0000884614 srt:MaximumMember ugi:TermLoanMember ugi:ThreeYearTermLoanMember us-gaap:LineOfCreditMember us-gaap:SubsequentEventMember us-gaap:PrimeRateMember 2019-07-02 2019-07-02
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
 
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30,December 31, 2019
OR
☐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 CORPCORPORATIONORATION
(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 valueUGINew York Stock Exchange
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  ý    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 and post such files). Yes ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 filerý 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 Exchange Act).    Yes  ☐    No  ý
At JulyJanuary 31, 20192020, there were 174,338,275208,548,324 shares of UGI Corporation Common Stock, without par value, outstanding.
     

Table of Contents



UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
 
 Page
  
Glossary of Terms and Abbreviations
1
  
Part I Financial Information
 
  
Item 1. Financial Statements (unaudited)
 
  
Condensed Consolidated Balance Sheets as of June 30,December 31, 2019, September 30, 20182019 and June 30,December 31, 2018
5
Condensed Consolidated Statements of Income for the three months ended December 31, 2019 and 2018
6
  
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30,December 31, 2019 and 2018
7
  
Condensed Consolidated Statements of Comprehensive IncomeCash Flows for the three and nine months ended June 30,December 31, 2019 and 2018
8
  
Condensed Consolidated Statements of Cash FlowsChanges in Equity for the ninethree months ended June 30,December 31, 2019 and 2018
9
Condensed Consolidated Statements of Changes in Equity for the three and nine months ended June 30, 2019 and 2018
10
  
Notes to Condensed Consolidated Financial Statements
1110
  
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
4436
  
Item 3. Quantitative and Qualitative Disclosures About Market Risk
6949
  
Item 4. Controls and Procedures
7151
  
Part II Other Information
 
  
Item 1A. Risk Factors
7252
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
52
  
Item 6. Exhibits
7353 
  
Signatures
7555
  
 

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GLOSSARY OF TERMS AND ABBREVIATIONS

Terms and abbreviations used in this Form 10-Q 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 publicly tradedDelaware limited partnership. AmeriGas Partners, L.P. ispartnership 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 and AmeriGas OLP. AlsoPartners; also referred to as the General Partner“General Partner”
AvantiGas - AvantiGas Limited, aan 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., aan 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 ownedsecond-tier 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, aan indirect wholly owned subsidiary of UGI International, LLC
Gas Utility - UGI Utilities’ regulated natural gas distribution businesses,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 and AmeriGas OLP
GP Audit Committee - The audit committee of the GP Board
GP Board - The board of directors of the General Partner
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 principally comprising Energy Services UGID and HVACUGID
Partnership - AmeriGas Partners and its consolidated subsidiaries, including AmeriGas OLP
Pennant - Pennant Midstream, LLC, a Delaware limited liability company
PennEast - PennEast Pipeline Company, LLC
PNG - UGI Penn Natural Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to the Utility Merger

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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), aan 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 second-tier 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

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UGID - UGI Development Company, a wholly owned subsidiary of Energy Services
UniverGas - UniverGas Italia S.r.l, aan indirect wholly owned subsidiary of UGI International, LLC
Other Terms and Abbreviations
2018 Annual Report -UGI Annual Report on Form 10-K for the fiscal year ended September 30, 2018, including annual financial statements and footnotes amended in the Current Report on Form 8-K dated May 6, 2019.
2018 nine-month period -Nine-month period ended June 30, 2018
2018 three-month period - Three-month period ended June 30,December 31, 2018
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
2019 nine-month periodAnnual Report - Nine-month periodUGI Annual Report on Form 10-K for the fiscal year ended JuneSeptember 30, 2019
2019 three-month period - Three-month period ended June 30,December 31, 2019
AFUDC - Allowance for funds used during constructionFunds Used During Construction
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
AOCI - Accumulated other comprehensive income (loss)Other Comprehensive Income (Loss)
ASC - Accounting Standards Codification
ASC 605- ASC 605, “Revenue Recognition”
ASC 606 - ASC 606, “Revenue from Contracts with Customers”
ASC 740840 - ASC 840, “Leases”
ASC 842 - ASC 740, “Income Taxes”842, “Leases” (effective October 1, 2019)
ASU - Accounting Standards Update
Bcf - Billions of cubic feet
BIE - Pennsylvania Public Utility Commission Bureau of Investigation and Enforcement
BRP - Balance Responsible Party providing electricity imbalance services in the European electricity markets
CMG - Columbia Midstream Group, LLC

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CMG Acquisition - Acquisition of CMG and Columbia Pennant, LLC on August 1, 2019 pursuant to purchase and sales agreements dated July 2, 2019 betweenthe CMG Energy Services and UGIAcquisition 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 solely for the limited purposes set forth therein, UGI and TransCanada PipeLine USA Ltd., and (2) a purchase and sale agreement, dated July 2, 2019, by and among Columbia Midstream & Minerals Group, LLC, Energy Services, and solely for the limited purposes set forth therein, TransCanada PipeLine USA Ltd.

COA - Consent orderOrder and agreementAgreement

CODM - Chief Operating Decision Maker as defined in ASC 280, “Segment Reporting”

Common Stock - shares of UGI common stock

Common Units - Limited partnership ownership interests in AmeriGas Partners

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 2017 French Finance Bills - The French Finance Bill for 2018 and the second amendment to the French Finance Bill for 2017 (also referred to as French Finance Bill)
DS - Default service
DSICEighth Circuit - Distribution System Improvement ChargeUnited States Court of Appeals for the Eighth Circuit

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Energy Service Credit AgreementServices Term Loan - An unsecured revolving creditA seven-year $700 million senior secured term loan agreement entered into by Energy Services providing for borrowings up to $240 million, includingon August 13, 2019, with a lettergroup of credit subfacility of up to $50 millionlenders

EPS - Earnings Per Share

Exchange Act - Securities Exchange Act of 1934, as amended

FASB - Financial Accounting Standards Board
FDIC - Federal Deposit Insurance Corporation
FERC - Federal Energy Regulatory Commission
FTR -Fiscal 2019 Financial transmission rights- The fiscal year ended September 30, 2019
Fiscal 2020 - The fiscal year ending September 30, 2020
Fiscal 2021 - The fiscal year ending September 30, 2021
Fiscal 2022 - The fiscal year ending September 30, 2022
Fiscal 2023 - The fiscal year ending September 30, 2023
Fiscal 2024 - The fiscal year ending September 30, 2024
GAAP - U.S. generally accepted accounting principles
Gwh - Millions of kilowatt hours
Hunlock - Hunlock Station, a 130-megawatt natural gas-fueled electricity generating station located near Wilkes-Barre, Pennsylvania
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 gasesgas
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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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
PADEP - Pennsylvania Department of Environmental Protection
PAPUC - Pennsylvania Public Utility Commission

3
Partnership Adjusted EBITDA - A non-GAAP financial measure used by UGI to evaluate the Partnership’s performance consistingTable of Partnership earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily haveContents
Partnership Agreement - Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009, as amended
Pennant - Pennant Midstream, LLC, a Delaware limited liability company

PGC - Purchased gas costs
PJM - PJM Interconnection, LLC
Proposed Merger - The transaction contemplated by the Merger Agreement pursuant to which AmeriGas Propane Holdings, LLC will merge with and into the Partnership, with the Partnership surviving as an indirect wholly owned subsidiary of UGI

PRP - Potentially responsible partyResponsible Party
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
ROU - Right-of-use
ROD - Record of Decision
SCAA - Storage contract administrative agreementsContract Administrative Agreements
SEC - U.S. Securities and Exchange Commission
Special Meeting - Special meeting of holders of Common Units to be held on August 21, 2019 to approve (i) the Merger Agreement and the transactions contemplated thereby, including the Proposed Merger, (ii) the adjournment of the Special Meeting, if necessary, to solicit additional proxies if there are not sufficient votes to approve the Merger Agreement and the transactions contemplated thereby, including the Proposed Merger, at the time of the Special Meeting and (iii) a non-binding advisory vote regarding certain compensation arrangements that may be payable to AmeriGas Partners’ named executive officers in connection with the completion of the Proposed Merger

Support Agreement - Agreement between the Partnership and the General Partner, dated as of April 1, 2019, pursuant to which the General Partner has agreed to vote all Common Units that it or its affiliates beneficially own as of the record date of the Special Meeting in favor of the Merger Agreement and the transactions contemplated thereby, including the Proposed Merger, at the Special Meeting

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

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 commitment;facility; (2) a three-year $300 million term loan commitment;facility; and (3) a five-year $300 million revolving credit facility (including a $10 million sublimit for letters of credit)


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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 Utilities 2019 Credit Agreement - An unsecured revolving credit agreement entered into by UGI Utilities 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

USD - U.S. dollar

U.S. Pension Plan - Defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities CPG, PNG and certain of UGI’s other domestic wholly owned subsidiaries

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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UGI CORPORATION AND SUBSIDIARIES

PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
 June 30,
2019		 September 30,
2018		 June 30,
2018		 December 31,
2019		 September 30,
2019		 December 31,
2018
ASSETS            
Current assets:            
Cash and cash equivalents $533.7
 $452.6
 $506.7
 $333.4
 $447.1
 $477.6
Restricted cash 42.3
 9.6
 7.7
 95.8
 63.7
 17.4
Accounts receivable (less allowances for doubtful accounts of $42.8, $35.1 and $43.4, respectively) 779.8
 751.9
 813.3
Accounts receivable (less allowances for doubtful accounts of $35.6, $31.6 and $38.5, respectively) 1,011.1
 640.7
 1,144.3
Accrued utility revenues 14.6
 14.0
 14.4
 80.2
 14.6
 64.7
Inventories 215.1
 318.2
 253.2
 247.5
 229.9
 293.7
Utility regulatory assets 3.5
 7.5
 2.2
 4.7
 9.1
 3.3
Derivative instruments 28.5
 142.5
 93.7
 28.4
 28.9
 60.2
Prepaid expenses and other current assets 100.1
 191.8
 117.0
 145.9
 132.2
 181.0
Total current assets 1,717.6
 1,888.1
 1,808.2
 1,947.0
 1,566.2
 2,242.2
Property, plant and equipment, at cost (less accumulated depreciation of $3,353.0, $3,153.9 and $3,131.0, respectively) 6,009.8
 5,808.2
 5,699.1
Property, plant and equipment, at cost (less accumulated depreciation of $3,490.1, $3,385.2 and $3,228.3, respectively) 6,783.6
 6,687.8
 5,855.1
Goodwill 3,159.1
 3,160.4
 3,169.0
 3,482.9
 3,456.4
 3,154.8
Intangible assets, net 480.0
 513.6
 529.8
 703.4
 708.6
 505.2
Utility regulatory assets 297.1
 293.5
 357.9
 385.8
 386.5
 295.5
Derivative instruments 29.9
 43.5
 23.1
 32.0
 43.2
 29.9
Other assets 325.4
 273.6
 289.6
 951.0
 497.9
 285.6
Total assets $12,018.9
 $11,980.9
 $11,876.7
 $14,285.7
 $13,346.6
 $12,368.3
LIABILITIES AND EQUITY            
Current liabilities:            
Current maturities of long-term debt $17.4
 $18.8
 $86.4
 $27.8
 $24.1
 $19.5
Short-term borrowings 380.2
 424.9
 299.1
 869.7
 796.3
 676.3
Accounts payable 444.4
 561.8
 443.4
 598.3
 438.8
 753.3
Derivative instruments 70.3
 11.7
 12.0
 113.3
 84.9
 56.8
Other current liabilities 682.4
 714.9
 725.4
 782.4
 682.8
 677.2
Total current liabilities 1,594.7
 1,732.1
 1,566.3
 2,391.5
 2,026.9
 2,183.1
Long-term debt 4,291.7
 4,146.5
 4,088.6
 5,827.6
 5,779.9
 4,150.7
Deferred income taxes 956.0
 991.9
 893.7
 562.5
 541.4
 973.4
Derivative instruments 22.1
 12.8
 12.3
 46.6
 48.4
 25.0
Other noncurrent liabilities 980.7
 997.6
 1,088.0
 1,452.9
 1,122.8
 989.5
Total liabilities 7,845.2
 7,880.9
 7,648.9
 10,281.1
 9,519.4
 8,321.7
Commitments and contingencies (Note 11) 

 

 

Commitments and contingencies (Note 10) 

 

 

Equity:            
UGI Corporation stockholders’ equity:            
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,678,299, 174,142,997 and 174,111,691 shares, respectively) 1,223.9
 1,200.8
 1,198.5
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 209,310,342, 209,304,129 and 174,262,763 shares, respectively) 1,398.4
 1,396.9
 1,206.5
Retained earnings 2,761.2
 2,610.7
 2,637.2
 2,797.5
 2,653.1
 2,620.8
Accumulated other comprehensive loss (145.4) (110.4) (111.6) (163.1) (216.6) (133.1)
Treasury stock, at cost (18.8) (19.7) (12.8) (37.4) (15.9) (24.8)
Total UGI Corporation stockholders’ equity 3,820.9
 3,681.4
 3,711.3
 3,995.4
 3,817.5
 3,669.4
Noncontrolling interests, principally in AmeriGas Partners 352.8
 418.6
 516.5
Noncontrolling interests 9.2
 9.7
 377.2
Total equity 4,173.7
 4,100.0
 4,227.8
 4,004.6
 3,827.2
 4,046.6
Total liabilities and equity $12,018.9
 $11,980.9
 $11,876.7
 $14,285.7
 $13,346.6
 $12,368.3
See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)
 Three Months Ended
June 30,		 Nine Months Ended
June 30,		 Three Months Ended
December 31,
 2019 2018 2019 2018 2019 2018
Revenues $1,363.7
 $1,440.9
 $6,170.0
 $6,378.1
 $2,006.6
 $2,200.2
Costs and expenses:            
Cost of sales (excluding depreciation and amortization shown below) 781.4
 732.5
 3,633.3
 3,430.1
 1,008.0
 1,425.0
Operating and administrative expenses 476.9
 495.1
 1,516.8
 1,536.7
 511.2
 503.2
Impairment of Partnership tradenames and trademarks —
 75.0
 —
 75.0
Depreciation and amortization 109.9
 118.8
 330.0
 341.3
 119.4
 111.2
Other operating income, net (14.1) (10.0) (26.2) (20.5) (9.2) (6.9)
 1,354.1
 1,411.4
 5,453.9
 5,362.6
 1,629.4
 2,032.5
Operating income 9.6
 29.5
 716.1
 1,015.5
 377.2
 167.7
Income from equity investees 1.5
 1.3
 4.6
 3.0
 6.5
 1.5
Loss on extinguishments of debt —
 —
 (6.1) —
 —
 (6.1)
Other non-operating income, net 0.7
 24.6
 17.6
 4.1
Other non-operating (expense) income, net (11.5) 9.0
Interest expense (60.5) (56.5) (181.7) (172.8) (84.1) (60.2)
(Loss) income before income taxes (48.7) (1.1) 550.5
 849.8
Income tax benefit (expense) 2.2
 (10.6) (111.8) (19.6)
Net (loss) income including noncontrolling interests (46.5) (11.7) 438.7
 830.2
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners 44.6
 64.1
 (131.0) (135.9)
Net (loss) income attributable to UGI Corporation $(1.9) $52.4
 $307.7
 $694.3
(Loss) earnings per common share attributable to UGI Corporation stockholders:        
Income before income taxes 288.1
 111.9
Income tax expense (76.1) (23.4)
Net income including noncontrolling interests 212.0
 88.5
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners —
 (24.3)
Net income attributable to UGI Corporation $212.0
 $64.2
Earnings per common share attributable to UGI Corporation stockholders:    
Basic $(0.01) $0.30
 $1.76
 $4.00
 $1.01
 $0.37
Diluted $(0.01) $0.30
 $1.73
 $3.93
 $1.00
 $0.36
Weighted-average common shares outstanding (thousands):            
Basic 174,759
 173,991
 174,541
 173,744
 209,439
 174,413
Diluted 174,759
 176,807
 177,389
 176,702
 211,258
 177,566
Dividends declared per common share $0.30
 $0.26
 $0.82
 $0.76
See accompanying notes to condensed consolidated financial statements.


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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Millions of dollars)
 Three Months Ended
December 31,
 2019 2018
Net income including noncontrolling interests$212.0
 $88.5
Other comprehensive income (loss):   
Net gains (losses) on derivative instruments (net of tax of $(2.2) and $0.4, respectively)5.6
 (1.5)
Reclassifications of net losses on derivative instruments (net of tax of $(0.3) and $(0.3), respectively)0.7
 0.7
Foreign currency adjustments (net of tax of $7.2 and $2.8, respectively)47.0
 (15.6)
Benefit plans (net of tax of $(0.1) and $(0.1), respectively)0.2
 0.3
Other comprehensive income (loss)53.5
 (16.1)
Comprehensive income including noncontrolling interests265.5
 72.4
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners—
 (24.3)
Comprehensive income attributable to UGI Corporation$265.5
 $48.1
See accompanying notes to condensed consolidated financial statements.


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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Millions of dollars)
  Three Months Ended
June 30,		 Nine Months Ended
June 30,
  2019 2018 2019 2018
Net (loss) income including noncontrolling interests $(46.5) $(11.7) $438.7
 $830.2
Other comprehensive income (loss):        
Net (losses) gains on derivative instruments (net of tax of $0.6, $(1.5), $2.0 and $(0.6), respectively) (1.6) 3.7
 (4.3) 1.7
Reclassifications of net losses on derivative instruments (net of tax of $(0.2), $(0.2), $(0.5) and $(1.6), respectively) 0.7
 0.2
 1.4
 2.6
Foreign currency adjustments (net of tax of $2.7, $0.0, $(2.2) and $(0.1), respectively) 16.1
 (82.0) (26.3) (23.8)
Benefit plans (net of tax of $(0.1), $(0.2), $(0.3) and $(0.5), respectively) 0.2
 0.6
 0.8
 1.3
Other comprehensive income (loss) 15.4
 (77.5) (28.4) (18.2)
Comprehensive (loss) income including noncontrolling interests (31.1) (89.2) 410.3
 812.0
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners 44.6
 64.1
 (131.0) (135.9)
Comprehensive income (loss) attributable to UGI Corporation $13.5
 $(25.1) $279.3
 $676.1
See accompanying notes to condensed consolidated financial statements.


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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
 Nine Months Ended
June 30,		 Three Months Ended
December 31,
 2019 2018 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES        
Net income including noncontrolling interests $438.7
 $830.2
 $212.0
 $88.5
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:        
Depreciation and amortization 330.0
 341.3
 119.4
 111.2
Deferred income tax benefit, net (38.6) (182.5)
Deferred income tax expense (benefit), net 5.0
 (20.7)
Provision for uncollectible accounts 25.3
 30.9
 7.8
 10.3
Changes in unrealized gains and losses on derivative instruments 200.7
 (54.0) 27.3
 165.9
Impairment of Partnership tradenames and trademarks —
 75.0
Loss on extinguishments of debt 6.1
 —
 —
 6.1
Income from equity investees (6.5) (1.5)
Other, net 2.6
 9.7
 (9.4) 12.4
Net change in:        
Accounts receivable and accrued utility revenues (51.3) (202.1) (431.6) (457.6)
Inventories 101.2
 28.1
 (15.6) 23.0
Utility deferred fuel and power costs, net of changes in unsettled derivatives (19.3) 39.8
 4.8
 (12.5)
Accounts payable (97.9) (17.7) 182.6
 217.4
Derivative instruments collateral deposits paid (14.5) (6.8)
Derivative instruments collateral deposits received (paid) 20.4
 (22.2)
Other current assets 79.4
 (0.5) (8.0) (11.4)
Other current liabilities (37.8) 35.4
 10.2
 (12.3)
Net cash provided by operating activities 924.6
 926.8
 118.4
 96.6
CASH FLOWS FROM INVESTING ACTIVITIES        
Expenditures for property, plant and equipment (510.2) (394.2) (182.0) (183.3)
Acquisitions of businesses and assets, net of cash acquired (58.4) (190.7)
Acquisitions of businesses and assets, net of cash and restricted cash acquired —
 (15.0)
Other, net 5.1
 9.4
 6.1
 4.3
Net cash used by investing activities (563.5) (575.5) (175.9) (194.0)
CASH FLOWS FROM FINANCING ACTIVITIES        
Dividends on UGI Common Stock (142.8) (131.8) (67.9) (45.3)
Distributions on AmeriGas Partners publicly held Common Units (198.1) (197.3) —
 (65.7)
Issuances of long-term debt, net of issuance costs 878.1
 124.4
 15.0
 728.9
Repayments of long-term debt (728.5) (141.3) (31.1) (721.1)
Decrease in short-term borrowings (99.6) (32.0)
Receivables Facility net borrowings (repayments) 55.0
 (39.0)
Increase in short-term borrowings 51.4
 243.4
Receivables Facility net borrowings 22.0
 8.0
Issuances of UGI Common Stock 15.3
 60.5
 0.6
 6.9
Repurchases of UGI Common Stock (16.9) (43.5) (22.6) (16.9)
Other, net (4.1) (2.3) —
 (4.2)
Net cash used by financing activities (241.6) (402.3)
EFFECT OF EXCHANGE RATE CHANGES ON CASH (5.7) (3.3)
Cash, cash equivalents and restricted cash increase (decrease) $113.8
 $(54.3)
Net cash (used) provided by financing activities (32.6) 134.0
Effect of exchange rate changes on cash, cash equivalents and restricted cash 8.5
 (3.8)
Cash, cash equivalents and restricted cash (decrease) increase $(81.6) $32.8
CASH, CASH EQUIVALENTS AND RESTRICTED CASH        
Cash, cash equivalents and restricted cash at end of period $576.0
 $514.4
 $429.2
 $495.0
Cash, cash equivalents and restricted cash at beginning of period 462.2
 568.7
 510.8
 462.2
Cash, cash equivalents and restricted cash increase (decrease) $113.8
 $(54.3)
Cash, cash equivalents and restricted cash (decrease) increase $(81.6) $32.8
See accompanying notes to condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(Millions of dollars, except per share amounts)
Three Months Ended
June 30,		 Nine Months Ended
June 30,		 Three Months Ended
December 31,
2019 2018 2019 2018 2019 2018
Common stock, without par value           
Balance, beginning of period$1,219.0
 $1,193.4
 $1,200.8
 $1,188.6
 $1,396.9
 $1,200.8
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld1.3
 2.1
 10.7
 (1.7)
Common Stock issued in connection with employee and director plans, net of tax withheld 0.3
 3.7
Equity-based compensation expense3.6
 3.0
 12.4
 11.6
 1.9
 2.0
Other (0.7) —
Balance, end of period$1,223.9
 $1,198.5
 $1,223.9
 $1,198.5
 $1,398.4
 $1,206.5
Retained earnings           
Balance, beginning of period$2,818.2
 $2,656.6
 $2,610.7
 $2,106.7
 $2,653.1
 $2,610.7
Cumulative effect of change in accounting principle - ASC 606—
 —
 (7.1) —
 —
 (7.1)
Reclassification of stranded income tax effects related to TCJA—
 —
 6.6
 —
 —
 6.6
Losses on common stock transactions in connection with employee and director plans(2.8) (26.6) (13.9) (32.0) (0.7) (8.3)
Net (loss) income attributable to UGI(1.9) 52.4
 307.7
 694.3
Cash dividends on UGI Common Stock ($0.30, $0.26, $0.82 and $0.76 per share, respectively)(52.3) (45.2) (142.8) (131.8)
Net income attributable to UGI 212.0
 64.2
Cash dividends on UGI Common Stock ($0.325 and $0.260 per share, respectively) (67.9) (45.3)
Other 1.0
 —
Balance, end of period$2,761.2
 $2,637.2
 $2,761.2
 $2,637.2
 $2,797.5
 $2,620.8
Accumulated other comprehensive income (loss)           
Balance, beginning of period$(160.8) $(34.1) $(110.4) $(93.4) $(216.6) $(110.4)
Reclassification of stranded income tax effects related to TCJA—
 —
 (6.6) —
 —
 (6.6)
Net (losses) gains on derivative instruments(1.6) 3.7
 (4.3) 1.7
Net gains (losses) on derivative instruments 5.6
 (1.5)
Reclassification of net losses on derivative instruments0.7
 0.2
 1.4
 2.6
 0.7
 0.7
Benefit plans0.2
 0.6
 0.8
 1.3
 0.2
 0.3
Foreign currency adjustments16.1
 (82.0) (26.3) (23.8) 47.0
 (15.6)
Balance, end of period$(145.4) $(111.6) $(145.4) $(111.6) $(163.1) $(133.1)
Treasury stock           
Balance, beginning of period$(23.4) $(41.6) $(19.7) $(38.6) $(15.9) $(19.7)
Common Stock issued in connection with employee and director plans, net of tax withheld4.6
 62.4
 20.6
 75.4
 1.1
 12.2
Repurchases of UGI Common Stock—
 (29.4) (16.9) (43.5) (22.6) (16.9)
Reacquired UGI Common Stock - employee and director plans—
 (4.2) (2.8) (6.1) —
 (0.4)
Balance, end of period$(18.8) $(12.8) $(18.8) $(12.8) $(37.4) $(24.8)
Total UGI stockholders’ equity$3,820.9
 $3,711.3
 $3,820.9
 $3,711.3
 $3,995.4
 $3,669.4
Noncontrolling interests           
Balance, beginning of period$463.0
 $646.7
 $418.6
 $577.6
 $9.7
 $418.6
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners(44.6) (64.1) 131.0
 135.9
Net income attributable to noncontrolling interests, principally in AmeriGas Partners —
 24.3
Dividends and distributions(65.8) (65.7) (197.3) (197.5) —
 (65.7)
Other0.2
 (0.4) 0.5
 0.5
 (0.5) —
Balance, end of period$352.8
 $516.5
 $352.8
 $516.5
 $9.2
 $377.2
Total equity$4,173.7
 $4,227.8
 $4,173.7
 $4,227.8
 $4,004.6
 $4,046.6
See accompanying notes to condensed consolidated financial statements.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)


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 (1) are the general partnerown and own limited partner interests inoperate (1) 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 market energy products and services.

We conduct a domestic propane marketing and distribution business through AmeriGas Partners. AmeriGas Partners is a publicly traded limited partnership that 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 August 21, 2019, we completed the AmeriGas Merger pursuant to which we issued 34,612,847 shares of UGI Common Stock and paid $528.9 in cash to acquire all of the outstanding Common Units in AmeriGas Partners andnot already held by UGI or its subsidiaries, with the Partnership surviving as a wholly owned subsidiary of UGI. Prior to the AmeriGas OLP. At June 30, 2019,Merger, UGI controlled the Partnership through its ownership of the General Partner, which held a 1% general partner interest (which included IDRs) and a 25.3% limited partner interestapproximately 25.5% of the outstanding Common Units in AmeriGas Partners, and held an effective 27.0% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises Common Units. The remaining 73.7% interest in AmeriGas Partners comprises Common UnitsIDRs held by the public. The General Partner also holds incentive distribution rights that entitleprior to the AmeriGas Merger entitled it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 14 of the Company’s 2018 Annual Report.circumstances. Incentive distributions received by the General Partner during the ninethree months ended June 30, 2019 andDecember 31, 2018 were $34.3 and $34.0, respectively.$11.3.

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., eastern Ohio and the panhandle of West Virginia. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. HVAC also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania. Energy Services and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation 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, for a total of approximately $1,275 in cash, subject to working capital and other adjustments. CMG and its direct and indirect subsidiaries provide natural gas gathering and processing services through five discrete systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia. See Note 17 for further information.

UGI Utilities directly owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one1 Maryland county directly and, prior to the Utility Merger on October 1, 2018, through PNG and CPG.county. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one1 Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.

Proposed Merger

On April 1, 2019, we entered into the Merger Agreement, pursuant to which Merger Sub will merge with and into the Partnership, with the Partnership surviving as an indirect, wholly owned subsidiary of UGI. Under the terms of the Merger Agreement, at the effective time of the Proposed Merger, each outstanding Common Unit other than Common Units owned by UGI and its subsidiaries, including the General Partner, will be converted into the right to receive, at the election of each holder of such Common Units, one of the following forms of merger consideration:

(i)0.6378 shares of UGI common stock;
(ii)$7.63 in cash, without interest, and 0.500 shares of UGI common stock; or
(iii)$35.325 in cash, without interest.

The merger consideration is subject to proration designed to ensure that the total number of shares of UGI common stock issuable as merger consideration will equal approximately 34.6 million shares, and the amount of cash consideration paid will equal

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

approximately $530. Also, at the effective time of the Proposed Merger, the General Partner’s 1% economic general partner interest in AmeriGas Partners, which includes its incentive distribution rights, will convert into (i) 10,615,711 Common Units, which will remain outstanding as partnership interests in AmeriGas Partners, and (ii) a non-economic general partner interest in AmeriGas Partners. Pursuant to the Merger Agreement, until such time as the Proposed Merger becomes effective, the General Partner will continue to declare and cause to be paid regular quarterly cash distributions on outstanding Common Units in accordance with the Partnership Agreement in an amount that will not be less than $0.95 per Common Unit. In addition, the Merger Agreement requires that the record date for the quarterly cash distribution related to the quarter immediately prior to the quarter in which the closing of the Proposed Merger occurs be designated so that such record date precedes the closing of the Proposed Merger so as to permit the payment of such quarterly distribution to the holders of the Common Units; provided that the Partnership’s unitholders are not intended to receive, for any quarter, distributions both in respect of Common Units and also dividends in respect of shares of UGI common stock that they receive in exchange for such Common Units in the transaction.

Completion of the Proposed Merger is subject to certain customary conditions, including, among others: (i) approval of the Merger Agreement by holders of a majority of the outstanding Common Units; (ii) there being no law or injunction prohibiting consummation of the transactions contemplated under the Merger Agreement; (iii) the effectiveness of a registration statement on Form S-4 relating to the issuance of shares of UGI common stock pursuant to the Merger Agreement; (iv) approval for listing on the New York Stock Exchange of the shares of UGI common stock issuable pursuant to the Merger Agreement; (v) subject to specified materiality standards, the accuracy of certain representations and warranties of the other party; and (vi) compliance by the respective parties in all material respects with their respective covenants. UGI’s registration statement on Form S-4 relating to the Proposed Merger became effective on July 12, 2019.

Pursuant to a Support Agreement, the General Partner has agreed to vote all Partnership Common Units that it or its affiliates beneficially own as of the record date of the Special Meeting in favor of the Merger Agreement and the Proposed Merger.

The Merger Agreement provides for certain termination rights for both UGI and the Partnership which, under certain circumstances, would require the Partnership to pay UGI a termination fee of $20 and/or reimburse UGI for expenses in an amount not to exceed $5, or require UGI to reimburse the Partnership for expenses not to exceed $5.

Upon completion of the Proposed Merger, Common Units will no longer be publicly traded. Subject to the satisfaction or waiver of certain conditions, including the approval of the Merger Agreement by AmeriGas Partners’ unitholders at the Special Meeting to be held on August 21, 2019, the Proposed Merger is expected to close in the fourth quarter of Fiscal 2019.

The Proposed Merger will be accounted for in accordance with ASC 810, Consolidation - Overall-Changes in a Parent’s Ownership Interest in a Subsidiary. Because UGI controls AmeriGas Partners before and after the Proposed Merger, the changes in UGI’s ownership interest in the Partnership resulting from the merger will be accounted for as an equity transaction and no gain or loss will be recognized in UGI’s consolidated income statement. In addition, the carrying amounts of AmeriGas Partners’ assets and liabilities will not be adjusted. Finally, the tax effects of the merger will be reported as adjustments to deferred income taxes and UGI stockholders’ equity.

Note 2 — Summary of Significant Accounting Policies

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the SEC. They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2018,2019, Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all footnote disclosures from the annual financial statements.

These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 20182019 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Revenue Recognition.Leases. Effective October 1, 2018,2019, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,”2016-02, "Leases," which, as amended, is included in ASC 606.842. This new accounting guidance supersedes previous revenue recognition requirementslease accounting guidance in ASC 605. ASC 606840 and requires entities that an entitylease assets to recognize revenue to depict the transferassets and liabilities for the rights and obligations created by those leases on its balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty 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 orcash flows from leases.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

services. We adopted this new accounting guidance using the modified retrospective transition methodmethod. Amounts and disclosures related to those contracts which were not completed as of October 1, 2018. Periodsperiods prior to October 1, 2018,2019 have not been restated and continue to be reported in accordance with ASC 605. The Company840. We elected to apply the following practical expedients in accordance with the guidance upon adoption:

Short-term leases: We did not recognize short-term leases (term of 12 months or less) on the balance sheet;
Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases; and
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 ASC 842.

Upon adoption, we recorded a $7.1 reductionROU assets and lease liabilities of $451.9 related to our operating leases. Our accounting for finance leases remained substantially unchanged. There were no cumulative effect adjustments made 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.2019. The adoption of ASC 606 did not, and is not expected to, have a materialsignificant impact on the amountour condensed consolidated statements of income 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.
flows. See Note 49 for additional disclosures regarding our leases.
Equity Method Investments. 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 Company’s revenueequity method. Our equity method investments are primarily comprised of PennEast and Pennant.
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. 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 contractsbringing 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. Following the Third Circuit denial of petition for rehearing, PennEast filed a petition for declaratory order with customers.the FERC regarding interpretation of the Natural Gas Act; the FERC issued an order favorable to PennEast’s position on January 30, 2020. 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.

Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3), changes in restricted cash is no longer reflected as a separate investing activity but included in cash, cash equivalents and restricted cash when reconciling the beginning and end of period total amounts in the Company’s Condensed Consolidated Statements of Cash Flows. The guidance required retrospective application, which resulted in adjustments to the previously reported cash flows from investing activities for the nine months ended June 30, 2018, increasing net cash used by investing activities by $2.6.

The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows.
 Cash, Cash Equivalents and Restricted Cash Cash, Cash Equivalents and Restricted Cash
 
June 30,
2019
 
June 30,
2018
 September 30, 2018 September 30, 2017 December 31, 2019 December 31, 2018 September 30, 2019 September 30, 2018
Cash and cash equivalents $533.7
 $506.7
 $452.6
 $558.4
 $333.4
 $477.6
 $447.1
 $452.6
Restricted cash 42.3
 7.7
 9.6
 10.3
 95.8
 17.4
 63.7
 9.6
Cash, cash equivalents and restricted cash $576.0
 $514.4
 $462.2
 $568.7
 $429.2
 $495.0
 $510.8
 $462.2


Earnings Per Common Share. Basic earnings per share attributable to UGI shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI include the effects of dilutive stock options and common stock awards.
 

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

Shares used in computing basic and diluted earnings per share are as follows: 
 Three Months Ended
June 30,		 Nine Months Ended
June 30,		 Three Months Ended
December 31,
 2019 2018 2019 2018 2019 2018
Denominator (thousands of shares):            
Weighted-average common shares outstanding — basic(a) 174,759
 173,991
 174,541
 173,744
 209,439
 174,413
Incremental shares issuable for stock options and awards (a)(b) —
 2,816
 2,848
 2,958
 1,819
 3,153
Weighted-average common shares outstanding — diluted 174,759
 176,807
 177,389
 176,702
 211,258
 177,566

(a)The three months ended December 31, 2019, reflects the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger.
(b)For the three months ended June 30,December 31, 2019 incremental shares of 2,576 have been excluded as such incremental shares would be antidilutive due to the net loss for the period. For the nine months ended June 30, 2019,and 2018, there were 2443,499 and 30 shares, respectively, associated with outstanding stock option awards that were excluded from the computation of diluted earnings per share above because their effect was antidilutive. There were no such shares for the three and nine months ended June 30, 2018.

Derivative Instruments. Derivative instruments are reported on the Condensed 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

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

instrument, and 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 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.

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. 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, net” on the Condensed Consolidated Statements of Income.

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 Condensed 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 Condensed 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 14.13.

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, if necessary,under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation.

Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP.  AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.

Our results for the three and nine months ended June 30, 2018 were significantly affected by the enactment of the TCJA in the U.S. and the enactment of the December 2017 French Finance Bills in France. See Note 6 for additional information regarding the effects of the TCJA and the December 2017 French Finance Bills.

Other non-operating (expense) income, (expense), net. Included in “Other non-operating (expense) income, net,” on the Condensed Consolidated Statements of Income are net gains and 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.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Reclassifications. Certain amounts for the three and nine months ended June 30, 2018, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.

Note 3 — Accounting Changes

New Accounting Standards Adopted Effective October 1, 2018

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. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. 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. The adoption of the new guidance did not have a material impact on our results of operations for the three and nine months ended June 30, 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.

The guidance became effective for the Company beginning October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization. The Company’s Condensed Consolidated Statement of Income for the three and nine months ended June 30, 2018, has been recast to reflect the retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit cost, net of estimated amounts capitalized, within “Other non-operating income, net,” on the Condensed Consolidated Statement of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.”

The amount of income (expense) comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Other non-operating income, net,” totaled $0.1 and $0.4, respectively, for the three and nine months ended June 30, 2019, and $(1.0) and $(5.7), respectively, for the three and nine months ended June 30, 2018.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

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. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance resulted in a change in presentation of restricted cash on the Condensed Consolidated Statements of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statements of Cash Flows and disclosures (see Note 2, “Restricted Cash”).
Accounting Standards Not Yet Adopted

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 defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1,Fiscal 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

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. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

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). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requiresrequired a modified retrospective approach. The amended presentation and disclosure guidance iswas required prospectively. The Company expects to adoptadopted the new guidance in the first quarter of Fiscal 2020.effective October 1, 2019. The adoption of the new guidance isdid not expected to have a material impact on the Company’sour consolidated financial statements.

Leases. Effective October 1, 2019, the Company adopted new accounting guidance for leases in accordance with ASC 842. See Notes 2 and 9 for a detailed description of the impact of the new guidance and related disclosures.

Accounting Standards Not Yet Adopted

Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU, as subsequently amended, 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 forlosses related to 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.

Income Taxes. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” This ASU simplifies the accounting for income taxes by eliminating certain exceptions within the existing guidance for recognizing deferred taxes for equity method investments, performing intraperiod allocations and calculating income taxes in interim periods. Further, this ASU clarifies existing guidance related to, among other things, recognizing deferred taxes for goodwill and allocated taxes to members of a consolidated group. ASU 2019-12 is effective for the Company for interim and annual periods beginning October 1, 2021 (Fiscal 2022). 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.

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). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements 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 will adopt ASU No. 2016-02, as updated, effective October 1, 2019, and expect to elect the transition option which would allow the Company to maintain historical presentation for periods

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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption and future reporting required by the standard.

Note 4 — Revenue from Contracts with Customers

The Company recognizes revenue when control of promised goods or services is transferred to our 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 our performance completed to date. As such, we have elected to recognize revenueSee Note 4 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 contractsCompany’s 2019 Annual Report for which we recognize revenueinformation 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 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.

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

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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

excess of amounts needed to meetRevenue Disaggregation
The following tables present 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 PJMdisaggregated revenues 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. 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 contractsreportable segment for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to customers at a fixed pricethree months ended December 31, 2019 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.2018:
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 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 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.
Three Months Ended December 31, 2019  Total  Eliminations  AmeriGas Propane  UGI International  Midstream & Marketing (a)  UGI Utilities (a)  Corporate & Other
Revenues from contracts with customers:              
Utility:              
Core Market:              
Residential $184.1
 $—
 $—
 $—
 $—
 $184.1
 $—
Commercial & Industrial 67.9
 —
 —
 —
 —
 67.9
 —
Large delivery service 41.3
 —
 —
 —
 —
 41.3
 —
Off-system sales and capacity releases 16.4
 (14.1) —
 —
 —
 30.5
 —
Other 4.4
 (0.6) —
 —
 —
 5.0
 —
Total Utility 314.1
 (14.7) —
 —
 —
 328.8
 —
Non-Utility:              
LPG:              
Retail 1,094.4
 —
 631.2
 463.2
 —
 —
 —
Wholesale 65.8
 —
 22.0
 43.8
 —
 —
 —
Energy Marketing 362.9
 (25.6) —
 123.9
 264.6
 —
 —
Midstream:              
Pipeline 43.2
 —
 —
 —
 43.2
 —
 —
Peaking 3.9
 (37.7) —
 —
 41.6
 —
 —
Other 1.8
 —
 —
 —
 1.8
 —
 —
Electricity Generation 8.8
 —
 —
 —
 8.8
 —
 —
Other 80.9
 (0.9) 59.2
 12.3
 10.3
 —
 —
Total Non-Utility 1,661.7
 (64.2) 712.4
 643.2
 370.3
 —
 —
Total revenues from contracts with customers 1,975.8
 (78.9) 712.4
 643.2
 370.3
 328.8
 —
Other revenues (b) 30.8
 (0.8) 18.0
 8.2
 2.2
 0.5
 2.7
Total revenues $2,006.6
 $(79.7) $730.4
 $651.4
 $372.5
 $329.3
 $2.7


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

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 which 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 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 & 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 also sells power generated from our 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.
Three Months Ended December 31, 2018  Total  Eliminations  AmeriGas Propane  UGI International  Midstream & Marketing (a)  UGI Utilities (a)  Corporate & Other
Revenues from contracts with customers:              
Utility:              
Core Market:              
Residential $175.7
 $—
 $—
 $—
 $—
 $175.7
 $—
Commercial & Industrial 67.6
 —
 —
 —
 —
 67.6
 —
Large delivery service 39.5
 —
 —
 —
 —
 39.5
 —
Off-system sales and capacity releases 15.2
 (22.9) —
 —
 —
 38.1
 —
Other (c) 0.5
 (0.7) —
 —
 —
 1.2
 —
Total Utility 298.5
 (23.6) —
 —
 —
 322.1
 —
Non-Utility:              
LPG:              
Retail 1,229.7
 —
 721.9
 507.8
 —
 —
 —
Wholesale 60.0
 —
 21.0
 39.0
 —
 —
 —
Energy Marketing 468.9
 (47.5) —
 143.1
 373.3
 —
 —
Midstream:              
Pipeline 19.4
 —
 —
 —
 19.4
 —
 —
Peaking 2.0
 (38.7) —
 —
 40.7
 —
 —
Other 1.0
 —
 —
 —
 1.0
 —
 —
Electricity Generation 11.7
 —
 —
 —
 11.7
 —
 —
Other 84.0
 (0.7) 60.6
 12.4
 11.7
 —
 —
Total Non-Utility 1,876.7
 (86.9) 803.5
 702.3
 457.8
 —
 —
Total revenues from contracts with customers 2,175.2
 (110.5) 803.5
 702.3
 457.8
 322.1
 —
Other revenues (b) 25.0
 (1.1) 16.7
 8.4
 1.6
 0.6
 (1.2)
Total revenues $2,200.2
 $(111.6) $820.2
 $710.7
 $459.4
 $322.7
 $(1.2)

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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
(a)Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(b)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.
(c)UGI Utilities includes an unallocated negative surcharge revenue reduction of $(4.1) for the three months ended December 31, 2018 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA.

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 June 30, 2019.for all periods presented. 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 Condensed 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 $75.0$93.1, $114.1 and $115.6$94.0 at JuneDecember 31, 2019, September 30, 2019 and October 1,December 31, 2018, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the ninethree months ended June 30,December 31, 2019 and 2018, from the amount included in contract liabilities at October 1,September 30, 2019 and 2018, was $89.3.

Revenue Disaggregation
The following tables present our disaggregated revenues by reportable segment for the three$61.0 and nine months ended June 30, 2019:$58.1, respectively.

Three Months Ended June 30, 2019  Total  Eliminations  AmeriGas Propane  UGI International  Midstream & Marketing (a)  UGI Utilities (a)  Corporate & Other
Revenues from contracts with customers:              
Utility:              
Core Market:              
Residential $78.1
 $—
 $—
 $—
 $—
 $78.1
 $—
Commercial & Industrial 34.2
 —
 —
 —
 —
 34.2
 —
Large delivery service 27.8
 —
 —
 —
 —
 27.8
 —
Off-system sales and capacity releases 4.0
 (10.1) —
 —
 —
 14.1
 —
Other (b) 8.3
 (0.8) —
 —
 —
 9.1
 —
Total Utility 152.4
 (10.9) —
 —
 —
 163.3
 —
Non-Utility:              
LPG:              
Retail 754.1
 —
 405.9
 348.2
 —
 —
 —
Wholesale 44.5
 —
 8.8
 35.7
 —
 —
 —
Energy Marketing 274.8
 (23.7) —
 80.4
 218.1
 —
 —
Midstream: 

            
Pipeline 17.6
 —
 —
 —
 17.6
 —
 —
Peaking 3.2
 (3.2) —
 —
 6.4
 —
 —
Other 0.1
 —
 —
 —
 0.1
 —
 —
Electricity Generation 8.9
 —
 —
 —
 8.9
 —
 —
Other 76.2
 (1.1) 48.2
 14.6
 14.5
 —
 —
Total Non-Utility 1,179.4
 (28.0) 462.9
 478.9
 265.6
 —
 —
Total revenues from contracts with customers 1,331.8
 (38.9) 462.9
 478.9
 265.6
 163.3
 —
Other revenues (c) 31.9
 (0.7) 15.8
 7.7
 1.7
 0.6
 6.8
Total revenues $1,363.7
 $(39.6) $478.7
 $486.6
 $267.3
 $163.9
 $6.8


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Nine Months Ended June 30, 2019  Total  Eliminations  AmeriGas Propane  UGI International  Midstream & Marketing (a)  UGI Utilities (a)  Corporate & Other
Revenues from contracts with customers:              
Utility:              
Core Market:              
Residential $494.1
 $—
 $—
 $—
 $—
 $494.1
 $—
Commercial & Industrial 202.5
 —
 —
 —
 —
 202.5
 —
Large delivery service 111.4
 —
 —
 —
 —
 111.4
 —
Off-system sales and capacity releases 41.1
 (57.5) —
 —
 —
 98.6
 —
Other (b) 5.5
 (2.3) —
 —
 —
 7.8
 —
Total Utility 854.6
 (59.8) —
 —
 —
 914.4
 —
Non-Utility:              
LPG:              
Retail 3,389.4
 —
 2,002.4
 1,387.0
 —
 —
 —
Wholesale 198.3
 —
 55.0
 143.3
 —
 —
 —
Energy Marketing 1,295.8
 (117.6) —
 386.2
 1,027.2
 —
 —
Midstream:              
Pipeline 59.4
 —
 —
 —
 59.4
 —
 —
Peaking 13.3
 (93.6) —
 —
 106.9
 —
 —
Other 1.8
 —
 —
 —
 1.8
 —
 —
Electricity Generation 32.2
 —
 —
 —
 32.2
 —
 —
Other 239.7
 (2.5) 165.9
 39.7
 36.6
 —
 —
Total Non-Utility 5,229.9
 (213.7) 2,223.3
 1,956.2
 1,264.1
 —
 —
Total revenues from contracts with customers 6,084.5
 (273.5) 2,223.3
 1,956.2
 1,264.1
 914.4
 —
Other revenues (c) 85.5
 (2.5) 47.2
 24.3
 5.0
 1.8
 9.7
Total revenues $6,170.0
 $(276.0) $2,270.5
 $1,980.5
 $1,269.1
 $916.2
 $9.7

(a)Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(b)UGI Utilities includes an unallocated negative surcharge revenue increase (reduction) of $3.3 and $(11.3) for the three and nine months ended June 30, 2019, respectively, as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 8).
(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 June 30,December 31, 2019, Midstream & Marketing and UGI Utilities expect to record approximately $1.5$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.
Note 5 — 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.

The Company has accounted for the CMG Acquisition using the acquisition method. At December 31, 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.

The components of the preliminary CMG purchase price allocations are as follows:
Assets acquired: 
Cash$0.3
Accounts receivable11.3
Prepaid expenses and other current assets1.1
Property, plant and equipment613.2
Investment in Pennant88.0
Intangible assets (a)250.0
Total assets acquired$963.9
  
Liabilities assumed: 
Accounts payable3.3
Other noncurrent liabilities0.1
Total liabilities assumed$3.4
Goodwill323.9
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:

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

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 impact of the CMG Acquisition on a pro forma basis as if the CMG Acquisition had occurred on October 1, 2018 was not material to the Company’s consolidated results for the three months ended December 31, 2018.

Note 56 — Inventories

Inventories comprise the following: 
 June 30,
2019		 September 30,
2018		 June 30,
2018		 December 31,
2019		 September 30,
2019		 December 31,
2018
Non-utility LPG and natural gas $141.6
 $231.7
 $177.0
 $163.7
 $150.2
 $206.7
Gas Utility natural gas 15.5
 37.3
 18.6
 24.3
 26.6
 34.9
Materials, supplies and other 58.0
 49.2
 57.6
 59.5
 53.1
 52.1
Total inventories $215.1
 $318.2
 $253.2
 $247.5
 $229.9
 $293.7


At June 30,December 31, 2019, UGI Utilities was party to four3 principal SCAAs with terms of up to three years. Pursuant to the 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 JuneDecember 31, 2019 and 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 non-affiliates at September 30, 2018 and June 30,December 31, 2018 comprising 2.3 bcf and 1.21.9 bcf of natural gas was $5.4 and $2.7, respectively. There were no gas storage inventories associated with non-affiliates at June 30, 2019.$4.6.

Note 6 — Income Taxes

Results for the three and nine months ended June 30, 2018, reflect the impacts of two significant tax law changes in the U.S. and in France including remeasurement adjustments to deferred income tax assets and liabilities in the U.S. and France. The following sections describe these tax law changes.

TCJA

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.
In accordance with GAAP as determined by ASC 740, we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and nine months ended June 30, 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 Accounting Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During the three months ended December 31, 2018, adjustments to provisional amounts recorded in prior periods were not material.
As a result of the enactment of the TCJA on December 22, 2017, during the three and nine months ended June 30, 2018, we reduced our net deferred income tax liabilities by $0.8 and $389.6, respectively, due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment of the TCJA, and as a result of adjusting our original provisional amounts during the quarters ended March 31, 2018 and June 30, 2018. Because current law requires that excess deferred income taxes associated with UGI Utilities’ regulated utility plant assets are to be amortized no more rapidly than over the remaining lives

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

of the assets that gave rise to the excess deferred taxes, UGI Utilities recorded a regulatory liability related to such excess deferred income taxes (see Note 8).
For the nine months ended June 30, 2018, discrete deferred income tax adjustments reduced income tax expense by $172.1, which amount includes $0.8 of adjustments recorded during the three months ended June 30, 2018 in accordance with the previously mentioned SEC Staff Accounting Bulletin No. 118. The $172.1 discrete deferred income tax adjustment for the nine months ended June 30, 2018, was comprised of the following:
(1)a $181.1 reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate;
(2)the establishment of $7.6 of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and
(3)a $1.4 “toll tax” on un-repatriated foreign earnings.

For the three and nine months ended June 30, 2019 and 2018, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We are subject to a 21.0% U.S. federal tax rate in Fiscal 2019. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21% on January 1, 2018. As a result, our annual effective income tax rate used for the nine months ended June 30, 2019 was based upon a federal income tax rate of 21.0% and our annual effective tax rate used for the nine months ended June 30, 2018 was based upon a federal income tax rate of 24.5%. Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC.
December 2017 French Finance Bills
In December 2017, the December 2017 French Finance Bills were approved. 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 future corporate income tax rate reduction effective in Fiscal 2023, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $17.3. During the six months ended June 30, 2018, this estimated deferred tax benefit was adjusted downward by $3.8 to $13.5. The estimated annual effective income tax rate used in determining income taxes for the nine months ended June 30, 2018, reflected the impact of the single year Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills.
Note 7 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following: 
 June 30,
2019		 September 30,
2018		 June 30,
2018		 December 31,
2019		 September 30,
2019		 December 31,
2018
Goodwill (not subject to amortization) $3,159.1
 $3,160.4
 $3,169.0
Goodwill $3,482.9
 $3,456.4
 $3,154.8
Intangible assets:            
Customer relationships, noncompete agreements and other $844.7
 $848.6
 $852.5
Customer relationships $1,054.9
 $1,038.4
 $795.4
Trademarks and tradenames 16.4
 7.9
 7.9
 16.4
 16.2
 7.9
Noncompete agreements and other 54.8
 46.4
 57.6
Accumulated amortization (432.7) (393.2) (381.2) (473.5) (441.8) (405.4)
Intangible assets, net (definite-lived) 428.4
 463.3
 479.2
 652.6
 659.2
 455.5
Trademarks and tradenames (indefinite-lived) 51.6
 50.3
 50.6
 50.8
 49.4
 49.7
Total intangible assets, net $480.0
 $513.6
 $529.8
 $703.4
 $708.6
 $505.2


The changeschange in goodwill and intangible assets aresince September 30, 2019 is primarily due to acquisitions and the effects of foreign currency translation. Amortization expense of intangible assets was $14.6$16.8 and $14.9$14.6 for the three months ended June 30, 2019 and 2018, respectively, and $43.7 and $43.4 for the nine months ended June 30,December 31, 2019 and 2018, respectively. Amortization expense included in “Cost of sales” on the Condensed Consolidated Statements of Income was not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 20192020 and for the next four fiscal years is as follows: remainder of Fiscal 2019 — $14.9; Fiscal 2020 — $58.1;$48.7; Fiscal 2021 — $54.9;$61.8; Fiscal 2022 — $51.8;$58.8; Fiscal 2023 — $50.3.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the 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 three months ended June 30, 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and, in accordance with GAAP associated with intangible assets, adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9. During the three months ended June 30, 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 Condensed 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.$57.3; Fiscal 2024 — $56.1.

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 89 in the Company’s 20182019 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets listed below. The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets:
 June 30,
2019		 September 30,
2018		 June 30,
2018		 December 31,
2019		 September 30,
2019		 December 31,
2018
Regulatory assets:            
Income taxes recoverable $123.9
 $110.1
 $130.0
 $121.2
 $115.2
 $115.2
Underfunded pension and postretirement plans 81.8
 87.1
 132.2
 175.2
 178.6
 85.3
Environmental costs 56.6
 58.8
 59.8
 57.5
 59.5
 58.5
Removal costs, net 29.3
 32.0
 31.0
 26.7
 28.3
 31.3
Other 9.0
 13.0
 7.1
 9.9
 14.0
 8.5
Total regulatory assets $300.6
 $301.0
 $360.1
 $390.5
 $395.6
 $298.8
Regulatory liabilities (a):            
Postretirement benefits $16.5
 $17.8
 $16.9
Postretirement benefit overcollections $14.1
 $14.5
 $17.3
Deferred fuel and power refunds 12.4
 36.7
 44.5
 6.3
 6.1
 22.2
State tax benefits — distribution system repairs 25.2
 22.6
 20.7
 26.3
 25.0
 23.5
PAPUC temporary rates order 25.4
 24.4
 24.1
PAPUC Temporary Rates Order 25.0
 31.3
 24.8
Excess federal deferred income taxes 282.7
 285.2
 301.2
 278.1
 279.5
 280.9
Other 14.0
 3.5
 5.1
 1.4
 2.4
 4.8
Total regulatory liabilities $376.2
 $390.2
 $412.5
 $351.2
 $358.8
 $373.5

(a)
Regulatory liabilities are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.


18
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

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 June 30,December 31, 2019, September 30, 20182019 and June 30,December 31, 2018 were $(2.1)$(2.9), $2.9$(2.2) and $1.9,$0.8, respectively.

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 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

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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

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 will remain in place until the effective date of new rates established in Gas Utility’s current general base rate proceeding filed January 28, 2019.
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). In its initial filing, Gas Utility has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $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 Order. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates.
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 6). 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 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 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, 2019,2020, Gas Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial and industrial customers by $71.1$74.6 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund newto continue funding programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, Gas Utility has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $24.0 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates. Gas Utility requested that the new gas rates become effective March 29, 2019. The28, 2020. However, the PAPUC entered an Order dated February 28, 2019, suspendingtypically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the rate increasefiling date to allow for investigation and public hearings. On July 22, 2019, a Joint Petition for Approval of Settlement of all issues supported by all active parties was filed with the PAPUC. The Joint Petition is subject to receipt of a recommended decision by a PAPUC administrative law judge and an order of the PAPUC approving the settlement. Unless the PAPUC issues a final order prior to the end of the statutory suspension period, October 28, 2019, the initial proposed rate increase will become effective the next day, subject to refund and a subsequent PAPUC order. The CompanyUGI Utilities cannot predict the timing or the ultimate outcome of the rate case review process.

On January 26, 2018, Electric28, 2019, Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial, and industrial customers throughout its annualPennsylvania service territory by an aggregate $71.1. 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 $9.2, which was later reduced by Electric$30.0 under a single consolidated tariff, approved a plan for uniform class rates, and permits Gas Utility to $7.7extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years. The PAPUC’s final Order approved a negative surcharge, to reflectreturn to customers $24.0 of tax benefits experienced by Gas Utility over the impactperiod January 1, 2018 to June 30, 2018, plus applicable interest, in accordance with the May 17, 2018 PAPUC Order, which became effective for a twelve-month period beginning on October 11, 2019, the effective date of the TCJA and other adjustments. The increased revenuesGas Utility’s new base rates.

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

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 order,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 January 19, 2017, PNG (now15, 2020, the UGI North rate district of Gas Utility) filed a rate request withPennsylvania Commonwealth Court affirmed the PAPUC Order adopting UGI Utilities’ position on both issues. The Office of Consumer Advocate has the right to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supportedseek an appeal of the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and 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 upCommonwealth Court Order to the explosion, and it requested that the PAPUC order UGI Utilities to pay approximately $2.1 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.Pennsylvania Supreme Court.

Note 9 — Energy Services Accounts Receivable Securitization FacilityLeases

Energy Services has a Receivables Facility currently scheduled to expire in October 2019. 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.Lessee

UnderWe lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the Receivables Facility, Energy Services transfers, onmajority of which are operating leases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an ongoing basis and without recourse, its trade accounts receivableasset, whether we have the right 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 orobtain substantially all of the receivableseconomic benefits of the identified leased asset and to a major bank. Amounts solddirect its use.

ROU assets represent our right to use an underlying asset for the banklease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize ROU assets at the lease commencement date at the value of the lease liability adjusted for any prepayments, lease incentives received, and initial direct costs incurred. Lease liabilities are reflected as “Short-term borrowings”recognized at the lease commencement date based on the Condensed Consolidated Balance Sheets. ESFC was created and has been structuredpresent value of lease payments over the lease term. These payments are discounted using the discount rate implicit in the lease, when available. We apply an incremental borrowing rate, which is developed utilizing a credit notching approach based on information available at the lease commencement date, to isolate its assets from creditorssubstantially all 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 the three and nine months ended June 30, 2019 and 2018, which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material.

Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the nine months ended June 30, 2019 and 2018, as wellour leases as the balance of ESFC trade receivables at June 30, 2019, September 30, 2018 and June 30, 2018,implicit rate is as follows:
  Nine Months Ended June 30,
  2019 2018
Trade receivables transferred to ESFC during the period $1,168.4
 $1,051.7
ESFC trade receivables sold to the bank during the period $173.0
 $176.0
  June 30, 2019 September 30, 2018 June 30, 2018
ESFC trade receivables - end of period (a) $74.2
 $65.0
 $58.3
(a)
At June 30, 2019 and September 30, 2018, the amounts of ESFC trade receivables sold to the bank were $55.0 and $2.0, respectively. At June 30, 2018, there were no ESFC trade receivables sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets.

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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
often not available.

Note 10 — Debt

UGI International. On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, 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 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 is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. 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.

Restrictive covenants under the 2018 UGI International Credit Facilities Agreement include 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. In addition, the 2018 UGI International Credit Facilities Agreement requires a ratio of net consolidated indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00.

On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 principal amount of the 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 have 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 also terminated (1) UGI International LLC’s existing revolving credit facility agreement dated December 19, 2017, (2) UGI France’s revolving credit facility under its 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.

UGI Utilities. 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 sale of the UGI Utilities 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes. The UGI Utilities 4.55% 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 4.55% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

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 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2019 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2019 Credit

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

AgreementLease expense is currently scheduled to expirerecognized on a straight-line basis over the expected lease term. Renewal and termination options are not included in June 2020, butthe lease term unless we are reasonably certain that such options will be extendedexercised. Leases with an original lease term of one year or less, including consideration of any renewal options assumed to June 2024 ifbe exercised, are not included in the Condensed Consolidated Balance Sheets.

Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to ten years, contain purchase options. The Company generally excludes purchase options in evaluating its leases unless it is reasonably certain that such options will be exercised. Additionally, leases of fleet vehicles often contain residual value guarantees that are due at the end of the lease. Such amounts are included in the determination of lease liabilities when we are reasonably certain that they will be owed.

Certain leasing arrangements require variable payments that are dependent on asset usage or before June 25, 2020, are based on changes in index rates, such as the Consumer Price Index. The variable payments component of such leases cannot be determined at lease commencement and is not recognized in the measurement of ROU assets or lease liabilities, but is recognized in earnings in the period in which the obligation occurs.

ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows:
 December 31, 2019 Location on the Balance Sheet
ROU assets:   
Operating lease ROU assets$429.6
 Other assets
Finance lease ROU assets55.3
 Property, plant and equipment
Total ROU assets$484.9
  
    
Lease liabilities:   
Operating lease liabilities - current$85.5
 Other current liabilities
Operating lease liabilities - noncurrent344.1
 Other noncurrent liabilities
Finance lease liabilities - current6.4
 Current maturities of long-term debt
Finance lease liabilities - noncurrent42.2
 Long-term debt
Total lease liabilities$478.2
  


The components of lease cost are as follows:
 Three Months Ended December 31, 2019
Operating lease cost$25.6
Finance lease cost: 
Amortization of ROU assets1.6
Interest on lease liabilities0.5
Variable lease cost1.4
Short-term lease cost1.0
Total lease cost$30.1


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

The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period:
 Three Months Ended December 31, 2019
Cash paid related to lease liabilities: 
Operating cash flows from operating leases$25.5
Operating cash flows from finance leases$0.5
Financing cash flows from finance leases$1.0
  
Non-cash lease liability activities: 
ROU assets obtained in exchange for operating lease liabilities$451.9
ROU assets obtained in exchange for finance lease liabilities$21.5

The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31, 2019:
Weighted-average remaining lease termIn years
Operating leases6.3
Finance leases2.5
Weighted-average discount rate%
Operating leases3.9%
Finance leases2.0%


Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows:
 Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities
Operating leases:$75.4
 $89.8
 $74.6
 $66.3
 $56.1
 $126.5
 $488.7
 $(59.1) $429.6
Finance leases:$4.6
 $5.1
 $4.1
 $3.4
 $3.1
 $85.9
 $106.2
 $(57.6) $48.6

Approximately 85% of the operating lease liabilities presented above relates to AmeriGas Propane.

At December 31, 2019, operating and finance leases that had not yet commenced were insignificant.

Disclosures related to periods prior to adoption of ASC 842

As discussed above, the Company adopted ASC 842 effective October 1, 2019, using a modified retrospective approach. As required, the following disclosure is provided for periods prior to adoption. The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019, which were accounted for under ASC 840, were as follows:
  Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 
After
Fiscal
2024
Total $100.4
 $85.9
 $71.0
 $61.7
 $53.6
 $139.2


Lessor

We enter into lessor arrangements for the purposes of storing, gathering or distributing natural gas and propane. AmeriGas Propane and UGI International have lessor arrangements that grant customers the right to use small, medium and large storage tanks, which

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

we classify as operating leases. These agreements contain renewal options for periods up to nine years and certain requirements relatingagreements at UGI International contain a purchase option. Energy Services leases certain natural gas gathering assets to approval bycustomers, which we classify as operating leases. Lease income is generally recognized on a straight-line basis over the PAPUC. UGI Utilities is currently seeking such PAPUC approval.lease term and included in “Revenues” on the Condensed Consolidated Statement of Income (see Note 4).

Note 1110 — Commitments and Contingencies
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, upon the request of AmeriGas Partners from time to time, in each instance only with prior approval by the General Partner Audit Committee, which would be made in its sole and absolute discretion, UGI committed to make up to $225 of capital contributions to the Partnership through July 1, 2019. Under the terms of the Commitment Agreement, the last date on which AmeriGas Partners could have requested a capital contribution, without the consent of UGI, was May 17, 2019. AmeriGas Partners did not request, and UGI did not make, any capital contributions under the Commitment Agreement and the agreement has now terminated in accordance with its terms.

Environmental Matters

UGI Utilities

From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Southgas and Electric Utility.electric operations. Beginning in 2006 and 2008, UGI Utilities also owned and operated two2 acquired subsidiaries (CPG and PNG), which now constitute UGI North and UGI Central, 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 June 30,December 31, 2019, September 30, 20182019 and June 30,December 31, 2018, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $47.6, $51.0$49.5, $50.4 and $52.2,$50.5, respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8).

We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities 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. As such, UGI Utilities has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 8).

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 June 30, 2019, September 30, 2018 and June 30, 2018, neitherNeither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.

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

material for all periods presented.

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 three3 RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s

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

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 as of December 31, 2019, the Partnership accruedhas an undiscounted environmental remediation liability of $7.5 related to the site during the third quarter of Fiscal 2017.site. 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 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.

Although we cannot predict On August 21, 2019, 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.

Proposed Merger Lawsuits. In connection with the Proposed Merger (see Note 1), on June 5, 2019, a single AmeriGas Partners unitholder filed a class action complaint in the United States 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 Delaware. Columbia.

On July 9,October 2, 2019, a second AmeriGas Partners unitholder filed a complaint in the United States District Court forCompany reached an agreement to resolve the Eastern District of Pennsylvania. The complaints generally allege that the May 6, 2019 registration statement filed with the SEC in connection with the Proposed Merger included materially incomplete and/or misleading information in violationclaims of the federal securities laws. The complaints request, among other things, that the respective courts enjoin the parties from proceeding with the Proposed Merger or rescind the Proposed Merger if it does close. Bothdirect purchaser class of plaintiffs, seek an award of attorneys’ fees and costs. AmeriGas Partners has not yet answered or respondedsubject to the complaints.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 Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Note 1211 — 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, PNG, CPG 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. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly allcertain U.S. active and retired employees. In addition, certain UGI International employees of UGIin France, Belgium and its subsidiariesthe Netherlands are covered by certain 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.


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

The service cost component of our pension and other postretirement plans, net of amounts capitalized, areis reflected in “Operating and administrative expenses” on the Condensed 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 (expense) income, net” on the Condensed Consolidated Statements of Income. Net periodic pension cost and other postretirement benefit cost include the following components:
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Three Months Ended June 30, 2019 2018 2019 2018
Three Months Ended December 31, 2019 2018 2019 2018
Service cost $2.5
 $2.8
 $—
 $0.2
 $2.8
 $2.5
 $0.1
 $—
Interest cost 6.8
 6.5
 0.2
 0.3
 5.8
 6.8
 0.2
 0.2
Expected return on assets (9.0) (8.7) (0.2) (0.2) (9.4) (9.0) (0.2) (0.2)
Amortization of:                
Prior service cost (benefit) 0.1
 —
 (0.1) —
 0.1
 0.1
 (0.1) (0.1)
Actuarial loss (gain) 1.9
 3.4
 —
 —
Actuarial loss 3.7
 1.9
 —
 —
Net benefit cost (benefit) 2.3
 4.0
 (0.1) 0.3
 3.0
 2.3
 —
 (0.1)
Change in associated regulatory liabilities —
 —
 (0.3) (0.1) —
 —
 (0.3) (0.3)
Net benefit cost (benefit) after change in regulatory liabilities $2.3
 $4.0
 $(0.4) $0.2
 $3.0
 $2.3
 $(0.3) $(0.4)
        
 Pension Benefits Other Postretirement Benefits
Nine Months Ended June 30, 2019 2018 2019 2018
Service cost $7.6
 $8.4
 $0.1
 $0.6
Interest cost 20.4
 19.5
 0.5
 0.7
Expected return on assets (27.1) (25.9) (0.6) (0.6)
Amortization of:        
Prior service cost (benefit) 0.2
 0.2
 (0.3) (0.2)
Actuarial loss (gain) 5.8
 10.0
 (0.1) —
Net benefit cost (benefit) 6.9
 12.2
 (0.4) 0.5
Change in associated regulatory liabilities —
 —
 (1.0) (0.4)
Net benefit cost (benefit) after change in regulatory liabilities $6.9
 $12.2
 $(1.4) $0.1


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. During the ninethree months ended June 30,December 31, 2019, and 2018, the Company made cash contributions to the U.S. Pension Plan of $8.2 and $10.1, respectively.$3.2. During the three months ended December 31, 2018, the Company made 0 cash contributions to the U.S. Pension Plan. The Company expects to make additional cash contributions of approximately $3.0$9.5 to the U.S. Pension Plan during the remainder of Fiscal 2019.2020.

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. The difference between such cash deposits or expense recorded and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers.determined under GAAP. There were no0 required contributions to the VEBA during the ninethree months ended June 30,December 31, 2019 and 2018.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net costs associated with these plans for the three and nine months ended June 30,December 31, 2019 and 2018, were not material.


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

Note 1312 — 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:
 Asset (Liability) Asset (Liability)
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
June 30, 2019:        
December 31, 2019:        
Derivative instruments:        
Assets:        
Commodity contracts $26.6
 $20.5
 $—
 $47.1
Foreign currency contracts $—
 $39.9
 $—
 $39.9
Interest rate contracts $—
 $2.7
 $—
 $2.7
Liabilities:        
Commodity contracts $(76.6) $(110.2) $—
 $(186.8)
Foreign currency contracts $—
 $(4.4) $—
 $(4.4)
Interest rate contracts $—
 $(6.9) $—
 $(6.9)
Non-qualified supplemental postretirement grantor trust investments (a) $42.1
 $—
 $—
 $42.1
September 30, 2019:        
Derivative instruments:                
Assets:                
Commodity contracts $30.1
 $24.3
 $—
 $54.4
 $32.0
 $10.1
 $—
 $42.1
Foreign currency contracts $—
 $29.5
 $—
 $29.5
 $—
 $59.0
 $—
 $59.0
Liabilities:                
Commodity contracts $(44.8) $(62.4) $—
 $(107.2) $(62.3) $(112.7) $—
 $(175.0)
Foreign currency contracts $—
 $(5.2) $—
 $(5.2) $—
 $(4.3) $—
 $(4.3)
Interest rate contracts $—
 $(7.8) $—
 $(7.8) $—
 $(12.3) $—
 $(12.3)
Non-qualified supplemental postretirement grantor trust investments (a) $40.8
 $—
 $—
 $40.8
 $39.7
 $—
 $—
 $39.7
September 30, 2018:        
December 31, 2018:        
Derivative instruments:                
Assets:                
Commodity contracts $93.5
 $117.5
 $—
 $211.0
 $72.1
 $27.9
 $—
 $100.0
Foreign currency contracts $—
 $20.6
 $—
 $20.6
 $—
 $24.4
 $—
 $24.4
Cross-currency contracts $—
 $0.9
 $—
 $0.9
Liabilities:                
Commodity contracts $(33.6) $(9.8) $—
 $(43.4) $(35.6) $(78.0) $—
 $(113.6)
Foreign currency contracts $—
 $(14.4) $—
 $(14.4) $—
 $(8.8) $—
 $(8.8)
Interest rate contracts $—
 $(1.0) $—
 $(1.0) $—
 $(3.7) $—
 $(3.7)
Non-qualified supplemental postretirement grantor trust investments (a) $40.8
 $—
 $—
 $40.8
 $38.0
 $—
 $—
 $38.0
June 30, 2018:        
Derivative instruments:        
Assets:        
Commodity contracts $58.5
 $70.0
 $—
 $128.5
Foreign currency contracts $—
 $18.4
 $—
 $18.4
Cross-currency contracts $—
 $0.7
 $—
 $0.7
Liabilities:        
Commodity contracts $(25.3) $(8.9) $—
 $(34.2)
Foreign currency contracts $—
 $(17.9) $—
 $(17.9)
Interest rate contracts $—
 $(1.5) $—
 $(1.5)
Non-qualified supplemental postretirement grantor trust investments (a) $38.4
 $—
 $—
 $38.4

(a)Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 12.)11).
 
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 and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments

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

and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) were as follows:
June 30, 2019 September 30, 2018 June 30, 2018December 31, 2019 September 30, 2019 December 31, 2018
Carrying amount$4,347.1
 $4,199.4
 $4,210.9
$5,905.8
 $5,856.6
 $4,211.0
Estimated fair value$4,571.3
 $4,150.3
 $4,143.1
$6,248.9
 $6,189.3
 $3,970.8


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 14. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.13.

Note 1413 — 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 moreadditional 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 on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8).


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

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 June 30, 2019, September 30, 2018 and June 30, 2018, allAll Electric Utility forward electricity purchase contracts were subject to the NPNS exception.exception for all periods presented.

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


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 forward contractsover-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 associated withderived from the purchase and anticipated later near-term sale of natural gas.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. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into NYISO capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity.

Interest Rate Risk
Prior to their repayment on October 25, 2018 (see Note 10), UGI France’s and Flaga’sCertain of our long-term debt agreements hadhave interest rates that wereare generally indexed to short-term market interest rates. UGI France and Flaga enteredIn order to fix the underlying short-term market interest rates, we may enter 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. In November 2018, UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on the 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34%. We designated these interest ratedesignate such swaps as cash flow hedges.
UGI Utilities has a variable-rate term loan with an interest rate that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019, that generally fixes the underlying variable interest rate on borrowings at 3.00% through July 2022. We designated this interest rate swap as a cash flow hedge.
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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Notes to Condensed Consolidated Financial Statements
(unaudited)
(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 IRPAs. We account for IRPAs as cash flow hedges.

There were 0 unsettled IRPAs during any of the periods presented. At June 30, 2019, September 30, 2018 and June 30, 2018, we had no unsettled IRPAs. At June 30,December 31, 2019, the amount of pre-tax net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.

Foreign Currency Exchange Rate Risk

Forward Foreign Currency Exchange Contracts

In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At June 30, 2019, the amount of net gains associated with these contracts expected to be reclassified into earnings during the next twelve months based upon current fair values is not material.

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 (expense) income, net,” on the Condensed Consolidated Statements of Income.


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

In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, we previously 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. The last such contracts expired in September 2019. We accounted for these foreign currency exchange contracts as cash flow hedges.

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 ofCertain euro-denominated long-term debt issued under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018 wehave been designated this euro-denominated debt as net investment hedges of a portion of our euro-denominated UGI International euro-denominated net investment. During the three months ended December 31, 2019 and 2018, we recognized pre-tax losses associated with these net investment (see Note 10).

Cross-currency Contracts
Prior to its repayment on October 25, 2018 (see Note 10), Flaga entered into cross-currency swaps to hedge its exposure tohedges of $20.4 and $6.1, respectively, in the variability in expected future cash flows associated with the foreign currency and interest rate riskcumulative translation adjustment component 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.AOCI.

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Notes to Condensed Consolidated Financial Statements
(unaudited)
(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 June 30,December 31, 2019, September 30, 20182019 and June 30,December 31, 2018, and the final settlement date of the Company's open derivative transactions as of June 30,December 31, 2019, excluding those derivatives that qualified for the NPNS exception:
 
Notional Amounts
(in millions)
 
Notional Amounts
(in millions)
Type Units Settlements Extending Through June 30, 2019 September 30, 2018 June 30, 2018 Units Settlements Extending Through December 31, 2019 September 30, 2019 December 31, 2018
Commodity Price Risk:            
Regulated Utility Operations            
Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2020 16.5
 23.2
 16.8
 Dekatherms October 2020 14.5
 23.3
 14.7
Non-utility Operations            
LPG swaps Gallons September 2021 635.2
 394.3
 339.7
 Gallons December 2021 772.0
 800.4
 450.4
Natural gas futures, forward and pipeline contracts Dekatherms December 2024 191.4
 159.7
 139.6
 Dekatherms December 2024 201.4
 196.1
 188.0
Natural gas basis swap contracts Dekatherms December 2024 90.3
 54.4
 64.1
 Dekatherms December 2024 154.7
 131.1
 81.2
NYMEX natural gas storage Dekatherms March 2020 1.7
 1.8
 1.4
NYMEX propane storage Gallons April 2020 0.5
 0.6
 1.1
NYMEX natural gas storage futures contracts Dekatherms March 2020 0.4
 0.3
 0.7
NYMEX natural gas option contracts Dekatherms March 2020 2.0
 2.4
 —
NYMEX propane storage futures contracts Gallons April 2020 0.1
 0.5
 0.3
Electricity long forward and futures contracts Kilowatt hours May 2022 3,140.0
 4,307.6
 4,283.0
 Kilowatt hours April 2024 4,145.1
 3,098.1
 3,974.7
Electricity short forward and futures contracts Kilowatt hours May 2022 589.3
 359.3
 424.2
 Kilowatt hours April 2024 555.8
 366.7
 366.7
Interest Rate Risk:            
Interest rate swaps Euro October 2022 €300.0
 €585.8
 €585.8
 Euro October 2022 €300.0
 €300.0
 €300.0
Interest rate swaps USD July 2022 $114.1
 $114.1
 $—
 USD July 2024 $1,354.0
 $1,357.3
 $114.1
Foreign Currency Exchange Rate Risk:            
Forward foreign currency exchange contracts USD September 2022 $436.7
 $512.2
 $492.7
 USD September 2022 $431.2
 $516.0
 $408.6
Forward foreign currency exchange contracts Euro October 2024 €172.8
 €—
 €—
Cross-currency contracts USD N/A $—
 $49.9
 $49.9
Net investment hedge forward foreign exchange contracts Euro October 2024 €172.8
 €172.8
 €172.8


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 December 31, 2019, September 30, 2019 and December 31, 2018, the Company pledged net cash collateral of $8.9, $29.3, and $10.0, respectively. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30,December 31, 2019, September 30, 20182019 and June 30,December 31, 2018, restricted cash in brokerage accounts totaled $42.3, $9.6$95.8, $63.7 and $7.7,$17.4, respectively.

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

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 June 30,December 31, 2019. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of

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

additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30,December 31, 2019, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on the Condensed 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 Condensed 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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Notes to Condensed Consolidated Financial Statements
(unaudited)
(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:
 June 30,
2019		 September 30,
2018		 June 30,
2018		 December 31,
2019		 September 30,
2019		 December 31,
2018
Derivative assets:            
Derivatives designated as hedging instruments:            
Foreign currency contracts $7.3
 $1.5
 $1.1
 $13.9
 $17.4
 $2.3
Cross-currency contracts —
 0.9
 0.7
Interest rate contracts 2.7
 —
 —
 7.3
 2.4
 1.8
 16.6
 17.4
 2.3
Derivatives subject to PGC and DS mechanisms:            
Commodity contracts 1.0
 3.0
 2.0
 0.2
 1.4
 1.3
Derivatives not designated as hedging instruments:            
Commodity contracts 53.4
 208.0
 126.5
 46.9
 40.7
 98.7
Foreign currency contracts 22.2
 19.1
 17.3
 26.0
 41.6
 22.1
 75.6
 227.1
 143.8
 72.9
 82.3
 120.8
Total derivative assets — gross 83.9
 232.5
 147.6
 89.7
 101.1
 124.4
Gross amounts offset in the balance sheet (25.5) (34.3) (29.3) (27.2) (29.0) (34.3)
Cash collateral received —
 (12.2) (1.5) (2.1) —
 —
Total derivative assets — net $58.4
 $186.0
 $116.8
 $60.4
 $72.1
 $90.1
Derivative liabilities:            
Derivatives designated as hedging instruments:            
Foreign currency contracts $—
 $(0.4) $(0.8)
Interest rate contracts (7.8) (1.0) (1.5) $(6.9) $(12.3) $(3.7)
 (7.8) (1.4) (2.3)
Derivatives subject to PGC and DS mechanisms:            
Commodity contracts (3.1) (0.1) (0.1) (3.2) (3.7) (0.5)
Derivatives not designated as hedging instruments:            
Commodity contracts (104.1) (43.3) (34.1) (183.6) (171.3) (113.1)
Foreign currency contracts (5.2) (14.0) (17.1) (4.4) (4.3) (8.8)
 (109.3) (57.3) (51.2) (188.0) (175.6) (121.9)
Total derivative liabilities — gross (120.2) (58.8) (53.6) (198.1) (191.6) (126.1)
Gross amounts offset in the balance sheet 25.5
 34.3
 29.3
 27.2
 29.0
 34.3
Cash collateral pledged 2.3
 —
 —
 11.0
 29.3
 10.0
Total derivative liabilities — net $(92.4) $(24.5) $(24.3) $(159.9) $(133.3) $(81.8)



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Notes to Condensed Consolidated Financial Statements
(unaudited)
(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 Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30,December 31, 2019 and 2018:
Three Months Ended June 30,:         
 Gain (Loss)
Recognized in
AOCI		 Gain (Loss)
Reclassified from
AOCI into Income		 Location of Gain (Loss) Reclassified from
AOCI into Income		         
Cash Flow Hedges: 2019 2018 2019 2018 
Foreign currency contracts $—
 $3.9
 $0.2
 $—
 Cost of sales
Cross-currency contracts —
 0.5
 —
 0.3
 Interest expense/other operating income, net
Interest rate contracts (2.2) 0.8
 (1.1) (0.7) Interest expense
Total $(2.2) $5.2
 $(0.9) $(0.4) 
         
Net Investment Hedges:         
Foreign currency contracts $0.4
 $—
     
         
 Gain (Loss)
Recognized in Income		 Location of Gain (Loss)
Recognized in Income		 
Derivatives Not Designated as Hedging Instruments: 2019 2018 
Commodity contracts $(58.6) $80.9
 Cost of sales 
Commodity contracts 7.2
 (1.1) Revenues 
Foreign currency contracts 0.4
 25.6
 Other non-operating income, net 
Total $(51.0) $105.4
     
         
Nine Months Ended June 30,:         
Three Months Ended December 31,:         
 Gain (Loss)
Recognized in
AOCI		 Gain (Loss)
Reclassified from
AOCI into Income		 Location of Gain (Loss) Reclassified from
AOCI into Income		 Gain (Loss)
Recognized in
AOCI		 Gain (Loss)
Reclassified from
AOCI into Income		 Location of Gain (Loss) Reclassified from
AOCI into Income
Cash Flow Hedges: 2019 2018 2019 2018  2019 2018 2019 2018 
Foreign currency contracts $1.2
 $(0.6) $2.3
 $(3.1) Cost of sales $—
 $1.0
 $—
 $0.8
 Cost of sales
Cross-currency contracts (0.1) 0.9
 (0.3) 0.8
 Interest expense/other operating income, net —
 (0.1) —
 (0.3) Interest expense/other operating income, net
Interest rate contracts (7.4) 2.0
 (3.9) (1.9) Interest expense 7.8
 (2.8) (1.0) (1.5) Interest expense
Total $(6.3) $2.3
 $(1.9) $(4.2)  $7.8
 $(1.9) $(1.0) $(1.0) 
                  
Net Investment Hedges:                  
Foreign currency contracts $7.2
 $—
      $(3.5) $0.9
     
                  
 Gain (Loss)
Recognized in Income		 Location of Gain (Loss)
Recognized in Income		  Gain (Loss)
Recognized in Income		 Location of Gain (Loss)
Recognized in Income		 
Derivatives Not Designated as Hedging Instruments: 2019 2018  2019 2018 
Commodity contracts $(244.5) $63.5
 Cost of sales  $(33.1) $(159.7) Cost of sales 
Commodity contracts 9.0
 (2.6) Revenues  2.5
 (2.8) Revenues 
Commodity contracts (0.3) 0.2
 Operating and administrative expenses  0.1
 (0.4) Operating and administrative expenses 
Foreign currency contracts 17.1
 9.8
 Other non-operating income, net  (11.3) 8.9
 Other non-operating (expense) income, net 
Total $(218.7) $70.9
      $(41.8) $(154.0)     



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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

For the three and nine months ended June 30, 2019 and 2018, 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,However, 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. 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.


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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Note 1514 — Accumulated Other Comprehensive Income (Loss)

The tables below present changes in AOCI, net of tax, during the three and nine months ended June 30,December 31, 2019 and 2018:
Three Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — March 31, 2019 $(13.3) $(21.8) $(125.7) $(160.8)
Other comprehensive (loss) income before reclassification adjustments (after-tax) —
 (1.6) 16.1
 14.5
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.3
 0.9
 —
 1.2
Reclassification adjustments tax benefit (0.1) (0.2) —
 (0.3)
Reclassification adjustments (after-tax) 0.2
 0.7
 —
 0.9
Other comprehensive income (loss) attributable to UGI 0.2
 (0.9) 16.1
 15.4
AOCI — June 30, 2019 $(13.1) $(22.7) $(109.6) $(145.4)
         
Three Months Ended June 30, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — March 31, 2018 $(18.5) $(21.0) $5.4
 $(34.1)
Other comprehensive income (loss) before reclassification adjustments (after-tax) —
 3.7
 (82.0) (78.3)
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.8
 0.4
 —
 1.2
Reclassification adjustments tax benefit (0.2) (0.2) —
 (0.4)
Reclassification adjustments (after-tax) 0.6
 0.2
 —
 0.8
Other comprehensive income (loss) attributable to UGI 0.6
 3.9
 (82.0) (77.5)
AOCI — June 30, 2018 $(17.9) $(17.1) $(76.6) $(111.6)

Nine Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
Three Months Ended December 31, 2019 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2019 $(25.7) $(25.4) $(165.5) $(216.6)
Other comprehensive income before reclassification adjustments (after-tax) —
 5.6
 47.0
 52.6
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.3
 1.0
 —
 1.3
Reclassification adjustments tax benefit (0.1) (0.3) —
 (0.4)
Reclassification adjustments (after-tax) 0.2
 0.7
 —
 0.9
Other comprehensive income attributable to UGI 0.2
 6.3
 47.0
 53.5
AOCI — December 31, 2019 $(25.5) $(19.1) $(118.5) $(163.1)
        
Three Months Ended December 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2018 $(11.0) $(16.1) $(83.3) $(110.4) $(11.0) $(16.1) $(83.3) $(110.4)
Other comprehensive loss before reclassification adjustments (after-tax) —
 (4.3) (26.3) (30.6) —
 (1.5) (15.6) (17.1)
Amounts reclassified from AOCI:                
Reclassification adjustments (pre-tax) 1.1
 1.9
 —
 3.0
 0.4
 1.0
 —
 1.4
Reclassification adjustments tax benefit (0.3) (0.5) —
 (0.8) (0.1) (0.3) —
 (0.4)
Reclassification adjustments (after-tax) 0.8
 1.4
 —
 2.2
 0.3
 0.7
 —
 1.0
Other comprehensive income (loss) attributable to UGI 0.8
 (2.9) (26.3) (28.4) 0.3
 (0.8) (15.6) (16.1)
Reclassification of stranded income tax effects related to TCJA (2.9) (3.7) —
 (6.6) (2.9) (3.7) —
 (6.6)
AOCI — June 30, 2019 $(13.1) $(22.7) $(109.6) $(145.4)
        
Nine Months Ended June 30, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2017 $(19.2) $(21.4) $(52.8) $(93.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax) —
 1.7
 (23.8) (22.1)
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 1.8
 4.2
 —
 6.0
Reclassification adjustments tax benefit (0.5) (1.6) —
 (2.1)
Reclassification adjustments (after-tax) 1.3
 2.6
 —
 3.9
Other comprehensive income (loss) attributable to UGI 1.3
 4.3
 (23.8) (18.2)
AOCI — June 30, 2018 $(17.9) $(17.1) $(76.6) $(111.6)
AOCI — December 31, 2018 $(13.6) $(20.6) $(98.9) $(133.1)

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 14.13.

Note 1615 — Segment Information

Our operations comprise four4 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.

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 principally comprise net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In(in addition Corporate & Other includesto net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, (including such amounts attributablewhich had previously been excluded). The revision to noncontrolling interests) because such items are excluded fromour segment profit measures evaluatedaligns with the financial information utilized by our CODM in assessingevaluating our reportable segments’ performance orand allocating resources. Prior period 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 UGI debt 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.

The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 20182019 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon Partnership Adjusted EBITDA. Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned.

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

Three Months Ended June 30, 2019 Total Eliminations 
AmeriGas
Propane
 UGI International Midstream & Marketing UGI
Utilities		 
Corporate
& Other (b)
Revenues $1,363.7
 $—
 $478.7
 $486.6
 $239.3
 $153.0
 $6.1
Intersegment revenues $—
 $(39.6)(c)$—
 $—
 $28.0
 $10.9
 $0.7
Cost of sales $781.4
 $(38.5)(c)$210.3
 $278.5
 $225.4
 $61.0
 $44.7
Segment profit:              
Operating income (loss) $9.6
 $0.2
 $(3.0) $27.5
 $2.7
 $20.4
 $(38.2)
Income from equity investees 1.5
 —
 —
 —
 1.5
(d)—
 —
Other non-operating income (expense), net 0.7
 —
 —
 1.2
 0.1
 0.4
 (1.0)
Interest expense (60.5) —
 (41.6) (5.8) (0.7) (12.4) —
(Loss) income before income taxes $(48.7) $0.2
 $(44.6) $22.9
 $3.6
 $8.4
 $(39.2)
Partnership Adjusted EBITDA (a)     $42.5
        
Noncontrolling interests’ net loss $(44.6) $—
 $(42.1) $(0.1) $—
 $—
 $(2.4)
Depreciation and amortization $109.9
 $(0.2) $44.0
 $30.8
 $11.8
 $23.2
 $0.3
Capital expenditures (including the effects of accruals) $166.0
 $—
 $21.0
 $24.1
 $36.4
 $84.5
 $—
Three Months Ended June 30, 2018 Total Eliminations 
AmeriGas
Propane
 UGI International Midstream & Marketing UGI
Utilities		 
Corporate
& Other (b)
Revenues $1,440.9
 $—
 $528.4
 $533.6
 $229.6
 $150.3
 $(1.0)
Intersegment revenues $—
 $(44.4)(c)$—
 $—
 $34.2
 $9.6
 $0.6
Cost of sales $732.5
 $(43.5)(c)$244.5
 $314.3
 $215.0
 $72.5
 $(70.3)
Segment profit:              
Operating income (loss) (f) $29.5
 $(0.3) $(54.7)(e)$9.2
 $7.4
 $4.4
 $63.5
Income from equity investees 1.3
 —
 —
 —
 1.3
(d)—
 —
Other non-operating income (expense), net (f) 24.6
 —
 —
 (0.7) —
 (0.5) 25.8
Interest expense (56.5) —
 (40.4) (5.5) (0.5) (10.0) (0.1)
(Loss) income before income taxes $(1.1) $(0.3) $(95.1) $3.0
 $8.2
 $(6.1) $89.2
Partnership Adjusted EBITDA (a)     $67.2
        
Noncontrolling interests’ net (loss) income $(64.1) $—
 $(78.1) $(0.8) $—
 $—
 $14.8
Depreciation and amortization $118.8
 $(0.1) $46.4
 $39.8
 $11.1
 $21.4
 $0.2
Capital expenditures (including the effects of accruals) $142.7
 $—
 $25.7
 $27.3
 $9.9
 $79.7
 $0.1
Three Months Ended December 31, 2019 Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (a)
Revenues from external customers $2,006.6
 $—
 $730.4
 $651.4
 $308.3
 $314.6
 $1.9
Intersegment revenues $—
 $(79.7)(b)$—
 $—
 $64.2
 $14.7
 $0.8
Cost of sales $1,008.0
 $(79.1)(b)$289.2
 $368.4
 $264.2
 $151.6
 $13.7
Operating income (loss) $377.2
 $0.3
 $165.3
 $95.8
(c)$55.1
 $91.8
 $(31.1)
Income from equity investees 6.5
 —
 —
 —
 6.5
(d)—
 —
Other non-operating (expense) income, net (11.5) —
 —
 4.4
 —
 (0.2) (15.7)
Earnings (loss) before interest expense and income taxes 372.2
 0.3
 165.3
 100.2
 61.6
 91.6
 (46.8)
Interest expense (84.1) —
 (42.5) (7.6) (11.5) (13.6) (8.9)
Income (loss) before income taxes $288.1
 $0.3
 $122.8
 $92.6
 $50.1
 $78.0
 $(55.7)
Depreciation and amortization $119.4
 $—
 $43.9
 $31.2
 $18.4
 $25.7
 $0.2
Capital expenditures (including the effects of accruals) $151.8
 $—
 $38.5
 $20.3
 $22.5
 $70.5
 $—
As of December 31, 2019              
Total assets $14,285.7
 $(365.5) $4,609.4
 $3,243.3
 $2,859.6
 $3,710.9
 $228.0
Short-term borrowings $869.7
 $—
 $321.0
 $181.3
 $88.4
 $279.0
 $—
Goodwill $3,482.9
 $—
 $2,003.0
 $956.8
 $341.0
 $182.1
 $—
Three Months Ended December 31, 2018 (e) Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (a)
Revenues from external customers $2,200.2
 $—
 $820.2
 $710.7
 $372.5
 $299.1
 $(2.3)
Intersegment revenues $—
 $(111.6)(b)$—
 $—
 $86.9
 $23.6
 $1.1
Cost of sales $1,425.0
 $(110.8)(b)$378.5
 $448.6
 $377.5
 $159.5
 $171.7
Operating income (loss) $167.7
 $0.4
 $166.6
 $58.3
 $41.1
 $77.0
 $(175.7)
Income from equity investees 1.5
 —
 —
 —
 1.5
(d)—
 —
Loss on extinguishments of debt (6.1) —
 —
 —
 —
 —
 (6.1)
Other non-operating income, net 9.0
 —
 —
 0.7
 —
 0.4
 7.9
Earnings (loss) before interest expense and income taxes 172.1
 0.4
 166.6
 59.0
 42.6
 77.4
 (173.9)
Interest expense (60.2) —
 (42.4) (5.4) (0.5) (11.7) (0.2)
Income (loss) before income taxes $111.9
 $0.4
 $124.2
 $53.6
 $42.1
 $65.7
 $(174.1)
Noncontrolling interests’ net income (loss) $24.3
 $—
 $81.5
 $0.1
 $—
 $—
 $(57.3)
Depreciation and amortization $111.2
 $—
 $45.7
 $31.4
 $11.5
 $22.5
 $0.1
Capital expenditures (including the effects of accruals) $161.8
 $—
 $31.0
 $27.8
 $25.1
 $77.3
 $0.6
As of December 31, 2018              
Total assets $12,368.3
 $(144.3) $4,020.6
 $3,287.5
 $1,504.9
 $3,424.8
 $274.8
Short-term borrowings $676.3
 $—
 $368.5
 $1.8
 $10.0
 $296.0
 $—
Goodwill $3,154.8
 $—
 $2,003.0
 $951.9
 $17.8
 $182.1
 $—


40
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

Nine Months Ended June 30, 2019 Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (b)
Revenues $6,170.0
 $—
 $2,270.5
 $1,980.5
 $1,055.4
 $856.4
 $7.2
Intersegment revenues $—
 $(276.0)(c)$—
 $—
 $213.7
 $59.8
 $2.5
Cost of sales $3,633.3
 $(272.9)(c)$1,024.0
 $1,171.8
 $1,052.2
 $438.5
 $219.7
Segment profit:              
Operating income (loss) $716.1
 $0.2
 $410.0
 $212.7
 $95.1
 $217.3
 $(219.2)
Income from equity investees 4.6
 —
 —
 0.1
 4.5
(d)—
 —
Loss on extinguishments of debt (6.1) —
 —
 (6.1) —
 —
 —
Other non-operating income, net 17.6
 —
 —
 5.0
 0.1
 1.2
 11.3
Interest expense (181.7) —
 (126.2) (17.3) (1.7) (36.3) (0.2)
Income (loss) before income taxes $550.5
 $0.2
 $283.8
 $194.4
 $98.0
 $182.2
 $(208.1)
Partnership Adjusted EBITDA (a)     $543.5
        
Noncontrolling interests’ net income (loss) $131.0
 $—
 $178.1
 $0.2
 $—
 $—
 $(47.3)
Depreciation and amortization $330.0
 $(0.3) $134.0
 $92.8
 $34.8
 $68.0
 $0.7
Capital expenditures (including the effects of accruals) $479.0
 $—
 $77.8
 $74.0
 $93.8
 $232.6
 $0.8
As of June 30, 2019              
Total assets $12,018.9
 $(116.9) $3,789.4
 $3,168.0
 $1,444.7
 $3,375.6
 $358.1
Short-term borrowings $380.2
 $—
 $248.5
 $0.7
 $55.0
 $76.0
 $—
Goodwill $3,159.1
 $—
 $2,003.0
 $956.2
 $17.8
 $182.1
 $—
Nine Months Ended June 30, 2018 Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (b)
Revenues $6,378.1
 $—
 $2,356.0
 $2,227.4
 $915.6
 $880.3
 $(1.2)
Intersegment revenues $—
 $(330.4)(c)$—
 $—
 $241.4
 $86.0
 $3.0
Cost of sales $3,430.1
 $(327.4)(c)$1,094.3
 $1,340.2
 $872.6
 $481.6
 $(31.2)
Segment profit:              
Operating income (f) $1,015.5
 $0.2
 $359.8
(e)$234.4
 $168.4
 $237.0
 $15.7
Income (loss) from equity investees 3.0
 —
 —
 (0.3) 3.3
(d)—
 —
Other non-operating income (expense), net (f) 4.1
 —
 —
 (14.7) (1.2) (1.7) 21.7
Interest expense (172.8) —
 (122.0) (16.3) (2.1) (32.0) (0.4)
Income before income taxes $849.8
 $0.2
 $237.8
 $203.1
 $168.4
 $203.3
 $37.0
Partnership Adjusted EBITDA (a)     $570.8
        
Noncontrolling interests’ net income (loss) $135.9
 $—
 $145.6
 $(2.3) $—
 $—
 $(7.4)
Depreciation and amortization $341.3
 $(0.2) $139.0
 $106.9
 $32.0
 $62.9
 $0.7
Capital expenditures (including the effects of accruals) $381.3
 $—
 $72.9
 $75.1
 $25.5
 $206.5
 $1.3
As of June 30, 2018              
Total assets $11,876.7
 $(74.2) $3,932.7
 $3,232.5
 $1,316.5
 $3,194.0
 $275.2
Short-term borrowings $299.1
 $—
 $177.0
 $3.6
 $—
 $118.5
 $—
Goodwill $3,169.0
 $—
 $2,005.5
 $969.9
 $11.5
 $182.1
 $—

(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 the three months ended December 31, 2019 and 2018:

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

Three Months Ended December 31, 2019 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing
Net gains (losses) on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $9.4
 $(13.5) $(7.5)
Unrealized losses on foreign currency derivative instruments Other non-operating (expense) income, net $—
 $(15.7) $—
Acquisition and integration expenses associated with the CMG Acquisition Operating and administrative expenses $—
 $—
 $(0.7)
LPG business transformation expenses Operating and administrative expenses $(11.2) $(5.5) $—
(a)The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income (loss) before income taxes:    
Three Months Ended December 31, 2018 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing
Net (losses) gains on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $(78.5) $(97.3) $1.8
Unrealized gains on foreign currency derivative instruments Other non-operating (expense) income, net $—
 $8.1
 $—
Loss on extinguishments of debt Loss on extinguishment of debt $—
 $(6.1) $—

  Three Months Ended
June 30,		 Nine Months Ended
June 30,
  2019 2018 2019 2018
Partnership Adjusted EBITDA $42.5
 $67.2
 $543.5
 $570.8
Depreciation and amortization (44.0) (46.4) (134.0) (139.0)
Interest expense (41.6) (40.4) (126.2) (122.0)
Impairment of Partnership tradenames and trademarks —
 (75.0) —
 (75.0)
Merger expense (1.8) —
 (2.7) —
Noncontrolling interest (i) 0.3
 (0.5) 3.2
 3.0
(Loss) income before income taxes $(44.6) $(95.1) $283.8
 $237.8

(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)Includes net pre-tax (losses) gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $(39.5) and $95.5 for the three months ended June 30, 2019 and 2018, respectively, and $(200.7) and $54.0 for the nine months ended June 30, 2019 and 2018, respectively.
(c)Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(c)Beginning October 1, 2019, UGI International is allocated a portion of indirect corporate expenses. Prior to October 1, 2019, these expenses were billed to Enterprises, which is included in Corporate & Other.
(d)RepresentsIncludes AFUDC associated with our PennEast PipelinePennEast. The three months ended December 31, 2019 also includes equity investment.income from Pennant (see Note 5).
(e)Includes a pre-tax impairment charge of $75.0, as a result of a planSegment information recast to discontinue the use of certain tradenames and trademarks primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane (see Note 7).
(f)Amounts reflect the reclassificationchanges adopted during the fourth quarter of non-service income (expense) associated withFiscal 2019 in the segment measure of profit used by our pension and other postretirement plans from “Operating and administrative expenses”CODM to “Other non-operating income, net,” onevaluate the Condensed Consolidated Statementsperformance of Income as a result of the adoption of ASU No. 2017-07 (see Note 3).our reportable segments.

Note 1716 — Subsequent EventsGlobal LPG Business Transformation Initiatives

CMG Acquisition. On August 1,During the fourth quarter of Fiscal 2019, UGI through its wholly owned indirect subsidiary, 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, for a total of approximately $1,275 in cash, subject to working capital and other adjustments. The CMG Acquisition was consummated pursuant to the CMG Acquisition Agreements dated July 2, 2019. 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 withwe began executing on multi-year business transformation initiatives at our growth strategies, including expanding our midstream natural gas gathering and processing assets within the Marcellus and Utica production regions.

On the closing date, the CMG Acquisition was funded with cash from $600 of borrowings under the UGI Corporation Senior Credit Facility (as further described below); borrowings under the Energy Services Credit Agreement;AmeriGas Propane and UGI cash on hand. Concurrent with the signing of the CMG Acquisition Agreements, Energy Services secured a committed bridge loan facility but did not draw on the bridge loan commitment, which expired on August 1, 2019.

The Company isInternational business segments. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the early stagesareas of allocatingsales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the purchase price tocustomer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. In connection with these initiatives, during the identifiable assets acquired and liabilities assumed, which primarily comprise property, plant and equipment, customer relationships, and CMG’s equity interest in Pennant. Accordingly, it is impracticable to provide a preliminary purchase price allocation at this time. During the most recent fiscal yearthree months ended December 31, 2018, CMG’s consolidated revenues totaled approximately $802019, we recognized $16.7 of expenses principally comprising consulting, advisory and Pennant’s revenues totaled approximately $50.

UGI Corporation Senior Credit Facility. On August 1, 2019, UGI entered intoemployee-related costs. These expenses are reflected in “Operating and administrative expenses” on the UGI Corporation Senior Credit Facility. The UGI Corporation Senior Credit Facility comprises (1) a five-year $250 amortizing term loan commitment; (2) a three-year $300 term loan commitment; and (3) a five-year $300 revolving credit facility (including a $10 sublimit for lettersCondensed Consolidated Statement of credit). ProceedsIncome.

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

from borrowings under the UGI Corporation Senior Credit Facility may be used to finance the cash portion of the Proposed Merger; the CMG Acquisition; and for general corporate purposes.
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 margin on the $250 term loan and $300 revolving credit facility, which is dependent upon a ratio of consolidated net indebtedness to consolidated EBITDA, as defined, and UGI’s credit ratings, ranges from 0.375% to 1.50% if the prime rate option is elected, and 1.375% to 2.50% if the LIBOR option is elected. The applicable margin on the $300 term loan, which is dependent upon a ratio of consolidated net indebtedness to consolidated EBITDA, as defined, and UGI’s credit ratings, ranges from 0.125% to 1.25% if the prime rate option is elected, and 1.125% to 2.25% if the LIBOR option is elected. We plan on entering into pay-fixed, receive-variable interest rate swaps for a portion of the borrowings under the UGI Corporation Senior Credit Facility.

Principal amounts under the UGI Corporation Senior Credit Facility $250 term loan will be due as follows: during the fourth year of the agreement, 15% of the original principal amount borrowed, in equal quarterly installments; during the fifth year of the agreement, 15% of the original principal amount borrowed in equal quarterly installments; and the remainder of the original amount borrowed at the maturity date. Borrowings under the UGI Corporation Senior Credit Facility $300 term loan are due in their entirety at the maturity date.

The UGI Corporation Senior Credit Facility restricts the ability of UGI to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. The UGI Corporation Senior Credit Facility also requires UGI to maintain a ratio of consolidated net indebtedness to consolidated EBITDA, each as defined, as of the last day of each fiscal quarter that shall not exceed (a) 4.50 to 1.00 from September 30, 2019 through March 31, 2021; (b) 4.25 to 1.00 from June 30, 2021 through March 31, 2022; and (c) 4.00 to 1.00 from June 30, 2022 through final maturity. Under certain circumstances relating to UGI’s credit ratings, UGI may also be required to maintain a ratio of consolidated EBITDA to consolidated interest expense, each as defined, as of the last day of each fiscal quarter of not less than 3.50 to 1.00.

On August 1, 2019, in order to fund a portion of the CMG Acquisition, UGI borrowed $300 under the UGI Corporation Senior Credit Facility revolving credit facility, and $300 under the $300 term loan.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. 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 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) adverse weather conditions resulting in reduced demand;demand and the seasonal nature of our business; (2) cost volatility and availability of propane and other LPG, oil, 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, and accounting matters;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, including, but not limited to, pending litigation relating to the Proposed Merger;proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers andor 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 inother foreign countries, including the current conflicts in the Middle East and the withdrawal of the United Kingdom from the European Union, 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;synergies; (21) the interruption, disruption, failure malfunction, or breachmalfunction of our information technology systems, including due to cyber attack; (22) continuous enactment of tax legislation; (23) the failure to realize the anticipated benefits of the Proposed Merger; (24) the possible diversion of management time on issues related to the Proposed Merger; (25) the risk that the requisite approvalsinability to complete pending or future energy infrastructure projects; and (23) our ability to achieve the Proposed Merger are not obtained; (26)operational benefits and cost efficiencies expected from the performancecompletion of the Partnership;pending and (27) the potential need to address any reviews, investigations or other proceedings by governmental authorities or shareholder actions.future transformation initiatives at our business units.

These factors, and those factors set forth in Item 1A. Risk Factors in this Form 10-Q and the Company’s 20182019 Annual Report, 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.

ANALYSIS OF RESULTS OF OPERATIONS

Fiscal 2019 and 2018 Quarterly Results

The following analyses compare the Company’s results of operations for the 2019 three-month period with the 2018 three-month period, and the 2019 nine-month period with the 2018 nine-month period. Our analyses of results of operations should be read in conjunction with the segment information included in Note 1615 to the Condensed 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 heating-season months of October through March. As a result, our operating results, excluding the effects of gains and losses on commodity derivative instruments not associated with current-period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.


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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. 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. For further information on these non-GAAP financial measures including

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reconciliations of such non-GAAP financial 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.

Impact of Fiscal 2019 Strategic Initiatives

Our Fiscal 2020 results forreflect the 2019 and 2018 three- and nine-month periods include the effectsimpacts of the December 2017 enactments of the TCJAtwo strategic transactions completed in the U.S. and the December 2017 French Finance Bills in France. Among other things, the TCJA reduces the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property, which for UGI Utilities and certain FERC-regulated assets is eliminated beginning inlate Fiscal 2019. The December 2017 French Finance Bills increasedlarger of these transactions was the corporate income tax rate in France for Fiscal 2018 but also included measures to reduce the corporate income tax rate for fiscal years starting after January 1, 2022.
Our results for the three and nine months ended June 30, 2018, reflect provisional amounts that resulted from remeasuring our deferred income tax assets and liabilities at the new tax rates in the U.S. and in France during the quarter ended December 31, 2017, the period during which the tax laws were enacted, and subsequent adjustments to provisional amounts made during the quarters ended March 31, 2018 and June 30, 2018. Because a significant amountpurchase of all of the reductionpublic’s ownership interest in U.S. deferred income taxes resulting from the TCJA related to our regulated utility plant assets, most of the reductions to UGI Utilities’ deferred income tax assets and liabilities during Fiscal 2018 were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities in accordance with utility ratemaking. In addition, actions taken by the PAPUC on May 17, 2018, to address the effects of the TCJA on rates we charge our customers significantly impacted our 2019 and 2018 three- and nine-month period results.
Although the remeasurement adjustments to our deferred income tax assets and liabilitiesAmeriGas Partners for the 2018 three-month and nine-month periods affected income tax expense and GAAP net income, we have eliminated these remeasurement adjustments from our non-GAAP adjusted net income presented in the section below entitled “Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP).” For further information on the TCJA and the December 2017 French Finance Bills, see Note 6 to Condensed Consolidated Financial Statements.
Strategic Transactions
Proposed AmeriGas Merger
On April 1, 2019, we entered into the Merger Agreement, pursuant to which Merger Sub will merge with and into the Partnership, with the Partnership surviving as an indirect, wholly owned subsidiary of UGI. Under the terms of the Merger Agreement, at the effective time of the Proposed Merger, each outstanding Common Unit other than Common Units owned by UGI and its subsidiaries, including the General Partner, will be converted into the right to receive, at the election of each holder of such Common Units, one of the following forms of merger consideration:

(i)0.6378 shares of UGI common stock;
(ii)$7.63 in cash, without interest, and 0.500 shares of UGI common stock; or
(iii)$35.325 in cash, without interest.

The merger consideration is subject to proration designed to ensure that the total number of34.6 million shares of UGI common stock issuable as merger consideration will equal approximately 34.6Common Stock and $529 million shares, and the amount ofin cash, consideration paid will equal approximately $530 million. Upon completionresulting in UGI owning 100% of the Proposed Merger, AmeriGas Partners Common Units will no longer be publicly traded. Subject to the satisfaction or waiver of certain conditions, including the approval of the Merger Agreement by the AmeriGas Partners’ unitholders at the Special Meeting to be held onPartnership effective August 21, 2019,2019. The second significant strategic transaction was the Proposed Merger is expected to close in the fourth quarteracquisition of Fiscal 2019.

The Proposed Merger will be accounted for in accordance with ASC 810, Consolidation - Overall-Changes in a Parent’s Ownership Interest in a Subsidiary. Because UGI controls AmeriGas Partners before and after the Proposed Merger, the changes in UGI’s ownership interest in the Partnership resultingCMG from the merger will be accounted for as an equity transaction and no gain or loss will be recognized in UGI’s consolidated income statement. In addition, the carrying amounts of AmeriGas Partners’ assets and

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liabilities will not be adjusted. Finally, the tax effects of the merger will be reported as adjustments to deferred income taxes and UGI stockholders’ equity. See Note 1 to Condensed Consolidated Financial Statements for further information.
CMG Acquisition
OnTC Energy on August 1, 2019, UGI, through its wholly owned indirect subsidiary Energy Services, completed the CMG Acquisition, including CMG’s 47% interestresulting in Pennant for a total of approximately $1.275 billionsubstantial increase in cash, subject to working capital and other adjustments. CMG and Pennant provideour natural gas gathering and processing services through five discrete systems located in western Pennsylvania, eastern Ohio andassets as well as the panhandleacquisition of West Virginia. The CMG Acquisition is consistent with our growth strategies including expanding our midstream naturalimportant gas gathering and processing assets withinin the Marcellus and Utica production regions.Shale formations. We anticipate executing on a number of system expansion projects associated with the CMG assets over the next several years.

Also in Fiscal 2019, we began executing on our Global LPG Business Transformation Initiatives at AmeriGas Propane and UGI International. These initiatives are designed to drive operational efficiencies, increase profitability and provide for an enhanced customer experience at both of our global LPG businesses. We fundedhave engaged strategic partners to assist us in the CMG Acquisitionidentification and execution of these initiatives.

At AmeriGas Propane, we are focused on efficiency and effectiveness initiatives in the closing date with $600following 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. The business activities will be carried out over the next two years and, once completed, will provide more than $120 million of borrowings underannual savings that will allow us to improve profitability through operational efficiencies and expense reductions and 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 Corporation Senior Credit Facility (as further described belowInternational LPG business, we launched an initiative in Fiscal 2019 and in Note 17 to Condensed Consolidated Financial Statements); borrowings under the Energy Service Credit Agreement; and UGI cash on hand. Energy Services expects to fund a portion of the CMG Acquisitionembarked on a longer-term basis during August 2019. Concurrent withprocess of identifying operational synergies across all 17 countries in which we currently do business. We call this initiative Project Alliance, the signinggoal of which is to focus attention on enhanced customer service and safe and efficient operations through the purchaseestablishment of two centers of excellence. One such center will be focused on commercial excellence to identify and sale agreements, Energy Services secured a committed bridge loan facility but did not drawexecute 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 bridge loan commitment, which expirednext two years and, once completed, will generate over €30 million of annual savings. We estimate the total cumulative cost of executing on August 1, 2019.

We do not expect the CMG Acquisitionthese Project Alliance initiatives, including approximately €20 million related to have a material impact on the Company’s Fiscal 2019 financial statements.

For further information on the CMG Acquisition, see Note 17IT capital expenditures, to Condensed Consolidated Financial Statements.be approximately €55 million.

EXECUTIVE OVERVIEW

THREE MONTHS ENDED JUNE 30,DECEMBER 31, 2019 AND 2018

Net Income Attributable to UGI Corporation and Diluted EPS by Business UnitSegment (GAAP):
Net income (loss) attributable to UGI Corporation as determined in accordance with GAAP for the three months ended June 30, 2019 and 2018 is as follows:
For the three months ended June 30, 2019 2018 
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount (a) % of Total Amount %
For the three months ended December 31, 2019 2018
(Dollars in millions, except per share amounts) Net Income (Loss) 
Diluted
EPS (a)
 Net Income (Loss) Diluted
EPS
AmeriGas Propane (c) $(2.3) N.M.
 $(11.2) (21.4)% $8.9
 79.5 % $91.1
 $0.43
 $30.6
 $0.17
UGI International (e) 14.8
 N.M.
 6.5
 12.4 % 8.3
 127.7 % 72.7
 0.34
 36.7
 0.20
Midstream & Marketing 2.2
 N.M.
 5.8
 11.1 % (3.6) (62.1)% 36.0
 0.17
 31.0
 0.17
UGI Utilities (f) 6.7
 N.M.
 (3.0) (5.7)% 9.7
 323.3 % 60.8
 0.29
 49.9
 0.28
Corporate & Other (g) (23.3) N.M.
 54.3
 N.M.
 (77.6) N.M.
Net (loss) income attributable to UGI Corporation $(1.9) 100.0% $52.4
 100.0 % $(54.3) (103.6)%
Corporate & Other (b) (c) (48.6) (0.23) (84.0) (0.46)
Net income attributable to UGI Corporation $212.0
 $1.00
 $64.2
 $0.36
(a)Net income attributable to UGI CorporationEPS for the three months ended June 30, 2018, includes changes to provisional remeasurement adjustments initially recorded2019 three-month period reflects 34.6 million incremental shares of UGI Common Stock issued in December 2017 as a result of the enactment of the TCJA which decreased (increased) income taxes and increased (decreased) net income attributable to UGI by business unit as follows:
AmeriGas Propane$0.2
UGI International0.5
Midstream & Marketing(0.5)
UGI Utilities1.1
Corporate & Other(0.5)
Net income attributable to UGI Corporation$0.8

(b)Three months ended June 30, 2019, includes after-tax expenses associatedconjunction with the Proposed Merger of $0.3 million.
(c)Three months ended June 30, 2018, includes after-tax impairment charge of $14.5 million as a result of a plan to discontinue use of certain Partnership tradenames and trademarks.AmeriGas Merger.

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(d)(b)Three months ended June 30, 2018,Corporate & Other includes changescertain adjustments made to provisional remeasurement adjustments initially recordedour reporting segments in December 2017 as a result of the enactment of the December 2017 French Finance Bills, which decreased income taxes and increasedarriving at net income attributable to UGI Corporation.  These adjustments have been excluded from the segment results to align with the measure used by $0.1 million.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 15 to Condensed Consolidated Financial Statements for additional information related to these adjustments, as well as other items included within Corporate & Other.  
(e)Three months ended June 30, 2018, includes after-tax integration expenses associated with Finagaz of $4.6 million.
(f)Three months ended June 30, 2018, includes reduction in net income of $16.2 million to reflect the establishment of a regulatory liability and associated deferred income taxes from tax savings as a result of the TCJA during the period January 1, 2018 to June 30, 2018.
(g)(c)Includes net after-tax (losses) gains on commodity derivative instruments not associated with current-period transactionsthe impact of $(25.0) million and $38.0 million for the three months ended June 30, 2019 and 2018, respectively. Also includes net after-tax unrealized (losses) gains on certain foreign currency derivative instruments of $(0.5) million and $17.7 million for the three months ended June 30, 2019 and 2018, respectively.rounding.
N.M. — Percentage variance is not meaningful.

Adjusted Net Income Attributable to UGI Corporation and Diluted EPS by Business UnitSegment (Non-GAAP):
For the three months ended December 31, 2019 2018
(Dollars in millions, except per share amounts) 
Adjusted Net Income
(Loss)
 Adjusted Diluted EPS (a) Adjusted Net Income
(Loss)		 Adjusted Diluted EPS
AmeriGas Propane $91.1
 $0.43
 $30.6
 $0.17
UGI International 72.7
 0.34
 36.7
 0.20
Midstream & Marketing 36.0
 0.17
 31.0
 0.17
UGI Utilities 60.8
 0.29
 49.9
 0.28
Total reportable segments 260.6
 1.23
 148.2
 0.82
Corporate & Other (b) (14.4) (0.06) (4.4) (0.01)
Adjusted net income attributable to UGI Corporation (b) $246.2
 $1.17
 $143.8
 $0.81

(a)EPS for the 2019 three-month period reflects 34.6 million incremental shares of UGI Common Stock issued in conjunction with the AmeriGas Merger.
(b)See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below for additional information related to these non-GAAP financial measures, as well as other items included within Corporate & Other.

Discussion. Net income attributable to UGI Corporation in accordance with GAAP for the 2019 three-month period was $212.0 million (equal to $1.00 per diluted share) compared to net income attributable to UGI Corporation for the three months ended June 30,2018 three-month period of $64.2 million (equal to $0.36 per diluted share). The higher GAAP net income in the 2019 three-month period reflects, in large part, lower net losses from changes in unrealized gains and 2018 islosses on commodity derivative instruments, higher earnings contributions from each of our business segments including the effects of the AmeriGas Merger and CMG Acquisition, and the absence of a loss from debt extinguishments recorded in the prior-year period. These positive factors were partially offset by higher interest expense, higher income taxes, and the effects of LPG transformation expenses recorded in the current-year period. Earnings per share in the 2019 three-month period reflects the impact of 34.6 million shares of UGI Common Stock issued as follows:a result of the AmeriGas Merger.
For the three months ended June 30, 2019 2018 
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount % of Total Amount %
AmeriGas Propane $(2.0) (8.4)% $3.1
 20.5 % $(5.1) (164.5)%
UGI International (a) 14.8
 61.9 % 10.7
 70.9 % 4.1
 38.3 %
Midstream & Marketing 2.2
 9.2 % 6.3
 41.7 % (4.1) (65.1)%
UGI Utilities 6.7
 28.0 % (4.1) (27.2)% 10.8
 263.4 %
Corporate & Other 2.2
 9.3 % (0.9) (5.9)% 3.1
 N.M.
Adjusted net income attributable to UGI Corporation $23.9
 100.0 % $15.1
 100.0 % $8.8
 58.3 %
(a)Includes net after-tax realized gains (losses) on certain foreign currency derivative instruments used to reduce volatility in foreign earnings of $0.9 million and $(0.3) million for the three months ended June 30, 2019 and 2018, respectively.
N.M. - Percentage variance is not meaningful.

Discussion.Adjusted net income attributable to UGI Corporation for the 2019 three-month period was $23.9$246.2 million (equal to $0.13$1.17 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2018 three-month period of $15.1$143.8 million (equal to $0.09$0.81 per diluted share).
Our results for the three months ended June 30,December 31, 2019, reflect average temperatures that were warmer than the prior year at each of our AmeriGas Propane,reportable segments, and warmer than normal at our UGI International, Midstream & Marketing and UGI Utilities reportable segments, but coldersegments. In particular, average temperatures in the critical heating-season month of December were warmer than normal at AmeriGas Propane, UGI International, and UGI Utilities, and warmer than the prior yearaverage temperatures in December 2018 at ourAmeriGas Propane and UGI International reportable segment. The warmer weather at our domestic business units occurred principally during the month of April, the primary heating month of the quarter. Because there are significantly fewer heating degree days in our fiscal third quarter than in the our fiscal first and second quarters, year-over-year variances in temperatures during the three months ended June 30 have less of an impact on the comparison of our results than variances in temperatures during the fiscal first and second quarters.International.
The significant increase in UGI Utilities’ 2019 three-month period results principally reflects the absence of adjustments recorded in the prior-year three-month period as a result of the PAPUC’s May 17, 2018, Order regarding the TCJA partially offset by the effects of the warmer weather on core market volumes. Pursuant to the PAPUC Order, during the 2018 three-month period UGI Utilities reduced its revenues by $22.7 million (and established an associated regulatory liability) relating to $16.2 million (equal to $0.09 per diluted share) of tax savings 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%. Approximately $14.9 million (equal to $0.08 per diluted share) of the $16.2 million adjustment recorded during the 2018 three-month period related to the period January 1, 2018 to March 31, 2018.
Adjustedadjusted net income attributable to UGI from AmeriGas Propane decreased $5.1 million in the 2019 three-month period. The decrease principally reflectsperiod was largely attributable to the effects on total margininclusion of lower retail propane gallons sold and slightly higher operating and administrative expenses. The lower retail volumes sold reflects100% of AmeriGas Propane’s results due to the AmeriGas Merger transaction completed in part the effects of the significantly warmer April weather.August 2019.
Our UGI International adjusted net income was $36.0 million higher in the 2019 three-month period reflecting higher total margin and lower operating and administrative expenses, lower depreciation expense and higher other operating income. The effect of these items was partially offset by lower total margin. During theexpenses. Although UGI International 2019 three-month period theadjusted net income was impacted by a weaker euro and British pound sterling were slightly weaker than duringcompared to the prior-year period.period, adjusted net income benefited from higher realized gains on foreign currency exchange contracts.

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Midstream & Marketing adjusted net income in the 2019 three-month period was $4.1$5.0 million lowerhigher than the prior-year period. This increase principally reflects incremental net income from CMG which was acquired in August 2019, including income from an equity method investment that was included as part of the 2018 three-month period. The decrease reflects, among other things, lower natural gas retail marketing unit margins and lower capacity total margin. These decreases in margin wereacquisition, partially offset by increased interest expense related to debt issued to finance a portion of the CMG Acquisition.
UGI Utilities 2019 three-month period adjusted net income was $10.9 million higher than the prior-year period principally reflecting higher margins from Gas Utility’s core market customers reflecting the Gas Utility base rates increase that became effective in October 2019 and lower year-over-year operating and administrative expenses.
NINE MONTHS ENDED JUNE 30, 2019 AND 2018
Net Income Attributable to UGI Corporation by Business Unit (GAAP):

Net income attributable to UGI Corporation determined in accordance with GAAP for the nine months ended June 30, 2019 and 2018 is as follows:
For the nine months ended June 30, 2019 2018 
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount (a) % of Total Amount %
AmeriGas Propane (b)(c) $75.8
 24.6 % $180.2
 26.0% $(104.4) (57.9)%
UGI International (d)(e)(f) 137.0
 44.5 % 145.0
 20.9% (8.0) (5.5)%
Midstream & Marketing 71.3
 23.2 % 194.4
 28.0% (123.1) (63.3)%
UGI Utilities (g) 139.4
 45.3 % 154.5
 22.3% (15.1) (9.8)%
Corporate & Other (h) (115.8) (37.6)% 20.2
 2.8% (136.0) N.M.
Net income attributable to UGI Corporation $307.7
 100.0 % $694.3
 100.0% $(386.6) (55.7)%
(a)Net income attributable to UGI Corporation for the nine months ended June 30, 2018, includes income (loss) from remeasurement adjustments to tax-related accounts as a result of the enactment of the TCJA as follows:
AmeriGas Propane$113.3
UGI International(8.6)
Midstream & Marketing73.8
UGI Utilities9.3
Corporate & Other(15.7)
Net income attributable to UGI Corporation$172.1

(b)Nine months ended June 30, 2019, includes after-tax expenses associated with the Proposed Merger of $0.5 million.
(c)Nine months ended June 30, 2018, includes after-tax impairment charge of $14.5 million as a result of a plan to discontinue use of certain Partnership tradenames and trademarks.
(d)Nine months ended June 30, 2019, includes net after-tax loss from extinguishment of debt of $4.2 million.
(e)Nine months ended June 30, 2018, includes beneficial impact of a $13.5 million remeasurement adjustment to net deferred income tax liabilities associated with a December 2017 change in French income tax rates.
(f)Nine months ended June 30, 2018, includes after-tax integration expenses associated with Finagaz of $12.6 million.
(g)Nine months ended June 30, 2018, includes reduction in net income of $17.1 million to reflect the establishment of a regulatory liability and associated deferred income taxes from tax savings during the period January 1, 2018 to June 30, 2018 as a result of the TCJA.
(h)Includes net after-tax (losses) gains on commodity derivative instruments not associated with current-period transactions of $(117.7) million and $26.9 million for the nine months ended June 30, 2019 and 2018, respectively. Also includes net after-tax unrealized gains on certain foreign currency derivative instruments of $8.5 million and $16.3 million for the nine months ended June 30, 2019 and 2018, respectively.
N.M. — Percentage variance is not meaningful.


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Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP):
Adjusted net income attributable to UGI Corporation for the nine months ended June 30, 2019 and 2018 is as follows:
For the nine months ended June 30, 2019 2018 
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount % of Total Amount %
AmeriGas Propane $76.3
 18.1 % $81.4
 16.5 % $(5.1) (6.3)%
UGI International (a) 141.2
 33.5 % 152.7
 31.0 % (11.5) (7.5)%
Midstream & Marketing 71.3
 16.9 % 120.6
 24.5 % (49.3) (40.9)%
UGI Utilities 139.4
 33.1 % 145.2
 29.5 % (5.8) (4.0)%
Corporate & Other (6.6) (1.6)% (7.3) (1.5)% 0.7
 N.M.
Adjusted net income attributable to UGI Corporation $421.6
 100.0 % $492.6
 100.0 % $(71.0) (14.4)%
(a)Includes net after-tax realized gains (losses) on certain foreign currency derivative instruments used to reduce volatility in foreign earnings of $3.7 million and $(9.7) million for the nine months ended June 30, 2019 and 2018, respectively.
N.M. - Percentage variance not meaningful.

Discussion. Adjusted net income attributable to UGI Corporation for the 2019 nine-month periodthese items was $421.6 million (equal to $2.38 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2018 nine-month period of $492.6 million (equal to $2.79 per diluted share).
Our results for the nine months ended June 30, 2019, reflect average temperatures that were slightly colder than the prior year at our AmeriGas Propane and Midstream & Marketing reportable segments but slightly warmer than the prior year at our UGI Utilities and UGI International reportable segments. Temperatures during the 2019 nine-month period at our domestic business units were generally less volatile than temperatures in the prior year.
Adjusted net income attributable to UGI from AmeriGas Propane declined during the nine months ended June 30, 2019. The lower AmeriGas Propane results reflect the margin impact of lower retail propane volumes sold partially offset by higher average retail unit margins. In addition, operating and administrative expenses were slightly higher reflecting, in part, higher litigation-related expensesdepreciation expense attributable to increased capital expenditures and higher vehicle leaseinterest expense.
Our UGI International adjusted net income was lower in the 2019 nine-month period reflecting lower volumes sold for crop drying due to a very dry and warm summer and early fall in Europe and the negative volume and associated margin effects of slightly warmer weather on heating-related sales. Although the euro and the British pound sterling were weaker during the current-year period, which reduced translated local currency results, UGI International’s period-over-period adjusted net income was favorably impacted by significantly higher realized gains on foreign currency contracts used to reduce volatility in foreign earnings.
Midstream & Marketing adjusted net income in the 2019 nine-month period was significantly lower than in the 2018 nine-month period. The lower results reflect significantly lower prices for pipeline capacity principally due to the absence of the prior-year period’s extremely cold and volatile weather, increased pipeline restrictions experienced during the current-year period and the effects on capacity values of new pipeline capacity. Midstream & Marketing’s 2019 nine-month period adjusted 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’ 2019 nine-month period 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 2019 nine-month period. UGI Utilities’ prior year net income reflects the credit on behalf of customers for the period beginning January 1, 2018 through June 30, 2018. In addition, UGI Utilities’ 2019 nine-month period results reflect temperatures that were slightly warmer than the prior year. The slightly warmer temperatures reduced core market volumes but this was offset by customer growth.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share
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. For the 2019 and 2018 three and nine-month periods, adjusted net income attributableManagement believes that these non-GAAP measures provide meaningful information to UGI Corporation is net income attributable to UGI after excluding (1) net after-taxinvestors about UGI’s performance because they eliminate gains and losses on commodity and certain foreign currency derivative instruments not associated

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with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments); (2) Finagaz integration expenses; (3) losses associated with extinguishmentsother significant discrete items that can affect the comparison of debt; (4) remeasurement impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills; (5) merger expenses associated with the Proposed Merger; and (6) impairment of Partnership tradenames and trademarks.period-over-period results.
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.
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 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 tables reconcile consolidated net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation, and reconcile diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above:
Three Months Ended June 30, 2019 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
(Dollars in millions, except per share data)            
Adjusted net income attributable to UGI Corporation:            
Net (loss) income attributable to UGI Corporation $(1.9) $(2.3) $14.8
 $2.2
 $6.7
 $(23.3)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(11.1)) (a) 25.0
 —
 —
 —
 —
 25.0
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.2)) (a) 0.5
 —
 —
 —
 —
 0.5
Merger expenses (net of tax of $(0.1)) (a) 0.3
 0.3
 —
 —
 —
 —
Adjusted net income (loss) attributable to UGI Corporation $23.9
 $(2.0) $14.8
 $2.2
 $6.7
 $2.2
             
Adjusted diluted earnings per share:            
UGI Corporation (loss) earnings per share — diluted $(0.01) $(0.01) $0.08
 $0.01
 $0.04
 $(0.13)
Net losses on commodity derivative instruments not associated with current-period transactions 0.14
 —
 —
 —
 —
 0.14
Unrealized losses on foreign currency derivative instruments —
 —
 —
 —
 —
 —
Merger expenses —
 —
 —
 —
 —
 —
Adjusted diluted earnings (loss) per share (c) $0.13
 $(0.01) $0.08
 $0.01
 $0.04
 $0.01


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Three Months Ended June 30, 2018 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
(Dollars in millions, except per share data)            
Adjusted net income attributable to UGI Corporation:            
Net income (loss) attributable to UGI Corporation $52.4
 $(11.2) $6.5
 $5.8
 $(3.0) $54.3
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $16.5) (a) (38.0) —
 —
 —
 —
 (38.0)
Unrealized gains on foreign currency derivative instruments (net of tax of $8.4) (a) (17.7) —
 —
 —
 —
 (17.7)
Integration expenses associated with Finagaz (net of tax of $(3.0)) (a) 4.6
 —
 4.6
 —
 —
 —
Impairment of Partnership tradenames and trademarks (net of tax of $(5.8)) (a) 14.5
 14.5
 —
 —
 —
 —
Impact of French Finance Bill 0.1
 —
 0.1
 —
 —
 —
Remeasurement impact of TCJA (0.8) (0.2) (0.5) 0.5
 (1.1) 0.5
Adjusted net income (loss) attributable to UGI Corporation $15.1
 $3.1
 $10.7
 $6.3
 $(4.1) $(0.9)
             
Adjusted diluted earnings per share:            
UGI Corporation earnings (loss) per share - diluted $0.30
 $(0.06) $0.04
 $0.03
 $(0.02) $0.31
Net gains on commodity derivative instruments not associated with current-period transactions (0.21) —
 —
 —
 —
 (0.21)
Unrealized gains on foreign currency derivative instruments (0.10) —
 —
 —
 —
 (0.10)
Integration expenses associated with Finagaz (b) 0.02
 —
 0.02
 —
 —
 —
Impairment of Partnership tradenames and trademarks 0.08
 0.08
 —
 —
 —
 —
Impact of French Finance Bill —
 —
 —
 —
 —
 —
Remeasurement impact of TCJA —
 —
 —
 —
 —
 —
Adjusted diluted earnings (loss) per share $0.09
 $0.02
 $0.06
 $0.03
 $(0.02) $0.00
  Three Months Ended
December 31,
(Millions of dollars, except per share amounts) 2019 2018
Adjusted net income attributable to UGI Corporation:    
Net income attributable to UGI Corporation $212.0
 $64.2
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(1.4) and $(35.5), respectively) (a) (b) 10.2
 81.2
Unrealized losses (gains) on foreign currency derivative instruments (net of tax of $(4.4) and $2.3, respectively) (a) 11.3
 (5.8)
Loss on extinguishments of debt (net of tax of $0 and $(1.9), respectively) (a) —
 4.2
Acquisition and integration expenses associated with the CMG Acquisition (net of tax of $(0.2) and $0, respectively) (a) 0.5
 —
LPG business transformation expenses (net of tax of $(4.5) and $0, respectively) (a) 12.2
 —
Total adjustments 34.2
 79.6
Adjusted net income attributable to UGI Corporation $246.2
 $143.8
     
Adjusted diluted earnings per share:    
UGI Corporation earnings per share - diluted $1.00
 $0.36
Net losses on commodity derivative instruments not associated with current-period transactions 0.05
 0.46
Unrealized losses (gains) on foreign currency derivative instruments (b) 0.06
 (0.03)
Loss on extinguishments of debt —
 0.02
Acquisition and integration expenses associated with the CMG Acquisition —
 —
LPG business transformation expenses 0.06
 —
Total adjustments 0.17
 0.45
Adjusted diluted earnings per share $1.17
 $0.81



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Nine Months Ended June 30, 2019 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
(Dollars in millions, except per share data)            
Adjusted net income attributable to UGI Corporation:            
Net income (loss) attributable to UGI Corporation $307.7
 $75.8
 $137.0
 $71.3
 $139.4
 $(115.8)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(47.5)) (a) 117.7
 —
 —
 —
 —
 117.7
Unrealized gains on foreign currency derivative instruments (net of tax of $3.4) (a) (8.5) —
 —
 —
 —
 (8.5)
Loss on extinguishments of debt (net of tax of $(1.9)) (a) 4.2
 —
 4.2
 —
 —
 —
Merger expenses (net of tax of $(0.2)) (a) 0.5
 0.5
 —
 —
 —
 —
Adjusted net income (loss) attributable to UGI Corporation $421.6
 $76.3
 $141.2
 $71.3
 $139.4
 $(6.6)
             
Adjusted diluted earnings per share:            
UGI Corporation earnings (loss) per share — diluted $1.73
 $0.43
 $0.77
 $0.40
 $0.79
 $(0.66)
Net losses on commodity derivative instruments not associated with current-period transactions (b) 0.67
 —
 —
 —
 —
 0.67
Unrealized gains on foreign currency derivative instruments (b) (0.04) —
 —
 —
 —
 (0.04)
Loss on extinguishments of debt 0.02
 —
 0.02
 —
 —
 —
Merger expenses —
 —
 —
 —
 —
 —
Adjusted diluted earnings (loss) per share $2.38
 $0.43
 $0.79
 $0.40
 $0.79
 $(0.03)


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Nine Months Ended June 30, 2018 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
(Dollars in millions, except per share data)            
Adjusted net income attributable to UGI Corporation:            
Net income attributable to UGI Corporation $694.3
 $180.2
 $145.0
 $194.4
 $154.5
 $20.2
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $10.4) (a) (26.9) —
 —
 —
 —
 (26.9)
Unrealized gains on foreign currency derivative instruments (net of tax of $7.7) (a) (16.3) —
 —
 —
 —
 (16.3)
Integration expenses associated with Finagaz (net of tax of $(8.2)) (a) 12.6
 —
 12.6
 —
 —
 —
Impairment of Partnership tradenames and trademarks (net of tax of $(5.8)) (a) 14.5
 14.5
 —
 —
 —
 —
Impact of French Finance Bill (13.5) —
 (13.5) —
 —
 —
Remeasurement impact of TCJA (172.1) (113.3) 8.6
 (73.8) (9.3) 15.7
Adjusted net income (loss) attributable to UGI Corporation $492.6
 $81.4
 $152.7
 $120.6
 $145.2
 $(7.3)
             
Adjusted diluted earnings per share:            
UGI Corporation earnings per share - diluted $3.93
 $1.02
 $0.82
 $1.10
 $0.87
 $0.12
Net gains on commodity derivative instruments not associated with current-period transactions (0.15) —
 —
 —
 —
 (0.15)
Unrealized gains on foreign currency derivative instruments (0.09) —
 —
 —
 —
 (0.09)
Integration expenses associated with Finagaz 0.07
 —
 0.07
 —
 —
 —
Impairment of Partnership tradenames and trademarks 0.08
 0.08
 —
 —
 —
 —
Impact of French Finance Bill (0.08) —
 (0.08) —
 —
 —
Remeasurement impact of TCJA (0.97) (0.64) 0.05
 (0.42) (0.05) 0.09
Adjusted diluted earnings (loss) per share $2.79
 $0.46
 $0.86
 $0.68
 $0.82
 $(0.03)
(a)Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.
(b)Includes the effects of rounding associated with per share amounts.
(c)
Adjusted diluted earnings per share for the three months ended June 30, 2019, is based upon fully diluted shares of 177.336 million.


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SEGMENT RESULTS OF OPERATIONS

2019 Three-Month Period Compared to the 2018 Three-Month Period
AmeriGas Propane
For the three months ended June 30, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues $478.7
 $528.4
 $(49.7) (9.4)%
Total margin (a) $268.4
 $283.9
 $(15.5) (5.5)%
Partnership operating and administrative expenses (b) $234.4
 $222.4
 $12.0
 5.4 %
Impairment of Partnership tradenames and trademarks (c) $—
 $75.0
 $(75.0) (100.0)%
Partnership Adjusted EBITDA (d) $42.5
 $67.2
 $(24.7) (36.8)%
Operating loss (c)(e) $(3.0) $(54.7) $(51.7) (94.5)%
Retail gallons sold (millions) 188.5
 202.0
 (13.5) (6.7)%
Heating degree days—% colder than normal (f) 0.0% 9.6% —
 —
For the three months ended December 31, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues $730.4
 $820.2
 $(89.8) (10.9)%
Total margin (a) $441.2
 $441.7
 $(0.5) (0.1)%
Operating and administrative expenses $240.0
 $235.1
 $4.9
 2.1 %
Operating income/earnings before interest expense and income taxes $165.3
 $166.6
 $(1.3) (0.8)%
Retail gallons sold (millions) 304.4
 310.3
 (5.9) (1.9)%
Heating degree days—% colder than normal (b) 3.7% 4.9% —
 —
(a)Total margin represents total revenues less total cost of sales. Total margin for the three months ended June 30, 2019 and 2018 excludes net pre-tax unrealized (losses) gains of $(3.5) million and $20.3 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)Partnership operating and administrative expenses for the three months ended June 30, 2019 include $1.8 million of expenses associated with the Proposed Merger and $5.0 million of expenses to correct vehicle lease expense associated with prior periods.
(c)The 2018 three-month period includes the impact of a $75.0 million impairment charge associated with the plan to discontinue the use of certain tradenames and trademarks.
(d)Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 16 to Condensed Consolidated Financial Statements).
(e)Operating loss includes certain operating and administrative expenses of the General Partner.
(f)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’sAmeriGas Propane retail gallons sold during the 2019 three-month period were 6.7%1.9% lower than the prior-year period. TemperaturesAverage temperatures based upon heating degree days averagedwere 3.7% colder than normal for the 2019 three-month period but 8.7%1.2% warmer than the prior-year period. In particular,Although average temperatures during the 2019 three-month period were colder than normal, average temperatures in the critical heating-season month of AprilDecember 2019 the primary heating month of the quarter, were 5.3%8.6% warmer than normal compared with temperatures in the month of April 2018 that were nearly 36% colder than normal.

Retail propane revenues decreased $44.6$90.7 million during the 2019 three-month period reflecting the effects of lower average retail selling prices ($14.677.0 million) and the lower retail volumes sold ($30.013.7 million). Wholesale propane revenues decreased $2.7increased $1.0 million reflecting higher wholesale volumes ($5.6 million) largely offset by lower average wholesale selling prices.prices ($4.6 million). Average daily wholesale propane commodity prices during the 2019 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 36%38% lower than such prices during the 2018 three-month period. Other revenues in the 2019 three-month period were slightly lower than the prior-year period. Total cost of sales decreased $34.1$89.3 million during the 2019 three-month period principally reflecting the effects of the lower average propane product costs ($17.488.4 million), and lower retail propane volumes sold ($14.06.4 million) and slightly lower other cost of sales.partially offset by the higher wholesale propane volumes sold ($5.5 million).

AmeriGas Propane total margin decreased $15.5$0.5 million in the 2019 three-month period principally reflecting lower retail propane total marginvolumes sold ($16.17.3 million) partiallylargely offset by higher tank rentaverage retail unit margins ($5.5 million) and, service total margin. The decrease in retail propane total margin principally reflects the effects of the lower retail volumes sold.to a much lesser extent, higher average wholesale unit margins ($1.3 million).

Partnership Adjusted EBITDAOperating income and earnings before interest expense and income taxes decreased $24.7$1.3 million in the 2019 three-month period principally reflecting higher operating and administrative expenses ($4.9 million) and the effects of thepreviously mentioned lower total margin ($15.50.5 million), partially offset by an increase in other operating income ($2.3 million) largely related to higher income on sales of excess real estate and higher Partnership operatinglower depreciation and administrativeamortization expense ($10.2 million, excluding $1.8 million of Proposed Merger expenses)1.8 million). The increase in Partnership operating and administrative expenses in the 2019 three-month period reflects, among other things, higher required accruals for litigationgeneral insurance and self-insured casualty and liability expense ($10.02.7 million) and higher vehicle lease expense ($6.32.1 million) which includes $5.0 million to correct vehicle lease expense associated with prior periods. These increases in Partnership.


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operating expenses were partially offset by lower general insurance and self-insured casualty and liability expense, lower travel and entertainment expense, and lower advertising and vehicle fuel expense. AmeriGas Propane operating loss was $51.7 million lower in the 2019 three-month period principally reflecting the absence of a $75.0 million impairment charge recorded in the prior-year period associated with a plan to discontinue the use of certain tradenames and trademarks and slightly lower depreciation and amortization expense ($2.4 million) partially offset by the previously mentioned $24.7 million decrease in Partnership Adjusted EBITDA.

UGI International
For the three months ended June 30, 2019 2018 Increase (Decrease)
For the three months ended December 31, 2019 2018 Increase (Decrease)
(Dollars in millions)                
Revenues $486.6
 $533.6
 $(47.0) (8.8)% $651.4
 $710.7
 $(59.3) (8.3)%
Total margin (a) $208.1
 $219.3
 $(11.2) (5.1)% $283.0
 $252.1
 $30.9
 12.3 %
Operating and administrative expenses (b) $156.0
 $173.1
 $(17.1) (9.9)% $157.5
 $164.4
 $(6.9) (4.2)%
Operating income $27.5
 $9.2
 $18.3
 198.9 % $95.8
 $58.3
 $37.5
 64.3 %
Income before income taxes (c) $22.9
 $3.0
 $19.9
 663.3 %
Earnings before interest expense and income taxes $100.2
 $59.0
 $41.2
 69.8 %
LPG retail gallons sold (millions) (d) 175.7
 177.5
 (1.8) (1.0)% 246.4
 237.6
 8.8
 3.7 %
Heating degree days—% colder (warmer) than normal (e) 10.8% (34.6)% —
 —
Heating degree days—% (warmer) than normal (b) (10.3)% (8.0)% —
 —
(a)Total margin represents total revenues less total cost of sales. Total margin forsales and, in the three months ended June 30,2018 three-month period, French energy certificate costs of $10.0 million. For financial statement purposes, French energy certificate costs in the 2018 three-month period are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above). In the 2019 and 2018 excludes net pre-tax (losses) gainsthree-month period, French energy certificate costs are included in cost of $(10.8) million and $42.9 million, respectively,sales on commodity derivative instruments not associated with current-period transactions.the Condensed Consolidated Statements of Income.
(b)The 2018 three-month period includes $7.6 million of Finagaz integration expenses.
(c)Income before income taxes for the three months ended June 30, 2019 and 2018 excludes net pre-tax unrealized (losses) gains on certain foreign currency derivative contracts of $(0.8) million and $26.2 million, respectively. Income before income taxes for the three months ended June 30, 2019 and 2018 includes net pre-tax realized gains (losses) on certain foreign currency derivative contracts of $1.2 million and $(0.5) million, respectively.
(d)Prior-year amounts adjusted to conform to current-year classification.
(e)Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

Average temperatures during the 2019 three-month period were 10.8% colder10.3% warmer than normal compared to temperatures inand 2.7% warmer than the prior-year period that were 34.6% warmer than normal.period. Notwithstanding the colder 2019 three-month periodwarmer temperatures, total LPG retail gallons sold during the 2019 three-month period were slightly lower. LPG retail3.7% higher reflecting strong bulk volumes in the 2019 three-month period were lower due in large part to the loss of a low-margin cylinder dealer in Polandassociated with crop drying partially offset by slightly higherlower cylinder volumes and the effects of the warmer weather on heating-related bulk volumes. Retail LPG volumes in the prior-year period benefited from the carryover effects on bulk LPG sales of cold late-March 2018 weather principally at our operations in France.sales. During the 2019 three-month period, average wholesale prices for propane and butane in northwest Europe were approximately 17% and 14%15% lower than in the prior-year period, respectively, principally reflecting a significant declineperiod. Average wholesale butane prices in such prices later innorthwest Europe for the 2019 three-month period were slightly lower than the prior-year period.

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 the 2019 and 2018 three-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.12$1.11 and $1.19,$1.14, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.28 and $1.36, respectively.$1.29 during both periods.

UGI International revenues decreased $47.0$59.3 million during the 2019 three-month period principally reflecting the translation effects of the weaker euro and British pound sterling (approximately $31.0 million), the effects of lower average LPG selling prices and the translation effects of the slightly lowerweaker euro (approximately $19 million) partially offset by the previously mentioned increase in LPG retail volumes sold.volumes. UGI International cost of sales decreased $35.8$90.2 million during the 2019 three-month period principally reflecting lower average LPG product costs and the translation effects of the weaker euro and British pound sterling (approximately $20.0$11 million), lower.

UGI International total margin increased $30.9 million reflecting higher average LPG productunit margins including margin management efforts and increased recovery of costs associated with energy conservation certificates, higher retail volumes associated with crop drying and, to a much lesser extent, the lower retail and lower wholesale LPG volumes sold.

UGI International total margin decreased $11.2 million largely reflectinghigher natural gas margins. The effect of these increases was partially offset by the translation effects of the weaker euro and British pound sterling on local currency total margin and, to a much lesser extent, the effects on margin of the slightly(approximately $8 million), lower LPG retailcylinder volumes sold. Local currency total margin was slightly higher in the 2019 three-month period asand the effects of the slightly lower retail LPG volumes sold were more than offset by margin management and the recovery of energy conservation compliance costs.warmer weather on heating-related bulk sales.

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Notwithstanding the lower total margin, UGI International operating income increased $18.3$37.5 million principally reflecting the previously mentioned $30.9 million increase in total margin and lower operating and administrative expenses ($17.1 million), lower depreciation and amortization expense ($9.0 million), and slightly higher other operating income ($3.66.9 million). The decrease in operating and administrative expenses largely reflects in part, the translation effects of the weaker euro and British pound sterling (approximately $9.0$4 million) and slightly lower local currency operatingmaintenance and administrative expenses. Operating and administrative expenses in the prior-year three-month period include $7.6 million of Finagaz integrationoutside services costs. Operating and administrative expenses in the current-year period reflect, among other things, lower required compliance costs associated with operational safety requirements partially offset by higher expenses related to strategic projects. The lower depreciation and amortization expense principally reflects depreciation adjustments recorded in the prior-year period mainly resulting from changes in depreciable lives of certain cylinders and tanks and, to a lesser extent, the translation effects of the weaker currencies. The increase in other operating income reflects, in large part, income from the settlement of a customer contract. UGI International incomeearnings before interest expense and income taxes in the 2019 three-month period increased $19.9$41.2 million principally reflecting the increase in operating income ($18.337.5 million) and higher pre-tax realized gains on foreign currency exchange contracts entered into in order to reduce volatility in UGI International net income resulting from the translation effects of changes in foreign currency exchange rates ($1.73.6 million).


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Midstream & Marketing
For the three months ended June 30, 2019 2018 Increase (Decrease)
For the three months ended December 31, 2019 2018 Increase (Decrease)
(Dollars in millions)                
Revenues $267.3
 $263.8
 $3.5
 1.3 % $372.5
 $459.4
 $(86.9) (18.9)%
Total margin (a) $41.9
 $48.8
 $(6.9) (14.1)% $108.3
 $81.9
 $26.4
 32.2 %
Operating and administrative expenses $27.4
 $30.4
 $(3.0) (9.9)% $34.9
 $29.2
 $5.7
 19.5 %
Operating income $2.7
 $7.4
 $(4.7) (63.5)% $55.1
 $41.1
 $14.0
 34.1 %
Income before income taxes $3.6
 $8.2
 $(4.6) (56.1)%
Earnings before interest expense and income taxes $61.6
 $42.6
 $19.0
 44.6 %
(a)Total margin represents total revenues less total cost of sales. Total margin for the three months ended June 30, 2019 and 2018 excludes net pre-tax (losses) gains of $(24.5) million and $6.2 million, respectively, on commodity derivative instruments not associated with current-period transactions.

Average temperatures across Midstream & Marketing’s energy marketing territory during the three months ended June 30,December 31, 2019 were approximately 14.5%slightly warmer than normal and 18.7%approximately 4.6% warmer than the prior-year period. Prior-year temperatures were impacted by significantly colder than normal temperatures in April.

Midstream & Marketing’s 2019 three-month period revenues were $3.5$86.9 million higher lower than the prior-year period principally reflecting higherdecreased natural gas revenues ($10.4108.1 million) partially offset by lower total revenues from midstream assets ($6.2 million) and, to a much lesser extent, lower electric generation revenues.($3.0 million), retail power ($1.6 million) and capacity revenues ($1.6 million). The increasesignificant decrease in natural gas revenues principally reflects the effects of higheris primarily attributable to lower average natural gas volumes resulting from customer growth, including customers obtained throughprices during the acquisition2019 three-month period. The effect of South Jersey Energy Company’s natural gas marketing business on December 1, 2018. The decrease in revenues from midstream assets principally reflects significantly lower capacity management revenues ($5.2 million) and lower peaking and storage revenues,these revenue decreases were partially offset by higher natural gas gathering revenues. The decrease in capacity management revenues reflects lower capacity values. Electric generation($32.8 million) largely attributable to incremental revenues were lower principally reflecting significantly lower off peak volumes at the Hunlock Station generating facility due to a decline in economic dispatch opportunities.from CMG which was acquired on August 1, 2019. Midstream & Marketing cost of sales were $225.4$264.2 million in the 2019 three-month period compared to $215.0$377.5 million in the 2018 three-month period, an increase of $10.4period. The $113.3 million principally reflecting the higher natural gas volumes partially offset by lower electric generationdecrease in cost of sales as a result of theprincipally reflects lower generation activity.natural gas costs.

Midstream & Marketing total margin decreased $6.9increased $26.4 million in the 2019 three-month period principally reflecting lower margin from natural gas marketing ($4.0 million) reflecting lower unit margins, lower total margin from our midstream assets ($2.5 million), and lower electric generation total margin ($0.9 million). The decrease in total margin from midstream assets is principally the result of lower capacity management total margin ($5.2 million) partially offset by higher natural gas gathering total margin ($2.932.8 million). largely attributable to incremental margins from CMG and, to a much lesser extent, our Auburn IV natural gas gathering system which was placed into service in November 2019. The decrease ineffect of these increases was partially offset by lower capacity management total margin reflectsand lower baseload capacity values, and higher prior-year pricing spreads between Marcellus and non-Marcellus delivery points. The lower total margin from electric generation reflects significantlythe Hunlock generating facility reflecting lower electric generation volumes principally at our Hunlock Station generating facility.volumes.

Midstream & Marketing operating income and incomeearnings before interest expense and income taxes during the 2019 three-month period decreased $4.7increased $14.0 million and $4.6$19.0 million, respectively. The decreasesincrease in operating income principally reflectreflects the previously mentioned decreaseincrease in total margin ($6.9 million) and slightly higher depreciation expense ($0.726.4 million) partially offset by lowerhigher depreciation and amortization expense ($6.9 million) and increased operating and administrative expenses ($3.05.7 million) reflecting, among other things, lower compensation. The higher depreciation and amortization expense and lower legaloperating and consulting expenses.administrative expenses are largely attributable to CMG. The increase in earnings before interest expense and income taxes reflects the increase in operating income and equity income from Pennant, a natural gas gathering and processing equity interest that was acquired as part of the CMG Acquisition.

UGI Utilities
56
For the three months ended December 31, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues $329.3
 $322.7
 $6.6
 2.0 %
Total margin (a) $176.6
 $161.9
 $14.7
 9.1 %
Operating and administrative expenses (a) $58.1
 $61.2
 $(3.1) (5.1)%
Operating income $91.8
 $77.0
 $14.8
 19.2 %
Earnings before interest expense and income taxes $91.6
 $77.4
 $14.2
 18.3 %
Gas Utility system throughput—bcf        
Core market 26.1
 26.5
 (0.4) (1.5)%
Total 84.5
 75.7
 8.8
 11.6 %
Electric Utility distribution sales - gwh 245.6
 249.7
 (4.1) (1.6)%
Gas Utility heating degree days—% (warmer) than normal (b) (4.2)% (0.5)% —
 —

(a)Total margin represents revenues less cost of sales and revenue-related taxes (i.e., Electric Utility gross receipts taxes) of $1.1 million and $1.3 million during the three months ended December 31, 2019 and 2018, respectively. For financial statement

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purposes, revenue-related taxes are included in depreciation expense principally reflects incremental depreciation“Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from the expansion of our natural gas gatheringoperating and LNG assets.

UGI Utilities
For the three months ended June 30, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues (a) $163.9
 $159.9
 $4.0
 2.5 %
Total margin (a)(b) $102.0
 $86.3
 $15.7
 18.2 %
Operating and administrative expenses (b) $58.5
 $61.0
 $(2.5) (4.1)%
Operating income $20.4
 $4.4
 $16.0
 363.6 %
Income (loss) before income taxes $8.4
 $(6.1) $(14.5) (237.7)%
Gas Utility system throughput—bcf        
Core market 9.0
 11.4
 (2.4) (21.1)%
Total 59.1
 53.7
 5.4
 10.1 %
Electric Utility distribution sales - gwh 209.0
 221.7
 (12.7) (5.7)%
Gas Utility heating degree days—% (warmer) colder than normal (c) (27.1)% 5.1% —
 —

administrative expenses presented above).
(a)In accordance with the PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the three months ended June 30, 2019, were reduced by $1.7 million to reflect the credit to customers of tax savings of the TCJA accrued during the period. In accordance with the PAPUC Order, Gas Utility’s revenues and total margin for the three months ended June 30, 2018 were reduced by $22.7 million and an associated regulatory liability established related to savings accrued during the period January 1, 2018 to June 30, 2018.
(b)Total margin represents total revenues less total cost of sales and revenue-related taxes (i.e. Electric Utility gross receipts taxes) of $0.9 million and $1.1 million during the three months ended June 30, 2019 and June 30, 2018, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed 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 the three months ended June 30,December 31, 2019, were 27.1%4.2% warmer than normal and 30.6% warmer than the prior-year period. Temperatures in the month of April 2019, the primary heating month of the quarter, were nearly 44%3.7% warmer than the prior-year period. Gas Utility core market volumes decreased 2.4slightly (0.5 bcf (21.1%and 1.9%) principally reflecting the effects of the significantly warmer weather partially offset by growth in the number of core market customers.customers and higher average use per customer. Total Gas Utility distribution system throughput increased 5.48.8 bcf reflecting higher large firm and interruptible delivery service volumes (7.8(5.1 bcf) and higher large firm delivery service volumes (4.1 bcf) partially offset by the previously mentioned lowerslight decrease in core market volumes. Electric Utility kilowatt-hour sales were lower than the prior-year period principally reflecting the impact of warmer spring weather on Electric Utility heating-related sales.
UGI Utilities revenues increased $4.0$6.6 million in the three months ended June 30,December 31, 2019, reflecting a $5.8$9.2 million increase in Gas Utility revenues partially offset by a $1.8$2.6 million decrease in Electric Utility revenues. In accordance with the May 17, 2018, PAPUC Order, during the prior-year three-month period, Gas Utility’s revenues were reduced by $22.7 million to reflect the credit to customers of tax savings of the TCJA. Substantially all of the $22.7 million reduction in revenues and margin recorded during the three months ended June 30, 2018 related to tax savings associated with the three months ended March 31, 2018. Excluding the impact of this reduction in revenues, Gas Utility revenues decreased $16.9 million. The decreaseincrease in Gas Utility revenues principally reflects lowerhigher core market revenues ($17.811.1 million) and lowerhigher large firm and interruptible delivery service total marginrevenues ($2.3 million), partially offset by higherlower off-system sales revenue ($5.2 million) which includes capacity releases due in part to the adoption of ASC 606 (which requires thatand capacity release contracts be reflected on a gross, rather than net, basis)revenues ($6.8 million). The $17.8$11.1 million decreaseincrease in Gas Utility core market revenues principally reflects the effects of the increase in base rates effective October 11, 2019 and slightly higher PGC rates partially offset by slightly lower core market throughput. The $1.8$2.6 million decrease in Electric Utility revenues during the 2019 three-month period principally reflects the effects ofis largely attributable to lower DS rates and, to a much lesser extent, the lower kilowatt-hour sales partially offset by an increase in Electric Utility base rates effective October 27, 2018 ($0.4 million) and higher transmission revenue ($0.4 million).sales.

UGI Utilities cost of sales was $61.0$151.6 million in the three months ended June 30,December 31, 2019 compared with $72.5$159.5 million in the three months ended June 30,December 31, 2018, reflecting lower Gas Utility cost of sales ($9.25.3 million) and lower Electric Utility cost of sales ($2.32.6 million) on the lower sales and DS customers transferring to alternate suppliers.. The lower Gas Utility cost of sales principally

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reflects the effects of the lower core market volumes ($9.8 million) and lower average retail core market PGC rates ($2.2 million), partially offset by an increase in costcosts of sales associated with off-system sales ($4.67.7 million), which includes capacity release partially offset by increased cost of sales (due principallyrelated to the presentation of capacity release contracts resulting from the adoption of ASC 606).core market volumes ($1.8 million) reflecting higher PGC rates.

UGI Utilities total margin increased $15.7 million reflecting the impact in the prior-year period of the $22.7 million reduction in revenues resulting from the previously mentioned PAPUC Order. Excluding this reduction in the prior year, UGI Utilities total margin decreased $7.0$14.7 million during the 2019 three-month period principally reflecting lowerhigher total margin from Gas Utility core market customers ($5.99.2 million), lower including the impact of the increase in base rates which became effective October 11, 2019. The margin increase was also impacted by an unallocated negative surcharge revenue reduction ($4.1 million) in the 2018 three-month period as a result of a PAPUC Order related to the TCJA and higher large firm and interruptible delivery service total margin ($0.51.0 million) partially offset by slightly higher Electric Utility total margin ($0.7 million) and higher off-system sales margin reflecting the margin impacts of the presentation of certain revenues in accordance with ASC 606. The increase in Electric Utility margin principally reflects the increase in base rates and higher transmission revenue partially offset by the lower distribution system sales..

UGI Utilities operating income and earnings before interest expense and income taxes increased $16.0$14.8 million and $14.2 million, respectively, during the 2019 three-month period principally reflecting the previously mentioned increase in total margin ($15.714.7 million) and slightly lower operating and administrative expenses ($2.53.1 million) partially offset by greater depreciation expense ($1.8 million) and a $0.5 million increase in other operating expense.. The decrease in UGI Utilities operating and administrative expenses reflects, among other things, lower allocated corporate expenses ($1.5 million), uncollectible accounts expense ($1.11.8 million), IT maintenance and consultinglower compensation and benefits expenses ($0.91.2 million) and travel and entertainment expenses ($0.7 million),. The effect of these increases was partially offset by higher contractor and outside servicesgreater depreciation expense ($1.53.2 million). The increase in depreciation expense reflects attributable to increased IT and distribution system capital expenditure activity. UGI Utilities income before income taxes was $14.5 million higher principally reflecting the increase in UGI Utilities operating income ($16.0 million) and, to a much lesser extent, higher postretirement plan non-service income partially offset by higher interest expense ($2.3 million).

Interest Expense and Income Taxes

Our consolidated interest expense during the 2019 three-month period was $60.5$84.1 million, slightly higher than the $56.5compared to $60.2 million of interest expense recorded during the 2018 three-month period. The highersignificant increase in interest expense principally reflects higher short-term interest expense on credit agreement borrowingslong-term debt outstanding 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 average long-term debt outstanding.interest on short-term borrowings.

OurThe higher effective income tax rate infor the 2019 three-month period reflects a U.S. federal income tax ratetaxes on our 100% ownership of 21%. Our effectivethe Partnerships compared to income tax rate intaxes on our approximately 26% ownership interest during the 2018 three-month period reflects a blended U.S. federal income tax rate of 24.5%. Income tax expense in the prior-year three-month period reflects adjustments to income tax balances initially recorded in December 2017 as a result of the enactment of the TCJA and the December 2017 French Finance Bills and higher excess tax benefits from share-based awards.

2019 Nine-Month Period Compared to the 2018 Nine-Month Period
AmeriGas Propane
For the nine months ended June 30, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues $2,270.5
 $2,356.0
 $(85.5) (3.6)%
Total margin (a) $1,246.5
 $1,261.7
 $(15.2) (1.2)%
Partnership operating and administrative expenses (b) $719.5
 $704.1
 $15.4
 2.2 %
Impairment of Partnership tradenames and trademarks (c) $—
 $75.0
 $(75.0) (100.0)%
Partnership Adjusted EBITDA (d) $543.5
 $570.8
 $(27.3) (4.8)%
Operating income (e) $410.0
 $359.8
 $50.2
 14.0 %
Retail gallons sold (millions) 882.4
 905.5
 (23.1) (2.6)%
Heating degree days—% colder than normal (f) 4.0% 0.4% —
 —
(a)Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2019 and 2018 excludes net pre-tax unrealized losses of $64.8 million and $10.1 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)Partnership operating and administrative expenses for the nine months ended June 30, 2019 include $2.7 million of expenses associated with the Proposed Merger and $5.0 million of expenses to correct vehicle lease expense associated with prior periods.
(c)The 2018 nine-month period includes the impact of the $75.0 million impairment charge associated with the plan to discontinue the use of certain tradenames and trademarks.

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(d)Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 16 to Condensed Consolidated Financial Statements).
(e)Operating income includes certain operating and administrative expenses of the General Partner.
(f)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 the 2019 nine-month period were 2.6% lower than the prior-year period. Average temperatures based upon heating degree days were 4.0% colder than normal and 3.6% colder than the prior-year period. Although average temperatures during the 2019 nine-month period across our entire service territory were colder than normal, we experienced significantly warmer than normal temperatures in the southeastern U.S. during January and February.
Retail propane revenues decreased $87.3 million during the 2019 nine-month period reflecting the effects of the lower retail volumes sold ($53.3 million) and the lower average retail selling prices ($34.0 million). Wholesale propane revenues increased $3.5 million reflecting higher wholesale volumes sold ($14.1 million) partially offset by lower average wholesale selling prices ($10.6 million). Average daily wholesale propane commodity prices during the 2019 nine-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 25% lower than such prices during the 2018 nine-month period. Other revenues in the 2019 nine-month period were slightly lower than in the prior-year period. Total cost of sales decreased $70.3 million reflecting the effects of lower average propane product costs ($55.5 million) and lower retail propane volumes sold ($25.0 million) partially offset by higher wholesale propane volumes sold ($13.6 million).

AmeriGas Propane total margin in the 2019 nine-month period was $15.2 million lower than in the 2018 nine-month period reflecting lower retail propane total margin ($16.9 million) partially offset by higher tank rent and service total margin. The decline in retail propane total margin reflects the lower retail volumes sold ($27.9 million) partially offset by slightly higher average retail propane unit margins ($11.0 million) due, in part, to the effects of declining wholesale propane prices during the 2019 nine-month period.

Partnership Adjusted EBITDA decreased $27.3 million in the 2019 nine-month period principally reflecting the lower total margin ($15.2 million) and slightly higher Partnership operating and administrative expenses ($12.7 million, excluding $2.7 million of Proposed Merger expenses). The increase in Partnership operating and administrative expenses in the 2019 nine-month period reflects, among other things, higher required accruals for litigation ($10.0 million) and higher vehicle lease expense ($8.7 million) which includes $5.0 million to correct vehicle lease expense associated with prior periods. These increases were partially offset by lower general insurance and self-insured casualty and liability expense, and lower travel and entertainment, professional fees and advertising expenses. AmeriGas Propane operating income was $50.2 million higher in the 2019 nine-month period principally reflecting the absence of a $75.0 million impairment charge recorded in the prior-year period associated with a plan to discontinue the use of certain tradenames and trademarks and slightly lower depreciation and amortization expense ($5.0 million) partially offset by the previously mentioned $27.3 million decrease in Partnership Adjusted EBITDA.

UGI International
For the nine months ended June 30, 2019 2018 Decrease
(Dollars in millions)        
Revenues $1,980.5
 $2,227.4
 $(246.9) (11.1)%
Total margin (a) $808.7
 $887.2
 $(78.5) (8.8)%
Operating and administrative expenses (b) $511.7
 $546.2
 $(34.5) (6.3)%
Operating income $212.7
 $234.4
 $(21.7) (9.3)%
Income before income taxes (c)(d) $194.4
 $203.1
 $(8.7) (4.3)%
LPG retail gallons sold (millions) (e) 672.0
 712.5
 (40.5) (5.7)%
Heating degree days—% (warmer) than normal (f) (5.0)% (4.1)% —
 —
(a)Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2019 and 2018 excludes net pre-tax (losses) gains of $(136.7) million and $39.3 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)The 2018 nine-month period includes $20.8 million of Finagaz integration expenses.
(c)Income before income taxes for the nine months ended June 30, 2019 and 2018 excludes net pre-tax unrealized gains on certain foreign currency derivative contracts of $11.9 million and $24.1 million, respectively. Income before income taxes

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for the nine months ended June 30, 2019 and 2018 includes net pre-tax realized gains (losses) on certain foreign currency derivative contracts of $5.2 million and $(14.2) million, respectively.
(d)Income before income taxes for the nine months ended June 30, 2019, is net of a $6.1 million pre-tax loss on extinguishments of debt.
(e)Prior-year amounts adjusted to conform to current-year classification.
(f)Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

Average temperatures during the 2019 nine-month period were 5.0% warmer than normal and 0.9% warmer than the prior-year period. Total retail gallons sold during the 2019 nine-month period were 5.7% 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 the beginning of the Fiscal 2019 heating season, average wholesale prices for propane and butane in northwest Europe were approximately 9% and 6% lower than in the prior-year period, respectively, reflecting a significant decline in LPG prices during the 2019 nine-month period.

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 the 2019 and 2018 nine-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.14 and $1.20, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.29 and $1.36, respectively. During the nine months ended June 30, 2019 and 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 $1.17 and $1.09, respectively, and at average British pound sterling-to-dollar exchange rates of $1.30 and $1.27, respectively.

UGI International revenues decreased $246.9 million during the 2019 nine-month period principally reflecting the lower retail and lower wholesale LPG volumes sold, and the translation effects of the weaker euro and British pound sterling (approximately $90 million). UGI International cost of sales decreased $168.4 million during the 2019 nine-month period 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 $55 million), and the effects of slightly lower average wholesale prices for LPG. Although the average un-weighted wholesale price for LPG during the 2019 nine-month period was slightly lower than in the prior-year period, wholesale LPG prices during late Fiscal 2018 and early in the 2019 nine-month period were higher than in the prior-year period resulting in higher LPG inventory costs entering the heating season.

UGI International total margin decreased $78.5 million primarily reflecting the lower retail LPG volumes sold, and the translation effects of the weaker euro and British pound sterling (approximately $35 million). These decreases in total margin were partially offset by slightly higher average retail LPG unit margin reflecting margin management efforts and the recovery of energy conservation compliance costs.

The $21.7 million decrease in UGI International operating income principally reflects the $78.5 million decrease in total margin partially offset by lower operating and administrative expenses ($34.5 million), lower depreciation and amortization expense ($14.1 million), and higher other operating income including higher income on asset sales and income from a customer contract settlement during the 2019 nine-month period. The decrease in operating and administrative expenses reflects, in large part, the impact of the weaker euro and British pound sterling (approximately $20 million) and lower local currency operating and administrative expenses. Operating and administrative expenses in the prior-year period include $20.8 million of Finagaz integration expenses. Excluding the Finagaz integration expenses recorded in the prior-year, local currency operating and administrative expenses were slightly higher principally reflecting higher compliance costs associated with energy conservation and costs related to strategic projects partially offset by lower expenses associated with operational safety requirements, and lower distribution, advertising and other general expenses. The lower depreciation and amortization expense principally reflects adjustments recorded in the prior-year period 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 income before income taxes in the 2019 nine-month period was $8.7 million lower than the prior-year period principally reflecting the net effects of the $21.7 million decrease in UGI International operating income and a $6.1 million loss on debt extinguishments 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 ($19.4 million).


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Midstream & Marketing
For the nine months ended June 30, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues $1,269.1
 $1,157.0
 $112.1
 9.7 %
Total margin (a) $216.9
 $284.4
 $(67.5) (23.7)%
Operating and administrative expenses $88.1
 $84.3
 $3.8
 4.5 %
Operating income $95.1
 $168.4
 $(73.3) (43.5)%
Income before income taxes $98.0
 $168.4
 $(70.4) (41.8)%
(a)Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2019 and 2018 excludes net pre-tax (losses) gains of $(11.1) million and $0.8 million, respectively, on commodity derivative instruments not associated with current-period transactions.

Average temperatures across Midstream & Marketing’s energy marketing territory during the 2019 nine-month period were approximately 0.6% warmer than normal and 0.2% colder than the prior-year period. Although average temperatures in the 2019 nine-month period were slightly colder than the prior-year period, the prior-year nine-month period experienced extremely cold and more volatile weather in late December 2017 and early January 2018.

Midstream & Marketing’s 2019 nine-month period revenues were $112.1 million higher than the prior-year period principally reflecting higher natural gas revenues ($168.3 million) and, to a much lesser extent, higher natural gas gathering, HVAC and peaking revenue. These increases in revenues were partially offset principally by lower capacity revenues ($61.3 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 from customer growth including customers obtained through the acquisition of South Jersey Energy Company’s natural gas marketing business on December 1, 2018, and higher average natural gas prices. The decrease in capacity management revenues reflects significantly lower capacity values during the 2019 nine-month period. 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 $1,052.2 million in the 2019 nine-month period compared to $872.6 million in the 2018 nine-month period, an increase of $179.6 million, principally reflecting the higher natural gas volumes and higher natural gas costs.

Midstream & Marketing total margin decreased $67.5 million in the 2019 nine-month period principally reflecting lower total margin from our midstream assets ($53.6 million), lower electric generation total margin ($8.3 million) and lower margin from natural gas marketing reflecting lower average unit margins. The decrease in total margin from our midstream assets is principally the result of significantly lower capacity management total margin ($61.3 million) partially offset by higher natural gas gathering and peaking total margin. 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 the 2019 nine-month period is principally the result of the absence in the current-year period of extremely cold and volatile weather experienced in late December and early January of the prior-year period, the effects of increased pipeline restrictions during the 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 income before income taxes during the 2019 nine-month period decreased $73.3 million and $70.4 million, respectively. The decrease in operating income principally reflects the previously mentioned decrease in total margin ($67.5 million), higher operating and administrative expenses ($3.8 million), and higher depreciation expense ($2.8 million). The $3.8 million increase in operating and administrative expenses principally reflects higher taxes other than income taxes ($1.5 million), slightly higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities. The increase in operating and administrative expense also reflects higher operating and maintenance expenses associated with a planned outage at the Conemaugh generating unit. The increase in depreciation expense principally reflects incremental depreciation from the expansion of our LNG, natural gas gathering and peaking assets. The $70.4 million decrease in income before income taxes in the 2019 nine-month period principally reflects the lower operating income ($73.3 million) partially offset by the absence of a pension settlement recorded in the prior-year period, higher AFUDC income associated with the PennEast pipeline and lower interest expense.


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UGI Utilities
For the nine months ended June 30, 2019 2018 Increase (Decrease)
(Dollars in millions)        
Revenues (a) $916.2
 $966.3
 $(50.1) (5.2)%
Total margin (a)(b) $474.1
 $481.0
 $(6.9) (1.4)%
Operating and administrative expenses (b) $187.4
 $182.6
 $4.8
 2.6 %
Operating income $217.3
 $237.0
 $(19.7) (8.3)%
Income before income taxes $182.2
 $203.3
 $(21.1) (10.4)%
Gas Utility system throughput—bcf        
Core market 75.7
 75.8
 (0.1) (0.1)%
Total 231.4
 210.2
 21.2
 10.1 %
Electric Utility distribution sales - gwh 737.8
 747.0
 (9.2) (1.2)%
Gas Utility heating degree days—% (warmer) than normal (c) (3.7)% (1.3)% —
 —
(a)In accordance with the PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the nine months ended June 30, 2019 were reduced by $37.9 million to reflect the credit to customers of tax savings of the TCJA. Gas Utility’s revenues and total margin for the nine months ended June 30, 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 $3.6 million and $3.7 million during the nine months ended June 30, 2019 and June 30, 2018, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed 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 the 2019 nine-month period were 3.7% warmer than normal and 2.4% warmer than the 2018 nine-month period. 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. Total Gas Utility distribution system throughput increased 21.2 bcf reflecting higher large firm delivery service volumes (23.6 bcf) partially offset by a decline in interruptible delivery service volumes (2.3 bcf). Electric Utility kilowatt-hour sales were 1.2% lower than the prior-year period principally reflecting the impact of the warmer weather on Electric Utility heating-related sales.
UGI Utilities revenues decreased $50.1 million reflecting a $51.5 million decrease in Gas Utility revenues partially offset by a $1.4 million increase in Electric Utility revenues. Gas Utility revenues in both the 2019 and 2018 nine-month periods 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 periods as a result of the PAPUC Order, Gas Utility’s revenues decreased $37.7 million principally reflecting lower core market revenues ($41.0 million) due to lower average PGC rates during the 2019 nine-month period, and lower large firm and interruptible delivery service revenues ($4.0 million) partially offset by an increase in off-system sales revenues ($4.0 million) which includes capacity release revenues due principally to the adoption of ASC 606 (which requires capacity release contracts be reflected on a gross, rather than net, basis) and higher other revenues ($3.0 million). The increase in Electric Utility revenues during the 2019 nine-month period principally reflects higher transmission revenue ($1.8 million) and an increase in Electric Utility base rates effective October 27, 2018 ($1.6 million) partially offset by the impact of the lower distribution system sales.

UGI Utilities cost of sales was $438.5 million in the 2019 nine-month period compared with $481.6 million in the 2018 nine-month period reflecting lower Gas Utility cost of sales ($41.8 million) and lower Electric Utility cost of sales ($1.3 million) as a result of the lower distribution system sales. The lower Gas Utility cost of sales principally reflects lower average retail core-market PGC rates ($42.4 million).

UGI Utilities total margin decreased $6.9 million reflecting lower total margin from Gas Utility ($9.7 million) partially offset by higher total margin from Electric Utility ($2.8 million). Gas Utility total margin in both the 2019 and 2018 nine-month periods reflects the effects of the May 17, 2018, PAPUC Order regarding the credit to customers of tax savings of the TCJA. Excluding the effects on margin in both periods as a result of the PAPUC Order, Gas Utility total margin increased $4.1 million. The increase in Gas Utility margin reflects higher off-system sales margin principally resulting from the presentation of certain revenues in accordance with the adoption of ASC 606, and higher total margin from core market customers reflecting, among other things,

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higher DSIC revenues. The increase in Electric Utility margin principally reflects higher transmission revenue and the increase in base rates.

UGI Utilities operating income decreased $19.7 million principally reflecting the decrease in total margin ($6.9 million), higher operating and administrative expenses ($4.8 million), greater depreciation expense ($5.1 million), and higher other operating expense ($3.1 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher general and administrative costs including higher contractor and outside services expense ($4.6 million), the absence of a favorable payroll tax adjustment recorded in the prior-year period ($2.1 million), and higher non-income taxes ($1.3 million), payroll expenses ($1.3 million), allocated corporate expenses ($0.8 million), materials expenses ($0.6 million) and IT maintenance and consulting expenses ($0.5 million). These increases were partially offset by lower employee benefits expense ($3.8 million) and a decrease in uncollectible accounts expense ($3.1 million). The increase in depreciation expense reflects increased distribution system and IT capital expenditure activity. UGI Utilities income before income taxes decreased $21.1 million principally reflecting the decrease in UGI Utilities operating income ($19.7 million) and higher interest expense ($4.3 million) partially offset by higher postretirement plan non-service income ($3.0 million).

Interest Expense and Income Taxes

Our consolidated interest expense during the 2019 nine-month period was $181.7 million, slightly higher than the $172.8 million of interest expense recorded during the 2018 nine-month period. The higher interest expense principally reflects higher short-term interest expense on credit agreement borrowings and higher long-term debt outstanding.

Our effective income tax rate in the 2019 nine-month period reflects a U.S. federal income tax rate of 21%. Our effective income tax rate in the 2018 nine-month period reflects a blended U.S. federal income tax rate of 24.5%.

As previously mentioned, our consolidated income taxes for the prior-year nine month period ended June 30, 2018, were significantly impacted by the enactment of the TCJA and the December 2017 French Finance Bills. As a result of the TCJA and the December 2017 French Finance Bills, during the three months ended December 31, 2017, 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 the nine months ended June 30, 2018, was reduced by remeasurement adjustments totaling $172.1 million to tax-related accounts as a result of the enactment of the TCJA and was reduced by remeasurement adjustments totaling $13.5 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 their effects on regulatory assets and liabilities, see Notes 6 and 8 to Condensed Consolidated Financial Statements.

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 ReceivableReceivables Facility borrowings;borrowing capacity; and the ability to obtain long-term financing to meet anticipated contractual and projected cash

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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 $533.7$333.4 million at June 30,December 31, 2019, compared with $452.6$447.1 million at September 30, 2018.2019. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at June 30,December 31, 2019 and September 30, 2018,2019, UGI had $308.3$96.1 million and $194.3$224.9 million of cash and cash equivalents, respectively, mosta substantial portion of which areis located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.


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Long-term Debt and Short-term BorrowingsCredit Facilities

Long-term Debt

The Company’s debt outstanding at June 30,December 31, 2019 and September 30, 2018,2019, comprises the following:
June 30, 2019 September 30, 2018December 31, 2019 September 30, 2019
(Millions of dollars)AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Other Total TotalAmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corp & Other Total Total
Short-term borrowings$248.5
 $0.7
 $55.0
 $76.0
 $—
 $380.2
 $424.9
$321.0
 $181.3
 $88.4
 $279.0
 $—
 $869.7
 $796.3
                          
Long-term debt (including current maturities):                          
Senior notes$2,575.0
 $397.9
 $—
 $825.0
 $—
 $3,797.9
 $3,250.0
$2,575.0
 $392.5
 $—
 $825.0
 $—
 $3,792.5
 $3,781.5
Term loans and notes18.5
 341.0
 —
 155.6
 —
 515.1
 890.4
Term loans—
 336.4
 696.5
 152.5
 550.0
 1,735.4
 1,729.4
Other long-term debt—
 20.2
 0.4
 5.3
 8.2
 34.1
 59.0
12.0
 22.5
 41.3
(a)4.2
 297.9
 377.9
 345.7
Unamortized debt issuance costs(24.6) (8.7) —
 (4.7) —
 (38.0) (34.1)(22.7) (7.9) (11.5) (4.5) (3.8) (50.4) (52.6)
Total long-term debt$2,568.9
 $750.4
 $0.4
 $981.2
 $8.2
 $4,309.1
 $4,165.3
$2,564.3
 $743.5
 $726.3
 $977.2
 $844.1
 $5,855.4
 $5,804.0
Total debt$2,817.4
 $751.1
 $55.4
 $1,057.2
 $8.2
 $4,689.3
 $4,590.2
$2,885.3
 $924.8
 $814.7
 $1,256.2
 $844.1
 $6,725.1
 $6,600.3

UGI International. On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, 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. 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 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 is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving 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 the UGI International 3.25% Senior Notes, 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.

UGI Utilities. 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 sale of the UGI Utilities 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes.

For further information on these transactions and the Company’s other long-term borrowings, see Note 10 to Condensed Consolidated Financial Statements.

Subsequent Event - UGI Corporation Senior Credit Facility. 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 term loan

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commitment; (2) a three-year $300 million term loan commitment; and (3) a five-year $300 million revolving credit facility (including a $10 million sublimit for letters of credit). Proceeds from borrowings under the UGI Corporation Senior Credit Facility may to be used to finance the cash portion of the Proposed Merger; the CMG Acquisition; and for general corporate purposes.
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 UGI Corporation Senior Credit Facility restricts the ability of UGI to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. The UGI Corporation Senior Credit Facility also requires UGI to maintain a ratio of consolidated net indebtedness to consolidated EBITDA and, under certain circumstances relating to UGI’s credit rating, a ratio of consolidated EBITDA to consolidated interest expense.

On August 1, 2019, in order to fund a portion of the CMG Acquisition, UGI borrowed $300 million under the UGI Corporation Senior Credit Facility revolving credit facility and $300 million under the $300 million term loan commitment.

For further information on the UGI Corporation Senior Credit Facility, see Note 17 to Condensed Consolidated Financial Statements.
(a)Amount includes finance lease recognized as a result of the adoption of ASU 2016-02. For additional information, see Notes 2 and 9 to Condensed Consolidated Financial Statements.

Credit Facilities

Additional information related to the Company’s credit agreements can be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 56 to the Consolidated Financial Statements in the Company’s 20182019 Annual Report.


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Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of June 30,December 31, 2019 and 2018, is presented in the table below.
(Currency in millions) Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity
As of June 30, 2019        
As of December 31, 2019        
AmeriGas OLP $600.0
 $248.5
 $62.8
 $288.7
 $600.0
 $321.0
 $62.7
 $216.3
UGI International, LLC(a) €300.0
 €—
 €—
 €300.0
 €300.0
 €160.5
 €—
 €139.5
Energy Services $240.0
 $—
 $—
 $240.0
 $200.0
 $20.0
 $—
 $180.0
UGI Utilities $350.0
 $76.0
 $—
 $274.0
 $350.0
 $279.0
 $—
 $71.0
As of June 30, 2018        
UGI Corporation (b) $300.0
 $290.0
 $—
 $10.0
As of December 31, 2018        
AmeriGas OLP $600.0
 $177.0
 $67.2
 $355.8
 $600.0
 $368.5
 $63.5
 $168.0
UGI International, LLC (a) €300.0
 €—
 €—
 €300.0
UGI France SAS (a) €60.0
 €—
 €—
 €60.0
Flaga (a) €55.0
 €—
 €1.0
 €54.0
UGI International, LLC €300.0
 €—
 €—
 €300.0
Energy Services $240.0
 $—
 $—
 $240.0
 $240.0
 $—
 $—
 $240.0
UGI Utilities (b) $300.0
 $118.5
 $2.0
 $179.5
UGI Utilities $450.0
 $296.0
 $2.0
 $152.0
(a)Facility terminated on October 25, 2018, concurrent with entering into theThe 2018 UGI International Credit Facilities Agreement.Agreement permits UGI International, LLC to borrow in euros or dollars. At December 31, 2019, the amount borrowed was USD-denominated borrowings of $180.0 million, equal to €160.5 million.
(b)Facility terminatedBorrowings outstanding have been classified as “Long-term debt” on June 27, 2019, concurrent with entering into the UGI Utilities 2019 Credit Agreement.Condensed Consolidated Balance Sheets.


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The average daily and peak short-term borrowings under the Company’s principal credit agreements during the ninethree months ended June 30,December 31, 2019 and 2018 are as follows:
 For the nine months ended For the nine months ended For the three months ended For the three months ended
 June 30, 2019 June 30, 2018 December 31, 2019 December 31, 2018
(Currency in millions) Average Peak Average Peak
(Millions of dollars or euros) Average Peak Average Peak
AmeriGas OLP $281.8
 $422.0
 $186.3
 $349.0
 $322.0
 $359.0
 $306.3
 $401.0
UGI International, LLC €—
 €—
 €—
 €—
 €187.0
 €187.3
 €—
 €—
Energy Services $0.2
 $25.0
 $20.7
 $79.0
 $40.5
 $76.5
 $—
 $—
UGI Utilities $174.0
 $311.0
 $150.0
 $215.0
 $225.6
 $281.0
 $250.7
 $311.0
UGI Corporation $293.9
 $300.0
 $—
 $—

UGI International. On October 18, 2018, UGI International, LLC entered into the 2018 UGI International Credit Facilities Agreement which includes a €300 million senior unsecured multicurrency revolving credit facility agreement. For further information on the 2018 UGI International Credit Facilities Agreement, see “Long-term Debt” above and Note 10 to Condensed Consolidated Financial Statements.

On July 31, 2019 and August 1, 2019, UGI International 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 and cash on hand.

Midstream & Marketing.Receivables Facility. Energy Services has a Receivables Facility with an issuer of receivables-backed commercial paper currently scheduled to expire on October 25, 2019.23, 2020. At June 30,December 31, 2019, the outstanding balance of ESFC trade receivables was $74.2$86.0 million, of which $55.0$68.4 million was sold to the bank. At June 30,December 31, 2018, the outstanding balance of ESFC trade receivables was $58.3$135.4 million, of which none were$10.0 million was sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. During the ninethree months ended June 30,December 31, 2019 and 2018, peak sales of receivables were $68.0$68.4 million and $68.0$15.0 million, respectively, and average daily amounts sold were $10.7$49.8 million and $14.8$1.5 million, respectively. For additional information regarding the Receivables Facility, see Note 9 to the Condensed Consolidated Financial Statements.

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). The Company may request an increase in the amount of loan commitments under the UGI Utilities 2019 Credit Agreement to a maximum aggregate amount of $150 million. Concurrently with entering into the UGI Utilities 2019 Credit Agreement, the Company terminated its existing $450 million revolving credit agreement dated as of 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 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 2020, but will be extended by UGI Utilities to June 2024 if on or before June 25, 2020, the Company satisfies certain requirements relating to approval by the PAPUC. The Company is currently seeking such regulatory approval.

Dividends and Distributions

On April 30,November 22, 2019, UGI’s Board of Directors approved an increase in the quarterlydeclared a cash dividend rateequal to $0.325 per common share. The dividend was paid on UGI Common Stock to $0.30 per Common Share, or $1.20 on an annual basis. The new dividend rate reflects an approximate 15.4% increase from the previous quarterly rate of $0.26. The new quarterly dividend rate was effective with the dividend payable on JulyJanuary 1, 2019,2020, to shareholders of record on June 14,December 16, 2019. On July 23, 2019,January 22, 2020, UGI’s Board of Directors approved an increase in thedeclared a quarterly dividend rate on UGI Common Stock toof $0.325 per Common Share, or $1.30 on an annual basis.common share. The new quarterly dividend rate will be effective with the dividendis payable on OctoberApril 1, 2019,2020, to shareholders of record on August 9, 2019.

On July 22, 2019, the General Partner’s Board of Directors approved a quarterly distribution of $0.95 per Common Unit payable August 19, 2019, to unitholders of record on August 9, 2019. During the nine months ended June 30, 2019, AmeriGas Partners declared and paid quarterly distributions on all limited partner units at a rate of $0.95 per Common Unit for the quarters ended March 31, 2019, December 31, 2018, and September 30, 2018.


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16, 2020.

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

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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 flow provided byfrom operating activities was $924.6$118.4 million in the 2019 nine-monththree-month period compared to $926.8$96.6 million in the 2018 nine-monththree-month period. Cash flow from operating activities before changes in operating working capital was $964.8$355.6 million in the 2019 nine-monththree-month period compared to $1,050.6$372.2 million in the prior-year period. The lower cash flow from operating activities before changes in operating working capital principally reflects the lower operating results in the current-year period. Cash used to fund changes in operating working capital totaled $40.2$237.2 million in the 2019 nine-monththree-month period compared to $123.8$275.6 million in the prior-year period. The lower net cash used byto fund changes in operating working capital in the 2019 nine-monththree-month period reflects, among other things, collateral deposits received from commodity derivative instrument counterparties in the effectscurrent year compared with collateral deposits paid in the prior year, and net recoveries of Gas Utility purchased gas costs in the lower 2019 nine-month period sales volumes and prices on changescurrent year compared to net repayments in accounts receivable, the impact of declines in commodity prices onprior year. These positive cash required to fund inventory, and lower income tax payments made during the current-year period. These reductions in cash required to fund changes in operating working capitalflow effects were partially offset by the effects ofgreater cash used to fund net refunds of UGI Utilities’ deferred fuelchanges in other operating working capital accounts including, among other things, lower cash flow from changes in inventories and power costs during the current-year period compared to net recoveries of such costs during the prior-year period.accounts payable.

Investing Activities. Cash flow used by investing activities was $563.5$175.9 million in the 2019 nine-monththree-month period compared with $575.5$194.0 million in the prior-year period. 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 investees; and proceeds from sales of assets and businesses. Cash expenditures for property, plant and equipment were $510.2$182.0 million in the 2019 nine-monththree-month period compared to $394.2$183.3 million in the prior-year period reflecting, in part, higher IT expenditures associated with Enterprise Resource Planning systems and higher UGI Utilities new business capital expenditures. Cash used for acquisitions of businesses and assets in the 2019 nine-month period reflects Energy Services’ acquisitions of South Jersey Energy Company’s natural gas marketing business and gas gathering assets in Pennsylvania and UGI International’s acquisitions of several smaller LPG retail businesses in Europe.period. Cash used for acquisitions of businesses and assets in the 2018 nine-monththree-month period principally reflects UGI International’sEnergy Services’ acquisition of UniverGas and Midstream & Marketing’s acquisition of the Texas CreekSouth Jersey Energy Company’s natural gas gathering assets in Pennsylvania.marketing business.

Financing Activities. Cash flow used by financing activities was $241.6$32.6 million in the 2019 nine-monththree-month period compared with $402.3cash flow provided by financing activities of $134.0 million in the prior-year period. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net short-term borrowings; dividends and distributions on UGI Common Stock and, in the 2018 three-month period, AmeriGas Partners publicly held Common Units; and from time to time, issuances of UGI and AmeriGas Partners equity instruments.Common stock. Cash flows from financing activities in the prior-year period reflect significant UGI International refinancing transactions during the month of October 2018. 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. Also 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 net proceeds from these borrowings plus cash on hand were used principally to repay €540 million outstanding principal of UGI France SAS’sFrance’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 termDollar 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.

UTILITY REGULATORY MATTERS

Base Rate Filings.On January 28, 2019,2020, Gas Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial and industrial customers by $71.1$74.6 million annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund newto continue funding programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, Gas Utility has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $24.0 million of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates. Gas Utility requested that the new gas rates become effective March 29, 2019. The28, 2020. However, the PAPUC entered an Order dated February 28, 2019, suspendingtypically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the rate increasefiling date to allow for investigation and public hearings. On July 22, 2019, a Joint Petition for Approval of Settlement of all issues supported by all active parties was filed with the PAPUC. The Joint Petition is subject to receipt of a recommended decision by a PAPUC administrative law judge and an order of the PAPUC approving the settlement. Unless the PAPUC issues a final order prior to the end of the statutory suspension period, October 28, 2019, the initial proposed rate increase will become effective the next day, subject to

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refund and a subsequent PAPUC order. The CompanyUtilities cannot predict the timing or the ultimate outcome of the rate case review process.

On January 26, 2018, Electric28, 2019, the Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial, and industrial customers throughout its annualPennsylvania service territory by an aggregate $71.1 million. 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 $9.2$30.0 million which was later reduced by Electricunder a single consolidated tariff, approved a plan for uniform class rates, and permits the Gas Utility to $7.7extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years. The PAPUC’s final Order approved a negative surcharge, to return to customers $24.0 million of tax benefits experienced by Gas Utility over the period January 1, 2018 to reflectJune 30, 2018, plus applicable interest, in accordance with the impactMay 17, 2018 PAPUC Order, which became effective for a twelve-month period beginning on October 11, 2019, the effective date of the TCJA and other adjustments. The increased revenues would be used to fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Gas Utility’s new base rate.

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 order,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.

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.January 15, 2020,

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the Pennsylvania Commonwealth Court affirmed the PAPUC Order adopting the UGI Utilities’ position on both issues. The Pennsylvania Office of Consumer Advocate has the right to seek an appeal of the Pennsylvania Commonwealth Court Order to the Pennsylvania Supreme Court.





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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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. In addition, certain of our UGI International businesses hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts as further described below.

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. At June 30, 2019, the fair values of Gas Utility’s natural gas futures and option contracts were not material.

Electric Utility's DS tariffs contain clauses whichthat 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 June 30,December 31, 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 Condensed Consolidated Statements of Income. At June 30, 2019, the fair values of Gas Utility’s and Electric Utility’s gasoline futures contracts were not material.

In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price salessale 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.

From time to time, Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into NYISO capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX and over-the-counter futures and options contracts to economically hedge price volatility associated with the gross margin associated withderived from the purchase and anticipated later near-term sale of natural gas or propane.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

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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.

The fair value
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Table of unsettled commodity price risk sensitive derivative instruments held at June 30, 2019 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a loss of $50.7 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas and electricity would result in a decrease in fair value of approximately $97.9 million at June 30, 2019.Contents
UGI CORPORATION AND SUBSIDIARIES

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 June 30,December 31, 2019, includes short-termrevolving credit facility borrowings and variable-rate term loans at UGI International’sInternational, LLC, UGI Utilities, Energy Services and UGI Utilities’ variable-rate term loans.Corporation. These debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI International hasWe have entered into pay-fixed, receive-variable interest rate swaps that generally fixswap agreements on all or a significant portion of the underlying euribor interest rate on its euro-denominated term loan at 0.34% through October 2022.loans’ principal balances and all or a significant portion of the term loans’ tenor. We have designated these interest rate swaps as a cash flow hedges. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on its variable-rate term loan at 3.00% beginning September 30, 2019 through July 2022. We have designated this forward-starting interest rate swap as a cash flow hedge. At June 30,December 31, 2019, combined borrowings outstanding under variable-rate debt agreements, excluding UGI International’sthe previously mentioned effectively fixed-rate debt, totaled $495.9$1,159.7 million.

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.

The fair value of unsettled interest rate risk sensitive derivative instruments held at June 30, 2019 (including pay-fixed, receive-variable interest rate swaps) was a loss of $7.8 million. A 50 basis point adverse change in short-term market interest rates would result in a decrease in fair value of approximately $1.7 million.

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 June 30,December 31, 2019, by approximately $110 million, which amount would be reflected in other comprehensive income. In October 2018, concurrent with entering intoWe have designated euro-denominated borrowings under 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.

The fair value of unsettled We layer in these foreign currency exchange rate risk sensitive derivative instruments held at June 30, 2019, wascontracts over a gainmulti-year period to eventually equal approximately 90% of $24.3 million. A hypothetical 10% adverse change in the value of the euro and the British pound sterling versus the U.S. dollar would result in a decrease in fair value of approximately $42.0 million.


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anticipated UGI CORPORATION AND SUBSIDIARIES

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 December 31, 2019, we had pledged net cash collateral with derivative instrument counterparties totaling $8.9. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30,December 31, 2019, restricted cash in brokerage accounts totaled $42.3$95.8 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 June 30,December 31, 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 June 30,December 31, 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 December 31, 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

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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
December 31, 2019    
Commodity price risk $(136.7) $(107.5)
Interest rate risk $(4.2) $(22.0)
Foreign currency exchange rate risk $35.5
 $(41.0)


ITEM 4. CONTROLS AND PROCEDURES

(a)Evaluation of Disclosure Controls and Procedures
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 Securities Exchange Act of 1934, as amended, 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 the end of the period covered by this Report, were effective at the reasonable assurance level.

(b)Change in Internal Control over Financial Reporting
During the quarter ended June 30,Effective October 1, 2019, the Partnership, implemented several new modules to its existing enterprise resource planning system. Specifically, this implementation further integrated, simplified and standardized processes and systems for the finance, procurement, payables and information technology functions and, as such, we consider this system implementation to be material to UGI Corporation. Where appropriate, we have made changes to our internal controls to address system changes and to ensure we maintain effective internal controls over financial reporting. Other than this system implementation, there were noCompany adopted ASU 2016-02, “Leases” (Topic 842), which required changes in the Company’s internal control over financial reporting, (as definedincluding implementation of new software to track and account for leases.
No changes in Rules 13a-15(f) and 15d-15(f) under the Exchange Act)Company’s internal control over financial reporting during the Company’s most recent fiscal quarter ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 20182019 Annual Report, and the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2019, which could materially affect our business, financial condition or future results. The risks described below, in our 20182019 Annual Report or in the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2019, are not the only risks facing UGI.the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

The acquisition of CMG by Energy Services from Columbia Midstream & Minerals Group, LLC (“CMMG”), a subsidiary of TC Energy, may not achieve some or all of the anticipated benefits.

On July 2, 2019, UGI announced its plan to complete the CMG Acquisition after entering into a Purchase and Sale Agreement, dated July 2, 2019, by and among CMMG, Energy Services, and solely for the limited purposes set forth therein, UGI and TransCanada PipeLine USA Ltd., and a Purchase and Sale Agreement, dated July 2, 2019, by and among CMMG, Energy Services, and solely for the limited purposes set forth therein, TransCanada PipeLine USA Ltd. The CMG Acquisition closed on August 1, 2019, and there can be no assurance that the CMG Acquisition will deliver the strategic, financial and operational benefits that we anticipate.

Securities lawsuits, including a class action, have been filed against UGI, the Partnership, the General Partner and members of the GP Board challenging aspects of the Proposed Merger and could result in substantial costs. An unfavorable judgment or ruling in these or any future lawsuits that may be filed may delay or prevent the completion of the Proposed Merger.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements in an effort to enjoin the merger or seek monetary relief from the counterparties. Following the announcement of the Proposed Merger on April 1, 2019, two unitholder lawsuits were filed that name the members of the GP Board, UGI, the Partnership, the General Partner and certain related entities as defendants. The first lawsuit, captioned Scarantino, et al., v. AmeriGas Partners, L.P., et al., Case No. 1:19CV01045 (the “Scarantino Lawsuit”), was filed as a putative class action in the United States District Court for the District of Delaware on June 5, 2019. The second lawsuit, captioned Votto v. AmeriGas Partners, L.P., et al., Case No. 2:19-cv-02888-CFK (the “Votto Lawsuit”), was filed as an individual action in the United States District Court for the Eastern District of Pennsylvania on July 2, 2019.ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The Scarantino and Votto Lawsuits each allege violations of Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder, as well as violations of Section 20(a) of the Exchange Act, because the proxy statement/prospectus relatedfollowing table sets forth information with respect to the Proposed Merger filed withCompany’s repurchases of its common stock during the SEC by UGI and the Partnership allegedly misrepresents or omits certain material information. Each of the plaintiffs in the Scarantino and Votto Lawsuits seeks equitable relief, including an injunction preventing completion of the Proposed Merger, rescission in the event the Proposed Merger is completed, damages and an award of attorneys’ and other fees and costs. Any other lawsuits that may be brought against UGI, the Partnership or any of the other parties involved in the Proposed Merger could seek similar remedies.quarter ended December 31, 2019.

Even if the Scarantino and Votto Lawsuits, and any future lawsuits, are without merit, which the defendants believe to be the case with the Scarantino and Votto Lawsuits, defending against these claims can result in substantial costs and divert management time and resources. We cannot predict the outcome of the Scarantino and Votto Lawsuits, or any future lawsuit, nor can we predict the amount of time and expense that will be required to resolve such lawsuits. An adverse judgment could result in monetary damages, which could have a negative impact on UGI’s liquidity and financial condition. UGI and the General Partner also have obligations under certain circumstances to hold harmless and indemnify each of the defendant directors against judgments, fines, settlements and expenses related to claims against such directors and otherwise to the fullest extent permitted under Pennsylvania law, Delaware law and the applicable bylaws and certificate of incorporation of UGI or the General Partner.
Period (a) Total Number of Shares Purchased (b) Average Price Paid per Share (or Unit) (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1) (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (1)
October 1, 2019 to October 31, 2019 — $0.00 — 6.80 million
November 1, 2019 to November 30, 2019 — $0.00 — 6.80 million
December 1, 2019 to December 31, 2019 500,000 $45.15 500,000 6.30 million
Total 500,000   500,000  

One of the conditions to the closing of the Proposed Merger is that no law, injunction, judgment or ruling enacted, promulgated, issued, entered, amended or enforced by any court or other governmental authority is in effect that enjoins, restrains, prevents or prohibits completion of the Proposed Merger or makes the completion of the Proposed Merger illegal. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Proposed Merger in the Scarantino or Votto Lawsuits, or any other similar lawsuit, then that injunction may delay or prevent the Proposed Merger from being completed within the expected timeframe or at all, which may adversely affect UGI’s and the Partnership’s business, financial position and results of operations.
(1)Shares of UGI Corporation Common Stock are repurchased through an extension of a previous share repurchase program announced by the Company on January 25, 2018. The UGI Board of Directors authorized the repurchase of up to 8 million shares of UGI Corporation Common Stock over a four-year period expiring in January 2022.


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ITEM 6. 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 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
         
2.1 
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
         
2.2 
Purchase and Sale Agreement - Pennant, dated as of July 2, 2019, by and among UGI Energy Services, LLC, Columbia Midstream & Minerals Group, LLC and TransCanada PipeLine USA Ltd.
 UGI Form 8-K (7/2/19) 2.2
         
10.1 
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.
 Utilities Form 8-K (6/27/19) 10.1
         
10.2 
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
         
31.1  
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 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-Q for the quarter ended June 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-Q for the quarter ended June 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      
         
Exhibit
No.
ExhibitRegistrantFilingExhibit
4.14
Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.
10.1
Amended and Restated Change in Control Agreement, dated December 6, 2019, between UGI Corporation and Mr. John L. Walsh.
10.2
First Amendment, dated as of December 17, 2019, to 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.
10.3
First Amendment, dated as of December 17, 2019, to 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.
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 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-Q for the quarter ended December 31, 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-Q for the quarter ended December 31, 2019, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INSXBRL Instance - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHXBRL Taxonomy Extension Schema
101.CALXBRL Taxonomy Extension Calculation Linkbase
101.DEFXBRL Taxonomy Extension Definition Linkbase
101.LABXBRL Taxonomy Extension Labels Linkbase
101.PREXBRL Taxonomy Extension Presentation Linkbase
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


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EXHIBIT INDEX
 
   
4.14
Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.
10.1
Amended and Restated Change in Control Agreement, dated December 6, 2019, between UGI Corporation and Mr. John L. Walsh.
10.2
First Amendment, dated as of December 17, 2019, to 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.
10.3
First Amendment, dated as of December 17, 2019, to 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.
31.1  
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30,December 31, 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-Q for the quarter ended June 30,December 31, 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-Q for the quarter ended June 30,December 31, 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
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)



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SIGNATURES
Pursuant to the requirements 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
  (Registrant)
    
Date:AugustFebruary 6, 20192020By:/s/ Ted J. Jastrzebski
   Ted J. Jastrzebski
   Chief Financial Officer
    
    
Date:AugustFebruary 6, 20192020By:/s/ Laurie A. Bergman
   Laurie A. Bergman
   Vice President, Chief Accounting Officer
   and Corporate Controller

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