmeriGas Partners. On April 1, 2019, we entered into the Merger Agreement pursuant to which we agreed to merge the Partnership with and into Merger Sub, an indirect wholly owned subsidiary of UGI, with the Partnership as the surviving entity. On August 21, 2019, the AmeriGas Merger was completed and we issued 34.6 million shares of UGI Common Stock and paid $528.9 in cash to acquire all of the outstanding AmeriGas Partners Common Units representing limited partnership interests in AmeriGas Partners not already held by UGI or its subsidiaries. Prior to the AmeriGas Merger, UGI controlled the Partnership through its ownership of the General Partner, which held a 1% general partner interest (which included IDRs) and approximately 25.5% of the outstanding Common Units, and held an effective 27% ownership interest in AmeriGas OLP. The IDRs held by the General Partner prior to the AmeriGas Merger entitled it to receive distributions from AmeriGas Partners in excess of its general partner interest under certain circumstances (see Note 15). For additional information on the AmeriGas Merger, see Note 5.
UGI International, through subsidiaries and affiliates, conducts (1) an LPG distribution business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. These businesses are conducted principally through our subsidiaries, UGI France, Flaga, AvantiGas, DVEP and UniverGas.
Energy Services conducts, directly and through subsidiaries, energy marketing, midstream transmission, LNG storage, natural gas gathering and processing, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. Energy Services and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation
F-13

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
by the FERC. On August 1, 2019, Energy Services completed the CMG Acquisition in which it acquired all of the equity interests in CMG and CMG’s approximately 47% interest in Pennant. CMG and its direct and indirect subsidiaries provide natural gas gathering and processing services through five discrete gathering systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia (see Note 5).
UGI Utilities directly owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county. Prior to the Utility Merger on October 1, 2018, Gas Utility also conducted operations through PNG and CPG. UGI Utilities also owns and operates Electric Utility, an electric distribution utility in northeastern Pennsylvania. Gas Utility is subject to regulation by the PAPUC and, with respect to a small service territory in one Maryland county, the MDPSC. Electric Utility is subject to regulation by the PAPUC and the FERC.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which are majority owned. We report outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. Prior to the AmeriGas Merger, we also reported the public’s interest in the Partnership as a noncontrolling interest. We eliminate intercompany accounts and transactions when we consolidate.
We account for privately held equity securities of entities without readily determinable fair values in which we do not have control, but have significant influence over operating and financial policies, under the equity method. Investments in equity securities related to such entities in which we do not have significant influence over operating and financial policies are valued at their cost less impairment (if any). Our investments in such entities totaled $242.4 and $147.2 at September 30, 2019 and 2018, respectively, and are included in “Other assets” on the Consolidated Balance Sheets.
On August 1, 2019, Energy Services completed the CMG Acquisition including CMG’s approximately 47% interest in Pennant. Pennant is considered to be an equity method investment as we have the ability to exercise significant influence, but not control, over Pennant. Our investment in Pennant at September 30, 2019 totaled $90.8. For additional information regarding the CMG Acquisition, see Note 5.
An indirect 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., each hold a 20% membership interest in PennEast. PennEast was formed to construct an approximate 120-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, 2019 and 2018 totaled $84.7 and $72.6, respectively.
In September 2019, a panel of the U.S. Court of Appeals for the Third Circuit ruled that New Jersey’s Eleventh Amendment immunity barred PennEast from bringing an eminent domain lawsuit in federal court, under the Natural Gas Act, against New Jersey or its agencies. The Third Circuit subsequently denied PennEast’s petition for rehearing en banc. In addition, in October 2019, in reliance on the Third Circuit ruling, the New Jersey Department of Environmental Protection rejected PennEast’s application for certain project permits. PennEast has filed a petition for declaratory order with the FERC regarding interpretation of the Natural Gas Act. PennEast also expects to file a petition for a writ of certiorari to seek U.S. Supreme Court review of the Third Circuit decision. The ultimate outcome of these matters cannot be determined at this time, and could result in delays, additional costs, or the inability to move forward with the project, resulting in an impairment of all or a portion of our investment in PennEast.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the FASB’s guidance in 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 through 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 9.
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 NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.
Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in AOCI, 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. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. Gains
F-15

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
and losses on net investment hedges that relate to our foreign operations are included in the cumulative translation adjustment component of AOCI until such foreign net investment is sold or liquidated.
Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating 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 flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 18.
Business Combination Purchase Price Allocations
From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information. Estimating fair values is generally subject to significant judgment and assumptions and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation.
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. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise with the impact of subsequent changes in such rates reflected in the income statement. The functional currency of a significant portion of our international operations is the euro.
Revenue Recognition
Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 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. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position.
Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year. The costs incurred to obtain contracts that have durations of longer than one year are not material. See Note 4 for additional disclosures regarding the Company’s revenue from contracts with customers.
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.
F-16

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 and amortization” 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. For additional information regarding the tax effects of the AmeriGas Merger, see Note 7.
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 records 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. At September 30, 2019 and 2018, such deferred investment tax credits totaled $2.3 and $2.6, respectively.
We record interest on underpayments and overpayments of income taxes, and income tax penalties, in “Income tax expense” on the Consolidated Statements of Income. For Fiscal 2019, Fiscal 2018 and Fiscal 2017, interest income or expense recognized in “Income tax expense” on the Consolidated Statements of Income was not material.
The TCJA was enacted on December 22, 2017, and included a broad range of tax reform provisions affecting the Company, including, among other things, changes in the U.S. corporate income tax rate. The TCJA reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. We were subject to a 24.5% blended U.S. federal income tax rate for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21%. In accordance with GAAP, at the date of enactment of the TCJA our federal deferred income taxes, including deferred income taxes related to items included in AOCI, were remeasured based upon the new corporate income tax rate. For our non-utility businesses, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and the adjustment recorded in the provision for income taxes. Our utility businesses were also required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, because it was probable that the effect of the change in income tax rates on deferred income tax balances would be recovered or refunded in future rates, our rate-regulated utility businesses recorded a regulatory asset or liability associated with these deferred income tax assets and liabilities. For additional information regarding the impact of the TCJA and associated regulatory effects, see Notes 7 and 9.
Other Non-Operating Income (Expense), Net
Included in “Other non-operating income (expense), net,” on the Consolidated Statements of Income are net gains (losses) on forward foreign currency contracts used to reduce volatility in net income associated with our foreign operations, and non-service income (expense) associated with our pension and other postretirement plans. Other non-operating income (expense), net comprises the following:

| 2019 |  | 2018 |  | 2017
Gains (losses) on foreign currency contracts, net | $ | 37.7 |  |  | $ | 16.2 |  |  | $ | (23.9 | )
Pension and other postretirement plans non-service income (expense), net | 0.5 |  |  | (0.6 | ) |  | (5.8 | )
Total other non-operating income (expense), net | $ | 38.2 |  |  | $ | 15.6 |  |  | $ | (29.7 | )

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 2019, Fiscal 2018 and Fiscal 2017:

(Thousands of shares) |  | 2019 |  | 2018 |  | 2017
Weighted-average common shares outstanding for basic computation (a) |  | 178,417 |  |  | 173,908 |  |  | 173,662 |
Incremental shares issuable for stock options and common stock awards (b) |  | 2,694 |  |  | 2,997 |  |  | 3,497 |
Weighted-average common shares outstanding for diluted computation |  | 181,111 |  |  | 176,905 |  |  | 177,159 |

(a) | Fiscal 2019 includes the partial-year impact from the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5).

(b) | For Fiscal 2019 and Fiscal 2017, there were 1,162 shares and 146 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.

Cash, Cash Equivalents and Restricted Cash
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 principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Consolidated Balance Sheets to the corresponding amounts reported on the Consolidated Statements of Cash Flows.

|  | Cash, Cash Equivalents and Restricted Cash
|  | September 30, 2019 |  | September 30, 2018 |  | September 30, 2017 |  | September 30, 2016
Cash and cash equivalents |  | $ | 447.1 |  |  | $ | 452.6 |  |  | $ | 558.4 |  |  | $ | 502.8 |
Restricted cash |  | 63.7 |  |  | 9.6 |  |  | 10.3 |  |  | 15.6 |
Cash, cash equivalents and restricted cash |  | $ | 510.8 |  |  | $ | 462.2 |  |  | $ | 568.7 |  |  | $ | 518.4 |

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 FIFO method for all other inventories.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at the lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, AFUDC. We also include in property, plant and equipment costs associated with computer software we develop or obtain for use in our business. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. When we retire or otherwise dispose of non-utility plant and equipment, we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in "Other operating income, net" on the Consolidated Statements of Income.
F-18

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives. At September 30, 2019, estimated useful lives by asset 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 |  | 30
Electricity generation facilities |  | 25 |  | 40
Pipeline and related assets |  | 25 |  | 40
Transportation equipment and office furniture and fixtures |  | 3 |  | 10
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 2019, Fiscal 2018 and Fiscal 2017 were as follows:

| 2019 |  | 2018 |  | 2017
Gas Utility | 2.2 | % |  | 2.3 | % |  | 2.2 | %
Electric Utility | 2.1 | % |  | 2.2 | % |  | 2.4 | %

UGI Utilities’ IT costs associated with major IT system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs, preliminary project stage costs and cloud computing, are deferred as a regulatory asset and included as a component of property, plant and equipment. As of September 30, 2019 and 2018, such costs deferred as a regulatory asset and not yet requested in a rate proceeding totaled $3.7 and $6.3, respectively. UGI Utilities amortizes computer software and related IT system installation costs on a straight-line basis over expected periods of benefit not exceeding 15 years once the installed software is ready for its intended use.
We classify amortization of computer software and related IT system installation costs included in property, plant and equipment as depreciation expense. Depreciation expense totaled $388.5, $396.5 and $365.5 for Fiscal 2019, Fiscal 2018 and Fiscal 2017, respectively.
For property subject to cost of service rate regulation including substantially all of UGI Utilities depreciable utility plant and equipment, upon retirement 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 on the Consolidated Statements of Income.
Goodwill and Intangible Assets
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 on the Consolidated Statements of Income (see Note 12). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships (other than customer relationships acquired in the CMG Acquisition), certain tradenames and noncompete agreements, generally do not exceed 15 years. The estimated useful lives of customer relationships acquired in the CMG Acquisition is 35 years (see Note 5). 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.
During Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing the remaining
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. For further information on these tradenames and trademarks, see Note 12.
Goodwill. 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 a business 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.
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 goodwill impairment losses at September 30, 2019 and 2018, and no provisions for goodwill impairments were recorded during Fiscal 2019, Fiscal 2018 or Fiscal 2017. For further information on our goodwill and intangible assets, see Note 12.
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. If the undiscounted future cash flows indicate that the recorded amounts are not expected to be recoverable, such long-lived assets are reduced to their estimated fair values. No material provisions for impairments of long-lived assets were recorded during Fiscal 2019, Fiscal 2018 or Fiscal 2017.
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 revolving credit facilities reflected as short-term borrowings are classified as “Other assets” on our Consolidated Balance Sheets. Amortization of debt 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 extinguishments of debt” on the Consolidated Statements of Income. 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 UGI France of $279.7 and $272.0 at September 30, 2019 and 2018, 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.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 Consolidated 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. These estimates are based upon a number of factors including whether the company will be responsible for such remediation, the scope and cost of the remediation work to be performed, the portion of costs that will be shared with other potentially responsible parties, the timing of the remediation and possible impact of changes in technology, and the regulations and requirements of local governmental authorities. 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. Under GAAP, if the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, such liabilities are discounted to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Utilities receives ratemaking recognition of environmental investigation and remediation costs associated with in-state 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 16.
Loss Contingencies Subject to Insurance
We are subject to risk of loss for general, automobile and product liability, and workers’ compensation claims for which we obtain insurance coverage under insurance policies that are subject to self-insured retentions or deductibles. In accordance with GAAP, we record accruals when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. When no amount within a range of possible loss is a better estimate than any other amount within the range, liabilities recorded are based upon the low end of the range. For litigation and pending claims including those covered by insurance policies, the analysis of probable loss is performed on a case by case basis and includes an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success in prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. With respect to unasserted claims arising from unreported incidents, we may use the work of specialists to estimate the ultimate losses to be incurred using actuarially determined loss development factors applied to actual claims data. Our estimated reserves for loss contingencies may differ materially from the ultimate liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted. We maintain insurance coverage such that our net exposure for claims covered by insurance would be limited to the self-insured retentions or deductibles, claims above which would be paid by the insurance carrier. For such claims, we record a receivable related to the amount of the liability expected to be paid by insurance.
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 8).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and, prior to the AmeriGas Merger, 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 all or a 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. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded on the Consolidated Statements of Income.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 in the reporting period in which they occur, and assumed proceeds under the treasury stock method used for computing diluted shares outstanding do not include windfall tax benefits in the diluted shares calculation. We account for forfeitures of share-based payments when they occur.
For additional information on our equity-based compensation plans and related disclosures, see Note 14.
Note 3 — Accounting Changes
New Accounting Standards Adopted in Fiscal 2019
Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures.
Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. As UGI Utilities receives rate recovery for cloud computing implementation costs, such costs will continue to be deferred as a regulatory asset and included as a component of property, plant, and equipment. The adoption of the new guidance did not have a material impact on our results of operations during Fiscal 2019.
Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $6.6 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI.
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 cost 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 income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. We adopted this ASU effective October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization, as required by the ASU. The adoption of the new standard did not have a material impact on our financial statements.
Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. We adopted this ASU effective October 1, 2018 with retrospective adoption as required by the ASU.
Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. We adopted this ASU during the fourth quarter of Fiscal 2019 and applied the new guidance retrospectively for all periods presented in the financial statements. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures.
Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. We adopted this ASU during the fourth quarter of Fiscal 2019. The guidance regarding removing and modifying disclosures was adopted on a retrospective basis and the guidance regarding new disclosures has been adopted on a prospective basis. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures.
New Accounting Standards Adopted Effective October 1, 2019
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 the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). 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 prospectively. The Company adopted the new guidance effective October 1, 2019. We do not expect the adoption of this new guidance will have a material impact on our financial statements.
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). 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 unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption.
We adopted this ASU, as updated, effective October 1, 2019, using the transition method which allows the Company to maintain historical presentation for periods before October 1, 2019. The Company elected to apply the following practical expedients:

• | Short-term leases: We have excluded short-term leases (term of 12 months or less) from balance sheet presentation.

• | Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases.

• | Other: We did not reassess the classification of expired or existing contracts or determine whether they are or contain a lease. We also did not reassess whether initial direct costs qualify for capitalization under this new guidance.

We enhanced controls and processes and implemented a new lease system that will enable the accumulation and presentation of financial information as required by the new standard. We continue to finalize our implementation efforts and estimate that the adoption will result in the recognition of approximately $400 to $600 of offsetting operating lease right-of-use assets and operating lease liabilities associated with operating leases in effect at the date of adoption. We do not expect the adoption to have a material impact on the consolidated statements of income or cash flows.
Accounting Standard Not Yet Adopted
Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for loss for receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. 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.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 4 — Revenue from Contracts with Customers
The Company recognizes revenue when control of promised goods or services is transferred to its customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain of UGI Utilities’ large delivery service customers and Midstream & Marketing’s peaking contracts for which we recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company.
We do not have a significant financing component in our contracts because we receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is generally one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component.
The Company’s revenues from contracts with customers are discussed below.
Utility Revenues
UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs.
Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service.
The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter, which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather.
UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis.
UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms.
Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmission services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service.
Other Utility revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers.
Non-Utility Revenues
LPG. AmeriGas Propane and UGI International record revenue principally from the sale of LPG to retail and wholesale customers. The primary performance obligation associated with the sale of LPG is the delivery of propane to (1) the customer’s point of delivery for retail customers and (2) the customer’s specified location where LPG is picked up by wholesale customers, at which point control of the propane is transferred to the customer, the performance obligation is satisfied, and the associated revenue is recognized. For contracts with retail customers that consume LPG from a metered tank, we recognize revenue as LPG is consumed, at which point we have the right to invoice, and generally invoice monthly based on consumption.
Contracts with customers comprise different types of contracts with varying length terms, fixed or variable prices, and fixed or variable quantities. Contracts with our residential customers, which comprise a substantial number of our customer contracts, are generally one year or less. Customer contracts for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to customers at a fixed price and a fixed volume, and contracts that provide for the sale of propane at market prices at date of delivery with no fixed volumes. AmeriGas Propane offers contracts that permit customers to lock in a fixed price for their volumes for a fee and also provide customers with the option to pre-buy a fixed amount of propane at a fixed price. Amounts received under pre-buy arrangements are recorded as a contract liability when received and recorded as revenue when LPG is delivered and control is transferred to the customer. Fees associated with fixed-price contracts are recorded as contract liabilities and recorded ratably over the contract period.
AmeriGas Propane and UGI International also distribute LPG to customers in portable cylinders. Under certain contracts, filled cylinders are delivered, and control is transferred, to a reseller. In such instances, the reseller is our customer and we record revenue upon delivery to the reseller. Under other contracts, filled cylinders are delivered to a reseller, but the Company retains control of the cylinders. In such instances, we record revenue at the time the reseller transfers control of the cylinder to the end user.
Certain retail LPG customers for AmeriGas Propane receive credits which we account for as variable consideration. We estimate these credits based upon past practices and historical customer experience and we reduce our revenues recognized for these credits.
Energy Marketing. Midstream & Marketing and UGI International operate energy marketing businesses that sell energy commodities, principally natural gas and electricity, to residential, commercial, industrial and wholesale customers. In addition, UGI International provides system balancing and procurement services to other energy marketers in the Netherlands.
Midstream & Marketing and UGI International market natural gas and electricity on full-requirements or agreed-upon volume bases under contracts with varying length terms and at fixed or floating prices that are based on market indices adjusted for differences in price between the market location and delivery locations. Performance obligations associated with these contracts primarily comprise the delivery of the natural gas and electricity over a contractual period of time. Performance obligations also include other energy-related ancillary services provided to customers such as capacity. For performance obligations that are satisfied at a point in time such as the delivery of natural gas, revenue is recorded when customers take control of the natural gas. Revenue is recorded for performance obligations that qualify as a series, when customers consume the natural gas or electricity is delivered, which corresponds to the amount invoiced to the customer. For transactions where the price or volume is not fixed, the transaction price is not determined until delivery occurs. The billed amount, and the revenue recorded, is based upon consumption by the customer.
In addition to providing natural gas and electricity to end-user customers, our energy marketing business in the Netherlands has contracts with third-party natural gas and electricity marketers to provide BRP services in the electricity and natural gas markets in the Netherlands. These contracts are typically multi-year agreements and include full BRP services that include, among other things, estimating, procuring and scheduling all energy requirements to meet third-party marketers’ needs, or provide more limited system procurement and balancing services. The amount of revenue recognized from our BRP customers is based upon the amount of energy delivered with respect to these agreements, and the level of BRP services provided. We typically receive payments from our BRP customers one month in advance of our performing the related services. Amounts received in advance are deferred on the balance sheet as contract liabilities. Based upon an evaluation of the terms and conditions of the BRP contracts and our ability to control the goods or services provided to the third-party marketers, in addition to other factors, we are considered a principal
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
in these contracts and are required to record the revenue associated with the sale of energy to the third-party energy marketers on a gross basis. We record the associated revenue ratably over time, typically monthly, as the performance obligations are satisfied.
Midstream. Midstream & Marketing provides natural gas pipeline transportation, natural gas gathering and natural gas underground storage services, which generally contain a performance obligation for the Company to have availability to transport or store a product. Additionally, the Company provides stand-ready services to sell supplemental energy products and related services, primarily LNG and propane-air mixtures during periods of high demand that typically result from cold weather. The Company also sells LNG to end-user customers for use by trucks, drilling rigs and other motored vehicles and equipment, and facilities that are located off the natural gas grid.
Contracts for natural gas transportation and gathering services are typically long-term contracts with terms of up to 30 years, while contracts for storage are typically for one-year or multiple storage season periods. Contracts to provide natural gas during periods of high demand have terms of up to 15 years. Contracts to sell LNG for trucks, drilling rigs and other motor vehicles and facilities are typically short-term (less than one year). Depending on the type of services provided or goods sold, midstream revenues may consist of demand rates, commodity rates, and transportation rates and may include other fees for ancillary services. Pipeline transportation, natural gas gathering and storage services provided and services to stand ready to sell supplemental energy products and services each are considered to have a single performance obligation satisfied through the passage of time ratably based upon providing a stand-ready service on a monthly basis. Contracts to sell LNG to end-user customers contain performance obligations to deliver LNG over the term of the contract and revenue is recognized at a point in time when the control of the energy products is transferred to the customer. The price in the contract corresponds to our efforts to satisfy the performance obligation and reflects the consideration we expect to receive for the satisfied performance obligation, and, therefore, the revenue is recognized based on the volume delivered and the price within the contract. In cases where shipping and handling occurs prior to the LNG being delivered to the customer’s storage vessel, we have elected to treat this as a cost of fulfillment and not a separate performance obligation. Revenues are typically billed and payment received monthly. Advance fees received from customers for stand-ready services are deferred as contract liabilities and revenue is recognized ratably over time as the performance obligation is satisfied over a period less than one year.
Electricity Generation. Midstream & Marketing sells power generated from electricity generation assets in the wholesale electricity markets administered by PJM regional transmission organization. Power contracts with PJM consist of the sale of power, capacity and ancillary services, all of which are considered a bundle of various services. Performance obligations are satisfied over time, generally on a daily basis, as electricity is delivered to and simultaneously consumed by the customer. As such, the Company has elected to recognize revenue in the amount to which we have a right to invoice which is based on market prices at the time of the delivery of the electricity to the customers.
Other. Other revenues from contracts with customers are generated primarily from services and products provided by Midstream & Marketing’s HVAC business and AmeriGas Propane’s parts and services business. The performance obligations of these businesses include installation, repair and warranty agreements associated with HVAC equipment and installation services provided for combined heat and power and solar panel installations. For installation and repair goods and services, the performance obligations under these contracts are satisfied, and revenue is recognized, as control of the product is transferred or the services are rendered. For warranty services, revenue is recorded ratably over the warranty period. Other LPG revenues from contracts with customers are generated primarily from certain fees AmeriGas Partners and UGI International charge associated with the delivery of LPG, including hazmat safety compliance, inspection, metering, installation, fuel recovery and certain other services. Revenues from fees are typically recorded when the LPG is delivered to the customer or the associated service is completed.
Contract Balances
The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at September 30, 2019. Substantially all of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and, in the case of UGI Utilities, “Accrued utility revenues” on the Consolidated Balance Sheets. Amounts billed are generally due within the following month.
Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balances of contract liabilities were $114.1 and $111.2 at September 30, 2019 and October 1, 2018, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. Revenue recognized during Fiscal 2019 from the amount included in contract liabilities at October 1, 2018 was $90.7.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Revenue Disaggregation
The following table presents our disaggregated revenues by reportable segment during Fiscal 2019:

2019 |  | Total |  | Eliminations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing (a) |  | UGI Utilities (a) |  | Corporate & Other
Revenues from contracts with customers: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Utility: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Core Market: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 552.7 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 552.7 |  |  | $ | — |
Commercial & Industrial |  | 226.3 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 226.3 |  |  | — |
Large delivery service |  | 138.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 138.0 |  |  | — |
Off-system sales and capacity releases |  | 46.4 |  |  | (64.8 | ) |  | — |  |  | — |  |  | — |  |  | 111.2 |  |  | — |
Other (b) |  | 14.9 |  |  | (3.1 | ) |  | — |  |  | — |  |  | — |  |  | 18.0 |  |  | — |
Total Utility |  | 978.3 |  |  | (67.9 | ) |  | — |  |  | — |  |  | — |  |  | 1,046.2 |  |  | — |
Non-Utility: |  |  |  |  |  |  |  |  |  |  |  |  |  |
LPG: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retail |  | 4,007.9 |  |  | — |  |  | 2,340.9 |  |  | 1,667.0 |  |  | — |  |  | — |  |  | — |
Wholesale |  | 233.3 |  |  | — |  |  | 63.9 |  |  | 169.4 |  |  | — |  |  | — |  |  | — |
Energy Marketing |  | 1,520.7 |  |  | (134.2 | ) |  | — |  |  | 448.3 |  |  | 1,206.6 |  |  | — |  |  | — |
Midstream: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pipeline |  | 94.5 |  |  | — |  |  | — |  |  | — |  |  | 94.5 |  |  | — |  |  | — |
Peaking |  | 17.6 |  |  | (96.8 | ) |  | — |  |  | — |  |  | 114.4 |  |  | — |  |  | — |
Other |  | 1.9 |  |  | — |  |  | — |  |  | — |  |  | 1.9 |  |  | — |  |  | — |
Electricity Generation |  | 43.2 |  |  | — |  |  | — |  |  | — |  |  | 43.2 |  |  | — |  |  | — |
Other |  | 313.3 |  |  | (3.3 | ) |  | 213.2 |  |  | 54.9 |  |  | 48.5 |  |  | — |  |  | — |
Total Non-Utility |  | 6,232.4 |  |  | (234.3 | ) |  | 2,618.0 |  |  | 2,339.6 |  |  | 1,509.1 |  |  | — |  |  | — |
Total revenues from contracts with customers |  | 7,210.7 |  |  | (302.2 | ) |  | 2,618.0 |  |  | 2,339.6 |  |  | 1,509.1 |  |  | 1,046.2 |  |  | — |
Other revenues (c) |  | 109.7 |  |  | (3.2 | ) |  | 64.0 |  |  | 32.6 |  |  | 6.6 |  |  | 2.4 |  |  | 7.3 |
Total revenues |  | $ | 7,320.4 |  |  | $ | (305.4 | ) |  | $ | 2,682.0 |  |  | $ | 2,372.2 |  |  | $ | 1,515.7 |  |  | $ | 1,048.6 |  |  | $ | 7.3 |

(a) | Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.

(b) | UGI Utilities includes an unallocated negative surcharge revenue reduction of $(5.5) during Fiscal 2019 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 9).

(c) | Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP.

Remaining Performance Obligations
The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to certain performance obligations that are unsatisfied as of the end of the reporting period because these contracts have an initial expected term of one year or less, or we have a right to bill the customer in an amount that corresponds directly with the value of services provided to the customer to date. Certain contracts with customers at Midstream & Marketing and UGI Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At September 30, 2019, Midstream & Marketing and UGI Utilities expect to record approximately $2.0 billion and $0.2 billion of revenues, respectively, related to the minimum future performance obligations over the remaining terms of the related contracts.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 5 — AmeriGas Merger and Acquisitions
AmeriGas Merger
On August 21, 2019, the AmeriGas Merger was completed in accordance with the terms of the Merger Agreement entered into on April 1, 2019. Under the terms of the Merger Agreement, the Partnership was merged with and into Merger Sub, with the Partnership surviving as an indirect wholly owned subsidiary of UGI. Each outstanding Common Unit other than the Common Units owned by UGI was automatically converted at the effective time of the AmeriGas Merger into the right to receive, at the election of each holder of such Common Units, one of the following forms of merger consideration (subject to proration designed to ensure the number of shares of UGI Common Stock issued would equal approximately 34.6 million):
(i)0.6378 shares of UGI Common Stock (the “Share Multiplier”);
(ii)$7.63 in cash, without interest, and 0.500 shares of UGI Common Stock; or
(iii)$35.325 in cash, without interest.
Pursuant to the terms of the Merger Agreement, effective on August 21, 2019, we issued 34,612,847 shares of UGI Common Stock and paid $528.9 in cash to the holders of Common Units other than UGI, for a total implied consideration of $2,227.7. In addition, the incentive distribution rights in the Partnership previously owned by the General Partner were canceled. After-tax transaction costs directly attributable to the transaction that were incurred by UGI totaling $7.7 were recorded as a reduction to UGI stockholders’ equity. Transaction costs incurred by the Partnership totaling $6.3 are reflected in “Operating and administrative expenses” on the 2019 Consolidated Statement of Income. The tax effects of the AmeriGas Merger resulting from the step-up in tax bases of the underlying assets resulted in the recording of a deferred tax asset in the amount of $512.3. This deferred tax asset is included in “Deferred income taxes” on the September 30, 2019 Consolidated Balance Sheet.
Effective upon completion of the AmeriGas Merger, Common Units are no longer publicly traded. Also pursuant to the Merger Agreement, Partnership equity-based awards were canceled and replaced with cash-settled restricted stock units relating to UGI Common Stock using the Share Multiplier ratio. For further information on the effects of the AmeriGas Merger on equity-based awards, see Note 14.
The AmeriGas Merger was accounted for in accordance with ASC 810, Consolidation - Overall-Changes in a Parent’s Ownership Interest in a Subsidiary. Because UGI controlled AmeriGas Partners before and after the merger, the changes in UGI’s ownership interest in the Partnership resulting from the merger were accounted for as an equity transaction. Accordingly, no gain or loss was recognized in UGI’s consolidated income statement and the carrying amounts of the Partnership assets and liabilities were not adjusted. The tax effects of the AmeriGas Merger were reported as adjustments to deferred income taxes and UGI stockholders’ equity. For additional information on the tax effects of the AmeriGas Merger, see Note 7.
CMG Acquisition
On August 1, 2019, UGI through its wholly owned indirect subsidiary, Energy Services, completed the CMG Acquisition in which Energy Services acquired all of the equity interests in CMG and CMG’s approximately 47% interest in Pennant, for total cash consideration of $1,284.4, subject to final working capital and other adjustments. The CMG Acquisition was consummated pursuant to the CMG Acquisition Agreements. CMG and Pennant provide natural gas gathering and processing services through five discrete systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia. The CMG Acquisition is consistent with our growth strategies, including expanding our midstream natural gas gathering and processing assets within the Marcellus and Utica Shale production regions. The CMG Acquisition was funded with cash from borrowings under the Energy Services Term Loan and the UGI Corporation Senior Credit Facility and cash on hand (See Note 6).
The Company has accounted for the CMG Acquisition using the acquisition method. At September 30, 2019, the allocation of the purchase price is substantially complete but remains preliminary pending the completion of our third-party valuation report and with regard to the identification and resolution of certain pre-acquisition contingencies and disputes. These amounts are preliminary pending the receipt of additional information. The purchase price allocation will be finalized once these items have been resolved. Accordingly, the fair value estimates presented below relating to these items are subject to change within the measurement period not to exceed one year from the date of acquisition.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The components of the preliminary CMG purchase price allocations are as follows:

Assets acquired: |
Cash | $ | 0.3 |
Accounts receivable | 11.3 |
Prepaid expenses and other current assets | 1.1 |
Property, plant and equipment | 613.2 |
Investment in Pennant | 88.0 |
Intangible assets (a) | 250.0 |
Total assets acquired | $ | 963.9 |
Liabilities assumed: |
Accounts payable | 3.3 |
Other noncurrent liabilities | 0.1 |
Total liabilities assumed | $ | 3.4 |
Goodwill | 323.9 |
Net consideration transferred (including preliminary working capital adjustments) | $ | 1,284.4 |

(a) | Represents customer relationships having an average amortization period of 35 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; 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 CMG Acquisition over the preliminary fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the Midstream & Marketing reportable segment, and results principally from anticipated future capital investment opportunities and value creation resulting from new natural gas processing assets in the Marcellus and Utica Shale production regions. The goodwill recognized from the CMG Acquisition is deductible for income tax purposes.
The Company recognized $15.3 of direct transaction-related costs associated with the CMG Acquisition during Fiscal 2019, which costs are reflected in “Operating and administrative expenses” on the Consolidated Statements of Income. The CMG Acquisition did not have a material impact on the Company’s revenues or net income attributable to UGI for Fiscal 2019. In addition, the impact of the CMG Acquisition on a pro forma basis as if the CMG Acquisition had occurred on October 1, 2017 was not material to the Company’s consolidated results for Fiscal 2019 and Fiscal 2018.
Other Acquisitions
During Fiscal 2019, UGI International acquired several retail LPG distribution businesses, and Midstream & Marketing acquired a natural gas marketing business. During Fiscal 2018, UGI International acquired UniverGas, an LPG distribution business with operations in northern and central regions of Italy, and AmeriGas Propane acquired two retail propane distribution businesses. During Fiscal 2017, UGI International acquired DVEP, 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.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Total cash paid and liabilities incurred in connection with these acquisitions were as follows:

|  | 2019 |  | 2018 |  | 2017
|  | UGI International |  | Midstream & Marketing |  | AmeriGas Propane |  | UGI International |  | AmeriGas Propane |  | UGI International
Total cash paid |  | $ | 49.3 |  |  | $ | 15.0 |  |  | $ | 10.1 |  |  | $ | 121.9 |  |  | $ | 36.8 |  |  | $ | 99.7 |
Liabilities incurred (a) |  | — |  |  | — |  |  | 2.7 |  |  | — |  |  | 10.8 |  |  | 20.6 |
Total purchase price |  | $ | 49.3 |  |  | $ | 15.0 |  |  | $ | 12.8 |  |  | $ | 121.9 |  |  | $ | 47.6 |  |  | $ | 120.3 |

(a) | UGI International Fiscal 2017 amount includes note payable to seller. AmeriGas Propane amounts principally comprise amounts payable under noncompete agreements.

Acquisitions of Assets
During Fiscal 2019, Midstream & Marketing acquired 21 miles of natural gas gathering lines and related dehydration and compression equipment located in northern Pennsylvania for cash consideration of $20. During Fiscal 2018, Midstream & Marketing acquired (1) 60 miles of natural gas gathering lines and related dehydration and compression equipment, and a smaller natural gas gathering system, both located in northern Pennsylvania and (2) a 44-megawatt, natural gas-fired peaking turbine located on its Hunlock Station site in northeast Pennsylvania, for total cash consideration of $70.3.
Note 6 — Debt
Significant Financing Activities
AmeriGas Propane. In December 2017, AmeriGas Partners entered into the AmeriGas OLP Credit Agreement with a group of banks. The AmeriGas OLP Credit Agreement amends and restates a previous credit agreement. The AmeriGas OLP Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas OLP Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas OLP Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%. The aforementioned margins on borrowings are dependent upon AmeriGas Partners’ ratio of debt to EBITDA (each as defined in the AmeriGas OLP Credit Agreement).
During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, the AmeriGas 2017 Senior Notes, comprising $700 principal amount of 5.50% Senior Notes due May 2025 and $525 principal amount of 5.75% Senior Notes due May 2027. 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.
In connection with the early repayment of AmeriGas Partners’ 7.00% Senior Notes, during Fiscal 2017, 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
Early redemption premiums | $ | 51.3 |
Write-off of unamortized debt issuance costs | 8.4 |
Loss on extinguishments of debt | $ | 59.7 |

UGI International. On October 18, 2018, UGI International, LLC entered into the 2018 UGI International Credit Facilities Agreement, a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement. The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan 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
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings was 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swap agreements to fix the underlying euribor rate on term loan borrowings at 0.34% through October 18, 2022. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined.
On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 principal amount of UGI International 3.25% Senior Notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s variable-rate term loan under its 2015 Senior Facilities Agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan; and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we classified €60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into the 2018 UGI International Credit Facilities Agreement, we terminated (1) the 2017 UGI International Credit Agreement; (2) UGI France’s revolving credit facility under the 2015 Senior Facilities Agreement; and (3) Flaga’s credit facility agreement. We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes as net investment hedges. In connection with these early repayments of debt, UGI International recognized pre-tax losses of $6.1, which are reflected in “Loss on extinguishments of debt” on the 2019 Consolidated Statement of Income, and primarily comprises the write-off of unamortized debt issuance costs and transaction costs.
In December 2017, UGI International, LLC entered into the 2017 UGI International Credit Agreement, a secured multicurrency revolving facility agreement due April 2020 with a group of banks providing for borrowings up to €300, with borrowings available in euros or U.S. dollars. Upon entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018, the 2017 UGI International Credit Agreement was terminated. There were no borrowings made under the 2017 UGI International Credit Agreement.
Also, in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into the Flaga U.S. Dollar Term Loan which amended the aforementioned term loan to extend the maturity to April 2020. Prior to its repayment in October 2018, borrowings under the Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga effectively fixed the LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
Energy Services. On August 13, 2019, Energy Services entered into a seven-year $700 variable-rate senior secured term loan agreement with a group of lenders. The Energy Services Term Loan is payable in equal quarterly installments of $1.8, commencing in September 2019, with the balance of the principal being due and payable in full at maturity. Under certain circumstances, Energy Services is required to make additional principal payments if the consolidated total leverage ratio, as defined, is greater than defined thresholds. Borrowings under the Energy Services Term Loan bear interest at rates per annum comprising the aggregate of the applicable margin and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. The initial margin on term loan borrowings is 3.75%. In August 2019, Energy Services entered into a pay-fixed, receive-variable interest rate swap agreement to fix the underlying LIBOR rate on a significant portion of the outstanding principal on Energy Services Term Loan borrowings at 1.55% through July 2024. Proceeds from borrowings under the Energy Services Term Loan were used to finance a portion of the CMG Acquisition and for general corporate purposes.
UGI Utilities. On June 27, 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350 (including a $100 sublimit for letters of credit). UGI Utilities may request an increase in the amount of loan commitments under the UGI Utilities 2019 Credit Agreement to a maximum aggregate amount of $150. Concurrently with entering into the UGI Utilities 2019 Credit Agreement, UGI Utilities terminated its existing $450 revolving credit agreement dated March 27, 2015. Under the UGI Utilities 2019 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2019 Credit Agreement is currently scheduled to expire in June 2024.
On February 1, 2019, UGI Utilities issued in a private placement $150 of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the issuance of the UGI Utilities 4.55% Senior Notes were used to reduce revolving credit agreement borrowings and for general corporate purposes.
In October 2017, UGI Utilities entered into the Utilities Term Loan, a $125 unsecured variable-rate term loan agreement with a group of banks. The Utilities Term Loan is payable in equal quarterly installments of $1.6, commencing in March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. 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. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commenced on September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge.
UGI Corporation. On August 1, 2019, UGI entered into the UGI Corporation Senior Credit Facility. The UGI Corporation Senior Credit Facility comprises (1) a five-year $250 amortizing variable-rate term loan which was drawn on August 21, 2019; (2) a three-year $300 variable-rate term loan which was drawn on August 1, 2019; and (3) a five-year $300 revolving credit facility (including a $10 sublimit for letters of credit) which was drawn in full on August 1, 2019. The $250 term loan commitment is payable in equal quarterly installments of $9.4, commencing in December 2022, with the balance of the principal being due and payable in full on August 1, 2024. Proceeds from borrowings under the UGI Corporation Senior Credit Facility were used to finance the cash portion of the AmeriGas Merger; the CMG Acquisition; and for general corporate purposes. Because management currently intends to maintain a substantial portion of the amounts outstanding under the $300 revolving credit facility beyond September 30, 2020, and has the ability to do so under the terms of the UGI Corporation Senior Credit Agreement, such amounts have been classified as “Long-term debt” on the 2019 Consolidated Balance Sheet.
Borrowings under the UGI Corporation Senior Credit Facility bear interest at rates per annum comprising the aggregate of the applicable margin and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. The applicable margins on term loan and revolving credit facility borrowings are dependent upon a ratio of consolidated net indebtedness to consolidated EBITDA, as defined, and UGI’s credit ratings. The initial margin on term loan borrowings is 2.50% for the $250 amortizing term loan and 2.25% for the $300 term loan. In August 2019, UGI entered into pay-fixed, receive-variable interest rate swap agreements at 1.51% through July 2022, in order to fix the underlying LIBOR rates on the $300 term loan borrowings. In September 2019, UGI entered into pay-fixed, receive-variable interest rate swap agreements at 1.56% through March 2023, in order to fix the underlying LIBOR rates on a significant portion of the $250 term loan borrowings.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Long-term Debt
Long-term debt comprises the following at September 30:

| 2019 |  | 2018
AmeriGas Propane: |  |  |
AmeriGas Partners Senior Notes: |  |  |
5.50% due May 2025 | $ | 700.0 |  |  | $ | 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 |  |  | 525.0 |
Heritage Operating, L.P. Senior Secured Notes (a) | 3.8 |  |  | 7.5 |
Other | 9.5 |  |  | 14.6 |
Unamortized debt issuance costs | (23.7 | ) |  | (27.5 | )
Total AmeriGas Propane | 2,564.6 |  |  | 2,569.6 |
UGI International: |  |  |
3.25% Senior Notes due November 2025 | 381.5 |  |  | — |
UGI International, LLC variable-rate term loan due October 2023 (b) | 327.0 |  |  | — |
UGI France Senior Facilities term loan (c) | — |  |  | 627.0 |
Flaga variable-rate term loan (d) | — |  |  | 53.2 |
Flaga U.S. dollar variable-rate term loan (e) | — |  |  | 49.9 |
Other | 19.3 |  |  | 20.9 |
Unamortized debt issuance costs | (8.3 | ) |  | (2.5 | )
Total UGI International | 719.5 |  |  | 748.5 |
Midstream & Marketing: |  |  |
Energy Services variable-rate term loan due through August 2026 (f) | 698.3 |  |  | — |
Other | 0.3 |  |  | 0.4 |
Unamortized discount and debt issuance costs | (12.0 | ) |  | — |
Total Energy Services | 686.6 |  |  | 0.4 |
UGI Utilities: |  |  |
Senior Notes: |  |  |
4.12%, due September 2046 | 200.0 |  |  | 200.0 |
4.98%, due March 2044 | 175.0 |  |  | 175.0 |
4.55%, due February 2049 | 150.0 |  |  | — |
4.12%, due October 2046 | 100.0 |  |  | 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 |
Variable-rate term loan due through October 2022 (g) | 114.1 |  |  | 120.3 |
Other | 4.7 |  |  | 6.8 |
Unamortized debt issuance costs | (4.6 | ) |  | (4.1 | )
Total UGI Utilities | 979.2 |  |  | 838.0 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)

| 2019 |  | 2018
UGI Corporation: |  |  |
UGI Corporation revolving credit facility maturing August 2024 (h) | 300.0 |  |  | — |
UGI Corporation variable-rate term loan due August 2022 (i) | 300.0 |  |  | — |
UGI Corporation variable-rate term loan due through August 2024 (i) | 250.0 |  |  | — |
Unamortized debt issuance costs | (4.0 | ) |  | — |
Total UGI Corporation | 846.0 |  |  | — |
Other | 8.1 |  |  | 8.8 |
Total long-term debt | 5,804.0 |  |  | 4,165.3 |
Less: current maturities | (24.1 | ) |  | (18.8 | )
Total long-term debt due after one year | $ | 5,779.9 |  |  | $ | 4,146.5 |

(a) | At September 30, 2019 and 2018, the effective interest rate on the Heritage Operating, L.P. Senior Secured Notes was 6.75%. These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash.

(b) | At September 30, 2019, the effective interest rate on the term loan was approximately 2.04%.

(c) | At September 30, 2018, the effective interest rate on the term loan was approximately 1.93%.

(d) | The effective interest rate on this term loan at September 30, 2018, was 1.93%.

(e) | At September 30, 2018, the effective interest rate on this term loan was 0.55%.

(f) | The effective interest rate on this term loan at September 30, 2019, was 5.79%. This term loan is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivable and certain real property.

(g) | At September 30, 2019 and September 30, 2018, the effective interest rate on this term loan was 3.05% and 2.76%, respectively.

(h) | The effective interest rate on credit facility borrowings at September 30, 2019, was 4.55%.

(i) | At September 30, 2019, the effective interest rates on the $300 variable-rate term loan and the $250 variable-rate term loan were 4.30% and 4.55%, respectively.

Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows:

| 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024
AmeriGas Propane | $ | 7.8 |  |  | $ | 3.6 |  |  | $ | 1.6 |  |  | $ | 0.3 |  |  | $ | 675.0 |
UGI International | 0.1 |  |  | 0.1 |  |  | 19.0 |  |  | 0.1 |  |  | 327.0 |
Midstream & Marketing | 7.1 |  |  | 7.1 |  |  | 7.1 |  |  | 7.0 |  |  | 7.0 |
UGI Utilities | 8.4 |  |  | 8.0 |  |  | 6.9 |  |  | 95.5 |  |  | — |
UGI Corporation | — |  |  | — |  |  | 300.0 |  |  | 37.5 |  |  | 512.5 |
Other | 0.6 |  |  | 0.9 |  |  | 0.9 |  |  | 5.7 |  |  | — |
Total | $ | 24.0 |  |  | $ | 19.7 |  |  | $ | 335.5 |  |  | $ | 146.1 |  |  | $ | 1,521.5 |

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Credit Facilities and Short-term Borrowings
Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility, which is discussed below) as of September 30, 2019 and 2018, is presented in the following table. Borrowings outstanding under these agreements (other than the UGI Corporation Credit Agreement) 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, 2019 |  |  |  |  |  |  |  |  |  |  |  |
AmeriGas OLP |  | December 2022 |  | $ | 600.0 |  |  | $ | 328.0 |  |  | $ | 62.7 |  |  | $ | 209.3 |  |  | 4.50 | %
UGI International, LLC (a) |  | October 2023 |  | € | 300.0 |  |  | € | 192.7 |  |  | € | — |  |  | € | 107.3 |  |  | 3.64 | %
Energy Services (b) |  | March 2021 |  | $ | 200.0 |  |  | $ | 45.0 |  |  | $ | — |  |  | $ | 155.0 |  |  | 6.25 | %
UGI Utilities |  | June 2024 |  | $ | 350.0 |  |  | $ | 166.0 |  |  | $ | — |  |  | $ | 184.0 |  |  | 3.00 | %
UGI Corporation (c) |  | August 2024 |  | $ | 300.0 |  |  | $ | 300.0 |  |  | $ | — |  |  | $ | — |  |  | 4.55 | %
September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |
AmeriGas OLP |  | December 2022 |  | $ | 600.0 |  |  | $ | 232.0 |  |  | $ | 63.5 |  |  | $ | 304.5 |  |  | 4.58 | %
UGI International, LLC |  | April 2020 |  | € | 300.0 |  |  | € | — |  |  | € | — |  |  | € | 300.0 |  |  | N.A. |
UGI France |  | April 2020 |  | € | 60.0 |  |  | € | — |  |  | € | — |  |  | € | 60.0 |  |  | N.A. |
Flaga |  | October 2020 |  | € | 55.0 |  |  | € | — |  |  | € | 0.5 |  |  | € | 54.5 |  |  | N.A. |
Energy Services |  | March 2021 |  | $ | 240.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 240.0 |  |  | N.A. |
UGI Utilities |  | March 2020 |  | $ | 450.0 |  |  | $ | 189.5 |  |  | $ | 2.0 |  |  | $ | 258.5 |  |  | 3.03 | %

N.A. - Not applicable

(a) | The 2018 UGI International Credit Facilities Agreement permits UGI International, LLC to borrow in euros or dollars. At September 30, 2019, the amount borrowed was USD-denominated borrowings of $210.0, equal to €192.7.

(b) | The Energy Services Credit Agreement includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services and its subsidiaries. Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) 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 ranges from 0.75% to 2.25%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services. This credit agreement is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivables and certain real property. On August 13, 2019, the Energy Services Credit Agreement was amended to decrease its borrowing capacity from $240 to $200.

(c) | Borrowings outstanding are classified as “Long-term debt” on the 2019 Consolidated Balance Sheet. See “Significant Financing Activities - UGI Corporation” above for further information.

Accounts Receivable Securitization Facility. Energy Services has a Receivables Facility with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2020. The Receivables Facility, as amended, provides Energy Services 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 uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, 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 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 2019,
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Fiscal 2018 and Fiscal 2017, 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 2019, Fiscal 2018 and Fiscal 2017, as well as the balance of ESFC trade receivables at September 30, 2019, 2018 and 2017 follows:

|  | 2019 |  | 2018 |  | 2017
Trade receivables transferred to ESFC during the year |  | $ | 1,372.7 |  |  | $ | 1,279.5 |  |  | $ | 1,017.3 |
ESFC trade receivables sold to the bank during the year |  | $ | 179.0 |  |  | $ | 193.0 |  |  | $ | 243.0 |
ESFC trade receivables - end of year (a) |  | $ | 54.5 |  |  | $ | 65.0 |  |  | $ | 44.8 |

(a) | At September 30, 2019 and 2018, the amounts of ESFC trade receivables sold to the bank were $46.4 and $2.0, 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.
AmeriGas Propane. The AmeriGas Propane OLP 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, 2019, these restrictions did not limit the amount of Available Cash. See Note 15 for the definition of Available Cash included in the Partnership Agreement.
The Heritage Operating, L.P. 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).
UGI International. The 2018 UGI International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00.
Energy Services. The Energy Services Term Loan requires that Energy Services and subsidiaries maintain a minimum ratio of consolidated EBITDA to debt service, as defined, of 1.10 to 1.00, and not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00. During an Acquisition Period, as defined in the agreement, the maximum ratio of total indebtedness to EBITDA is increased to 4.00 to 1.00. As of September 30, 2019, Energy Services was within an Acquisition Period as defined in the agreement.
Energy Services’ Credit Agreement requires that Energy Services 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. During an Acquisition Period, as defined in the agreement, the maximum ratio of total indebtedness to EBITDA is increased to 4.00 to 1.00. As of September 30, 2019, Energy Services was within the Acquisition Period as defined in the agreement.
UGI Utilities. Certain of UGI Utilities’ Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The UGI Utilities 2019 Credit Agreement, certain of UGI Utilities’ Senior Notes and the Utilities Term Loan require UGI Utilities not to exceed a ratio of consolidated debt to consolidated total capital, as defined, of 0.65 to 1.00.
UGI Corporation. The UGI Corporation Senior Credit Facility requires that UGI maintain a ratio of consolidated EBITDA to consolidated interest expense, as defined and as calculated on a rolling four-quarter basis, above 3.50 to 1.00. In addition, UGI
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
may not exceed a ratio of consolidated net indebtedness to consolidated EBITDA, as defined and as calculated on a rolling four-quarter basis, of 4.50 to 1.00 (declining over time to 4.00 to 1.00). During an Acquisition Period, as defined by the agreement, the ratio of consolidated net indebtedness to consolidated EBITDA, as defined and as calculated on a rolling four-quarter basis, is raised to 4.875 to 1.00 (declining over time to 4.50 to 1.00). At September 30, 2019, UGI was within an Acquisition Period as defined in the agreement.
Restricted Net Assets
At September 30, 2019, 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 $2,100.
Note 7 — Income Taxes
Income before income taxes comprises the following:

| 2019 |  | 2018 |  | 2017
Domestic | $ | 329.4 |  |  | $ | 576.0 |  |  | $ | 527.3 |
Foreign | 71.1 |  |  | 278.5 |  |  | 174.1 |
Total income before income taxes | $ | 400.5 |  |  | $ | 854.5 |  |  | $ | 701.4 |

The provisions for income taxes consist of the following:

| 2019 |  | 2018 |  | 2017
Current expense (benefit): |  |  |  |  |
Federal | $ | 51.7 |  |  | $ | (2.7 | ) |  | $ | (2.7 | )
State | 14.0 |  |  | 26.0 |  |  | 14.0 |
Foreign | 69.6 |  |  | 77.6 |  |  | 56.2 |
Total current expense | 135.3 |  |  | 100.9 |  |  | 67.5 |
Deferred expense (benefit): |  |  |  |  |
Federal | 2.9 |  |  | (77.1 | ) |  | 125.8 |
State | 3.5 |  |  | 6.7 |  |  | 16.4 |
Foreign | (48.8 | ) |  | 1.9 |  |  | (31.8 | )
Investment tax credit amortization | (0.3 | ) |  | (0.3 | ) |  | (0.3 | )
Total deferred expense | (42.7 | ) |  | (68.8 | ) |  | 110.1 |
Total income tax expense | $ | 92.6 |  |  | $ | 32.1 |  |  | $ | 177.6 |

Federal income taxes for Fiscal 2019, Fiscal 2018 and Fiscal 2017 are net of foreign tax credits of $9.8, $13.0 and $40.9, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

| 2019 |  | 2018 |  | 2017
U.S. federal statutory tax rate | 21.0 | % |  | 24.5 | % |  | 35.0 | %
Difference in tax rate due to: |  |  |  |  |
Effect of tax rate changes - TJCA | 0.2 |  |  | (20.9 | ) |  | — |
Effect of tax rate changes - International | (0.5 | ) |  | (2.1 | ) |  | (4.1 | )
Noncontrolling interests not subject to tax | (2.7 | ) |  | (3.0 | ) |  | (4.3 | )
State income taxes, net of federal benefit | 3.6 |  |  | 2.9 |  |  | 2.9 |
Valuation allowance adjustments | — |  |  | 1.1 |  |  | (1.1 | )
Effects of foreign operations | 1.8 |  |  | 3.1 |  |  | (1.1 | )
Excess tax benefits on share-based payments | (1.0 | ) |  | (1.1 | ) |  | (1.3 | )
Other, net | 0.7 |  |  | (0.7 | ) |  | (0.7 | )
Effective tax rate | 23.1 | % |  | 3.8 | % |  | 25.3 | %

On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, created a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities and certain FERC-regulated property beginning in Fiscal 2019 and applied a broader application of compensation limitations.
As a result of the TCJA, we reduced our net deferred income tax liabilities in Fiscal 2018 by $384.4 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment of the TCJA on December 22, 2017. Because most of the reduction to UGI Utilities’ net deferred income taxes related to regulated utility plant assets, most of UGI Utilities’ reduction in deferred income taxes was not recognized immediately in income tax expense.
In accordance with GAAP as determined by ASC 740, we are required to record the effects of tax law changes in the period enacted. Our results for Fiscal 2018 contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During Fiscal 2019, adjustments to provisional amounts recorded in prior periods were not material.
In Fiscal 2018, we were subject to a blended federal tax rate of 24.5% because our fiscal year contained the effective date of the rate change from 35% to 21%. The effects of the tax law changes on Fiscal 2018 results (excluding the remeasurement impact described above) decreased income tax by $52.1.
In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. As a result of the TCJA, for Fiscal 2018, UGI Utilities initially recorded a net regulatory liability of $205.6 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $83.6 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 9.
As further described in Note 9, on May 17, 2018, the PAPUC issued a Temporary Rates Order for all PAPUC-regulated utilities with regard to federal tax reform. Among other things, the Temporary Rates Order required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the change in the federal income tax rate from 35% to 21%. In accordance with the Temporary Rates Order, during Fiscal 2018, UGI Utilities reduced its revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction of $24.1 primarily reflects (1) $17.1 of tax benefits accrued during the period January 1, 2018 to June 30, 2018, and (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability and accrued interest.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
In Fiscal 2018 and Fiscal 2017, earnings of the Company’s foreign subsidiaries were generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provisions reflected the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings were considered to be indefinitely reinvested. No deferred tax liability had been recognized with regard to remittance of those earnings because of the availability of U.S. foreign tax credits made it likely that no U.S. tax would be due if such earnings were repatriated. Upon enactment of the TCJA, substantially all prior unrepatriated earnings were subjected to U.S. tax under the transition tax rules. The transition tax was immaterial to the Company and we generally expect to have the ability to repatriate prior unrepatriated earnings without material U.S. federal tax cost.
Our Fiscal 2019 effective tax rate was subject to the impact of changes to the taxation of foreign source income made by the TCJA. Fiscal 2019 tax expense includes $3.8 of GILTI and Branch taxes that are treated as current period costs and carry no related deferred taxes.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2019, Fiscal 2018 and Fiscal 2017, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $7.4, $4.2 and $2.5, respectively.
Deferred tax liabilities (assets) comprise the following at September 30:

| 2019 |  | 2018
Excess book basis over tax basis of property, plant and equipment | $ | 804.5 |  |  | $ | 807.8 |
Investment in AmeriGas Partners | — |  |  | 219.2 |
Utility regulatory assets | 107.6 |  |  | 86.7 |
Intangible assets and goodwill | 70.5 |  |  | 67.6 |
Derivative instruments | — |  |  | 30.4 |
Other | 8.3 |  |  | 10.6 |
Gross deferred tax liabilities | 990.9 |  |  | 1,222.3 |
Investment in AmeriGas Partners | (303.5 | ) |  | — |
Pension plan liabilities | (49.9 | ) |  | (20.0 | )
Employee-related benefits | (43.8 | ) |  | (43.6 | )
Operating loss carryforwards | (21.2 | ) |  | (26.2 | )
Foreign tax credit carryforwards | (81.4 | ) |  | (106.1 | )
Utility regulatory liabilities | (94.3 | ) |  | (118.6 | )
Derivative instruments | (15.3 | ) |  | — |
Utility environmental liabilities | (15.3 | ) |  | (14.7 | )
Other | (33.4 | ) |  | (29.0 | )
Gross deferred tax assets | (658.1 | ) |  | (358.2 | )
Deferred tax assets valuation allowance | 90.7 |  |  | 116.8 |
Net deferred tax liabilities | $ | 423.5 |  |  | $ | 980.9 |

As a result of the AmeriGas Merger, we acquired all of the equity interests of AmeriGas Partners. In exchange for the interest acquired from the public, we issued stock and paid cash having a total implied fair value of $2,227.7. The transaction represents a taxable exchange for which we received a step-up in the tax basis in the underlying assets acquired. A gross deferred tax asset of $2,030.3 related to the book tax basis difference in this investment has been recorded through equity in accordance with ASC 810. We evaluated the realizability of the resulting net deferred tax asset position of $512.3 assessing the available positive and negative evidence. As the taxable temporary differences of the Partnership’s tax depreciation in excess of book depreciation reverses, the associated deferred taxes are expected to be fully realized.
In July 2019, the French Parliament enacted legislation retroactively increasing the corporate income tax rate for tax years beginning in 2019. As a result, the Fiscal 2020 tax rate remains at 34.43%. The impact on deferred income tax liabilities increased income tax expense by $2.4.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
In December 2017, the French Parliament approved the December 2017 French Finance Bills. One impact of the December 2017 French Finance Bills was an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the December 2017 French Finance Bills, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $12.1 to reflect the estimated impact of the corporate income tax rate reductions that will be implemented through Fiscal 2023. The Company’s Fiscal 2018 effective income tax rate reflects the impact of the higher Fiscal 2018 income tax rate in France as a result of the December 2017 French Finance Bills, which increased income tax expense for the year by approximately $0.6.
At September 30, 2019, foreign net operating loss carryforwards principally relating to Flaga and certain subsidiaries of UGI France totaled $10.0 and $22.0, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries that approximate $147.9 and expire through 2039. We also have federal operating loss carryforwards of $14.3 for certain operations of AmeriGas Propane that expire through 2036. At September 30, 2019, deferred tax assets relating to operating loss carryforwards include $2.0 for Flaga, $6.8 for certain subsidiaries of UGI France, $3.0 for AmeriGas Propane and $9.4 for certain other subsidiaries.
Valuation allowances against deferred tax assets exist for foreign tax credit carryforwards and net operating loss carryforwards of foreign subsidiaries. The valuation allowance for all deferred tax assets decreased by $26.1 in Fiscal 2019. The decrease consisted of the release of $24.8 of valuation allowances on foreign tax credits that expired in Fiscal 2019 and a decrease in foreign operating loss carryforwards of $1.3.
The valuation allowance for all deferred tax assets increased by $9.7 in Fiscal 2018 due to an increase of $7.6 to re-establish a full valuation allowance associated with future utilization of foreign tax credits, primarily due to impacts of the TCJA and an increase in foreign operating loss carryforwards of $2.1. 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 2015 tax year, our French tax returns are settled through the 2017 tax year, our Austrian tax returns are settled through 2016 and our other European tax returns are effectively settled for various years from 2010 to 2017. 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. UGI Corporation and subsidiaries’ 2017 and 2016 consolidated U.S. federal tax returns are currently under examination by the Internal Revenue Service.
As of September 30, 2019, we have unrecognized income tax benefits totaling $10.9 including related accrued interest of $1.0. If these unrecognized tax benefits were subsequently recognized, $10.9 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. The expected change in unrecognized tax benefits and related interest in the next twelve months is $2.8 as the result of the expiration of certain statutes of limitation.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

| 2019 |  | 2018 |  | 2017
Unrecognized tax benefits — beginning of year | $ | 11.5 |  |  | $ | 12.2 |  |  | $ | 7.2 |
Additions for tax positions of the current year | 0.9 |  |  | 1.5 |  |  | 1.9 |
Additions for tax positions taken in prior years | 0.4 |  |  | 0.6 |  |  | 4.6 |
Settlements with tax authorities/statute lapses | (1.9 | ) |  | (2.8 | ) |  | (1.5 | )
Unrecognized tax benefits — end of year | $ | 10.9 |  |  | $ | 11.5 |  |  | $ | 12.2 |

Note 8 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans
The U.S. Pension Plan is a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, and certain of UGI’s other domestic wholly owned subsidiaries. U.S. Pension Plan benefits are based on years of service, age and employee compensation.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to certain 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 PBOs of the U.S. Pension Plan and the UGI International pension plans, the ABOs of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2019 and 2018. 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
| 2019 |  | 2018 |  | 2019 |  | 2018
Change in benefit obligations: |  |  |  |  |  |  |
Benefit obligations — beginning of year | $ | 669.2 |  |  | $ | 697.8 |  |  | $ | 19.3 |  |  | $ | 27.0 |
Service cost | 9.8 |  |  | 11.2 |  |  | 0.2 |  |  | 0.5 |
Interest cost | 27.3 |  |  | 26.3 |  |  | 0.7 |  |  | 0.8 |
Actuarial loss (gain) | 89.0 |  |  | (37.0 | ) |  | 3.6 |  |  | (2.1 | )
Plan amendments | 0.3 |  |  | — |  |  | — |  |  | (5.8 | )
Curtailment | (1.3 | ) |  | (0.6 | ) |  | — |  |  | (0.1 | )
Settlements | (13.1 | ) |  | — |  |  | — |  |  | — |
Foreign currency | (3.1 | ) |  | (1.0 | ) |  | (0.2 | ) |  | — |
Benefits paid | (28.0 | ) |  | (27.5 | ) |  | (0.9 | ) |  | (1.0 | )
Benefit obligations — end of year | $ | 750.1 |  |  | $ | 669.2 |  |  | $ | 22.7 |  |  | $ | 19.3 |
Change in plan assets: |  |  |  |  |  |  |
Fair value of plan assets — beginning of year | $ | 563.3 |  |  | $ | 529.2 |  |  | $ | 15.3 |  |  | $ | 14.8 |
Actual gain on plan assets | 13.0 |  |  | 44.9 |  |  | 0.9 |  |  | 0.9 |
Foreign currency | (1.5 | ) |  | (0.6 | ) |  | — |  |  | — |
Employer contributions | 12.4 |  |  | 16.2 |  |  | 0.4 |  |  | 0.4 |
Settlements | (13.1 | ) |  | — |  |  | — |  |  | — |
Benefits paid | (27.3 | ) |  | (26.4 | ) |  | (0.4 | ) |  | (0.8 | )
Fair value of plan assets — end of year | $ | 546.8 |  |  | $ | 563.3 |  |  | $ | 16.2 |  |  | $ | 15.3 |
Funded status of the plans — end of year | $ | (203.3 | ) |  | $ | (105.9 | ) |  | $ | (6.5 | ) |  | $ | (4.0 | )
Assets (liabilities) recorded in the balance sheet: |  |  |  |  |  |  |
Assets in excess of liabilities — included in other noncurrent assets | $ | — |  |  | $ | — |  |  | $ | 2.8 |  |  | $ | 6.7 |
Unfunded liabilities — included in other noncurrent liabilities | (203.3 | ) |  | (105.9 | ) |  | (9.3 | ) |  | (10.7 | )
Net amount recognized | $ | (203.3 | ) |  | $ | (105.9 | ) |  | $ | (6.5 | ) |  | $ | (4.0 | )
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): |  |  |  |  |  |  |
Prior service cost (benefit) | $ | 1.3 |  |  | $ | 0.6 |  |  | $ | (1.2 | ) |  | $ | (1.3 | )
Net actuarial loss (gain) | 25.4 |  |  | 14.0 |  |  | 0.5 |  |  | (0.4 | )
Total | $ | 26.7 |  |  | $ | 14.6 |  |  | $ | (0.7 | ) |  | $ | (1.7 | )
Amounts recorded in regulatory assets and liabilities (pre-tax): |  |  |  |  |  |  |
Prior service cost (benefit) | $ | 0.5 |  |  | $ | 0.7 |  |  | $ | (0.7 | ) |  | $ | (1.2 | )

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)

| Pension Benefits |  | Other Postretirement Benefits
| 2019 |  | 2018 |  | 2019 |  | 2018
Net actuarial loss (gain) | 177.4 |  |  | 85.7 |  |  | 1.4 |  |  | (0.1 | )
Total | $ | 177.9 |  |  | $ | 86.4 |  |  | $ | 0.7 |  |  | $ | (1.3 | )

In Fiscal 2019 and Fiscal 2018, the change in the pension plans’ PBO due to actuarial gains and losses is principally the result of changes in discount rates. The change in the pension plans’ PBO in Fiscal 2019 also reflects a settlement resulting from the conversion of a defined benefit pension plan to a defined contribution plan in the Netherlands. In Fiscal 2020, we estimate that we will amortize approximately $15.0 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.3 of net prior service cost 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
| 2019 |  | 2018 |  | 2017 |  | 2019 |  | 2018 |  | 2017
Weighted-average assumptions: |  |  |  |  |  |  |  |  |  |  |
Discount rate – benefit obligations | 3.30 | % |  | 4.40 | % |  | 4.00 | % |  | 3.30 | % |  | 4.40 | % |  | 4.00 | %
Discount rate – benefit cost | 4.40 | % |  | 4.00 | % |  | 3.80 | % |  | 4.40 | % |  | 4.00 | % |  | 3.80 | %
Expected return on plan assets | 7.30 | % |  | 7.40 | % |  | 7.50 | % |  | 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 $658.5 and $572.8 as of September 30, 2019 and 2018, respectively.
The service cost component of our pension and other postretirement plans, net of amounts capitalized, are reflected in “Operating and administrative expenses” on the Consolidated Statements of Income. The non-service cost component, net of amounts capitalized by UGI Utilities as a regulatory asset, are reflected in “Other non-operating income (expense), net” on the Consolidated Statements of Income. Net periodic pension cost and other postretirement benefit cost include the following components:

| Pension Benefits |  | Other Postretirement Benefits
| 2019 |  | 2018 |  | 2017 |  | 2019 |  | 2018 |  | 2017
Service cost | $ | 9.8 |  |  | $ | 11.2 |  |  | $ | 11.9 |  |  | $ | 0.2 |  |  | $ | 0.5 |  |  | $ | 1.0 |
Interest cost | 27.3 |  |  | 26.3 |  |  | 25.0 |  |  | 0.7 |  |  | 0.8 |  |  | 0.8 |
Expected return on assets | (36.3 | ) |  | (35.0 | ) |  | (33.6 | ) |  | (0.8 | ) |  | (0.7 | ) |  | (0.7 | )
Curtailment gain | (0.4 | ) |  | (0.2 | ) |  | (1.4 | ) |  | — |  |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |  |  |  |  |
Prior service cost (benefit) | 0.3 |  |  | 0.3 |  |  | 0.3 |  |  | (0.5 | ) |  | (6.3 | ) |  | (0.6 | )
Actuarial loss (gain) | 7.8 |  |  | 13.4 |  |  | 16.7 |  |  | (0.1 | ) |  | (0.1 | ) |  | 0.3 |
Net benefit cost (benefit) | 8.5 |  |  | 16.0 |  |  | 18.9 |  |  | (0.5 | ) |  | (5.8 | ) |  | 0.8 |
Change in associated regulatory liabilities | — |  |  | — |  |  | — |  |  | (1.4 | ) |  | (0.5 | ) |  | (0.5 | )
Net benefit cost (benefit) after change in regulatory liabilities | $ | 8.5 |  |  | $ | 16.0 |  |  | $ | 18.9 |  |  | $ | (1.9 | ) |  | $ | (6.3 | ) |  | $ | 0.3 |

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. 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
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
may, at our discretion, contribute additional amounts. During Fiscal 2019, Fiscal 2018 and Fiscal 2017, we made cash contributions to the U.S. Pension Plan of $11.5, $15.1 and $11.4, respectively. The minimum required contributions in Fiscal 2020 are not expected to be material.
UGI Utilities has established a 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. We do not expect to be required to make any contributions to the VEBA during Fiscal 2020.
Expected payments for pension and other postretirement welfare benefits are as follows:

| Pension Benefits |  | Other Postretirement Benefits
Fiscal 2020 | $ | 32.7 |  |  | $ | 1.0 |
Fiscal 2021 | $ | 31.7 |  |  | $ | 1.0 |
Fiscal 2022 | $ | 33.0 |  |  | $ | 1.0 |
Fiscal 2023 | $ | 35.6 |  |  | $ | 0.9 |
Fiscal 2024 | $ | 37.2 |  |  | $ | 0.9 |
Fiscal 2025 - 2029 | $ | 204.3 |  |  | $ | 4.9 |

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. At September 30, 2019 and 2018, the PBOs of these plans, including obligations for amounts held in grantor trusts, were $52.9 and $48.3, respectively. We recorded pre-tax costs for these plans of $2.2 in Fiscal 2019, $4.3 in Fiscal 2018 (which amount includes a $2.1 settlement charge) and $3.1 in Fiscal 2017. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $9.1 and $4.3 at September 30, 2019 and 2018, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.9 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2020. During Fiscal 2019, Fiscal 2018 and Fiscal 2017, the payments the Company made with respect to the supplemental executive defined benefit retirement plans were not material. The total fair value of the grantor trust investment assets associated with the supplemental executive defined benefit retirement plans, which are included in “Other assets” on the Consolidated Balance Sheets, totaled $33.8 and $34.3 at September 30, 2019 and 2018, 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 index mutual funds 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
| 2019 |  | 2018 |  |
Equity investments: |  |  |  |  |  |  |
Domestic | 54.8 | % |  | 58.2 | % |  | 52.5 | % |  | 40.0% – 65.0%
International | 11.8 | % |  | 11.8 | % |  | 12.5 | % |  | 7.5% – 17.5%
Total | 66.6 | % |  | 70.0 | % |  | 65.0 | % |  | 60.0% – 70.0%
Fixed income funds & cash equivalents | 33.4 | % |  | 30.0 | % |  | 35.0 | % |  | 30.0% – 40.0%
Total | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
VEBA

| Actual |  | Target Asset Allocation |  | Permitted Range
| 2019 |  | 2018 |  |
Domestic equity investments | 64.9 | % |  | 65.6 | % |  | 65.0 | % |  | 60.0% – 70.0%
Fixed income funds & cash equivalents | 35.1 | % |  | 34.4 | % |  | 35.0 | % |  | 30.0% – 40.0%
Total | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  |

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and mid- and small-cap index mutual funds. 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 8.5% of U.S. Pension Plan assets at September 30, 2019 and 2018, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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, 2019 and 2018 are as follows:

| U.S. Pension Plan
| Level 1 |  | Level 2 |  | Level 3 |  | Other(a) |  | Total
September 30, 2019: |  |  |  |  |  |  |  |  |
Domestic equity investments: |  |  |  |  |  |  |  |  |
S&P 500 Index equity mutual funds | $ | 176.4 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 176.4 |
Small and midcap equity mutual funds | 72.8 |  |  | — |  |  | — |  |  | — |  |  | 72.8 |
UGI Corporation Common Stock | 40.9 |  |  | — |  |  | — |  |  | — |  |  | 40.9 |
Total domestic equity investments | 290.1 |  |  | — |  |  | — |  |  | — |  |  | 290.1 |
International index equity mutual funds | 62.1 |  |  | — |  |  | — |  |  | — |  |  | 62.1 |
Fixed income investments: |  |  |  |  |  |  |  |  |
Bond index mutual funds | 170.5 |  |  | — |  |  | — |  |  | — |  |  | 170.5 |
Cash equivalents | — |  |  | — |  |  | — |  |  | 6.4 |  |  | 6.4 |
Total fixed income investments | 170.5 |  |  | — |  |  | — |  |  | 6.4 |  |  | 176.9 |
Total | $ | 522.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 6.4 |  |  | $ | 529.1 |
September 30, 2018: |  |  |  |  |  |  |  |  |
Domestic equity investments: |  |  |  |  |  |  |  |  |
S&P 500 Index equity mutual funds | $ | 188.4 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 188.4 |
Small and midcap equity mutual funds | 75.7 |  |  | — |  |  | — |  |  | — |  |  | 75.7 |
UGI Corporation Common Stock | 45.2 |  |  | — |  |  | — |  |  | — |  |  | 45.2 |
Total domestic equity investments | 309.3 |  |  | — |  |  | — |  |  | — |  |  | 309.3 |
International index equity mutual funds | 62.9 |  |  | — |  |  | — |  |  | — |  |  | 62.9 |
Fixed income investments: |  |  |  |  |  |  |  |  |
Bond index mutual funds | 154.3 |  |  | — |  |  | — |  |  | — |  |  | 154.3 |
Cash equivalents | — |  |  | — |  |  | — |  |  | 5.2 |  |  | 5.2 |
Total fixed income investments | 154.3 |  |  | — |  |  | — |  |  | 5.2 |  |  | 159.5 |
Total | $ | 526.5 |  |  | $ | — |  |  | $ | — |  |  | $ | 5.2 |  |  | $ | 531.7 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)

| VEBA
| Level 1 |  | Level 2 |  | Level 3 |  | Other(a) |  | Total
September 30, 2019: |  |  |  |  |  |  |  |  |
S&P 500 Index equity mutual fund | $ | 10.5 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 10.5 |
Bond index mutual fund | 5.5 |  |  | — |  |  | — |  |  | — |  |  | 5.5 |
Cash equivalents | — |  |  | — |  |  | — |  |  | 0.2 |  |  | 0.2 |
Total | $ | 16.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 0.2 |  |  | $ | 16.2 |
September 30, 2018: |  |  |  |  |  |  |  |  |
S&P 500 Index equity mutual fund | $ | 10.1 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 10.1 |
Bond index mutual fund | 4.9 |  |  | — |  |  | — |  |  | — |  |  | 4.9 |
Cash equivalents | — |  |  | — |  |  | — |  |  | 0.3 |  |  | 0.3 |
Total | $ | 15.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 0.3 |  |  | $ | 15.3 |

(a) | Assets measured at 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 $19.3 in Fiscal 2019, $17.1 in Fiscal 2018 and $15.1 in Fiscal 2017. 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 2019, Fiscal 2018 and Fiscal 2017 were not material. At September 30, 2019 and 2018, the total fair values of these grantor trust investment assets, which amounts are included in “Other assets” on the Consolidated Balance Sheets, were $5.9 and $6.5, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 9 — 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:

| 2019 |  | 2018
Regulatory assets: |  |  |
Income taxes recoverable | $ | 115.2 |  |  | $ | 110.1 |
Underfunded pension and postretirement plans | 178.6 |  |  | 87.1 |
Environmental costs | 59.5 |  |  | 58.8 |
Removal costs, net | 28.3 |  |  | 32.0 |
Other | 14.0 |  |  | 13.0 |
Total regulatory assets | $ | 395.6 |  |  | $ | 301.0 |
Regulatory liabilities (a): |  |  |
Postretirement benefit overcollections | $ | 14.5 |  |  | $ | 17.8 |
Deferred fuel and power refunds | 6.1 |  |  | 36.7 |
State income tax benefits — distribution system repairs | 25.0 |  |  | 22.6 |
PAPUC Temporary Rates Order | 31.3 |  |  | 24.4 |
Excess federal deferred income taxes | 279.5 |  |  | 285.2 |
Other | 2.4 |  |  | 3.5 |
Total regulatory liabilities | $ | 358.8 |  |  | $ | 390.2 |

(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 Gas Utility expects to incur, primarily at MGP sites in Pennsylvania, in conjunction with remediation COAs with the PADEP. Pursuant to base rate orders, Gas Utility receives ratemaking recognition of its estimated environmental investigation and remediation costs associated with 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, 2019, the period over which Gas Utility expects to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 16.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PAPUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, Gas Utility expects to recover these costs over five years.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by Gas Utility and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to Gas Utility, postretirement benefit overcollections are generally being refunded to customers over a ten-year period beginning October 19, 2016. With respect to Electric Utility, the overcollections are being refunded to ratepayers over a 20-year period beginning October 27, 2018.
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 PGC rates in the case of Gas Utility and DS tariffs in the case of Electric Utility. These 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 retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel and power costs or refunds. Net unrealized (losses) gains on such contracts at September 30, 2019 and 2018 were $(2.2) and $2.9, respectively.
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 that 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.
PAPUC Temporary Rates Order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates to credit customers any tax savings as a result of the TCJA through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. In accordance with the terms of the Temporary Rates Order, the initial temporary negative surcharge was reconciled at the end of Fiscal 2018 to reflect the difference in the amount of bill credit received by customers and the amount of benefits received by the Company through the fiscal year end period and updated negative surcharges were placed in effect on January 1, 2019 at rates of 4.71%, 2.87% and 6.34%, respectively, for the UGI South, UGI North and UGI Central rate districts (as described below). These negative surcharges remained in effect until October 11, 2019, the effective date of Gas Utility’s new base rates.
In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability is addressed in Gas Utility’s base rate proceeding filed January 28, 2019 (see “Base Rate Filings” below).
For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applied. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below) were refunded to Electric Utility ratepayers through a one-time bill credit.
Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 7). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to tax expense.
Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, over or under refunds of tax benefits related to the TCJA for periods after June 30, 2018, certain information technology costs, energy efficiency conservation costs and rate case expenses.
Other Regulatory Matters
Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged with and into UGI Utilities effective October 1, 2018. Consistent with the MDPSC Order issued July 25, 2018, and the PAPUC Order issued September 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 28, 2019, the merged Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial, and industrial customers throughout its Pennsylvania service territory by an aggregate $71.1. As part of this rate request, Gas Utility also proposed to create uniform class rates under a single tariff such that all members of each customer class, throughout a consolidated UGI Gas service territory, would be charged the same base distribution and purchased gas cost rates, and other surcharges, eliminating the need to maintain the former UGI North, UGI South, and UGI Central rate districts formed as part of the earlier merger. In its initial filing, Gas Utility proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return to ratepayers $24.0 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 PAPUC Order. On October 4, 2019, the PAPUC issued a final Order approving a settlement that permits Gas Utility, effective October 11, 2019, to increase its base distribution revenues by $30.0 under a single tariff, approved a plan for uniform class rates, and permits the Company to extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years. The PAPUC’s final Order approved the negative surcharge, mentioned above, which became effective for a twelve-month period beginning on October 11, 2019.
On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2, which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final Order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final PAPUC Order, Electric Utility provided customers with a one-time $0.2 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. UGI Utilities cannot predict the ultimate outcome of this appeal.
On August 31, 2017, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 base distribution rate increase for PNG (now part of the consolidated UGI Gas service territory). The increase became effective on October 20, 2017.
Note 10 — Inventories
Inventories comprise the following at September 30:

| 2019 |  | 2018
Non-utility LPG and natural gas | $ | 150.2 |  |  | $ | 231.7 |
Gas Utility natural gas | 26.6 |  |  | 37.3 |
Materials, supplies and other | 53.1 |  |  | 49.2 |
Total inventories | $ | 229.9 |  |  | $ | 318.2 |

At September 30, 2019, UGI Utilities was a party to four SCAAs with terms up to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain natural gas storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated natural gas 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, 2019, all of UGI Utilities’ SCAAs were with Energy Services, the effects of which are eliminated in consolidation. The carrying value of gas storage inventories released under the SCAAs with a non-affiliate at September 30, 2018, comprising 2.3 bcf of natural gas, was $5.4.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 11 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:

| 2019 |  | 2018
Utility: |  |  |
Distribution | $ | 3,366.2 |  |  | $ | 3,106.6 |
Transmission | 106.0 |  |  | 97.1 |
General and other | 389.3 |  |  | 281.7 |
Work in process | 76.6 |  |  | 130.9 |
Total Utility | 3,938.1 |  |  | 3,616.3 |
Non-utility: |  |  |
Land | 183.5 |  |  | 191.4 |
Buildings and improvements | 403.8 |  |  | 364.9 |
Transportation equipment | 258.3 |  |  | 257.1 |
Equipment, primarily cylinders and tanks | 3,455.2 |  |  | 3,375.4 |
Electric generation | 326.9 |  |  | 319.5 |
Pipeline and related assets | 1,150.2 |  |  | 473.0 |
Other | 255.3 |  |  | 306.6 |
Work in process | 101.7 |  |  | 57.9 |
Total non-utility | 6,134.9 |  |  | 5,345.8 |
Total property, plant and equipment | $ | 10,073.0 |  |  | $ | 8,962.1 |

Note 12 — 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, 2017 | $ | 2,001.3 |  |  | $ | 912.2 |  |  | $ | 11.6 |  |  | $ | 182.1 |  |  | $ | 3,107.2 |
Acquisitions | 4.5 |  |  | 54.9 |  |  | — |  |  | — |  |  | 59.4 |
Dispositions | (2.8 | ) |  | — |  |  | — |  |  | — |  |  | (2.8 | )
Purchase accounting adjustments | — |  |  | 13.6 |  |  | — |  |  | — |  |  | 13.6 |
Foreign currency translation | — |  |  | (17.0 | ) |  | — |  |  | — |  |  | (17.0 | )
Balance September 30, 2018 | 2,003.0 |  |  | 963.7 |  |  | 11.6 |  |  | 182.1 |  |  | 3,160.4 |
Acquisitions | — |  |  | 25.6 |  |  | 329.9 |  |  | — |  |  | 355.5 |
Foreign currency translation | — |  |  | (59.5 | ) |  | — |  |  | — |  |  | (59.5 | )
Balance September 30, 2019 | $ | 2,003.0 |  |  | $ | 929.8 |  |  | $ | 341.5 |  |  | $ | 182.1 |  |  | $ | 3,456.4 |

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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Intangible assets comprise the following at September 30:

| 2019 |  | 2018
Customer relationships | $ | 1,038.4 |  |  | $ | 790.4 |
Trademarks and tradenames | 16.2 |  |  | 7.9 |
Noncompete agreements and other | 46.4 |  |  | 58.2 |
Accumulated amortization | (441.8 | ) |  | (393.2 | )
Intangible assets, net (definite-lived) | 659.2 |  |  | 463.3 |
Trademarks and tradenames (indefinite-lived) | 49.4 |  |  | 50.3 |
Total intangible assets, net | $ | 708.6 |  |  | $ | 513.6 |

The increase in the gross carrying amount of intangible assets in Fiscal 2019 is due to acquisitions partially offset by the effects of currency translation. Amortization expense of intangible assets was $59.6, $58.6 and $50.8 for Fiscal 2019, Fiscal 2018 and Fiscal 2017, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2020 — $64.6; Fiscal 2021 — $61.4; Fiscal 2022 — $58.3; Fiscal 2023 — $56.8; Fiscal 2024 — $55.6.
In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over a period of approximately three years. As a result, during the third quarter of Fiscal 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9. During the third quarter of Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. See Note 17 for further information on the determination of fair values for the affected tradenames and trademarks.
Note 13 — 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. UGI had no shares of UGI Series Preferred Stock outstanding at September 30, 2019 or 2018.
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, 2019 and 2018, there were no shares of UGI Utilities Series Preferred Stock outstanding.
Note 14 — Common Stock and Equity-Based Compensation
Common Stock
On January 25, 2018, UGI’s Board of Directors approved an extension of the Company’s share repurchase program, which authorizes the repurchase of up to 8,000,000 shares of UGI Corporation Common Stock over a four-year period. Pursuant to these authorizations, during Fiscal 2019, Fiscal 2018 and Fiscal 2017, the Company purchased and placed in treasury stock 300,000, 1,200,000 and 900,000 shares at a total cost of $16.9, $59.8 and $43.3, respectively.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
UGI Common Stock share activity for Fiscal 2017, Fiscal 2018 and Fiscal 2019 follows:

| Issued |  | Treasury |  | Outstanding
Balance at 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 at September 30, 2017 | 173,987,691 |  |  | (843,954 | ) |  | 173,143,737 |
Issued: |  |  |  |  |
Employee and director plans | 155,306 |  |  | 1,804,712 |  |  | 1,960,018 |
Repurchases of common stock | — |  |  | (1,200,000 | ) |  | (1,200,000 | )
Reacquired common stock – employee and director plans | — |  |  | (154,780 | ) |  | (154,780 | )
Balance at September 30, 2018 | 174,142,997 |  |  | (394,022 | ) |  | 173,748,975 |
Issued: |  |  |  |  |
Employee and director plans | 548,285 |  |  | 430,847 |  |  | 979,132 |
AmeriGas Merger | 34,612,847 |  |  | — |  |  | 34,612,847 |
Sale of reacquired common stock | — |  |  | 15,759 |  |  | 15,759 |
Repurchases of common stock | — |  |  | (300,000 | ) |  | (300,000 | )
Reacquired common stock – employee and director plans | — |  |  | (51,924 | ) |  | (51,924 | )
Balance at September 30, 2019 | 209,304,129 |  |  | (299,340 | ) |  | 209,004,789 |

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, prior to the AmeriGas Merger, AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $18.1 ($13.2 after-tax), $22.5 ($15.7 after-tax) and $19.3 ($11.8 after-tax) in Fiscal 2019, Fiscal 2018 and Fiscal 2017, respectively.
UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2013 OICP, we may grant options to acquire shares of UGI Common Stock, 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 unvested grant 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 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 UGI France 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. Beginning in Fiscal 2019, we began issuing shares of UGI Common Stock to satisfy substantially all option exercises and UGI Unit Awards. Prior to Fiscal 2019, we issued 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 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. Pursuant to the AmeriGas Merger Agreement, all holders of AmeriGas Partners equity-based compensation awards received replacement awards comprising UGI cash-settled restricted
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
stock units. See discussion below under “AmeriGas Partners Equity-Based Compensation Plans and Awards” for additional information.
UGI Stock Option Awards. Stock option transactions under equity-based compensation plans during Fiscal 2017, Fiscal 2018 and Fiscal 2019 follow:

| Shares |  | Weighted - Average Option Price |  | Total Intrinsic Value |  | Weighted - Average Contract Term (Years)
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
Granted | 1,401,400 |  |  | $ | 47.85 |  |  |  |  |
Canceled | (152,017 | ) |  | $ | 42.14 |  |  |  |  |
Expired | (1,666 | ) |  | $ | 35.80 |  |  |  |  |
Exercised | (1,832,396 | ) |  | $ | 26.00 |  |  | $ | 44.5 |  |  |
Shares under option — September 30, 2018 | 8,197,069 |  |  | $ | 33.93 |  |  | $ | 176.6 |  |  | 6.2
Granted | 1,197,100 |  |  | $ | 53.27 |  |  |  |  |
Canceled | (123,012 | ) |  | $ | 48.69 |  |  |  |  |
Expired | (13,699 | ) |  | $ | 47.49 |  |  |  |  |
Exercised | (779,353 | ) |  | $ | 25.75 |  |  | $ | 22.8 |  |  |
Shares under option — September 30, 2019 | 8,478,105 |  |  | $ | 37.18 |  |  | $ | 114.9 |  |  | 5.9
Options exercisable — September 30, 2017 | 5,973,668 |  |  | $ | 25.53 |  |  |  |  |
Options exercisable — September 30, 2018 | 5,498,330 |  |  | $ | 28.63 |  |  |  |  |
Options exercisable — September 30, 2019 | 5,963,530 |  |  | $ | 32.02 |  |  | $ | 109.3 |  |  | 4.9
Options not exercisable — September 30, 2019 | 2,514,575 |  |  | $ | 49.43 |  |  | $ | 5.6 |  |  | 7.4

Cash received from stock option exercises and associated tax benefits were $19.5 and $5.1, $43.4 and $12.6, and $17.7 and $9.6 in Fiscal 2019, Fiscal 2018 and Fiscal 2017, respectively. As of September 30, 2019, there was $8.3 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.0 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2019:

| Range of exercise prices
| Under $30.00 |  | $30.00 – $35.00 |  | $35.01 – $40.00 |  | $40.01 – $45.00 |  | Over $45.00
Options outstanding at September 30, 2019: |  |  |  |  |  |  |  |  |
Number of options | 2,879,501 |  |  | 1,094,763 |  |  | 870,115 |  |  | 81,593 |  |  | 3,552,133 |
Weighted average remaining contractual life (in years) | 3.1 |  |  | 6.1 |  |  | 5.3 |  |  | 7.1 |  |  | 8.3 |
Weighted average exercise price | $ | 23.24 |  |  | $ | 33.66 |  |  | $ | 37.81 |  |  | $ | 44.42 |  |  | $ | 49.25 |
Options exercisable at September 30, 2019: |  |  |  |  |  |  |  |  |
Number of options | 2,879,501 |  |  | 995,313 |  |  | 870,115 |  |  | 76,593 |  |  | 1,142,008 |
Weighted average exercise price | $ | 23.24 |  |  | $ | 33.65 |  |  | $ | 37.81 |  |  | $ | 44.48 |  |  | $ | 47.48 |

UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $8.70 in Fiscal 2019, $7.51 in Fiscal 2018 and $7.62 in Fiscal 2017. These amounts were determined using a Black-Scholes option pricing model that 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.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 2019, Fiscal 2018 and Fiscal 2017 are as follows:

| 2019 |  | 2018 |  | 2017
Expected life of option | 6 years |  | 6 years |  | 5.75 years
Weighted average volatility | 17.2% |  | 17.5% |  | 19.8%
Weighted average dividend yield | 1.8% |  | 2.1% |  | 2.1%
Expected volatility | 17.2% |  | 17.5% |  | 19.8%
Expected dividend yield | 1.8% |  | 2.1% |  | 2.1%
Risk free rate | 1.5% – 2.6% |  | 2.2% – 2.9% |  | 1.8% – 2.1%

UGI Unit Awards. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of UGI 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 TSR percentile rank relative to the UGI comparator group. 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%. 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, 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 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
| 2019 |  | 2018 |  | 2017
Risk free rate | 2.5% |  | 2.0% |  | 1.5%
Expected life | 3 years |  | 3 years |  | 3 years
Expected volatility | 17.7% |  | 18.9% |  | 18.9%
Dividend yield | 1.9% |  | 2.1% |  | 2.1%

The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $55.40 for Units granted in Fiscal 2019, $55.26 for Units granted in Fiscal 2018 and $50.91 for Units granted in Fiscal 2017.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table summarizes UGI Unit award activity for Fiscal 2019:

| UGI Units |  | Weighted-Average Grant-Date Fair Value (per Unit)
Total UGI Units at September 30, 2018 (a) | 959,718 |  |  | $ | 32.38 |
UGI Performance Units: |  |  |
Granted | 128,910 |  |  | $ | 55.40 |
Forfeited | (13,102 | ) |  | $ | 53.29 |
Unit awards paid | (144,521 | ) |  | $ | 34.62 |
UGI Stock Units: |  |  |
Granted (b) | 29,784 |  |  | $ | 55.39 |
Forfeited | (4,900 | ) |  | $ | 51.22 |
Unit awards paid | (62,069 | ) |  | $ | 25.12 |
Total UGI Units at September 30, 2019 (a) | 893,820 |  |  | $ | 36.39 |

(a) | Total UGI Units includes UGI Stock Units issued to non-employee directors, which vest on the grant date, and UGI Performance Units and UGI Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2019 and September 30, 2018 were 616,319 and 660,795, respectively.

(b) | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2018 and Fiscal 2017 were 52,314 and 42,079, respectively.

During Fiscal 2019, Fiscal 2018 and Fiscal 2017, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:

| 2019 |  | 2018 |  | 2017
UGI Performance Unit awards: |  |  |  |  |
Number of original awards granted, net of forfeitures | 144,521 |  |  | 136,621 |  |  | 178,450 |
Performance period beginning January 1: | 2016 |  |  | 2015 |  |  | 2014 |
Payment of awards: |  |  |  |  |
Shares of UGI Common Stock issued, net of shares withheld for taxes | 116,950 |  |  | 69,680 |  |  | 138,985 |
Cash paid | $ | 9.9 |  |  | $ | 1.6 |  |  | $ | 10.9 |
UGI Stock Unit awards: |  |  |  |  |
Number of original awards granted, net of forfeitures | 50,985 |  |  | 39,680 |  |  | 43,699 |
Payment of awards: |  |  |  |  |
Shares of UGI Common Stock issued, net of shares withheld for taxes | 43,479 |  |  | 29,095 |  |  | 15,990 |
Cash paid | $ | 1.0 |  |  | $ | 0.6 |  |  | $ | 0.3 |

During Fiscal 2019, Fiscal 2018 and Fiscal 2017, we granted UGI Unit awards representing 158,694, 196,114 and 185,379 shares, respectively, having weighted-average grant date fair values per Unit of $55.40, $53.36 and $50.08, respectively.
As of September 30, 2019, there was a total of approximately $7.6 of unrecognized compensation cost associated with 893,820 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years. The total grant-date fair values of UGI Units that vested during Fiscal 2019, Fiscal 2018 and Fiscal 2017 were $4.9, $7.3 and $7.1, respectively. As of September 30, 2019 and 2018, total liabilities of $10.2 and $18.8, respectively, associated with UGI Unit awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.
At September 30, 2019, 8,700,734 shares of Common Stock were available for future grants under the 2013 OICP, which includes the number of AmeriGas Common Units available for grant under the 2010 Propane Plan that were converted to UGI Units as further described below.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
AmeriGas Partners Equity-Based Compensation Plans and Awards. Prior to the AmeriGas Merger, under the 2010 Propane Plan on behalf of AmeriGas Partners, L.P., the General Partner could award to employees and non-employee directors of the General Partner 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 that, depending on the award, vested immediately or ratable over a period of time. Under the terms of the 2010 Propane Plan, each unvested grant generally terminated when the participant ceased to be employed (except in the event of retirement, death or disability, as defined). The 2010 Propane Plan also defined certain change of control and retirement eligibility conditions that, if met, generally resulted in accelerated vesting or elimination of further service requirements. Participants were eligible to receive Common Unit distribution equivalents under the terms of certain awards (ultimately paid in cash only on awards that vested). Effective with the AmeriGas Merger, all outstanding AmeriGas Stock Units and AmeriGas Performance Units were canceled and converted to cash-settled restricted stock units relating to UGI Common Stock (see “Impact of AmeriGas Merger on AmeriGas Unit Awards” below).
AmeriGas Stock Unit and AmeriGas Performance Unit awards entitled the grantee to AmeriGas Partners Common Units or cash once the service condition was met and, with respect to AmeriGas Performance Units, subject to market performance conditions or actual net customer acquisition and retention performance (as defined in the applicable awards). Recipients were awarded a target number of AmeriGas Performance Units, and the number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years) could have been higher or lower than the target number, or it may have been zero. For that portion of Performance Unit awards whose ultimate payout was based upon market-based conditions (“AmeriGas TUR Performance Units”), the number of awards ultimately paid was based upon AmeriGas Partners’ TUR percentile rank relative to entities in the Tortoise MLP Group for those awards granted on or after January 1, 2019, and AmeriGas Partners’ TUR percentile rank relative to entities in the Alerian MLP Group with certain awards subject to modification as described below for those awards granted prior to January 1, 2019. AmeriGas TUR Performance Unit awards provided various performance target tiers ranging from 0% to 200%, with 0% payment when the AmeriGas Partners’ TUR was below the 25th percentile and up to 200% payment at the 90th percentile or above. The actual amount of the award was interpolated between the percentile rankings of each performance target tier. For AmeriGas TUR Performance Unit awards granted on or after January 1, 2015, but prior to January 1, 2019, the number of AmeriGas TUR Performance Units ultimately paid was based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group (0% to 200% as described above) as modified by AmeriGas Partners’ performance relative to the Propane MLP Group. Such modification ranged from 70% to 130%, but in no event did the amount ultimately paid, after such modification, exceed 200% of the target award. Pursuant to the terms of the AmeriGas Merger Agreement, the performance periods for AmeriGas TUR Performance Units outstanding immediately prior to the AmeriGas Merger ended on August 20, 2019, the last trading day of the Common Units prior to the completion of the AmeriGas Merger.
Under GAAP, AmeriGas TUR Performance Units awards were recorded as equity awards to the extent they were to be settled in Common Units. This resulted in the recognition of compensation cost equal to the fair value of such award estimated using a Monte Carlo valuation model, over the requisite employee service period regardless of whether the market-based conditions were satisfied. The fair value associated with the target awards, which were to be paid in Common Units, was accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents, which were to be paid in cash, was accounted for as a liability. For purposes of valuing AmeriGas TUR Performance Unit awards, expected volatility was based on the historical volatility of Common Units over a three-year period. The risk-free interest rate was based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the peer group was based on historical volatility. The expected term of the AmeriGas TUR Performance Unit awards was three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout was based upon net customer acquisition and retention performance measures were recorded as expense if it became probable that all or a portion of the award would be paid. The fair value associated with the target award was the market price of the Common Units on the date of grant and was accounted for as equity. The fair value of the award over the target, as well as all Common Unit distribution equivalents, which were to be paid in cash, was 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
| 2019 |  | 2018 |  | 2017
Risk-free rate | 2.5% |  | 2.0% |  | 1.5%
Expected life | 3 years |  | 3 years |  | 3 years
Expected volatility | 22.4% |  | 21.1% |  | 21.7%
Dividend yield | 12.5% |  | 8.2% |  | 7.8%

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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The General Partner granted awards under the 2010 Propane Plan representing 133,098, 84,811 and 67,563 Common Units in Fiscal 2019, Fiscal 2018 and Fiscal 2017, respectively, having weighted-average grant date fair values per Common Unit subject to award of $30.58, $50.05 and $52.37, respectively.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2019:

| AmeriGas Partners Common Units |  | Weighted-Average Grant-Date Fair Value (per Unit)
Total Units at September 30, 2018 (a) | 236,762 |  |  | $ | 47.12 |
AmeriGas Performance Units: |  |  |
Granted | 79,980 |  |  | $ | 30.23 |
Forfeited | (42,916 | ) |  | $ | 46.83 |
Awards paid | (17,133 | ) |  | $ | 43.02 |
Performance criteria not met | (29,394 | ) |  | $ | 34.27 |
AmeriGas Stock Units: |  |  |
Granted | 53,118 |  |  | $ | 31.10 |
Forfeited | (800 | ) |  | $ | 45.30 |
Awards paid | (16,056 | ) |  | $ | 40.98 |
Total Units at the date of AmeriGas Merger (a) | 263,561 |  |  | $ | 40.89 |
Units converted to UGI cash-settled restricted units | (263,561 | ) |  | $ | (40.89 | )
Total Units at September 30, 2019 | — |  |  | $ | — |

(a) | Total units includes AmeriGas Stock Units issued to non-employee directors, which vested on the grant date, and AmeriGas Performance Units and AmeriGas Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2018 were 71,148.

During Fiscal 2019, Fiscal 2018 and Fiscal 2017, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:

| 2019 |  | 2018 |  | 2017
AmeriGas Performance Unit awards: |  |  |  |  |
Number of Common Units subject to original awards granted, net of forfeitures | 52,495 |  |  | 65,525 |  |  | 53,800 |
Performance periods beginning in fiscal year: | 2016 |  |  | 2015 |  |  | 2014 |
Payment of awards: |  |  |  |  |
AmeriGas Partners Common Units issued, net of units withheld for taxes | 10,902 |  |  | 13,164 |  |  | 29,489 |
Cash paid | $ | 0.8 |  |  | $ | 1.2 |  |  | $ | 2.9 |
AmeriGas Stock Unit awards: |  |  |  |  |
Number of Common Units subject to original awards granted, net of forfeitures | 20,585 |  |  | 14,811 |  |  | 32,658 |
Payment of awards: |  |  |  |  |
AmeriGas Partners Common Units issued, net of units withheld for taxes | 9,706 |  |  | 5,322 |  |  | 3,932 |
Cash paid | $ | 0.2 |  |  | $ | 0.1 |  |  | $ | 0.1 |

The total grant-date fair values of AmeriGas Unit awards that vested during Fiscal 2019, Fiscal 2018 and Fiscal 2017 were $0.9, $2.2 and $2.1, respectively. As of September 30, 2018, total liabilities of $2.3 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheet.
Impact of AmeriGas Merger on AmeriGas Unit Awards. Effective with the AmeriGas Merger on August 21, 2019, each outstanding award of AmeriGas Stock Units and AmeriGas Performance Units, including awards subject to market performance conditions,
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
was canceled and converted into a number of cash-settled restricted stock units relating to UGI Common Stock determined by multiplying the number of such AmeriGas Unit awards by 0.6378.
With respect to outstanding AmeriGas TUR Performance Units, the number of such awards canceled and converted to UGI restricted stock units was determined by multiplying the target number of such awards times the performance multiplier as determined based upon a shortened performance period ending August 20, 2019, the last full trading day of the Common Units prior to the AmeriGas Merger. In accordance with the AmeriGas Merger Agreement, the resulting number of cash-settled restricted stock units relating to UGI Common Stock could be more, but not less, than the associated target number of AmeriGas TUR Performance Unit awards. These restricted stock units vest on the originally scheduled AmeriGas TUR Performance Unit award vesting dates with the only condition being employment with the Company at the time of vesting.
With respect to AmeriGas Performance Unit awards whose payout was based upon net customer gain and retention performance, grantees’ target awards were canceled and converted to UGI cash-settled performance-based restricted units at a ratio of 0.6378:1. Grantees of such awards may ultimately receive from 0% to 200% of the replacement awards based upon actual net customer gain and retention performance over the original three-year performance period.
The converted awards remain subject to the same terms, conditions and restrictions as applied to the corresponding AmeriGas Unit awards immediately prior to the conversion including vesting terms, forfeitures, and distribution equivalent rights except that distribution equivalent rights will be based upon UGI dividends subsequent to the conversion.
Pursuant to the terms of the AmeriGas Unit conversions described above, effective on August 21, 2019, 137,472 AmeriGas Performance Units and 126,089 AmeriGas Stock Units were converted into 215,957 of cash-settled restricted stock units relating to UGI Common Stock.
The UGI cash-settled restricted stock units issued as replacement awards, other than those issued to AmeriGas’ independent board directors who terminated their directorship effective with the AmeriGas Merger, have been accounted for as modifications in accordance with ASC 718 which contemplates an exchange of the original award for a new award. Since the modifications changed the fixed portion of the award from an equity to a cash-settled award, any compensation expense related to an increase in the fair value of the award between the original grant date and the modification date was accounted for as equity. All compensation expense on the replacement awards recognized subsequent to the modification will be accounted for as a liability.
The AmeriGas independent board members who terminated their directorship on August 21, 2019, received a cash payment based upon the market price of UGI Common Stock on that date, plus accrued distribution equivalents, totaling $1.8. These payments were accounted for as settlements in accordance with ASC 718.
All amounts accrued with respect to dividend equivalents relating to AmeriGas equity-compensation awards were carried over to the corresponding UGI replacement awards and will be paid, or forfeited, on the same terms and conditions as applied under the AmeriGas Unit awards. Holders of UGI replacement awards will receive a cash payment at the end of the performance period associated with such awards equal to the market price of UGI Common Stock plus any accumulated distribution or dividend equivalents, if applicable.
As of September 30, 2019, there was a total of approximately $2.4 of unrecognized compensation cost associated with 212,896 UGI cash-settled restricted stock units that is expected to be recognized over a weighted-average period of 1.3 years. As of September 30, 2019, total liabilities of $4.6 associated with UGI cash-settled restricted stock units are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheet.
UGI has assumed the obligations of the General Partner and the Partnership under the 2010 Propane Plan, and the 2010 Propane Plan was deemed amended to conform to all of the terms and form of the 2013 OICP and combined with the 2013 OICP. The number of Common Units that remain available for grant under the 2010 Propane Plan were converted to 1,420,949 UGI awards available for future grant and delivery based upon a conversion ratio of 0.6378:1. These available converted awards may be granted only to those individuals who were eligible to receive awards under the 2010 Propane Plan immediately before the AmeriGas Merger including any such eligible individuals hired after the AmeriGas Merger.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 15 — Partnership Distributions
In accordance with the Partnership Agreement, 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 is generally defined as:

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.
Prior to the AmeriGas Merger, distributions of Available Cash were 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 exceeded 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 exceeded $0.605 per Common Unit in any quarter, the General Partner would 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 exceeded $0.605.
During Fiscal 2019 (prior to the AmeriGas Merger), Fiscal 2018 and Fiscal 2017, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2019, Fiscal 2018 and Fiscal 2017, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $54.9, $54.9 and $52.7, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2019, Fiscal 2018 and Fiscal 2017 of $45.7, $45.3 and $43.5, respectively.
Note 16 — 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 $115.1 in Fiscal 2019, $106.2 in Fiscal 2018 and $99.5 in Fiscal 2017.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:

| 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | After 2024
AmeriGas Propane | $ | 82.1 |  |  | $ | 71.6 |  |  | $ | 60.0 |  |  | $ | 52.3 |  |  | $ | 45.0 |  |  | $ | 94.8 |
UGI Utilities | 1.2 |  |  | 0.5 |  |  | 0.4 |  |  | 0.3 |  |  | 0.3 |  |  | — |
UGI International | 12.9 |  |  | 10.0 |  |  | 7.0 |  |  | 5.7 |  |  | 5.1 |  |  | 6.5 |
Other | 4.2 |  |  | 3.8 |  |  | 3.6 |  |  | 3.4 |  |  | 3.2 |  |  | 37.9 |
Total | $ | 100.4 |  |  | $ | 85.9 |  |  | $ | 71.0 |  |  | $ | 61.7 |  |  | $ | 53.6 |  |  | $ | 139.2 |

Contingencies
Environmental Matters
UGI Utilities
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 gas and electric operations. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018.
Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is 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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap (i.e. minimum expenditure threshold). The cost cap of the three COAs, in the aggregate, is $5.4. The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At September 30, 2019 and 2018, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50.4 and $51.0, respectively. UGI Utilities has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 9).
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 receives 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, 2019 and 2018, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.
AmeriGas Propane
AmeriGas OLP Saranac Lake. In 2008, the NYDEC notified AmeriGas OLP that the NYDEC 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 NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention it was a PRP as it did not operate the MGP and appeared to only own a portion of the site. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s purported ownership. AmeriGas OLP renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC subsequently identified a third party PRP with respect to the site.
The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during Fiscal 2017, 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, purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI 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
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 Missouri District Court. As the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S. Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect customer plaintiffs were remanded to the Western Missouri District Court. The decision of the Western Missouri District Court to dismiss the federal antitrust claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. On April 15, 2019, the Western Missouri District Court ruled that it has jurisdiction over the indirect purchasers’ state law claims and that the indirect customer plaintiffs have standing to pursue those claims. On August 21, 2019, the District Court partially granted the Company’s motion for judgment on the pleadings and dismissed the claims of indirect customer plaintiffs from ten states and the District of Columbia.
On October 2, 2019, the Company reached an agreement to resolve the claims of the direct purchaser class of plaintiffs, subject to court approval.
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.
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.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 17 — 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:

| Asset (Liability)
| Level 1 |  | Level 2 |  | Level 3 |  | Total
September 30, 2019: |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Commodity contracts | $ | 32.0 |  |  | $ | 10.1 |  |  | $ | — |  |  | $ | 42.1 |
Foreign currency contracts | $ | — |  |  | $ | 59.0 |  |  | $ | — |  |  | $ | 59.0 |
Liabilities: |  |  |  |  |  |  |
Commodity contracts | $ | (62.3 | ) |  | $ | (112.7 | ) |  | $ | — |  |  | $ | (175.0 | )
Foreign currency contracts | $ | — |  |  | $ | (4.3 | ) |  | $ | — |  |  | $ | (4.3 | )
Interest rate contracts | $ | — |  |  | $ | (12.3 | ) |  | $ | — |  |  | $ | (12.3 | )
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 39.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 39.7 |
September 30, 2018 |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Commodity contracts | $ | 93.5 |  |  | $ | 117.5 |  |  | $ | — |  |  | $ | 211.0 |
Foreign currency contracts | $ | — |  |  | $ | 20.6 |  |  | $ | — |  |  | $ | 20.6 |
Cross-currency contracts | $ | — |  |  | $ | 0.9 |  |  | $ | — |  |  | $ | 0.9 |
Liabilities: |  |  |  |  |  |  |
Commodity contracts | $ | (33.6 | ) |  | $ | (9.8 | ) |  | $ | — |  |  | $ | (43.4 | )
Foreign currency contracts | $ | — |  |  | $ | (14.4 | ) |  | $ | — |  |  | $ | (14.4 | )
Interest rate contracts | $ | — |  |  | $ | (1.0 | ) |  | $ | — |  |  | $ | (1.0 | )
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 40.8 |  |  | $ | — |  |  | $ | — |  |  | $ | 40.8 |

(a) | Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8).

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. 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.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Nonrecurring Fair Value Measurements
As discussed in Note 12, in April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years. This action required the Partnership to remeasure the fair values of these tradenames and trademarks based upon their remaining period of benefit. The Partnership used the relief from royalty method to estimate the fair values of the tradenames and trademarks, which method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions reflect current economic conditions, management expectations and projected future cash flows expected to be generated from these tradenames and trademarks. The Partnership determined that the lowest level of the inputs that were significant to the fair value measurement were unobservable inputs that fall within Level 3 of the fair value hierarchy. As of the April 2018 measurement date, these tradenames and trademarks had an estimated fair value of $7.9.
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) were as follows:

| 2019 |  | 2018
Carrying amount | $ | 5,856.6 |  |  | $ | 4,199.4 |
Estimated fair value | $ | 6,189.3 |  |  | $ | 4,150.3 |

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 18.
Note 18 — 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 prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses 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
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 9).
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, 2019 and 2018, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.
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 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 agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, from time to time, 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 physical natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and over-the-counter and ICE natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX and over-the-counter futures and options contracts to economically hedge price volatility associated with the gross margin derived from the purchase and anticipated later near-term sale of natural gas storage inventories. Outside of the financial market, Midstream & Marketing also uses ICE and over-the-counter forward physical contracts. 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. 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
From time to time we enter into long-term debt agreements with interest rates that are generally indexed to short-term market interest rates. In order to fix the underlying short-term market interest rates, we enter into pay-fixed, receive-variable interest rate swap agreements and designate such swaps as cash flow hedges. As more fully described in Note 6, during Fiscal 2019 UGI Corporation, UGI International, LLC and Energy Services entered into variable-rate, long-term debt agreements and also entered into associated pay-fixed, receive-variable interest rate swap agreements for all or a significant portion of the loans’ outstanding principal balance, and all or a significant portion of the loans’ tenor. In Fiscal 2018, UGI Utilities entered into a variable-rate amortizing term loan agreement and also entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019.
Prior to their repayment on October 25, 2018 (see Note 6), UGI France’s and Flaga’s long-term debt agreements had interest rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor and LIBOR rates of interest on these variable-rate debt agreements. We designated these interest rate swaps as cash flow hedges. These interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt.
The remainder of our 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
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 in IRPAs. We account for IRPAs as cash flow hedges. At September 30, 2019 and 2018, we had no unsettled IRPAs. At September 30, 2019, 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 the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we enter into forward foreign currency exchange contracts. We layer in these foreign currency exchange contracts over a multi-year period to eventually equal approximately 90% of anticipated UGI International local currency earnings before income taxes. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Other non-operating income (expense), net” on the Consolidated Statements of Income.
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, expiring through September 2019. We accounted for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2019, there were no amounts associated with these contracts remaining in AOCI.
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. We use the forward rate method for measuring ineffectiveness for these net investment hedges and all changes in the fair value of the forward foreign currency contracts are reported in the cumulative translation adjustment component of AOCI.
Concurrent with the issuance of euro-denominated long-term debt under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018, we designated this euro-denominated debt as net investment hedges of a portion of our euro-denominated UGI International net investment (see Note 6).
Cross-currency Contracts
Prior to its repayment on October 25, 2018 (see Note 6), Flaga entered 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 its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included 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 included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges. These cross-currency swaps were settled concurrent with the repayment of Flaga’s U.S. dollar variable rate term loan in October 2018.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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, 2019 and 2018 and the final settlement date of the Company's open derivative transactions as of September 30, 2019, excluding those derivatives that qualified for the NPNS exception:

|  |  |  |  |  | Notional Amounts (in millions)
|  |  |  |  |  | September 30,
Type |  | Units |  | Settlements Extending Through |  | 2019 |  | 2018
Commodity Price Risk: |  |  |  |  |  |  |  |
Regulated Utility Operations |  |  |  |  |  |  |  |
Gas Utility NYMEX natural gas futures and option contracts |  | Dekatherms |  | October 2020 |  | 23.3 |  |  | 23.2 |
Non-utility Operations |  |  |  |  |  |  |  |
LPG swaps |  | Gallons |  | September 2021 |  | 800.4 |  |  | 394.3 |
Natural gas futures, forward and pipeline contracts |  | Dekatherms |  | December 2024 |  | 196.1 |  |  | 159.7 |
Natural gas basis swap contracts |  | Dekatherms |  | December 2024 |  | 131.1 |  |  | 54.4 |
NYMEX natural gas storage futures contracts |  | Dekatherms |  | March 2020 |  | 0.3 |  |  | 1.8 |
NYMEX natural gas option contracts |  | Dekatherms |  | March 2020 |  | 2.4 |  |  | — |
NYMEX propane storage futures contracts |  | Gallons |  | April 2020 |  | 0.5 |  |  | 0.6 |
Electricity long forward and futures contracts |  | Kilowatt hours |  | January 2023 |  | 3,098.1 |  |  | 4,307.6 |
Electricity short forward and futures contracts |  | Kilowatt hours |  | May 2022 |  | 366.7 |  |  | 359.3 |
Interest Rate Risk: |  |  |  |  |  |  |  |
Interest rate swaps |  | Euro |  | October 2022 |  | € | 300.0 |  |  | € | 585.8 |
Interest rate swaps |  | USD |  | July 2024 |  | $ | 1,357.3 |  |  | $ | 114.1 |
Foreign Currency Exchange Rate Risk: |  |  |  |  |  |  |  |
Forward foreign exchange contracts |  | USD |  | September 2022 |  | $ | 516.0 |  |  | $ | 512.2 |
Net investment hedge forward foreign exchange contracts |  | Euro |  | October 2024 |  | € | 172.8 |  |  | € | — |
Cross-currency swaps |  | USD |  | N/A |  | $ | — |  |  | $ | 49.9 |

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. At September 30, 2019 and 2018, the Company paid (received) cash collateral of $29.3 and $(12.2), respectively. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2019 and 2018, restricted cash in brokerage accounts totaled $63.7 and $9.6, 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, 2019. 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, 2019, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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:

| 2019 |  | 2018
Derivative assets: |  |  |
Derivatives designated as hedging instruments: |  |  |
Foreign currency contracts | $ | 17.4 |  |  | $ | 1.5 |
Cross-currency contracts | — |  |  | 0.9 |
| 17.4 |  |  | 2.4 |
Derivatives subject to PGC and DS mechanisms: |  |  |
Commodity contracts | 1.4 |  |  | 3.0 |
Derivatives not designated as hedging instruments: |  |  |
Commodity contracts | 40.7 |  |  | 208.0 |
Foreign currency contracts | 41.6 |  |  | 19.1 |
| 82.3 |  |  | 227.1 |
Total derivative assets – gross | 101.1 |  |  | 232.5 |
Gross amounts offset in the balance sheet | (29.0 | ) |  | (34.3 | )
Cash collateral received | — |  |  | (12.2 | )
Total derivative assets – net | $ | 72.1 |  |  | $ | 186.0 |
Derivative liabilities: |  |  |
Derivatives designated as hedging instruments: |  |  |
Foreign currency contracts | $ | — |  |  | $ | (0.4 | )
Interest rate contracts | (12.3 | ) |  | (1.0 | )
| (12.3 | ) |  | (1.4 | )
Derivatives subject to PGC and DS mechanisms: |  |  |
Commodity contracts | (3.7 | ) |  | (0.1 | )
Derivatives not designated as hedging instruments: |  |  |
Commodity contracts | (171.3 | ) |  | (43.3 | )
Foreign currency contracts | (4.3 | ) |  | (14.0 | )
| (175.6 | ) |  | (57.3 | )
Total derivative liabilities – gross | (191.6 | ) |  | (58.8 | )
Gross amounts offset in the balance sheet | 29.0 |  |  | 34.3 |
Cash collateral pledged | 29.3 |  |  | — |
Total derivative liabilities – net | $ | (133.3 | ) |  | $ | (24.5 | )

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 for Fiscal 2019, Fiscal 2018 and Fiscal 2017:

| Gain (Loss) Recognized in AOCI |  | Gain (Loss) Reclassified from AOCI into Income |  | Location of Gain (Loss) Reclassified from AOCI into Income
| 2019 |  | 2018 |  | 2017 |  | 2019 |  | 2018 |  | 2017 |
Cash Flow Hedges: |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency contracts | $ | 1.2 |  |  | $ | 0.4 |  |  | $ | 0.2 |  |  | $ | 2.4 |  |  | $ | (3.0 | ) |  | $ | 17.8 |  |  | Cost of sales
Cross-currency contracts | (0.1 | ) |  | 1.2 |  |  | 0.5 |  |  | (0.3 | ) |  | 1.1 |  |  | (0.1 | ) |  | Interest expense /other operating income, net
Interest rate contracts | (11.6 | ) |  | 0.2 |  |  | 1.5 |  |  | (4.5 | ) |  | (5.0 | ) |  | (3.9 | ) |  | Interest expense
Total | $ | (10.5 | ) |  | $ | 1.8 |  |  | $ | 2.2 |  |  | $ | (2.4 | ) |  | $ | (6.9 | ) |  | $ | 13.8 |  |  |
Net Investment Hedges: |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency contracts | $ | 17.4 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |  |  |

| Gain (Loss) Recognized in Income |  | Location of Gain (Loss) Recognized in Income
| 2019 |  | 2018 |  | 2017 |
Derivatives Not Designated as Hedging Instruments: |  |  |  |  |  |  |
Commodity contracts | $ | (344.1 | ) |  | $ | 155.4 |  |  | $ | 166.0 |  |  | Cost of sales
Commodity contracts | 7.2 |  |  | (5.3 | ) |  | (2.0 | ) |  | Revenues
Commodity contracts | (0.3 | ) |  | 0.3 |  |  | 0.2 |  |  | Operating and administrative expenses
Foreign currency contracts | 37.7 |  |  | 16.2 |  |  | (23.8 | ) |  | Other non-operating income (expense), net
Total | $ | (299.5 | ) |  | $ | 166.6 |  |  | $ | 140.4 |  |  |

For Fiscal 2019, Fiscal 2018, and Fiscal 2017, 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.
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 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.
Note 19 — 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.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Changes in AOCI during Fiscal 2019, Fiscal 2018 and Fiscal 2017 are as follows:

| Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency |  | Total
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 comprehensive income (loss) before reclassification adjustments (after-tax) | 10.4 |  |  | 1.0 |  |  | (30.5 | ) |  | (19.1 | )
Amounts reclassified from AOCI: |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) | (3.3 | ) |  | 6.9 |  |  | — |  |  | 3.6 |
Reclassification adjustments tax expense (benefit) | 1.1 |  |  | (2.6 | ) |  | — |  |  | (1.5 | )
Reclassification adjustments (after-tax) | (2.2 | ) |  | 4.3 |  |  | — |  |  | 2.1 |
Other comprehensive income (loss) attributable to UGI | 8.2 |  |  | 5.3 |  |  | (30.5 | ) |  | (17.0 | )
AOCI - September 30, 2018 | $ | (11.0 | ) |  | $ | (16.1 | ) |  | $ | (83.3 | ) |  | $ | (110.4 | )
Other comprehensive loss before reclassification adjustments (after-tax) | (13.0 | ) |  | (7.3 | ) |  | (82.2 | ) |  | (102.5 | )
Amounts reclassified from AOCI: |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) | 1.7 |  |  | 2.4 |  |  | — |  |  | 4.1 |
Reclassification adjustments tax benefit | (0.5 | ) |  | (0.7 | ) |  | — |  |  | (1.2 | )
Reclassification adjustments (after-tax) | 1.2 |  |  | 1.7 |  |  | — |  |  | 2.9 |
Other comprehensive loss attributable to UGI | (11.8 | ) |  | (5.6 | ) |  | (82.2 | ) |  | (99.6 | )
Reclassification of stranded income tax effects related to TCJA | (2.9 | ) |  | (3.7 | ) |  | — |  |  | (6.6 | )
AOCI - September 30, 2019 | $ | (25.7 | ) |  | $ | (25.4 | ) |  | $ | (165.5 | ) |  | $ | (216.6 | )

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 18.
Note 20 — Other Operating Income, Net
Other operating income, net, for Fiscal 2019, Fiscal 2018 and Fiscal 2017 comprises the following:

| 2019 |  | 2018 |  | 2017
Finance charges | $ | 16.5 |  |  | $ | 16.4 |  |  | $ | 11.8 |
AFUDC associated with pipeline projects | — |  |  | — |  |  | 5.5 |
Interest and interest-related income | 5.6 |  |  | 3.2 |  |  | 1.7 |
Utility non-tariff service income | 0.7 |  |  | 2.8 |  |  | 1.5 |
Loss on private equity partnership investment | (1.5 | ) |  | — |  |  | (11.0 | )
Gains (losses) on sales of fixed assets, net | 2.9 |  |  | 5.3 |  |  | (3.9 | )
Other, net | 6.9 |  |  | 3.6 |  |  | 4.9 |
Total other operating income, net | $ | 31.1 |  |  | $ | 31.3 |  |  | $ | 10.5 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 21 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) that 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 18) and other significant discrete items that can affect the comparison of period-over-period results.

| December 31, |  | March 31, |  | June 30, |  | September 30,
| 2018 (a) |  | 2017 (b) |  | 2019 |  | 2018 (b) |  | 2019 |  | 2018 (b) (c) |  | 2019 (d) |  | 2018 (b)
Revenues | $ | 2,200.2 |  |  | $ | 2,125.2 |  |  | $ | 2,606.1 |  |  | $ | 2,812.0 |  |  | $ | 1,363.7 |  |  | $ | 1,440.9 |  |  | $ | 1,150.4 |  |  | $ | 1,273.1 |
Operating income (loss) | $ | 167.7 |  |  | $ | 395.0 |  |  | $ | 538.8 |  |  | $ | 591.0 |  |  | $ | 9.6 |  |  | $ | 29.5 |  |  | $ | (99.0 | ) |  | $ | 49.2 |
Net income (loss) including noncontrolling interests | $ | 88.5 |  |  | $ | 434.2 |  |  | $ | 396.7 |  |  | $ | 407.7 |  |  | $ | (46.5 | ) |  | $ | (11.7 | ) |  | $ | (130.8 | ) |  | $ | (7.8 | )
Net income (loss) attributable to UGI Corporation | $ | 64.2 |  |  | $ | 365.9 |  |  | $ | 245.4 |  |  | $ | 276.0 |  |  | $ | (1.9 | ) |  | $ | 52.4 |  |  | $ | (51.5 | ) |  | $ | 24.4 |
Earnings (loss) per common share attributable to UGI Corporation stockholders: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic | $ | 0.37 |  |  | $ | 2.11 |  |  | $ | 1.41 |  |  | $ | 1.59 |  |  | $ | (0.01 | ) |  | $ | 0.30 |  |  | $ | (0.27 | ) |  | $ | 0.14 |
Diluted | $ | 0.36 |  |  | $ | 2.07 |  |  | $ | 1.38 |  |  | $ | 1.57 |  |  | $ | (0.01 | ) |  | $ | 0.30 |  |  | $ | (0.27 | ) |  | $ | 0.14 |
Weighted-average common shares outstanding (thousands): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic | 174,413 |  |  | 173,670 |  |  | 174,501 |  |  | 173,570 |  |  | 174,759 |  |  | 173,991 |  |  | 189,905 |  |  | 174,391 |
Diluted | 177,566 |  |  | 176,948 |  |  | 177,318 |  |  | 176,350 |  |  | 174,759 |  |  | 176,807 |  |  | 189,905 |  |  | 177,506 |

(a) | Includes loss on extinguishments of debt at UGI International which reduced net income attributable to UGI by $4.2 (see Note 6).

(b) | The quarters ended December 31, 2017, March 31, 2018, June 30, 2018 and September 30, 2018, include the impact of adjustments to remeasure net deferred income tax liabilities associated with (1) the TCJA, including adjustments to provisional amounts, which increased (decreased) net income by $166.0, $5.3, $0.8 and $(5.8), respectively, and (2) the December 2017 French Finance Bills, which increased (decreased) net income by $17.3, $(3.7), $(0.1) and $(1.4), respectively (see Note 7).

(c) | Includes the impact of the impairment of Partnership tradenames and trademarks, which decreased net income attributable to UGI by $14.5 (see Notes 12 and 17).

(d) | Weighted-average common shares outstanding includes the impact from the August 2019 issuance of 34,612,847 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5).

Note 22 — 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.
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 derives revenue from natural gas marketing businesses in France, Belgium and the United Kingdom and a natural gas and electricity marketing business in the Netherlands. Midstream & Marketing derives its revenues principally from the sale of natural gas, liquid fuels and electricity as well as revenues and fees from storage, pipeline transportation, natural gas gathering 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. The accounting policies of our reportable segments are the same as those described in Note 2.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
During the fourth quarter of Fiscal 2019, the measurement of segment profit used by our CODM was revised to exclude certain items that are now included in Corporate & Other (in addition to net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, which had previously been excluded). The revision to our segment profit measures aligns with the financial information utilized by our CODM in evaluating our reportable segments’ performance and allocating resources. Fiscal 2018 and Fiscal 2017 amounts have been recast to reflect the change in segment measure of profit. Also during the fourth quarter of Fiscal 2019, principally as a result of the AmeriGas Merger and the CMG Acquisition and related transactions, our CODM began evaluating the performance of all of our reportable segments based upon earnings before interest expense and income taxes, excluding the items noted above.
In addition to the items described above, Corporate & Other includes the net expenses of UGI’s captive general liability insurance company, UGI’s corporate headquarters facility and UGI’s unallocated corporate and general expenses as well as interest expense on debt incurred by UGI Corporation that is not allocated. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.
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. The amounts of revenues and long-lived assets associated with our operations in France represent approximately 20% and 10% of the respective consolidated amounts.

| Total |  | Elim- inations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (a) |
2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues from external customers | $ | 7,320.4 |  |  | $ | — |  |  | $ | 2,682.0 |  |  | $ | 2,372.2 |  |  | $ | 1,281.1 |  |  | $ | 980.7 |  |  | $ | 4.4 |  |
Intersegment revenues | $ | — |  |  | $ | (305.4 | ) | (b) | $ | — |  |  | $ | — |  |  | $ | 234.6 |  |  | $ | 67.9 |  |  | $ | 2.9 |  |
Cost of sales | $ | 4,323.1 |  |  | $ | (301.7 | ) | (b) | $ | 1,191.3 |  |  | $ | 1,416.4 |  |  | $ | 1,241.2 |  |  | $ | 481.3 |  |  | $ | 294.6 |  |
Operating income (loss) | $ | 617.1 |  |  | $ | 0.5 |  |  | $ | 404.0 |  |  | $ | 228.9 |  |  | $ | 105.0 |  |  | $ | 224.2 |  |  | $ | (345.5 | ) |
Income from equity investees | 9.1 |  |  | — |  |  | — |  |  | — |  |  | 9.1 |  | (c) | — |  |  | — |  |
Loss on extinguishments of debt | (6.1 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (6.1 | ) |
Other non-operating income, net | 38.2 |  |  | — |  |  | — |  |  | 5.4 |  |  | — |  |  | 1.5 |  |  | 31.3 |  |
Earnings (losses) before interest expense and income taxes | 658.3 |  |  | 0.5 |  |  | 404.0 |  |  | 234.3 |  |  | 114.1 |  |  | 225.7 |  |  | (320.3 | ) |
Interest expense | (257.8 | ) |  | — |  |  | (167.4 | ) |  | (25.0 | ) |  | (9.0 | ) |  | (49.6 | ) |  | (6.8 | ) |
Income tax (expense) benefit | (92.6 | ) |  | (0.2 | ) |  | (25.7 | ) |  | (64.6 | ) |  | (27.1 | ) |  | (42.9 | ) |  | 67.9 |  |
Noncontrolling interests’ net (income) loss | (51.7 | ) |  | — |  |  | (142.7 | ) |  | 0.1 |  |  | — |  |  | — |  |  | 90.9 |  |
Net income (loss) attributable to UGI | $ | 256.2 |  |  | $ | 0.3 |  |  | $ | 68.2 |  |  | $ | 144.8 |  |  | $ | 78.0 |  |  | $ | 133.2 |  |  | $ | (168.3 | ) |
Depreciation and amortization | $ | 448.1 |  |  | $ | (0.2 | ) |  | $ | 179.4 |  |  | $ | 123.8 |  |  | $ | 51.4 |  |  | $ | 92.8 |  |  | $ | 0.9 |  |
Total assets | $ | 13,346.6 |  |  | $ | (352.8 | ) |  | $ | 4,095.3 |  |  | $ | 2,975.2 |  |  | $ | 2,744.5 |  |  | $ | 3,559.5 |  |  | $ | 324.9 |  |
Short-term borrowings | $ | 796.3 |  |  | $ | — |  |  | $ | 328.0 |  |  | $ | 210.9 |  |  | $ | 91.4 |  |  | $ | 166.0 |  |  | $ | — |  |
Capital expenditures (including the effects of accruals) | $ | 707.6 |  |  | $ | — |  |  | $ | 107.3 |  |  | $ | 106.4 |  |  | $ | 137.7 |  |  | $ | 355.3 |  |  | $ | 0.9 |  |
Investments in equity investees | $ | 189.6 |  |  | $ | — |  |  | $ | — |  |  | $ | 11.6 |  |  | $ | 178.0 |  |  | $ | — |  |  | $ | — |  |
Goodwill | $ | 3,456.4 |  |  | $ | — |  |  | $ | 2,003.0 |  |  | $ | 929.8 |  |  | $ | 341.5 |  |  | $ | 182.1 |  |  | $ | — |  |
2018 (d)(e) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues from external customers | $ | 7,651.2 |  |  | $ | — |  |  | $ | 2,823.0 |  |  | $ | 2,683.8 |  |  | $ | 1,149.1 |  |  | $ | 998.5 |  |  | $ | (3.2 | ) |
Intersegment revenues | $ | — |  |  | $ | (370.8 | ) | (b) | $ | — |  |  | $ | — |  |  | $ | 272.6 |  |  | $ | 93.9 |  |  | $ | 4.3 |  |
Cost of sales | $ | 4,074.9 |  |  | $ | (366.6 | ) | (b) | $ | 1,314.7 |  |  | $ | 1,620.1 |  |  | $ | 1,090.8 |  |  | $ | 522.9 |  |  | $ | (107.0 | ) |
Operating income (loss) | $ | 1,064.7 |  |  | $ | 0.3 |  |  | $ | 422.2 |  |  | $ | 247.9 |  |  | $ | 175.1 |  |  | $ | 239.9 |  |  | $ | (20.7 | ) | (d)
Income (loss) from equity investees | 4.3 |  |  | — |  |  | — |  |  | (0.5 | ) |  | 4.8 |  | (c) | — |  |  | — |  |
Other non-operating income (expense), net | 15.6 |  |  | — |  |  | — |  |  | (7.0 | ) |  | (1.2 | ) |  | (2.4 | ) |  | 26.2 |  |
Earnings before interest expense and income taxes | 1,084.6 |  |  | 0.3 |  |  | 422.2 |  |  | 240.4 |  |  | 178.7 |  |  | 237.5 |  |  | 5.5 |  |

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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)

| Total |  | Elim- inations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (a) |
Interest expense | (230.1 | ) |  | — |  |  | (163.1 | ) |  | (21.1 | ) |  | (2.4 | ) |  | (42.9 | ) |  | (0.6 | ) |
Income tax (expense) benefit | (32.1 | ) |  | (1.4 | ) |  | (30.5 | ) |  | (69.2 | ) |  | (49.6 | ) |  | (53.7 | ) |  | 172.3 |  |
Noncontrolling interests’ net (income) loss | (103.7 | ) |  | — |  |  | (152.3 | ) |  | 3.0 |  |  | — |  |  | — |  |  | 45.6 |  |
Net income (loss) attributable to UGI | $ | 718.7 |  |  | $ | (1.1 | ) |  | $ | 76.3 |  |  | $ | 153.1 |  |  | $ | 126.7 |  |  | $ | 140.9 |  |  | $ | 222.8 |  |
Depreciation and amortization | $ | 455.1 |  |  | $ | (0.3 | ) |  | $ | 185.8 |  |  | $ | 140.6 |  |  | $ | 43.5 |  |  | $ | 84.6 |  |  | $ | 0.9 |  |
Total assets | $ | 11,980.9 |  |  | $ | (125.3 | ) |  | $ | 3,933.9 |  |  | $ | 3,279.0 |  |  | $ | 1,328.9 |  |  | $ | 3,266.6 |  |  | $ | 297.8 |  |
Short-term borrowings | $ | 424.9 |  |  | $ | — |  |  | $ | 232.0 |  |  | $ | 1.4 |  |  | $ | 2.0 |  |  | $ | 189.5 |  |  | $ | — |  |
Capital expenditures (including the effects of accruals) | $ | 597.0 |  |  | $ | — |  |  | $ | 101.3 |  |  | $ | 111.4 |  |  | $ | 43.1 |  |  | $ | 338.5 |  |  | $ | 2.7 |  |
Investments in equity investees | $ | 87.6 |  |  | $ | — |  |  | $ | — |  |  | $ | 12.8 |  |  | $ | 74.8 |  |  | $ | — |  |  | $ | — |  |
Goodwill | $ | 3,160.4 |  |  | $ | — |  |  | $ | 2,003.0 |  |  | $ | 963.7 |  |  | $ | 11.6 |  |  | $ | 182.1 |  |  | $ | — |  |
2017 (e) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues from external customers | $ | 6,120.7 |  |  | $ | — |  |  | $ | 2,453.5 |  |  | $ | 1,877.5 |  |  | $ | 943.0 |  |  | $ | 847.5 |  |  | $ | (0.8 | ) |
Intersegment revenues | $ | — |  |  | $ | (222.7 | ) | (b) | $ | — |  |  | $ | — |  |  | $ | 178.2 |  |  | $ | 40.1 |  |  | $ | 4.4 |  |
Cost of sales | $ | 2,837.3 |  |  | $ | (218.3 | ) | (b) | $ | 1,002.9 |  |  | $ | 935.3 |  |  | $ | 856.7 |  |  | $ | 367.3 |  |  | $ | (106.6 | ) |
Operating income | $ | 1,010.0 |  |  | $ | 0.3 |  |  | $ | 355.3 |  |  | $ | 234.3 |  |  | $ | 139.4 |  |  | $ | 232.7 |  |  | $ | 48.0 |  |
Income from equity investees | 4.3 |  |  | — |  |  | — |  |  | — |  |  | 4.3 |  | (c) | — |  |  | — |  |
Loss on extinguishments of debt | (59.7 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (59.7 | ) |
Other non-operating (expense) income, net | (29.7 | ) |  | — |  |  | — |  |  | 1.2 |  |  | (0.2 | ) |  | (4.4 | ) |  | (26.3 | ) |
Earnings (losses) before interest expense and income taxes | 924.9 |  |  | 0.3 |  |  | 355.3 |  |  | 235.5 |  |  | 143.5 |  |  | 228.3 |  |  | (38.0 | ) |
Interest expense | (223.5 | ) |  | — |  |  | (160.2 | ) |  | (20.6 | ) |  | (2.1 | ) |  | (40.2 | ) |  | (0.4 | ) |
Income tax (expense) benefit | (177.6 | ) |  | (0.2 | ) |  | (32.5 | ) |  | (58.9 | ) |  | (54.5 | ) |  | (72.1 | ) |  | 40.6 |  |
Noncontrolling interests’ net (income) loss | (87.2 | ) |  | — |  |  | (108.4 | ) |  | (0.2 | ) |  | — |  |  | — |  |  | 21.4 |  |
Net income attributable to UGI | $ | 436.6 |  |  | $ | 0.1 |  |  | $ | 54.2 |  |  | $ | 155.8 |  |  | $ | 86.9 |  |  | $ | 116.0 |  |  | $ | 23.6 |  |
Depreciation and amortization | $ | 416.3 |  |  | $ | (0.2 | ) |  | $ | 190.5 |  |  | $ | 117.4 |  |  | $ | 35.4 |  |  | $ | 72.3 |  |  | $ | 0.9 |  |
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 |  |  | $ | — |  |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)

(a) | Corporate & Other includes specific items attributable to our reportable segments that are not included in the segment profit measures used by our CODM in assessing our reportable segments’ performance or allocating resources. The following table presents such pre-tax gains (losses) which have been included in Corporate & Other, and the reportable segments to which they relate, for Fiscal 2019, Fiscal 2018 and Fiscal 2017:

|  | Location on Income Statement |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing
2019 |  |  |  |  |  |  |  |
Net losses on commodity derivative instruments not associated with current-period transactions |  | Revenue / Cost of sales |  | $ | (116.8 | ) |  | $ | (142.5 | ) |  | $ | (31.0 | )
Unrealized gains on foreign currency derivative instruments |  | Other non-operating income (expense), net |  | $ | — |  |  | $ | 32.2 |  |  | $ | — |
Loss on extinguishments of debt |  | Loss on extinguishment of debt |  | $ | — |  |  | $ | (6.1 | ) |  | $ | — |
AmeriGas Merger expenses |  | Operating and administrative expenses |  | $ | (6.3 | ) |  | $ | — |  |  | $ | — |
Acquisition and integration expenses associated with the CMG Acquisition |  | Operating and administrative expenses |  | $ | — |  |  | $ | — |  |  | $ | (15.6 | )
LPG business transformation costs |  | Operating and administrative expenses |  | $ | (14.5 | ) |  | $ | (9.3 | ) |  | $ | — |
2018 |  |  |  |  |  |  |  |
Net gains (losses) on commodity derivative instruments not associated with current-period transactions |  | Revenue / Cost of sales |  | $ | 12.5 |  |  | $ | 92.9 |  |  | $ | (1.5 | )
Unrealized gains on foreign currency derivative instruments |  | Other non-operating income (expense), net |  | $ | — |  |  | $ | 28.9 |  |  | $ | — |
Integration expenses associated with Finagaz |  | Operating and administrative expenses |  | $ | — |  |  | $ | (30.5 | ) |  | $ | — |
Impairment of Partnership tradenames and trademarks |  | Impairment of Partnership tradenames and trademarks |  | $ | (75.0 | ) |  | $ | — |  |  | $ | — |
2017 |  |  |  |  |  |  |  |
Net gains on commodity derivative instruments not associated with current-period transactions |  | Revenue / Cost of sales |  | $ | 31.1 |  |  | $ | 19.0 |  |  | $ | 55.7 |
Unrealized losses on foreign currency derivative instruments |  | Other non-operating income (expense), net |  | $ | — |  |  | $ | (23.8 | ) |  | $ | — |
Loss on extinguishments of debt |  | Loss on extinguishment of debt |  | $ | (59.7 | ) |  | $ | — |  |  | $ | — |
Integration expenses associated with Finagaz |  | Operating and administrative expenses |  | $ | — |  |  | $ | (39.9 | ) |  | $ | — |

(b) | Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.

(c) | Includes AFUDC associated with PennEast (see Note 2). Fiscal 2019 also includes income from Pennant subsequent to the CMG Acquisition (see Note 5).

(d) | Fiscal 2018 results include impacts from the TCJA in the U.S. See Notes 7 and 9 for additional information. For Fiscal 2018, the remeasurement impacts from the TCJA and, for UGI International, the December 2017 French Finance Bills, were allocated from each of AmeriGas Propane, UGI International, Midstream & Marketing and UGI Utilities to Corporate & Other in amounts of $112.9, $4.0, $70.1 and $8.0, respectively. For Fiscal 2017, the remeasurement impact from the December 2016 French Finance Bills of $29.0 was allocated from UGI International to Corporate & Other.

(e) | Segment information recast to reflect the changes adopted during the fourth quarter of Fiscal 2019 in the segment measure of profit used by our CODM to evaluate the performance of our reportable segments.

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 23 — Global LPG Business Transformation Initiatives
During the fourth quarter of Fiscal 2019, we began executing on multi-year business transformation initiatives at our AmeriGas Propane and UGI International business segments. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. In connection with these initiatives, during Fiscal 2019 we incurred $23.8 of costs principally comprising consulting, advisory and employee-related costs. These costs are reflected in “Operating and administrative expenses” on the 2019 Consolidated Statement of Income.
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UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)

| September 30,
| 2019 |  | 2018
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 53.7 |  |  | $ | 13.4 |
Accounts receivable – related parties | 5.4 |  |  | 12.8 |
Prepaid expenses and other current assets | 22.8 |  |  | 10.5 |
Total current assets | 81.9 |  |  | 36.7 |
Property, plant and equipment, net | 3.0 |  |  | 2.6 |
Investments in subsidiaries | 4,585.1 |  |  | 3,652.0 |
Other assets | 77.4 |  |  | 71.9 |
Total assets | $ | 4,747.4 |  |  | $ | 3,763.2 |
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts and notes payable | $ | 15.4 |  |  | $ | 14.9 |
Accrued liabilities | 9.1 |  |  | 6.7 |
Total current liabilities | 24.5 |  |  | 21.6 |
Long-term debt | 846.0 |  |  | — |
Other noncurrent liabilities | 59.4 |  |  | 60.2 |
Total liabilities | 929.9 |  |  | 81.8 |
Commitments and contingencies (Note 1) |  |  |
Common stockholders’ equity: |  |  |
Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively) | 1,396.9 |  |  | 1,200.8 |
Retained earnings | 2,653.1 |  |  | 2,610.7 |
Accumulated other comprehensive loss | (216.6 | ) |  | (110.4 | )
Treasury stock, at cost | (15.9 | ) |  | (19.7 | )
Total common stockholders’ equity | 3,817.5 |  |  | 3,681.4 |
Total liabilities and common stockholders’ equity | $ | 4,747.4 |  |  | $ | 3,763.2 |

Note 1 — Commitments and Contingencies:
At September 30, 2019, UGI Corporation had agreed to indemnify the issuers of $84.4 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $475.0 of obligations to suppliers and customers of Energy Services and subsidiaries of which $378.4 of such obligations were outstanding as of September 30, 2019.
Scheduled principal repayments of long-term debt during the next five fiscal years include $300.0 in Fiscal 2022, $37.5 in Fiscal 2023 and $512.5 in Fiscal 2024.
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UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
Revenues | $ | — |  |  | $ | — |  |  | $ | — |
Costs and expenses: |  |  |  |  |
Operating and administrative expenses | 50.0 |  |  | 63.4 |  |  | 44.5 |
Other operating income, net (a) | (49.7 | ) |  | (52.2 | ) |  | (45.9 | )
| 0.3 |  |  | 11.2 |  |  | (1.4 | )
Operating (loss) income | (0.3 | ) |  | (11.2 | ) |  | 1.4 |
Pension and other postretirement plans non-service expense | (0.9 | ) |  | (1.3 | ) |  | (1.8 | )
Interest expense | (6.4 | ) |  | — |  |  | — |
Intercompany interest income | 0.3 |  |  | 0.1 |  |  | — |
Loss before income taxes | (7.3 | ) |  | (12.4 | ) |  | (0.4 | )
Income tax (benefit) expense | (2.8 | ) |  | 6.1 |  |  | (5.7 | )
(Loss) income before equity in income of unconsolidated subsidiaries | (4.5 | ) |  | (18.5 | ) |  | 5.3 |
Equity in income of unconsolidated subsidiaries | 260.7 |  |  | 737.2 |  |  | 431.3 |
Net income attributable to UGI Corporation | $ | 256.2 |  |  | $ | 718.7 |  |  | $ | 436.6 |
Other comprehensive (loss) income | (3.3 | ) |  | 3.4 |  |  | 1.3 |
Equity in other comprehensive (loss) income of unconsolidated subsidiaries | (96.3 | ) |  | (20.4 | ) |  | 60.0 |
Comprehensive income attributable to UGI Corporation | $ | 156.6 |  |  | $ | 701.7 |  |  | $ | 497.9 |
Earnings per common share attributable to UGI Corporation stockholders: |  |  |  |  |
Basic | $ | 1.44 |  |  | $ | 4.13 |  |  | $ | 2.51 |
Diluted | $ | 1.41 |  |  | $ | 4.06 |  |  | $ | 2.46 |
Weighted - average common shares outstanding (thousands): |  |  |  |  |
Basic | 178,417 |  |  | 173,908 |  |  | 173,662 |
Diluted | 181,111 |  |  | 176,905 |  |  | 177,159 |

(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.

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UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)

| Year Ended September 30,
| 2019 |  | 2018 |  | 2017
NET CASH PROVIDED BY OPERATING ACTIVITIES (a) | $ | 169.8 |  |  | $ | 208.2 |  |  | $ | 253.2 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |
Expenditures for property, plant and equipment | — |  |  | (2.3 | ) |  | (0.4 | )
Net investments in unconsolidated subsidiaries | (768.1 | ) |  | (6.5 | ) |  | (40.7 | )
Net cash used by investing activities | (768.1 | ) |  | (8.8 | ) |  | (41.1 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |
Payment of dividends on Common Stock | (199.5 | ) |  | (176.9 | ) |  | (168.9 | )
Issuances of debt, net of issuance costs | 845.9 |  |  | — |  |  | — |
Issuances of Common Stock | 16.8 |  |  | 34.9 |  |  | 11.0 |
Repurchases of UGI Common Stock | (16.9 | ) |  | (59.8 | ) |  | (43.3 | )
Other | (7.7 | ) |  | — |  |  | 0.1 |
Net cash provided (used) by financing activities | 638.6 |  |  | (201.8 | ) |  | (201.1 | )
Cash and cash equivalents increase (decrease) | $ | 40.3 |  |  | $ | (2.4 | ) |  | $ | 11.0 |
Cash and cash equivalents: |  |  |  |  |
End of year | $ | 53.7 |  |  | $ | 13.4 |  |  | $ | 15.8 |
Beginning of year | 13.4 |  |  | 15.8 |  |  | 4.8 |
Cash and cash equivalents increase (decrease) | $ | 40.3 |  |  | $ | (2.4 | ) |  | $ | 11.0 |

(a) | Includes dividends received from unconsolidated subsidiaries of $162.5, $190.5 and $241.9 for the years ended September 30, 2019, 2018 and 2017, respectively.

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Table of Contents
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, 2019 |  |  |  |  |  |  |  |
Reserves deducted from assets in the consolidated balance sheet: |  |  |  |  |  |  |  |
Allowance for doubtful accounts | $ | 35.1 |  |  | $ | 28.6 |  |  | $ | (32.1 | ) | (1) | $ | 31.6 |  |
Other reserves: |  |  |  |  |  |  |  |
Deferred tax assets valuation allowance | $ | 116.8 |  |  | $ | (26.1 | ) |  | $ | — |  |  | $ | 90.7 |  |
Year Ended September 30, 2018 |  |  |  |  |  |  |  |
Reserves deducted from assets in the consolidated balance sheet: |  |  |  |  |  |  |  |
Allowance for doubtful accounts | $ | 26.9 |  |  | $ | 35.6 |  |  | $ | (27.4 | ) | (1) | $ | 35.1 |  |
Other reserves: |  |  |  |  |  |  |  |
Deferred tax assets valuation allowance | $ | 107.1 |  |  | $ | 9.7 |  |  | $ | — |  |  | $ | 116.8 |  |
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 |  | (2) | $ | 107.1 |  |

(1) | Uncollectible accounts written off, net of recoveries.

(2) | Foreign tax credit valuation allowance adjustment.

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