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

FORM 10-Q
 
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 20182019
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 CORPORATION
(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, PA19406
(Address of principal executive offices)(Zip Code)
(610) 460 North Gulph Road, King of Prussia, PA19406
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 January 31, 20192020, there were 173,844,100208,548,324 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 December 31, 2018,2019, September 30, 20182019 and December 31, 20172018
5
  
Condensed Consolidated Statements of Income for the three months ended December 31, 20182019 and 20172018
6
  
Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 20182019 and 20172018
7
  
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 20182019 and 20172018
8
  
Condensed Consolidated Statements of Changes in Equity for the three months ended December 31, 20182019 and 20172018
9
  
Notes to Condensed Consolidated Financial Statements
10
  
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
3936
  
Item 3. Quantitative and Qualitative Disclosures About Market Risk
5349
  
Item 4. Controls and Procedures
5551
  
Part II Other Information
 
  
Item 1A. Risk Factors
5652
  
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
5652
  
Item 6. Exhibits
5753
  
Signatures
5955
  
 


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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, 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 October 1, 2018the 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
HVAC - UGI HVAC Enterprises, Inc., a wholly owned subsidiary of Enterprises
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 October 1, 2018the Utility Merger
UGI- UGI Corporation
UGI Central- The natural gas rate district of CPG subsequent to the Utility Merger
UGI France - UGI France SAS (a Société par actions simplifiée), aan indirect wholly owned subsidiary of UGI International, LLC
UGI Gas - UGI Utilities’ natural gas utility prior to the Utility Merger
UGI International- Reportable segment principally comprising UGI’s foreign operations
UGI International, LLC- UGI International, LLC, a wholly owned second-tier subsidiary of EnterprisesUGI

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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
2017 three-month period -Three-month period ended December 31, 2017
2018 Annual Report -UGI Annual Report on Form 10-K for the fiscal year ended September 30, 2018
2018 three-month period -Three-month period ended 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 Annual Report -UGI Annual Report on Form 10-K for the fiscal year ended September 30, 2019
2019 three-month period -Three-month period ended 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 740, “Income Taxes”840, “Leases”
ASC 842 - ASC 842, “Leases” (effective October 1, 2019)
ASU - Accounting Standards Update
Bcf - Billions of cubic feet
BIECMG - Pennsylvania Public Utility Commission Bureau Columbia Midstream Group, LLC
CMG Acquisition - Acquisition of InvestigationCMG and EnforcementColumbia Pennant, LLC on August 1, 2019 pursuant to the CMG Acquisition Agreements
BRP
CMG Acquisition Agreements - Balance Responsible Party providing electricity imbalance services inAgreements related to the European electricity marketsCMG Acquisition comprising (1) a purchase and sale agreement related to the CMG acquisition, dated July 2, 2019, by and among Columbia Midstream & Minerals Group, LLC, Energy Services, UGI and TransCanada PipeLine USA Ltd., and (2) a purchase and sale agreement related to the Columbia Pennant, LLC acquisition, dated July 2, 2019, by and among Columbia Midstream & Minerals Group, LLC, Energy Services, and TransCanada PipeLine USA Ltd.

COA - Consent 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 forto whom UGI Utilities has a statutory obligation to serveprovide service who purchase their natural gas or electricity from UGI Utilities; and (2) residential, commercial and industrial customers forto whom UGI Utilities has a statutory obligation to serveprovide 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
DS - Default service
Eighth Circuit - United States Court of Appeals for the Eighth Circuit

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Energy Services Term Loan - A seven-year $700 million senior secured term loan agreement entered into on August 13, 2019, with a group of lenders

EPS - Earnings Per Share

Exchange Act - Securities Exchange Act of 1934, as amended

FASB - Financial Accounting Standards Board

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FDIC - Federal Deposit Insurance Corporation
FERC - Federal Energy Regulatory Commission
FTRFiscal 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
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
Partnership Adjusted EBITDA - A non-GAAP financial measure used by UGI to evaluate the Partnership’s performance consisting
3
Table 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



PGC - Purchased gas costs
PJM - PJM Interconnection, LLC
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 forto whom UGI Utilities has a statutory obligation to serveprovide service that purchase their natural gas from Gas Utility
ROU - Right-of-use
ROD - RecordsRecord of Decision
SCAA - Storage contract administrative agreementsContract Administrative Agreements
SEC - U.S. Securities and Exchange Commission

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

UGI International 3.25% Senior Notes - An underwritten private placement of €350 million principal amount of senior unsecured notes due November 1, 2025, issued by UGI International, LLC
UGI 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)
 December 31,
2018		 September 30,
2018		 December 31,
2017		 December 31,
2019		 September 30,
2019		 December 31,
2018
ASSETS            
Current assets:            
Cash and cash equivalents $477.6
 $452.6
 $446.4
 $333.4
 $447.1
 $477.6
Restricted cash 17.4
 9.6
 19.8
 95.8
 63.7
 17.4
Accounts receivable (less allowances for doubtful accounts of $38.5, $35.1 and $35.1, respectively) 1,144.3
 751.9
 1,101.8
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 64.7
 14.0
 95.9
 80.2
 14.6
 64.7
Inventories 293.7
 318.2
 307.3
 247.5
 229.9
 293.7
Utility regulatory assets 3.3
 7.5
 0.6
 4.7
 9.1
 3.3
Derivative instruments 60.2
 142.5
 73.4
 28.4
 28.9
 60.2
Prepaid expenses and other current assets 181.0
 191.8
 135.4
 145.9
 132.2
 181.0
Total current assets 2,242.2
 1,888.1
 2,180.6
 1,947.0
 1,566.2
 2,242.2
Property, plant and equipment, at cost (less accumulated depreciation of $3,228.3, $3,153.9 and $3,393.1, respectively) 5,855.1
 5,808.2
 5,690.5
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 3,154.8
 3,160.4
 3,185.5
 3,482.9
 3,456.4
 3,154.8
Intangible assets, net 505.2
 513.6
 641.9
 703.4
 708.6
 505.2
Utility regulatory assets 295.5
 293.5
 362.2
 385.8
 386.5
 295.5
Derivative instruments 29.9
 43.5
 13.3
 32.0
 43.2
 29.9
Other assets 285.6
 273.6
 269.9
 951.0
 497.9
 285.6
Total assets $12,368.3
 $11,980.9
 $12,343.9
 $14,285.7
 $13,346.6
 $12,368.3
LIABILITIES AND EQUITY            
Current liabilities:            
Current maturities of long-term debt $19.5
 $18.8
 $224.1
 $27.8
 $24.1
 $19.5
Short-term borrowings 676.3
 424.9
 586.1
 869.7
 796.3
 676.3
Accounts payable 753.3
 561.8
 680.8
 598.3
 438.8
 753.3
Derivative instruments 56.8
 11.7
 32.7
 113.3
 84.9
 56.8
Other current liabilities 677.2
 714.9
 692.3
 782.4
 682.8
 677.2
Total current liabilities 2,183.1
 1,732.1
 2,216.0
 2,391.5
 2,026.9
 2,183.1
Long-term debt 4,150.7
 4,146.5
 4,056.4
 5,827.6
 5,779.9
 4,150.7
Deferred income taxes 973.4
 991.9
 890.7
 562.5
 541.4
 973.4
Derivative instruments 25.0
 12.8
 22.2
 46.6
 48.4
 25.0
Other noncurrent liabilities 989.5
 997.6
 1,076.5
 1,452.9
 1,122.8
 989.5
Total liabilities 8,321.7
 7,880.9
 8,261.8
 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 — 174,262,763, 174,142,997 and 173,997,441 shares, respectively) 1,206.5
 1,200.8
 1,189.3
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 2,620.8
 2,610.7
 2,429.3
 2,797.5
 2,653.1
 2,620.8
Accumulated other comprehensive loss (133.1) (110.4) (71.5) (163.1) (216.6) (133.1)
Treasury stock, at cost (24.8) (19.7) (45.4) (37.4) (15.9) (24.8)
Total UGI Corporation stockholders’ equity 3,669.4
 3,681.4
 3,501.7
 3,995.4
 3,817.5
 3,669.4
Noncontrolling interests, principally in AmeriGas Partners 377.2
 418.6
 580.4
Noncontrolling interests 9.2
 9.7
 377.2
Total equity 4,046.6
 4,100.0
 4,082.1
 4,004.6
 3,827.2
 4,046.6
Total liabilities and equity $12,368.3
 $11,980.9
 $12,343.9
 $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
December 31,		 Three Months Ended
December 31,
 2018 2017 2019 2018
Revenues $2,200.2
 $2,125.2
 $2,006.6
 $2,200.2
Costs and expenses:        
Cost of sales (excluding depreciation and amortization shown below) 1,425.0
 1,137.4
 1,008.0
 1,425.0
Operating and administrative expenses 503.2
 486.9
 511.2
 503.2
Depreciation and amortization 111.2
 110.3
 119.4
 111.2
Other operating income, net (6.9) (4.4) (9.2) (6.9)
 2,032.5
 1,730.2
 1,629.4
 2,032.5
Operating income 167.7
 395.0
 377.2
 167.7
Income from equity investees 1.5
 1.0
 6.5
 1.5
Loss on extinguishments of debt (6.1) —
 —
 (6.1)
Other non-operating income (expense), net 9.0
 (8.0)
Other non-operating (expense) income, net (11.5) 9.0
Interest expense (60.2) (58.2) (84.1) (60.2)
Income before income taxes 111.9
 329.8
 288.1
 111.9
Income tax (expense) benefit (23.4) 104.4
Income tax expense (76.1) (23.4)
Net income including noncontrolling interests 88.5
 434.2
 212.0
 88.5
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners (24.3) (68.3) —
 (24.3)
Net income attributable to UGI Corporation $64.2
 $365.9
 $212.0
 $64.2
Earnings per common share attributable to UGI Corporation stockholders:        
Basic $0.37
 $2.11
 $1.01
 $0.37
Diluted $0.36
 $2.07
 $1.00
 $0.36
Weighted-average common shares outstanding (thousands):        
Basic 174,413
 173,670
 209,439
 174,413
Diluted 177,566
 176,948
 211,258
 177,566
Dividends declared per common share $0.26
 $0.25
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,		Three Months Ended
December 31,
 2018 20172019 2018
Net income including noncontrolling interests $88.5
 $434.2
$212.0
 $88.5
Other comprehensive income (loss):       
Net losses on derivative instruments (net of tax of $0.4 and $0.2, respectively) (1.5) (0.4)
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.3) and $0.1, respectively) 0.7
 (0.4)
Foreign currency adjustments (net of tax of $2.8 and $0.0, respectively) (15.6) 22.3
Benefit plans (net of tax of $(0.1), and $(0.2), respectively) 0.3
 0.4
Other comprehensive (loss) income (16.1) 21.9
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 interests 72.4
 456.1
265.5
 72.4
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners (24.3) (68.3)—
 (24.3)
Comprehensive income attributable to UGI Corporation $48.1
 $387.8
$265.5
 $48.1
See accompanying notes to condensed consolidated financial statements.




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UGI CORPORATION AND SUBSIDIARIES


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
 Three Months Ended
December 31,		 Three Months Ended
December 31,
 2018 2017 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES        
Net income including noncontrolling interests $88.5
 $434.2
 $212.0
 $88.5
Adjustments to reconcile net income including noncontrolling interest to net cash provided by operating activities:    
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:    
Depreciation and amortization 111.2
 110.3
 119.4
 111.2
Deferred income tax benefit, net (20.7) (173.9)
Deferred income tax expense (benefit), net 5.0
 (20.7)
Provision for uncollectible accounts 10.3
 9.3
 7.8
 10.3
Changes in unrealized gains and losses on derivative instruments 165.9
 (6.6) 27.3
 165.9
Loss on extinguishments of debt 6.1
 —
 —
 6.1
Income from equity investees (6.5) (1.5)
Other, net 10.9
 7.6
 (9.4) 12.4
Net change in:        
Accounts receivable and accrued utility revenues (457.6) (530.5) (431.6) (457.6)
Inventories 23.0
 (23.5) (15.6) 23.0
Utility deferred fuel and power costs, net of changes in unsettled derivatives (12.5) 11.6
 4.8
 (12.5)
Accounts payable 217.4
 235.0
 182.6
 217.4
Derivative instruments collateral deposits (paid) received (22.2) 3.7
Derivative instruments collateral deposits received (paid) 20.4
 (22.2)
Other current assets (11.4) (34.0) (8.0) (11.4)
Other current liabilities (12.3) (11.8) 10.2
 (12.3)
Net cash provided by operating activities 96.6
 31.4
 118.4
 96.6
CASH FLOWS FROM INVESTING ACTIVITIES        
Expenditures for property, plant and equipment (183.3) (147.5) (182.0) (183.3)
Acquisitions of businesses and assets, net of cash acquired (15.0) (175.8)
Other 4.3
 5.3
Acquisitions of businesses and assets, net of cash and restricted cash acquired —
 (15.0)
Other, net 6.1
 4.3
Net cash used by investing activities (194.0) (318.0) (175.9) (194.0)
CASH FLOWS FROM FINANCING ACTIVITIES        
Dividends on UGI Common Stock (45.3) (43.3) (67.9) (45.3)
Distributions on AmeriGas Partners publicly held Common Units (65.7) (65.7) —
 (65.7)
Issuances of long-term debt, net of issuance costs 728.9
 124.3
 15.0
 728.9
Repayments of long-term debt (721.1) (41.9) (31.1) (721.1)
Increase in short-term borrowings 243.4
 212.5
 51.4
 243.4
Receivables Facility net borrowings 8.0
 6.0
 22.0
 8.0
Issuances of UGI Common Stock 6.9
 1.4
 0.6
 6.9
Repurchases of UGI Common Stock (16.9) (9.5) (22.6) (16.9)
Other (4.2) (2.7)
Net cash provided by financing activities 134.0
 181.1
EFFECT OF EXCHANGE RATE CHANGES ON CASH (3.8) 3.0
Cash, cash equivalents and restricted cash increase (decrease) $32.8
 $(102.5)
Other, net —
 (4.2)
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 $495.0
 $466.2
 $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) $32.8
 $(102.5)
Cash, cash equivalents and restricted cash (decrease) increase $(81.6) $32.8
See accompanying notes to condensed consolidated financial statements.


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UGI CORPORATION AND SUBSIDIARIES


CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(Millions of dollars, except per share amounts)
Three Months Ended
December 31,		 Three Months Ended
December 31,
2018 2017 2019 2018
Common stock, without par value       
Balance, beginning of period$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 withheld3.7
 (1.3)
Common Stock issued in connection with employee and director plans, net of tax withheld 0.3
 3.7
Equity-based compensation expense2.0
 2.0
 1.9
 2.0
Other (0.7) —
Balance, end of period$1,206.5
 $1,189.3
 $1,398.4
 $1,206.5
Retained earnings       
Balance, beginning of period$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 TCJA6.6
 —
 —
 6.6
Losses on treasury stock transactions in connection with employee and director plans(8.3) —
Losses on common stock transactions in connection with employee and director plans (0.7) (8.3)
Net income attributable to UGI64.2
 365.9
 212.0
 64.2
Cash dividends on Common Stock ($0.26 and $0.25 per share, respectively)(45.3) (43.3)
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$2,620.8
 $2,429.3
 $2,797.5
 $2,620.8
Accumulated other comprehensive income (loss)       
Balance, beginning of period$(110.4) $(93.4) $(216.6) $(110.4)
Reclassification of stranded income tax effects related to TCJA(6.6) —
 —
 (6.6)
Net losses on derivative instruments(1.5) (0.4)
Reclassification of net losses (gains) on derivative instruments0.7
 (0.4)
Net gains (losses) on derivative instruments 5.6
 (1.5)
Reclassification of net losses on derivative instruments 0.7
 0.7
Benefit plans0.3
 0.4
 0.2
 0.3
Foreign currency adjustments(15.6) 22.3
 47.0
 (15.6)
Balance, end of period$(133.1) $(71.5) $(163.1) $(133.1)
Treasury stock       
Balance, beginning of period$(19.7) $(38.6) $(15.9) $(19.7)
Common Stock issued in connection with employee and director plans, net of tax withheld12.2
 2.7
 1.1
 12.2
Repurchases of Common Stock(16.9) (9.5)
Reacquired Common Stock — employee and director plans(0.4) —
Repurchases of UGI Common Stock (22.6) (16.9)
Reacquired UGI Common Stock - employee and director plans —
 (0.4)
Balance, end of period$(24.8) $(45.4) $(37.4) $(24.8)
Total UGI stockholders’ equity$3,669.4
 $3,501.7
 $3,995.4
 $3,669.4
Noncontrolling interests       
Balance, beginning of period$418.6
 $577.6
 $9.7
 $418.6
Net income attributable to noncontrolling interests, principally in AmeriGas Partners24.3
 68.3
 —
 24.3
Dividends and distributions(65.7) (65.7) —
 (65.7)
Other—
 0.2
 (0.5) —
Balance, end of period$377.2
 $580.4
 $9.2
 $377.2
Total equity$4,046.6
 $4,082.1
 $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 December 31, 2018,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 three months ended December 31, 2018 and 2017 were $11.3 each.$11.3.


Our wholly owned subsidiary, Enterprises,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, a first-tier subsidiary of Enterprises, 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.


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.


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 required by GAAP.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 or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reportedcash 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)


We adopted this new guidance using the modified retrospective transition method. Amounts and disclosures related to periods prior to October 1, 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 duration of longer than one year are not material.
flows. See Note 49 for the 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), restricted cash is included within the Company’s Condensed Consolidated Statements of Cash Flows, with changes in the balance no longer reflected as a separate investing activity. The retrospective application of the new guidance on the previously reported cash flows from investing activities for the three months ended December 31, 2017, resulted in the elimination of the item “Decrease in restricted cash,” which had previously been reported as a use of cash of $9.5.

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:

Flows.
  Cash, Cash Equivalents and Restricted Cash
  December 31, 2019 December 31, 2018 September 30, 2019 September 30, 2018
Cash and cash equivalents $333.4
 $477.6
 $447.1
 $452.6
Restricted cash 95.8
 17.4
 63.7
 9.6
Cash, cash equivalents and restricted cash $429.2
 $495.0
 $510.8
 $462.2

  Cash, Cash Equivalents and Restricted Cash
  December 31, 2018 December 31, 2017 September 30, 2018 September 30, 2017
Cash and cash equivalents $477.6
 $446.4
 $452.6
 $558.4
Restricted cash 17.4
 19.8
 9.6
 10.3
Cash, cash equivalents and restricted cash $495.0
 $466.2
 $462.2
 $568.7


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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UGI CORPORATION AND SUBSIDIARIES
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
December 31,
  2019 2018
Denominator (thousands of shares):    
Weighted-average common shares outstanding — basic (a) 209,439
 174,413
Incremental shares issuable for stock options and awards (b) 1,819
 3,153
Weighted-average common shares outstanding — diluted 211,258
 177,566
  Three Months Ended
December 31,
  2018 2017
Denominator (thousands of shares):    
Weighted-average common shares outstanding — basic 174,413
 173,670
Incremental shares issuable for stock options and awards (a) 3,153
 3,278
Weighted-average common shares outstanding — diluted 177,566
 176,948

(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 December 31, 20182019 and 2017,2018, there were 303,499 and 14630 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.


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 instrument, and whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.

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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)



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 sectioncomponent 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 (expense), 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.


Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amountsBusiness Combination Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with noncontrolling interests inbusiness combinations, the Partnership, which principally comprises AmeriGas Partnerspurchase price is allocated to the various assets acquired and AmeriGas OLP.  AmeriGas Partnersliabilities assumed at their estimated fair value as of the acquisition date. Fair values of assets acquired and AmeriGas OLPliabilities assumed are not directlybased upon available information. Estimating fair values is generally subject to federalsignificant judgment and assumptions and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation.

Other non-operating (expense) income, taxes. As a result, UGI’s consolidated effectivenet. Included in “Other non-operating (expense) income, tax rate is affected bynet,” on the amountCondensed Consolidated Statements of Income are net gains and losses on forward foreign currency contracts used to reduce volatility in net income (loss) beforeassociated with our foreign operations, and non-service income taxes attributable(expense) associated with our pension and other postretirement plans.


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Notes to noncontrolling interestsCondensed Consolidated Financial Statements
(unaudited)
(Currency in the Partnership not subject to income taxes.millions, except per share amounts and where indicated otherwise)


See Note 6 for discussions regarding the December 22, 2017, enactment of the TCJA in the U.S. and the December 2017 French Finance Bills.

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.


Reclassifications.Certain amounts for the three months ended December 31, 2017, 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.


Other non-operating income (expense), net. Included in “Other non-operating income (expense), 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)

Note 3 — Accounting Changes

New Accounting Standards Adopted Effective October 1, 2018in Fiscal 2020


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 months ended December 31, 2018.

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 months ended December 31, 2017, 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 (expense), net,” on the Condensed Consolidated Statement of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.”

For the three months ended December 31, 2018, the amount of income comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Other non-operating income (expense), net,” totaled $0.1. For the three months ended December 31, 2017, the amount of expense comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, which has been reclassified from "Operating and administrative expenses" to "Other non-operating income (expense), net,” totaled $3.2.

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

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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)

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 Statement of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statement 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, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

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 is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for 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 adopted the new guidance effective October 1, 2019. The adoption did not have a material impact on our 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 losses 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 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 of 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 UGI Utilities’ large delivery service customers and Midstream & Marketing’s peakingCompany’s 2019 Annual Report for information on our revenues from contracts for which wewith customers.




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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)


recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company.

We do not have a significant financing component in our contracts because we receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is 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.Revenue Disaggregation
The Company’sfollowing tables present our disaggregated 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 providesreportable segment for the recovery, subject to reasonableness reviews, of PGCthree months ended December 31, 2019 and DS costs.

Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service.

The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather.

UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis.

UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms.
Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. 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.

2018:
15
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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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)

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 right to invoice, and generally invoice monthly based on consumption.
Contracts with customers comprise different types of contracts with varying length terms, fixed or variable prices, and fixed or variable quantities. Contracts with our residential customers, which comprise a substantial number of our customer contracts, are generally one year or less. Customer contracts for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to a customer at a fixed price and a fixed volume, and contracts that provide for the sale of propane at market prices at date of delivery with no fixed volumes. AmeriGas Propane offers contracts that permit the customer to lock in a fixed price for their volumes for a fee and also provide the customer with the option to pre-buy a fixed amount of propane at a fixed price. Amounts received under pre-buy arrangements are recorded as a contract liability when received and recorded as revenue when LPG is delivered and control is transferred to the customer. Fees associated with fixed-price contracts are recorded as contract liabilities and recorded ratably over the contract period.
AmeriGas Propane and UGI International also distribute LPG to customers in portable cylinders. Under certain contracts, filled cylinders are delivered, and control is transferred, to a reseller. In such instances, the reseller is our customer and we record revenue upon delivery to the reseller. Under other contracts, filled cylinders are delivered to a reseller, but the Company retains control of the cylinders. In such instances, we record revenue at the time the reseller transfers control of the cylinder to the end user.
Certain retail LPG customers 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.
In addition to providing natural gas and electricity to end use 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


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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)

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)
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 results 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.
(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.
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 a 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.
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 December 31, 2018.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 balancebalances of contract liabilities waswere $93.1, $114.1 and $94.0 and $115.6 at December 31, 20182019, 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 three months ended December 31, 2019 and 2018, from the amount included in contract liabilities at October 1,September 30, 2019 and 2018, was $58.1.$61.0 and $58.1, respectively.





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


Revenue Disaggregation
The following table presents our disaggregated revenues by reportable segment for the 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 (b) 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 (c) 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)

(a)Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(b)UGI Utilities includes unallocated negative surcharge revenue of $(4.1) as a result of a PAPUC Order issued May 17, 2018, related to 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, all of which are not within the scope of ASC 606 and 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 December 31, 2018,2019, 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:
18
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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UGI CORPORATION AND SUBSIDIARIES
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:
  December 31,
2019		 September 30,
2019		 December 31,
2018
Non-utility LPG and natural gas $163.7
 $150.2
 $206.7
Gas Utility natural gas 24.3
 26.6
 34.9
Materials, supplies and other 59.5
 53.1
 52.1
Total inventories $247.5
 $229.9
 $293.7

  December 31,
2018		 September 30,
2018		 December 31,
2017
Non-utility LPG and natural gas $206.7
 $231.7
 $216.4
Gas Utility natural gas 34.9
 37.3
 34.6
Materials, supplies and other 52.1
 49.2
 56.3
Total inventories $293.7
 $318.2
 $307.3


At December 31, 2018,2019, UGI Utilities was a party to five3 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 December 31, 2018,2019 and September 30, 2019, all of UGI Utilities hadUtilities’ SCAAs were with Energy Services, the effects of which are eliminated in consolidation, and with a non-affiliate.consolidation. The carrying value of gas storage inventories released under the SCAAs with the non-affiliatenon-affiliates at December 31, 2018 September 30, 2018 and December 31, 2017, comprising 1.9 bcf, 2.3 bcf and 1.8 bcf of natural gas was $4.6, $5.4, and $5.1, respectively.$4.6.



17
Note 6 — Income Taxes

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 months ended December 31, 2017, 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 months ended December 31, 2017, we reduced our net deferred income tax liabilities due to the remeasuring of our existing federal deferred income tax assets and liabilities. 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 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 three months ended December 31, 2017, discrete deferred income tax adjustments reduced income tax expense by $166.0 and consisted primarily of the following items:
(1)a $180.3 reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate;

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


(2)the establishment of $12.6 of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and
(3)a $1.7 “toll tax” on un-repatriated foreign earnings.
For the three months ended December 31, 2018 and 2017, 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, the U.S. federal income tax rates included in our estimated annual effective tax rates used for the three months ended December 31, 2018 and 2017 were based on rates of 21.0% and 24.5%, respectively. 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. The estimated annual effective income tax rate used in determining income taxes for the three months ended December 31, 2017, reflected the impact of the single year Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills. The impact of the single year rate change increased income tax expense for the three months ended December 31, 2017, by $3.9.
Note 7 — Goodwill and Intangible Assets


Goodwill and intangible assets comprise the following:
  December 31,
2019		 September 30,
2019		 December 31,
2018
Goodwill $3,482.9
 $3,456.4
 $3,154.8
Intangible assets:      
Customer relationships $1,054.9
 $1,038.4
 $795.4
Trademarks and tradenames 16.4
 16.2
 7.9
Noncompete agreements and other 54.8
 46.4
 57.6
Accumulated amortization (473.5) (441.8) (405.4)
Intangible assets, net (definite-lived) 652.6
 659.2
 455.5
Trademarks and tradenames (indefinite-lived) 50.8
 49.4
 49.7
Total intangible assets, net $703.4
 $708.6
 $505.2

  December 31,
2018		 September 30,
2018		 December 31,
2017
Goodwill (not subject to amortization) $3,154.8
 $3,160.4
 $3,185.5
Intangible assets:      
Customer relationships, noncompete agreements and other $853.0
 $848.6
 $862.0
Trademarks and tradenames 7.9
 7.9
 —
Accumulated amortization (405.4) (393.2) (355.0)
Intangible assets, net (definite-lived) 455.5
 463.3
 507.0
Trademarks and tradenames (indefinite-lived) 49.7
 50.3
 134.9
Total intangible assets, net $505.2
 $513.6
 $641.9

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 $14.8$14.6 for the three months ended December 31, 20182019 and 2017,2018, 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 — $43.4; Fiscal 2020 — $56.7;$48.7; Fiscal 2021 — $53.4;$61.8; Fiscal 2022 — $50.4;$58.8; Fiscal 2023 — $48.9.$57.3; Fiscal 2024 — $56.1.



20
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 9 in the Company’s 2019 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:
  December 31,
2019		 September 30,
2019		 December 31,
2018
Regulatory assets:      
Income taxes recoverable $121.2
 $115.2
 $115.2
Underfunded pension and postretirement plans 175.2
 178.6
 85.3
Environmental costs 57.5
 59.5
 58.5
Removal costs, net 26.7
 28.3
 31.3
Other 9.9
 14.0
 8.5
Total regulatory assets $390.5
 $395.6
 $298.8
Regulatory liabilities (a):      
Postretirement benefit overcollections $14.1
 $14.5
 $17.3
Deferred fuel and power refunds 6.3
 6.1
 22.2
State tax benefits — distribution system repairs 26.3
 25.0
 23.5
PAPUC Temporary Rates Order 25.0
 31.3
 24.8
Excess federal deferred income taxes 278.1
 279.5
 280.9
Other 1.4
 2.4
 4.8
Total regulatory liabilities $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.


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


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 8 in the Company’s 2018 Annual Report. Other than removal costs, UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
  December 31,
2018		 September 30,
2018		 December 31,
2017
Regulatory assets:      
Income taxes recoverable $115.2
 $110.1
 $126.5
Underfunded pension and postretirement plans 85.3
 87.1
 138.3
Environmental costs 58.5
 58.8
 60.8
Removal costs, net 31.3
 32.0
 31.4
Other 8.5
 13.0
 5.8
Total regulatory assets $298.8
 $301.0
 $362.8
Regulatory liabilities (a):      
Postretirement benefits $17.3
 $17.8
 $17.3
Deferred fuel and power refunds 22.2
 36.7
 12.7
State tax benefits — distribution system repairs 23.5
 22.6
 19.1
PAPUC temporary rates order 24.8
 24.4
 —
Excess federal deferred income taxes 280.9
 285.2
 303.9
Other 4.8
 3.5
 4.5
Total regulatory liabilities $373.5
 $390.2
 $357.5
(a)
Regulatory liabilities are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

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. TheThese 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 (losses) on such contracts at December 31, 2018,2019, September 30, 20182019 and December 31, 20172018 were $0.8, $2.9$(2.9), $(2.2) and $(1.7),$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 through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. The temporary negative surcharge will be reconciled at the end of each fiscal year to actual tax savings realized. Any difference in the amount of bill credit received by customers and the amount of benefits received by the Company during the period the negative surcharge is in effect is reconciled in the calculation of a new negative surcharge effective January 1 of the subsequent calendar year. The negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. For the merged Gas Utility, such negative surcharge reduced base rate revenues by 5.78%, 3.90% and 8.19%, respectively, for the UGI South, UGI North and UGI Central rate districts for the three months ended December 31, 2018 and is subject to reconciliation during the period the negative surcharges remain in effect.
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 beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability, plus accrued interest, for each Gas Utility rate district will be addressed in a future proceeding and the Company cannot predict the ultimate treatment of this liability. In UGI Gas’s base rate proceeding filed January 28, 2019 (see “Base Rate Filings” below), UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service

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

bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 Order. The negative surcharge will 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 applies. 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, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged 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, UGI2020, 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, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas is requestingUtility requested that the new gas rates become effective March 29, 2019.28, 2020. However, the PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for investigation and public hearings. UGI 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 revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Gas Utility’s new base rates.

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 the 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 baseseek an appeal of the Pennsylvania Commonwealth Court Order to the Pennsylvania Supreme Court.

Note 9 — Leases

Lessee

We lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the majority of which are operating revenuesleases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an asset, whether we have the right to obtain substantially all of the economic benefits of the identified leased asset and to direct its use.

ROU assets represent our right to use an underlying asset for residential, commercialthe lease term and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvementslease 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 operations necessaryinitial direct costs incurred. Lease liabilities are recognized at the lease commencement date based on the present 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 maintain safe and reliable natural gas service. On June 30, 2017,substantially all active parties supportedof our leases as the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11.3 PNG annual base distributionimplicit rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective October 20, 2017.is often not available.



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



Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection withLease expense is recognized on a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resultedstraight-line basis over the expected lease term. Renewal and termination options are not included in the deathlease term unless we are reasonably certain that such options will be exercised. Leases with an original lease term of one UGI Utilities employee and injuriesyear or less, including consideration of any renewal options assumed to two UGI Utilities employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUCbe exercised, are not included 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 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.

Note 9 — Energy Services Accounts Receivable Securitization Facility

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.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, ESFC, which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time, sell an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured

Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank.ten years, contain purchase options. The Company records interest expense on amounts owed togenerally 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 bank. Energy Services continues to service, administer and collect trade receivables on behalfend of the bank, as applicable. Losses on sales of receivables to the bank during the three months ended December 31, 2018 and 2017, whichlease. Such amounts are included in “Interest expense”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 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 StatementsBalance 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 Income, were not material.

Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the three months ended December 31, 2018 and 2017, as well as the balance of ESFC trade receivables at December 31, 2018, September 30, 2018 and December 31, 2017, islease cost are as follows:
  Three Months Ended December 31,
  2018 2017
Trade receivables transferred to ESFC during the period $392.6
 $270.6
ESFC trade receivables sold to the bank during the period $25.0
 $48.0
 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



  December 31, 2018 September 30, 2018 December 31, 2017
ESFC trade receivables — end of period (a) $135.4
 $65.0
 $101.0
(a)
At December 31, 2018, September 30, 2018, and December 31, 2017, the amounts of ESFC trade receivables sold to the bank were $10.0, $2.0 and $45.0, respectively. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets.

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

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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 underlying euriborcash 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 term loan borrowingsmaturities 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 0.34%. UnderSeptember 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 multicurrency revolving credit facility agreement,purposes of storing, gathering or distributing natural gas and propane. AmeriGas Propane and UGI International LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest athave lessor arrangements that grant customers the associated euribor rate plus a margin ranging from 1.20%right 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.use small, medium and large storage tanks, which

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 consolidated total net 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’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 Subsequent Event. 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.

Note 11 — 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, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019. UGI’s capital contributions may be made from time to time through July 1, 2019 upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the Standby Equity Commitment Agreement, AmeriGas Partners will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in AmeriGas Partners. The Class B Common Units will be issued at a price per unit equal to the 20-day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Common Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Common Units. While outstanding, the Class B Common Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Common Units, holders may elect to convert all or any portion of the Class B Common Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial


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issuance of the Class B Common Units, the Partnership may electwe classify as operating leases. These agreements contain renewal options for periods up to convert all or any portion of the Class B Common Units into Common Units if (i) the closing trading price of the Common Unitsnine years and certain agreements at UGI International contain a purchase option. Energy Services leases certain natural gas gathering assets to customers, which we classify as operating leases. Lease income is greater than 110% of the applicable purchase price for the Class B Common Units and (ii) the Common Units are listed or admitted for tradinggenerally recognized on a National Securities Exchange. Upon certain events involving a changestraight-line basis over the lease term and included in “Revenues” on the Condensed Consolidated Statement of controlIncome (see Note 4).

Note 10 — Commitments and immediately prior to a liquidation or winding up of the Partnership, the Class B Common Units will automatically convert into Common Units on a one-for-one basis.Contingencies


Environmental Matters


UGI Utilities


From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI 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.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 December 31, 2018,2019, September 30, 20182019 and December 31, 2017,2018, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $49.5, $50.4 and $50.5, $51.0 and $53.4, 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 December 31, 2018, September 30, 2018 and December 31, 2017, neitherNeither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.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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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. Motions are pending beforeOn April 15, 2019, the Western Missouri District Court regardingruled that it has jurisdiction over the indirect purchasers’ state law claims.

We are unableclaims and that the indirect customer plaintiffs have standing to reasonably estimatepursue those claims. On August 21, 2019, the impact, if any, arising from such litigation. We believe we have strong defenses toDistrict Court partially granted the Company’s motion for judgment on the pleadings and dismissed the claims of indirect customer plaintiffs from ten states and intendthe District of Columbia.

On October 2, 2019, the Company reached an agreement to vigorously defend against them.resolve the claims of the direct purchaser class of plaintiffs, subject to court approval.


Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.


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.

Net periodic pension expense and other postretirement benefit costs include the following components:
  Pension Benefits Other Postretirement Benefits
Three Months Ended December 31, 2018 2017 2018 2017
Service cost $2.5
 $2.8
 $—
 $0.2
Interest cost 6.8
 6.5
 0.2
 0.2
Expected return on assets (9.0) (8.6) (0.2) (0.2)
Amortization of:        
Prior service cost (benefit) 0.1
 0.1
 (0.1) (0.1)
Actuarial loss 1.9
 3.3
 —
 0.1
Net benefit cost (benefit) 2.3
 4.1
 (0.1) 0.2
Change in associated regulatory liabilities —
 —
 (0.3) (0.1)
Net benefit cost (benefit) after change in regulatory liabilities $2.3
 $4.1
 $(0.4) $0.1


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The service cost component of our pension and other postretirement plans, net of amounts capitalized, is 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
Three Months Ended December 31, 2019 2018 2019 2018
Service cost $2.8
 $2.5
 $0.1
 $—
Interest cost 5.8
 6.8
 0.2
 0.2
Expected return on assets (9.4) (9.0) (0.2) (0.2)
Amortization of:        
Prior service cost (benefit) 0.1
 0.1
 (0.1) (0.1)
Actuarial loss 3.7
 1.9
 —
 —
Net benefit cost (benefit) 3.0
 2.3
 —
 (0.1)
Change in associated regulatory liabilities —
 —
 (0.3) (0.3)
Net benefit cost (benefit) after change in regulatory liabilities $3.0
 $2.3
 $(0.3) $(0.4)


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 three months ended December 31, 2018, the Company made no cash contributions to the U.S. Pension Plan. During the three months ended December 31, 2017,2019, the Company made cash contributions to the U.S. Pension Plan of $3.4.$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 $11.5$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 three months ended December 31, 20182019 and 2017.2018.


We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net costs associated with these plans for the three months ended December 31, 20182019 and 2017,2018, were not material.



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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, as of December 31, 2018, September 30, 2018 and December 31, 2017:hierarchy:
  Asset (Liability)
  Level 1 Level 2 Level 3 Total
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 $32.0
 $10.1
 $—
 $42.1
Foreign currency contracts $—
 $59.0
 $—
 $59.0
Liabilities:        
Commodity contracts $(62.3) $(112.7) $—
 $(175.0)
Foreign currency contracts $—
 $(4.3) $—
 $(4.3)
Interest rate contracts $—
 $(12.3) $—
 $(12.3)
Non-qualified supplemental postretirement grantor trust investments (a) $39.7
 $—
 $—
 $39.7
December 31, 2018:        
Derivative instruments:        
Assets:        
Commodity contracts $72.1
 $27.9
 $—
 $100.0
Foreign currency contracts $—
 $24.4
 $—
 $24.4
Liabilities:        
Commodity contracts $(35.6) $(78.0) $—
 $(113.6)
Foreign currency contracts $—
 $(8.8) $—
 $(8.8)
Interest rate contracts $—
 $(3.7) $—
 $(3.7)
Non-qualified supplemental postretirement grantor trust investments (a) $38.0
 $—
 $—
 $38.0
  Asset (Liability)
  Level 1 Level 2 Level 3 Total
December 31, 2018:        
Derivative instruments:        
Assets:        
Commodity contracts $72.1
 $27.9
 $—
 $100.0
Foreign currency contracts $—
 $24.4
 $—
 $24.4
Liabilities:        
Commodity contracts $(35.6) $(78.0) $—
 $(113.6)
Foreign currency contracts $—
 $(8.8) $—
 $(8.8)
Interest rate contracts $—
 $(3.7) $—
 $(3.7)
Non-qualified supplemental postretirement grantor trust investments (a) $38.0
 $—
 $—
 $38.0
September 30, 2018:        
Derivative instruments:        
Assets:        
Commodity contracts $93.5
 $117.5
 $—
 $211.0
Foreign currency contracts $—
 $20.6
 $—
 $20.6
Cross-currency contracts $—
 $0.9
 $—
 $0.9
Liabilities:        
Commodity contracts $(33.6) $(9.8) $—
 $(43.4)
Foreign currency contracts $—
 $(14.4) $—
 $(14.4)
Interest rate contracts $—
 $(1.0) $—
 $(1.0)
Non-qualified supplemental postretirement grantor trust investments (a) $40.8
 $—
 $—
 $40.8
December 31, 2017:        
Derivative instruments:        
Assets:        
Commodity contracts $47.9
 $71.7
 $—
 $119.6
Foreign currency contracts $—
 $11.6
 $—
 $11.6
Liabilities:        
Commodity contracts $(31.0) $(13.5) $—
 $(44.5)
Foreign currency contracts $—
 $(39.9) $—
 $(39.9)
Interest rate contracts $—
 $(2.1) $—
 $(2.1)
Cross-currency contracts $—
 $(0.9) $—
 $(0.9)
Non-qualified supplemental postretirement grantor trust investments (a) $37.7
 $—
 $—
 $37.7

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


Other Financial Instruments


The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2018, September 30, 2018 and December 31, 2017 were as follows:
 December 31, 2019 September 30, 2019 December 31, 2018
Carrying amount$5,905.8
 $5,856.6
 $4,211.0
Estimated fair value$6,248.9
 $6,189.3
 $3,970.8

 December 31, 2018 September 30, 2018 December 31, 2017
Carrying amount$4,211.0
 $4,199.4
 $4,319.5
Estimated fair value$3,970.8
 $4,150.3
 $4,430.0


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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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 December 31, 2018, September 30, 2018 and December 31, 2017, allAll Electric Utility forward electricity purchase contracts were subject to the NPNS exception.exception for all periods presented.


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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, AmeriGas Partners,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 rates and LIBOR rates of interest on this variable-rate debt. 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 have 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 December 31, 2018, September 30, 2018 and December 31, 2017, we had no unsettled IRPAs. At December 31, 2018,2019, 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 December 31, 2018, 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 $1.4.


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, (expense), 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 sectioncomponent 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).hedges of $20.4 and $6.1, respectively, in the cumulative translation adjustment component of AOCI.

Cross-currency Contracts
Prior to its repayment on October 25, 2018 (see Note 10), Flaga entered into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges. These cross-currency swaps were settled concurrent with the repayment of Flaga’s U.S. dollar variable rate term loan in October 2018.


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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 December 31, 2018,2019, September 30, 20182019 and December 31, 2017,2018, and the final settlement date of the Company's open derivative transactions as of December 31, 2018,2019, excluding those derivatives that qualified for the NPNS exception:
      
Notional Amounts
(in millions)
Type 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 October 2020 14.5
 23.3
 14.7
Non-utility Operations          
LPG swaps Gallons December 2021 772.0
 800.4
 450.4
Natural gas futures, forward and pipeline contracts Dekatherms December 2024 201.4
 196.1
 188.0
Natural gas basis swap contracts Dekatherms December 2024 154.7
 131.1
 81.2
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 April 2024 4,145.1
 3,098.1
 3,974.7
Electricity short forward and futures contracts Kilowatt hours April 2024 555.8
 366.7
 366.7
Interest Rate Risk:          
Interest rate swaps Euro October 2022 €300.0
 €300.0
 €300.0
Interest rate swaps USD July 2024 $1,354.0
 $1,357.3
 $114.1
Foreign Currency Exchange Rate Risk:          
Forward foreign currency exchange contracts USD September 2022 $431.2
 $516.0
 $408.6
Net investment hedge forward foreign exchange contracts Euro October 2024 €172.8
 €172.8
 €172.8

      
Notional Amounts
(in millions)
Type Units Settlements Extending Through December 31, 2018 September 30, 2018 December 31, 2017
Commodity Price Risk:          
Regulated Utility Operations          
Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2019 14.7
 23.2
 13.4
FTRs contracts Kilowatt hours N/A —
 —
 63.1
Non-utility Operations          
LPG swaps Gallons January 2021 450.4
 394.3
 275.4
Natural gas futures, forward and pipeline contracts Dekatherms October 2023 188.0
 159.7
 128.3
Natural gas basis swap contracts Dekatherms March 2023 81.2
 54.4
 90.2
NYMEX natural gas storage Dekatherms June 2019 0.7
 1.8
 1.3
NYMEX propane storage Gallons April 2019 0.3
 0.6
 0.1
Electricity long forward and futures contracts Kilowatt hours May 2022 3,974.7
 4,307.6
 4,733.9
Electricity short forward and futures contracts Kilowatt hours May 2022 366.7
 359.3
 325.2
Interest Rate Risk:          
Interest rate swaps Euro October 2022 €300.0
 €585.8
 €645.8
Interest rate swaps USD July 2022 $114.1
 $114.1
 $—
Foreign Currency Exchange Rate Risk:          
Forward foreign currency exchange contracts USD September 2021 $408.6
 $512.2
 $485.7
Forward foreign currency exchange contracts Euro October 2024 €172.8
 €—
 €—
Cross-currency contracts USD N/A $—
 $49.9
 $49.9


Derivative Instrument Credit Risk


We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. At 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 December 31, 2018,2019, September 30, 20182019 and December 31, 2017,2018, restricted cash in brokerage accounts totaled $95.8, $63.7 and $17.4, $9.6respectively.

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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and $19.8, respectively. 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

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

instruments, was not material at December 31, 2018.2019. 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 December 31, 2018,2019, 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, as of December 31, 2018, September 30, 2018 and December 31, 2017:offsetting:
  December 31,
2019		 September 30,
2019		 December 31,
2018
Derivative assets:      
Derivatives designated as hedging instruments:      
Foreign currency contracts $13.9
 $17.4
 $2.3
Interest rate contracts 2.7
 —
 —
  16.6
 17.4
 2.3
Derivatives subject to PGC and DS mechanisms:      
Commodity contracts 0.2
 1.4
 1.3
Derivatives not designated as hedging instruments:      
Commodity contracts 46.9
 40.7
 98.7
Foreign currency contracts 26.0
 41.6
 22.1
  72.9
 82.3
 120.8
Total derivative assets — gross 89.7
 101.1
 124.4
Gross amounts offset in the balance sheet (27.2) (29.0) (34.3)
Cash collateral received (2.1) —
 —
Total derivative assets — net $60.4
 $72.1
 $90.1
Derivative liabilities:      
Derivatives designated as hedging instruments:      
Interest rate contracts $(6.9) $(12.3) $(3.7)
Derivatives subject to PGC and DS mechanisms:      
Commodity contracts (3.2) (3.7) (0.5)
Derivatives not designated as hedging instruments:      
Commodity contracts (183.6) (171.3) (113.1)
Foreign currency contracts (4.4) (4.3) (8.8)
  (188.0) (175.6) (121.9)
Total derivative liabilities — gross (198.1) (191.6) (126.1)
Gross amounts offset in the balance sheet 27.2
 29.0
 34.3
Cash collateral pledged 11.0
 29.3
 10.0
Total derivative liabilities — net $(159.9) $(133.3) $(81.8)

  December 31,
2018		 September 30,
2018		 December 31,
2017
Derivative assets:      
Derivatives designated as hedging instruments:      
Foreign currency contracts $2.3
 $1.5
 $1.2
Cross-currency contracts —
 0.9
 —
  2.3
 2.4
 1.2
Derivatives subject to PGC and DS mechanisms:      
Commodity contracts 1.3
 3.0
 0.4
Derivatives not designated as hedging instruments:      
Commodity contracts 98.7
 208.0
 119.2
Foreign currency contracts 22.1
 19.1
 10.4
  120.8
 227.1
 129.6
Total derivative assets — gross 124.4
 232.5
 131.2
Gross amounts offset in the balance sheet (34.3) (34.3) (32.5)
Cash collateral received —
 (12.2) (12.0)
Total derivative assets — net $90.1
 $186.0
 $86.7
Derivative liabilities:      
Derivatives designated as hedging instruments:      
Foreign currency contracts $—
 $(0.4) $(5.6)
Cross-currency contracts —
 —
 (0.9)
Interest rate contracts (3.7) (1.0) (2.1)
  (3.7) (1.4) (8.6)
Derivatives subject to PGC and DS mechanisms:      
Commodity contracts (0.5) (0.1) (2.3)
Derivatives not designated as hedging instruments:      
Commodity contracts (113.1) (43.3) (42.2)
Foreign currency contracts (8.8) (14.0) (34.3)
  (121.9) (57.3) (76.5)
Total derivative liabilities — gross (126.1) (58.8) (87.4)
Gross amounts offset in the balance sheet 34.3
 34.3
 32.5
Cash collateral pledged 10.0
 —
 —
Total derivative liabilities — net $(81.8) $(24.5) $(54.9)




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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 months ended December 31, 20182019 and 20172018:
           
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
Cash Flow Hedges: 2019 2018 2019 2018 
Foreign currency contracts $—
 $1.0
 $—
 $0.8
 Cost of sales
Cross-currency contracts —
 (0.1) —
 (0.3) Interest expense/other operating income, net
Interest rate contracts 7.8
 (2.8) (1.0) (1.5) Interest expense
Total $7.8
 $(1.9) $(1.0) $(1.0)  
           
Net Investment Hedges:          
Foreign currency contracts $(3.5) $0.9
      
           
  Gain (Loss)
Recognized in Income		 Location of Gain (Loss)
Recognized in Income		  
Derivatives Not Designated as Hedging Instruments: 2019 2018   
Commodity contracts $(33.1) $(159.7) Cost of sales  
Commodity contracts 2.5
 (2.8) Revenues  
Commodity contracts 0.1
 (0.4) Operating and administrative expenses  
Foreign currency contracts (11.3) 8.9
 Other non-operating (expense) income, net  
Total $(41.8) $(154.0)      

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
Cash Flow Hedges: 2018 2017 2018 2017 
Foreign currency contracts $1.0
 $(1.4) $0.8
 $0.8
 Cost of sales
Cross-currency contracts (0.1) 0.1
 (0.3) 0.2
 Interest expense/other operating income, net
Interest rate contracts (2.8) 0.7
 (1.5) (0.5) Interest expense
Total $(1.9) $(0.6) $(1.0) $0.5
  
           
Net Investment Hedges:          
Foreign currency contracts $0.9
 $—
      
           
  Gain (Loss)
Recognized in Income		 Location of Gain (Loss)
Recognized in Income		  
Derivatives Not Designated as Hedging Instruments: 2018 2017   
Commodity contracts $(159.7) $24.4
 Cost of sales  
Commodity contracts (2.8) (1.3) Revenues  
Commodity contracts (0.4) 0.1
 Operating and administrative expenses  
Foreign currency contracts 8.9
 (4.8) Other non-operating income (expense), net  
Total $(154.0) $18.4
      

For the three months ended December 31, 2018 and 2017, the amounts of derivative gains or losses representing ineffectiveness and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material.


We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument,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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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 months ended December 31, 20182019 and 2017:2018:
         

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)
Other comprehensive loss before reclassification adjustments (after-tax) —
 (1.5) (15.6) (17.1)
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.4
 1.0
 —
 1.4
Reclassification adjustments tax benefit (0.1) (0.3) —
 (0.4)
Reclassification adjustments (after-tax) 0.3
 0.7
 —
 1.0
Other comprehensive income (loss) attributable to UGI 0.3
 (0.8) (15.6) (16.1)
Reclassification of stranded income tax effects related to TCJA (2.9) (3.7) —
 (6.6)
AOCI — December 31, 2018 $(13.6) $(20.6) $(98.9) $(133.1)
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)
Other comprehensive loss before reclassification adjustments (after-tax) —
 (1.5) (15.6) (17.1)
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.4
 1.0
 —
 1.4
Reclassification adjustments tax expense (0.1) (0.3) —
 (0.4)
Reclassification adjustments (after-tax) 0.3
 0.7
 —
 1.0
Other comprehensive income (loss) attributable to UGI 0.3
 (0.8) (15.6) (16.1)
Reclassification of stranded income tax effects related to TCJA (2.9) (3.7) —
 (6.6)
AOCI — December 31, 2018 $(13.6) $(20.6) $(98.9) $(133.1)
         
Three Months Ended December 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2017 $(19.2) $(21.4) $(52.8) $(93.4)
Other comprehensive (loss) income before reclassification adjustments (after-tax) —
 (0.4) 22.3
 21.9
Amounts reclassified from AOCI:        
Reclassification adjustments (pre-tax) 0.6
 (0.5) —
 0.1
Reclassification adjustments tax (benefit) expense (0.2) 0.1
 —
 (0.1)
Reclassification adjustments (after-tax) 0.4
 (0.4) —
 —
Other comprehensive income (loss) attributable to UGI 0.4
 (0.8) 22.3
 21.9
AOCI — December 31, 2017 $(18.8) $(22.2) $(30.5) $(71.5)

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


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

on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned.
               
               
Three Months Ended December 31, 2018 Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (b)
Revenues $2,200.2
 $—
 $820.2
 $710.7
 $372.5
 $299.1
 $(2.3)
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 $—
 $(111.6)(c)$—
 $—
 $86.9
 $23.6
 $1.1
 $—
 $(79.7)(b)$—
 $—
 $64.2
 $14.7
 $0.8
Cost of sales $1,425.0
 $(110.8)(c)$378.5
 $448.6
 $377.5
 $159.5
 $171.7
 $1,008.0
 $(79.1)(b)$289.2
 $368.4
 $264.2
 $151.6
 $13.7
Segment profit:              
Operating income (loss) $167.7
 $0.4
 $166.6
 $58.3
 $41.1
 $77.0
 $(175.7) $377.2
 $0.3
 $165.3
 $95.8
(c)$55.1
 $91.8
 $(31.1)
Income from equity investees 1.5
 —
 —
 —
 1.5
(d)—
 —
 6.5
 —
 —
 —
 6.5
(d)—
 —
Loss on extinguishments of debt (6.1) —
 —
 (6.1) —
 —
 —
Other non-operating income (expense), net 9.0
 —
 —
 0.7
 —
 0.4
 7.9
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 (60.2) —
 (42.4) (5.4) (0.5) (11.7) (0.2) (84.1) —
 (42.5) (7.6) (11.5) (13.6) (8.9)
Income (loss) before income taxes $111.9
 $0.4
 $124.2
 $47.5
 $42.1
 $65.7
 $(168.0) $288.1
 $0.3
 $122.8
 $92.6
 $50.1
 $78.0
 $(55.7)
Partnership Adjusted EBITDA (a) 
   $210.7
        
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
 $119.4
 $—
 $43.9
 $31.2
 $18.4
 $25.7
 $0.2
Capital expenditures (including the effects of accruals) $161.8
 $—
 $31.0
 $27.8
 $25.1
 $77.3
 $0.6
 $151.8
 $—
 $38.5
 $20.3
 $22.5
 $70.5
 $—
As of December 31, 2018              
As of December 31, 2019              
Total assets $12,368.3
 $(144.3) $4,020.6
 $3,287.5
 $1,504.9
 $3,424.8
 $274.8
 $14,285.7
 $(365.5) $4,609.4
 $3,243.3
 $2,859.6
 $3,710.9
 $228.0
Short-term borrowings $676.3
 $—
 $368.5
 $1.8
 $10.0
 $296.0
 $—
 $869.7
 $—
 $321.0
 $181.3
 $88.4
 $279.0
 $—
Goodwill $3,154.8
 $—
 $2,003.0
 $951.9
 $17.8
 $182.1
 $—
 $3,482.9
 $—
 $2,003.0
 $956.8
 $341.0
 $182.1
 $—
Three Months Ended December 31, 2017 Total Eliminations AmeriGas
Propane		 UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other (b)
Revenues $2,125.2
 $—
 $787.3
 $784.2
 $249.8
 $305.4
 $(1.5)
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 $—
 $(97.1)(c)$—
 $—
 $78.2
 $17.7
 $1.2
 $—
 $(111.6)(b)$—
 $—
 $86.9
 $23.6
 $1.1
Cost of sales $1,137.4
 $(96.0)(c)$366.1
 $484.8
 $239.0
 $151.8
 $(8.3) $1,425.0
 $(110.8)(b)$378.5
 $448.6
 $377.5
 $159.5
 $171.7
Segment profit:              
Operating income (e) $395.0
 $0.2
 $147.9
 $93.2
 $53.4
 $96.9
 $3.4
Income (loss) from equity investees 1.0
 —
 —
 (0.2) 1.2
(d)—
 —
Other non-operating expense, net (e) (8.0) —
 —
 (4.8) (1.1) (0.6) (1.5)
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 (58.2) —
 (40.6) (5.6) (0.9) (10.9) (0.2) (60.2) —
 (42.4) (5.4) (0.5) (11.7) (0.2)
Income before income taxes $329.8
 $0.2
 $107.3
 $82.6
 $52.6
 $85.4
 $1.7
Partnership Adjusted EBITDA (a)     $194.1
        
Income (loss) before income taxes $111.9
 $0.4
 $124.2
 $53.6
 $42.1
 $65.7
 $(174.1)
Noncontrolling interests’ net income (loss) $68.3
 $—
 $68.0
 $(0.3) $—
 $—
 $0.6
 $24.3
 $—
 $81.5
 $0.1
 $—
 $—
 $(57.3)
Depreciation and amortization $110.3
 $—
 $47.4
 $32.2
 $10.1
 $20.4
 $0.2
 $111.2
 $—
 $45.7
 $31.4
 $11.5
 $22.5
 $0.1
Capital expenditures (including the effects of accruals) $128.5
 $—
 $23.6
 $21.7
 $11.3
 $71.7
 $0.2
 $161.8
 $—
 $31.0
 $27.8
 $25.1
 $77.3
 $0.6
As of December 31, 2017              
As of December 31, 2018              
Total assets $12,343.9
 $(62.6) $4,206.2
 $3,450.1
 $1,325.1
 $3,174.7
 $250.4
 $12,368.3
 $(144.3) $4,020.6
 $3,287.5
 $1,504.9
 $3,424.8
 $274.8
Short-term borrowings $586.1
 $—
 $263.5
 $41.1
 $100.0
 $181.5
 $—
 $676.3
 $—
 $368.5
 $1.8
 $10.0
 $296.0
 $—
Goodwill $3,185.5
 $—
 $2,001.3
 $990.6
 $11.5
 $182.1
 $—
 $3,154.8
 $—
 $2,003.0
 $951.9
 $17.8
 $182.1
 $—




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

(a)The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:    
  Three Months Ended
December 31,
  2018 2017
Partnership Adjusted EBITDA $210.7
 $194.1
Depreciation and amortization (45.7) (47.4)
Interest expense (42.4) (40.6)
Noncontrolling interest (i) 1.6
 1.2
Income before income taxes $124.2
 $107.3

(i)(a)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 amountsCorporate & Other includes specific items attributable to noncontrolling interests) totaling $(165.9)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 $6.6 duringthe reportable segments to which they relate, for the three months ended December 31, 20182019 and 2017, respectively.2018:

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) $—
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) $—


(c)(b)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)AmountsSegment information recast to 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 (expense), 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 16 — Global LPG Business Transformation Initiatives
During the fourth quarter of Fiscal 2019, we began executing on multi-year business transformation initiatives at our AmeriGas Propane and UGI International business segments. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. In connection with these initiatives, during the three months ended December 31, 2019, we recognized $16.7 of expenses principally comprising consulting, advisory and employee-related costs. These expenses are reflected in “Operating and administrative expenses” on the Condensed Consolidated Statement of Income.

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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; (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; (21) the interruption, disruption, failure malfunction, or breachmalfunction of our information technology systems, including due to cyber attack; (22) the inability to complete pending or future energy infrastructure projects; and (22) continued analysis(23) our ability to achieve the operational benefits and cost efficiencies expected from the completion of recent tax legislation.pending and future transformation initiatives at our business units.


These factors, and those factors set forth in Item 1A. Risk Factors in 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


The following analysis comparesanalyses compare the Company’s results of operations for the 20182019 three-month period with the 20172018 three-month period. Our analysisanalyses of results of operations should be read in conjunction with the segment information included in Note 1615 to the condensed consolidated financial statements.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.


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 reconciliations of such non-GAAP financial measures


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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 Diluted Share” below.


Impact of Fiscal 2019 Strategic Initiatives

Our GAAP net income attributable toFiscal 2020 results reflect the impacts of two strategic transactions completed in late Fiscal 2019. The larger of these transactions was the purchase of all of the public’s ownership interest in AmeriGas Partners for 34.6 million shares of UGI Corporation forCommon Stock and $529 million in cash, resulting in UGI owning 100% of the three months ended December 31, 2017Partnership effective August 21, 2019. The second significant strategic transaction was significantly impacted by the TCJAacquisition of CMG from TC Energy on August 1, 2019, resulting in a substantial increase in our natural gas gathering assets as well as the acquisition of important gas processing assets in the U.S.Marcellus and Utica Shale formations. We anticipate executing on a number of system expansion projects associated with the December 2017 French Finance Bills in France. Among other things,CMG assets over 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 beginningnext several years.

Also in Fiscal 2019. For2019, 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 have engaged strategic partners to assist us in the identification and execution of these initiatives.

At AmeriGas Propane, we are focused on efficiency and effectiveness initiatives in the following key areas: customer digital experience; customer relationship management; operating process redesign and specialization; distribution and routing optimization; sales and marketing effectiveness; purchasing and general and administrative efficiencies; and supply and logistics. The business activities will be carried out over the next two years and, once completed, will provide more than $120 million of annual 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 International LPG business, we launched an initiative in Fiscal 2019 and embarked on a process of identifying operational synergies across all 17 countries in which we currently do business. We call this initiative Project Alliance, the goal of which is to focus attention on enhanced customer service and safe and efficient operations through the establishment of two centers of excellence. One such center will be focused on commercial excellence to identify and execute projects that improve the customer’s experience. The second center will be focused on operational excellence across our U.S. federal income tax rate is 21% compared with a blended ratedistribution network and our filling centers. These efforts will be executed primarily over the next two years and, once completed, will generate over €30 million of 24.5% in Fiscal 2018.
As a resultannual savings. We estimate the total cumulative cost of the TCJA and the December 2017 French Finance Bills, during the 2017 three-month period we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. Because a significant amount of the reductionexecuting on these Project Alliance initiatives, including approximately €20 million related to our regulated utility plant assets, most of the reductionsIT capital expenditures, to UGI Utilities’ deferred income tax assets and liabilities were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities in accordance with utility ratemaking. Although these remeasurement adjustments decreased our income tax expense and increased our GAAP net income in the 2017 three-month period, we eliminated these remeasurement adjustments from our non-GAAP adjusted results 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.be approximately €55 million.


EXECUTIVE OVERVIEW


THREE MONTHS ENDED DECEMBER 31, 20182019 AND 20172018


Net Income Attributable to UGI Corporation and Diluted EPS by Business UnitSegment (GAAP):
Net income attributable to UGI Corporation determined in accordance with GAAP for the three months ended December 31, 2018 and 2017 is as follows:
For the three months ended December 31, 2018 2017 
Variance - Favorable
(Unfavorable)
 2019 2018
(Dollars in millions) Amount % of Total Amount (a) % of Total Amount % Change
(Dollars in millions, except per share amounts) Net Income (Loss) 
Diluted
EPS (a)
 Net Income (Loss) Diluted
EPS
AmeriGas Propane $30.6
 47.7 % $141.6
 38.7 % $(111.0) (78.4)% $91.1
 $0.43
 $30.6
 $0.17
UGI International (d) 32.5
 50.6 % 61.1
 16.7 % (28.6) (46.8)% 72.7
 0.34
 36.7
 0.20
Midstream & Marketing 31.0
 48.3 % 112.0
 30.6 % (81.0) (72.3)% 36.0
 0.17
 31.0
 0.17
UGI Utilities 49.9
 77.7 % 68.3
 18.7 % (18.4) (26.9)% 60.8
 0.29
 49.9
 0.28
Corporate & Other (e) (79.8) (124.3)% (17.1) (4.7)% (62.7) N.M.
Corporate & Other (b) (c) (48.6) (0.23) (84.0) (0.46)
Net income attributable to UGI Corporation $64.2
 100.0 % $365.9
 100.0 % $(301.7) (82.5)% $212.0
 $1.00
 $64.2
 $0.36
(a)Net income attributable to UGI CorporationEPS for the three months ended December 31, 2017, includes income (loss) from remeasurement adjustments to tax-related accounts as a result2019 three-month period reflects 34.6 million incremental shares of UGI Common Stock issued in conjunction with the enactment of the TCJA as follows:AmeriGas Merger.

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AmeriGas Propane$113.1
UGI International(9.3)
Midstream & Marketing74.3
UGI Utilities8.1
Corporate & Other(20.2)
Net income attributable to UGI Corporation$166.0


(b)Three months ended December 31, 2018,Corporate & Other includes certain adjustments made to our reporting segments in arriving at net after-tax lossincome attributable to UGI Corporation.  These adjustments have been excluded from extinguishment of debt of $4.2 million.the segment results to align with the measure used by our CODM in assessing segment performance and allocating resources.  See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below and Note 15 to Condensed Consolidated Financial Statements for additional information related to these adjustments, as well as other items included within Corporate & Other.  
(c)Three months ended December 31, 2017, includes beneficialIncludes the impact of a $17.3 million remeasurement adjustment to net deferred income tax liabilities associated with a December 2017 change in French income tax rates.
(d)Three months ended December 31, 2017, includes after-tax integration expenses associated with Finagaz of $1.2 million.rounding.


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(e)Includes net after-tax (losses) gains on commodity derivative instruments not associated with current-period transactions of $(81.2) million and $4.6 million for the three months ended December 31, 2018 and 2017, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $5.8 million and $(0.1) million for the three months ended December 31, 2018 and 2017, respectively.
N.M. — Variance is not meaningful.


Adjusted Net Income Attributable to UGI Corporation and Diluted EPS by Business UnitSegment (Non-GAAP):
Adjusted net
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 three months ended December 31, 2018 and 2017 is as follows:
For the three months ended December 31, 2018 2017 
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount % of Total Amount % Change
AmeriGas Propane $30.6
 21.3 % $28.5
 15.9 % $2.1
 7.4 %
UGI International 36.7
 25.5 % 54.3
 30.3 % (17.6) (32.4)%
Midstream & Marketing 31.0
 21.6 % 37.7
 21.0 % (6.7) (17.8)%
UGI Utilities 49.9
 34.7 % 60.2
 33.6 % (10.3) (17.1)%
Corporate & Other (4.4) (3.1)% (1.4) (0.8)% (3.0) N.M.
Adjusted net income attributable to UGI Corporation $143.8
 100.0 % $179.3
 100.0 % $(35.5) (19.8)%
N.M. - Variance not meaningful.
Discussion. Adjusted2019 three-month period was $212.0 million (equal to $1.00 per diluted share) compared to net income attributable to UGI Corporation for the 2018 three-month period was $143.8of $64.2 million (equal to $0.81$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 losses 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 a result of the AmeriGas Merger.
Adjusted net income attributable to UGI Corporation for the 2019 three-month period was $246.2 million (equal to $1.17 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 20172018 three-month period of $179.3$143.8 million (equal to $1.01$0.81 per diluted share).
Our results for the three months ended December 31, 2018,2019, reflect average temperatures that were significantlywarmer than the prior year at each of our reportable segments, and warmer than normal at our UGI International, Midstream & Marketing and UGI Utilities reportable segments. 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-year periodaverage temperatures in December 2018 at our UGI International segment; colder than normal and colder than the prior-year period at our Midstream & Marketing and AmeriGas Propane segments; and approximately normal and slightly colder than the prior-year period at our UGI Utilities segment. Although average temperatures during the 2018 three-month period at our domestic units were colder than the prior-year period, temperatures during the peak heating-season month of December 2018 were much warmer and less volatile than the extremely cold and volatile temperatures experienced during late December 2017.International.
AdjustedThe significant increase in adjusted net income attributable to UGI from AmeriGas Propane increased in the 20182019 three-month period reflecting higher average retail unit margins and higher retail gallons sold from temperatures that averaged 6.3% colder thanwas largely attributable to the prior-year period. Our inclusion of 100% of AmeriGas Propane’s results due to the AmeriGas Merger transaction completed in August 2019.
UGI International adjusted net income was lower$36.0 million higher in the 2019 three-month period reflecting the negative volume and associatedhigher total margin effects of significantly warmer weather on heating-related sales, and lower volumes sold for crop drying due to a very dryoperating and warm summer and early fall in Europe. Through December 2018, ouradministrative expenses. Although UGI International operations had experienced nine consecutive months2019 three-month period adjusted net income was impacted by a weaker euro compared to the prior-year period, adjusted net income benefited from higher realized gains on foreign currency exchange contracts.

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Midstream & Marketing adjusted net income was also lower than in the 20172019 three-month period as results in the prior year benefited from the effects on capacity values of extremely cold late December 2017 weather and, to a lesser extent, due to lower margin from electric generation. Although the weather at UGI Utilities was slightly colder$5.0 million higher than the prior-year period, UGI Utilities’ 2018 three-month periodperiod. This increase principally reflects incremental net income from CMG which was lower primarily because netacquired in August 2019, including income in the prior yearfrom an equity method investment that was included approximately $8.1 million of lower income taxes resulting from the enactmentas part of the TCJA. Althoughacquisition, partially offset by increased interest expense related to debt issued to finance a portion of the lower federal tax rates from the TCJA also impacted the 2018 three-month period at CMG Acquisition.
UGI Utilities the tax benefits in the current-year period are being given back to UGI Utilities’ customers through negative surcharge rates in accordance with a May 17, 2018, PAPUC Order. Excluding the $8.1 million tax benefit in the prior-year period, UGI Utilities’ 20182019 three-month period adjusted net income was $2.2$10.9 million lowerhigher 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 operating and administrative expensesexpenses. The effect of these items was partially offset by higher depreciation expense attributable to increased capital expenditures and higher depreciationinterest expense.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Diluted 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 2018 and 2017 three-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 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; and (4) one-time impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills. 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

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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 December 31, 2018 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
Adjusted net income attributable to UGI Corporation (millions):            
Net income (loss) attributable to UGI Corporation $64.2
 $30.6
 $32.5
 $31.0
 $49.9
 $(79.8)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(35.5)) (a) 81.2
 —
 —
 —
 —
 81.2
Unrealized gains on foreign currency derivative instruments (net of tax of $2.3) (a) (5.8) —
 —
 —
 —
 (5.8)
Loss on extinguishments of debt (net of tax of $(1.9)) (a) 4.2
 —
 4.2
 —
 —
 —
Adjusted net income (loss) attributable to UGI Corporation $143.8
 $30.6
 $36.7
 $31.0
 $49.9
 $(4.4)
             
Adjusted diluted earnings per share:            
UGI Corporation earnings (loss) per share — diluted $0.36
 $0.17
 $0.18
 $0.17
 $0.28
 $(0.44)
Net losses on commodity derivative instruments not associated with current-period transactions (b) 0.46
 —
 —
 —
 —
 0.46
Unrealized gains on foreign currency derivative instruments (0.03) —
 —
 —
 —
 (0.03)
Loss on extinguishments of debt 0.02
 —
 0.02
 —
 —
 —
Adjusted diluted earnings (loss) per share $0.81
 $0.17
 $0.20
 $0.17
 $0.28
 $(0.01)


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Three Months Ended December 31, 2017 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities		 Corporate
& Other
Adjusted net income attributable to UGI Corporation (millions):            
Net income (loss) attributable to UGI Corporation $365.9
 $141.6
 $61.1
 $112.0
 $68.3
 $(17.1)
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $2.1) (a) (4.6) —
 —
 —
 —
 (4.6)
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.0)) (a) 0.1
 —
 —
 —
 —
 0.1
Integration expenses associated with Finagaz (net of tax of $(0.7)) (a) 1.2
 —
 1.2
 —
 —
 —
Impact of French Finance Bill (17.3) —
 (17.3) —
 —
 —
Remeasurement impact of TCJA (166.0) (113.1) 9.3
 (74.3) (8.1) 20.2
Adjusted net income (loss) attributable to UGI Corporation $179.3
 $28.5
 $54.3
 $37.7
 $60.2
 $(1.4)
             
Adjusted diluted earnings per share:            
UGI Corporation earnings (loss) per share - diluted $2.07
 $0.80
 $0.35
 $0.63
 $0.39
 $(0.10)
Net gains on commodity derivative instruments not associated with current-period transactions (0.03) —
 —
 —
 —
 (0.03)
Unrealized losses on foreign currency derivative instruments —
 —
 —
 —
 —
 —
Integration expenses associated with Finagaz 0.01
 —
 0.01
 —
 —
 —
Impact of French Finance Bill (0.10) —
 (0.10) —
 —
 —
Remeasurement impact of TCJA (0.94) (0.64) 0.05
 (0.42) (0.05) 0.12
Adjusted diluted earnings (loss) per share $1.01
 $0.16
 $0.31
 $0.21
 $0.34
 $(0.01)
  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

(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.




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SEGMENT RESULTS OF OPERATIONS


20182019 Three-Month Period Compared to the 20172018 Three-Month Period
AmeriGas Propane
For the three months ended December 31, 2018 2017 Increase 2019 2018 Increase (Decrease)
(Dollars in millions)                
Revenues $820.2
 $787.3
 $32.9
 4.2% $730.4
 $820.2
 $(89.8) (10.9)%
Total margin (a) $441.7
 $421.2
 $20.5
 4.9% $441.2
 $441.7
 $(0.5) (0.1)%
Partnership operating and administrative expenses $235.1
 $230.3
 $4.8
 2.1%
Partnership Adjusted EBITDA (b) $210.7
 $194.1
 $16.6
 8.6%
Operating income (c) $166.6
 $147.9
 $18.7
 12.6%
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) 310.3
 305.0
 $5.3
 1.7% 304.4
 310.3
 (5.9) (1.9)%
Heating degree days—% colder (warmer) than normal (d) 4.9% (1.4)% —
 —
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 December 31, 2018 and 2017 excludes net pre-tax (losses) gains of $(78.5) million and $0.8 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)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).
(c)Operating income includes certain operating and administrative expenses of the General Partner.
(d)Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by the NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.


The Partnership’sAmeriGas Propane retail gallons sold during the 20182019 three-month period were 1.7% higher1.9% lower than the prior-year period. Average temperatures based upon heating degree days were 4.9%3.7% colder than normal and 6.3% colderfor the 2019 three-month period but 1.2% warmer than the prior-year period. AverageAlthough average temperatures during the 2019 three-month period were colder than normal, average temperatures in the 2017 three-month periodcritical heating-season month of December 2019 were impacted by significantly colder8.6% warmer than normal weather in late December.normal.


Retail propane revenues increased $29.1decreased $90.7 million during the 20182019 three-month period reflecting the effects of higherlower average retail selling prices ($17.177.0 million) and the higherlower retail volumes sold ($12.013.7 million). Wholesale propane revenues increased $2.3$1.0 million reflecting higher wholesale volumes sold ($5.45.6 million) partiallylargely offset by lower average wholesale selling prices ($3.14.6 million). Average daily wholesale propane commodity prices during the 20182019 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were slightlyapproximately 38% lower than such prices during the 2017 three-month period reflecting lower year-over-year wholesale propane commodity prices later in the 2018 three-month period. Other revenues in the 20182019 three-month period were slightly higherlower than in the prior-year period principally reflecting higher service and ancillary revenues.period. Total cost of sales increased $12.4decreased $89.3 million principally reflecting the effects of the higher propane volumes sold ($10.9 million).

AmeriGas Propane total margin increased $20.5 million in the 2018 three-month period principally reflecting higher retail propane total margin ($19.5 million) and slightly higher non-propane total margin. The increase in retail propane total margin principally reflects higher average retail propane unit margins due, in part, to the effects of declining wholesale propane prices later during the 2018 three-month period and, to a lesser extent, the higher retail volumes sold.

Partnership Adjusted EBITDA increased $16.6 million in the 20182019 three-month period principally reflecting the effects of the higher total marginlower average propane product costs ($20.588.4 million) and slightly higher other operating incomelower retail propane volumes sold ($1.16.4 million), partially offset by a $4.8 million increase in the Partnership operating and administrative expenses. The slight increase in the Partnership operating and administrative expenses includes higher total compensation and benefits costswholesale propane volumes sold ($3.15.5 million), principally higher labor and overtime costs associated with the increased activity, and higher vehicle expenses ($2.2 million).

AmeriGas Propane operating income increased $18.7total margin decreased $0.5 million in the 20182019 three-month period principally reflecting the $16.6 million increase in Partnership Adjusted EBITDAlower retail volumes sold ($7.3 million) largely offset by higher average retail unit margins ($5.5 million) and, to a much lesser extent, higher average wholesale unit margins ($1.3 million).

Operating income and earnings before interest expense and income taxes decreased $1.3 million principally reflecting higher operating and administrative expenses ($4.9 million) and the previously mentioned lower total margin ($0.5 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 lower depreciation and amortization expense ($1.71.8 million). The increase in operating and administrative expenses in the 2019 three-month period reflects, among other things, higher general insurance and self-insured casualty and liability expense ($2.7 million) and higher vehicle lease expense ($2.1 million).




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UGI International
For the three months ended December 31, 2018 2017 Increase (Decrease) 2019 2018 Increase (Decrease)
(Dollars in millions)                
Revenues $710.7
 $784.2
 $(73.5) (9.4)% $651.4
 $710.7
 $(59.3) (8.3)%
Total margin (a) $262.1
 $299.4
 $(37.3) (12.5)% $283.0
 $252.1
 $30.9
 12.3 %
Operating and administrative expenses (b) $174.4
 $173.7
 $0.7
 0.4 % $157.5
 $164.4
 $(6.9) (4.2)%
Operating income $58.3
 $93.2
 $(34.9) (37.4)% $95.8
 $58.3
 $37.5
 64.3 %
Income before income taxes (c) $47.5
 $82.6
 $(35.1) (42.5)%
Earnings before interest expense and income taxes $100.2
 $59.0
 $41.2
 69.8 %
LPG retail gallons sold (millions) 237.6
 260.6
 $(23.0) (8.8)% 246.4
 237.6
 8.8
 3.7 %
UGI International degree days—% (warmer) than normal (d) (8.0)% (0.7)% —
 —
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 December 31, 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 2017 excludes net pre-tax (losses) gainsadministrative expenses” on the Condensed Consolidated Statements of $(97.3) millionIncome (but are excluded from operating and $17.0 million, respectively,administrative expenses presented above). In the 2019 three-month period, French energy certificate costs are included in cost of sales on commodity derivative instruments not associated with current-period transactions.the Condensed Consolidated Statements of Income.
(b)The 2017 three-month period includes $1.9 million of Finagaz integration expenses.
(c)Income before income taxes for the three months ended December 31, 2018 and 2017 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $8.1 million and $(0.1) million, respectively. Income before income taxes during the three months ended December 31, 2018, is also net of a $6.1 million loss on extinguishments of debt.
(d)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 20182019 three-month period were 8.0%10.3% warmer than normal and 7.3%2.7% warmer than the prior-year period. TotalNotwithstanding the warmer temperatures, total LPG retail gallons sold during the 20182019 three-month period were approximately 9% lower3.7% higher reflecting lowerstrong bulk volumes associated with crop drying as a result of a very warm and dry summer,partially offset by lower cylinder volumes and the effects of the significantly warmer weather on heating-related bulk sales. Through December 2018, UGI International had experienced nine consecutive months of warmer-than-normal weather. AlthoughDuring the 2019 three-month period, average un-weighted wholesale priceprices for LPGpropane in northwest Europe were approximately 15% lower than the prior-year period. Average wholesale butane prices in northwest Europe for the 20182019 three-month period waswere slightly lower than in the prior-year period, reflecting a significant decline in LPG prices later in the three-month period, wholesale LPG prices during late Fiscal 2018 and early in the 2018 three-month period were significantly higher than in 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 20182019 and 20172018 three-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.14$1.11 and $1.18,$1.14, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.29 and $1.33, respectively. Although the euro and British pound sterling were slightly weaker during the 2018 three-month period and affect the comparison of line item amounts presented in the table above, the impact of the weaker currencies on net income was substantially offset by net gains on foreign currency exchange contracts.both periods.


UGI International revenues decreased $73.5$59.3 million during the 20182019 three-month period principally reflecting the effects of the lower volumes soldaverage LPG selling prices and to a much lesser extent, the translation effects of the weaker euro and British pound sterling.(approximately $19 million) partially offset by the previously mentioned increase in LPG retail volumes. UGI International cost of sales decreased $36.2$90.2 million during the 20182019 three-month period principally reflecting the effects of the lower LPG volumes sold and the translation effects of the slightly lower euro and British pound sterling partially offset by higher average LPG cost of sales reflecting the impact of higher average LPG inventoryproduct costs entering the heating season.

UGI International total margin decreased $37.3 million primarily reflecting the lower retail LPG volumes sold and slightly lower LPG unit margins. The lower total margin also reflects, to a lesser extent, the translation effects of the weaker euro and British pound sterling.(approximately $11 million).


The $34.9 million decrease in UGI International operating income principally reflects the previously mentioned $37.3 million decrease in total margin increased $30.9 million reflecting higher average LPG unit margins including margin management efforts and slightly higher operating and administrative expenses. These decreases to operating income were partially offset by slightly higher other operating income ($2.1 million) and a $0.8 million decrease in depreciation and amortization expense. The slight increase in operating and administrative expenses largely reflects higher complianceincreased recovery of costs associated with energy conservation certificates, higher retail volumes associated with crop drying and, costs related to strategic projects substantiallya much lesser extent, higher natural gas margins. The effect of these increases was partially offset by the translation effects of the weaker euro (approximately $8 million), lower cylinder volumes and British pound sterlingthe effects of the warmer weather on heating-related bulk sales.

UGI International operating income increased $37.5 million principally reflecting the previously mentioned $30.9 million increase in total margin and lower cylinder repair costs. Operatingoperating and administrative expenses ($6.9 million). The decrease in the prior-year three-month period includes $1.9 million of Finagaz integration costs. The lower depreciationoperating and amortization expense principallyadministrative expenses largely reflects the translation effects of the weaker currencies.euro (approximately $4 million) and lower maintenance and outside services costs. UGI International incomeearnings before interest expense and income taxes in the 20182019 three-month period was $35.1increased $41.2 million lower than the prior-year period principally reflecting the net effects of the $34.9 million decreaseincrease in UGI International

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operating income ($37.5 million) 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 the translation effects of changes in foreign currency exchange rates ($5.43.6 million).



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Midstream & Marketing
For the three months ended December 31, 2018 2017 Increase (Decrease) 2019 2018 Increase (Decrease)
(Dollars in millions)                
Revenues $459.4
 $328.0
 $131.4
 40.1 % $372.5
 $459.4
 $(86.9) (18.9)%
Total margin (a) $81.9
 $89.0
 $(7.1) (8.0)% $108.3
 $81.9
 $26.4
 32.2 %
Operating and administrative expenses $29.2
 $25.6
 $3.6
 14.1 % $34.9
 $29.2
 $5.7
 19.5 %
Operating income $41.1
 $53.4
 $(12.3) (23.0)% $55.1
 $41.1
 $14.0
 34.1 %
Income before income taxes $42.1
 $52.6
 $(10.5) (20.0)%
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 December 31, 2018 and 2017 excludes net pre-tax gains (losses) of $1.8 million and $(11.1) 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 December 31, 20182019 were approximately 4.1% colderslightly warmer than normal and 5.2% colderapproximately 4.6% warmer than the prior-year period. Although weather for the 2018 three-month period was colder than the prior year, weather in the month of December was approximately 16% warmer than the prior year as the 2017 three-month period experienced extremely cold and more volatile weather in late December.


Midstream & Marketing 2018Marketing’s 2019 three-month period revenues were $131.4$86.9 million higherlower than the prior-year period principally reflecting higherdecreased natural gas revenues ($133.8108.1 million) and, to a much lesser extent, higher retail power marketing revenues ($2.4 million). These increases in revenue were partially offset by lower electric generation revenues ($4.63.0 million), retail power ($1.6 million) and lower totalcapacity revenues from midstream assets ($2.91.6 million). The significant increasedecrease in natural gas revenues principally reflects higheris primarily attributable to lower average natural gas prices during the 20182019 three-month period, the effectsperiod. The effect of higher natural gas volumes resulting from the colder 2018 three-month period temperatures, and customer growth including customers obtained through Midstream & Marketing’s acquisition of South Jersey Energy Company’s natural gas marketing business. The decrease in revenues from midstream assets principally reflects lower capacity management revenues ($9.1 million)these revenue decreases were partially offset by higher peaking and natural gas gathering revenues. The decrease in capacity management revenues reflects lower capacity values as the prior-year period benefited($32.8 million) largely attributable to incremental revenues from extremely cold weather in late December. Electric generation revenues were lower principally reflecting lower off-peak volumes generated from the Hunlock Station generating facility.CMG which was acquired on August 1, 2019. Midstream & Marketing cost of sales were $264.2 million in the 2019 three-month period compared to $377.5 million in the 2018 three-month period compared to $239.0period. The $113.3 million decrease in the 2017 three-month period, an increasecost of $138.5 million,sales principally reflecting the higherreflects lower natural gas costs and higher natural gas volumes.costs.


Midstream & Marketing total margin decreased $7.1increased $26.4 million in the 20182019 three-month period principally reflecting lower total margin from our midstream assets ($3.9 million) and lower electric generation total margin ($3.0 million). The decrease in total margin from our midstream assets is principally the result of lower capacity management total margin ($9.1 million) partially offset by higher peaking and natural gas gathering total margin.margin ($32.8 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 effect of these increases was partially offset by lower totalcapacity management margin and lower margin from electric generation principally reflects lower electric generation volumes principally from ourthe Hunlock Station generating facility reflecting lower off-peak volumes. The decrease in capacity management total margin reflects higher capacity values in the prior-year period resulting in large part from extremely cold and more volatile late December 2017 weather.


Midstream & Marketing operating income and incomeearnings before interest expense and income taxes during the 20182019 three-month period decreased $12.3increased $14.0 million and $10.5$19.0 million, respectively. The decreaseincrease in operating income principally reflects the previously mentioned decreaseincrease in total margin ($7.126.4 million), partially offset by higher depreciation and amortization expense ($6.9 million) and increased operating and administrative expenses ($3.65.7 million), and. The higher depreciation and amortization expense ($1.4 million). The $3.6 million increase inand operating and administrative expenses reflects higher compensation and benefitsare largely attributable to CMG. The increase in earnings before interest expense and higher expenses associated with greater peaking, LNGincome taxes reflects the increase in operating income and equity income from Pennant, a natural gas gathering activities. The increase in operating and administrative expense also reflects higher operating and maintenance expenses associated with a planned outage atprocessing equity interest that was acquired as part of the Conemaugh generating unit. The increase in depreciation expense principally reflects incremental depreciation from the expansion of our LNG and peaking assets. The $10.5 million decrease in income before income taxes in the 2018 three-month period principally reflects the lower operating income ($12.3 million) partially offset by the absence of a pension settlement recorded in the prior-year period and lower interest expense.CMG Acquisition.



UGI Utilities
46
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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UGI Utilities
For the three months ended December 31, 2018 2017 Increase (Decrease)
(Dollars in millions)        
Revenues (a) $322.7
 $323.1
 $(0.4) (0.1)%
Total margin (b) $161.9
 $170.0
 $(8.1) (4.8)%
Operating and administrative expenses (b) $61.2
 $52.9
 $8.3
 15.7 %
Operating income $77.0
 $96.9
 $(19.9) (20.5)%
Income before income taxes $65.7
 $85.4
 $(19.7) (23.1)%
Gas Utility system throughput—bcf        
Core market 26.5
 25.5
 1.0
 3.9 %
Total 75.7
 69.2
 6.5
 9.4 %
Electric Utility distribution sales - gwh 249.7
 246.6
 3.1
 1.3 %
Gas Utility heating degree days—% (warmer) than normal (c) (0.5)% (1.9)% —
 —
purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and 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 December 31, 2018, were reduced by $13.5 million to reflect the give back of tax savings of the TCJA (see Notes 6 and 8 to Condensed Consolidated Financial Statements).
(b)Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $1.3 million during each of the three months ended December 31, 2018 and 2017. 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 December 31, 2018,2019, were slightly4.2% warmer than normal and 1.5% colder3.7% warmer than the three months ended December 31, 2017.prior-year period. Gas Utility core market volumes increased 1.0decreased slightly (0.5 bcf (3.9%and 1.9%) principally reflecting the effects of the colderwarmer weather andpartially offset by growth in the number of core market customers.customers and higher average use per customer. Total Gas Utility distribution system throughput increased 6.58.8 bcf reflecting higher interruptible delivery service volumes (5.1 bcf) and higher large firm delivery service volumes and(4.1 bcf) partially offset by the previously mentioned higherslight decrease in core market volumes partially offset by a decrease in interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 1.3% higherlower than the prior-year period principally reflecting the impact of the colderwarmer weather on Electric Utility heating-related sales.
UGI Utilities revenues decreased $0.4increased $6.6 million in the three months ended December 31, 2019, reflecting a $2.9$9.2 million decreaseincrease in Gas Utility revenues partially offset by a $2.5$2.6 million increasedecrease in Electric Utility revenues. In accordance withThe increase in Gas Utility revenues principally reflects higher core market revenues ($11.1 million) and higher large firm and interruptible delivery service revenues ($2.3 million), partially offset by lower off-system sales and capacity release revenues ($6.8 million). The $11.1 million increase in Gas Utility core market revenues principally reflects the May 17, 2018, PAPUC Order,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 $2.6 million decrease in Electric Utility revenues during the 2019 three-month period is largely attributable to lower DS rates and, to a much lesser extent, the lower kilowatt-hour sales.

UGI Utilities cost of sales was $151.6 million in the three months ended December 31, 2018, Gas Utility’s revenues were reduced by $13.5 million to reflect the give back of tax savings of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $10.6 million principally reflecting an increase in off-system sales revenues including capacity releases ($17.5 million), due in large part to the adoption of ASC 606 (which requires that capacity release contracts be reflected on a gross, rather than net, basis), and higher other revenues ($1.8 million), partially offset by lower core market revenues ($9.9 million). The $9.9 million decrease in Gas Utility core market revenues reflects lower average retail core market PGC rates ($19.0 million) partially offset by the effects of the higher core market throughput ($9.0 million).The increase in Electric Utility revenues during the 2018 three-month period principally reflects higher DS rates ($0.9 million), higher transmission revenue ($0.7 million), and an increase in Electric Utility base rates effective October 27, 2018 ($0.5 million).
UGI Utilities’ cost of sales was2019 compared with $159.5 million in the three months ended December 31, 2018, compared with $151.8 million in the three months ended December 31, 2017, principally reflecting higherlower Gas Utility cost of sales ($6.35.3 million) and higherlower Electric Utility cost of sales ($1.52.6 million) from the higher DS rates and slightly higher distribution system sales.. The higherlower Gas Utility cost of sales principally reflects higher costthe effects of the lower costs of sales associated with off-system sales including capacity releases ($16.97.7 million) due in large partpartially offset by increased cost of sales related to the previously mentioned impact of ASC 606 on the presentation of capacity release contracts, and the effects of higher core market volumes ($4.31.8 million) partially offset by lower average retail core-marketreflecting higher PGC rates ($16.3 million).rates.

UGI Utilities total margin decreased $8.1increased $14.7 million reflecting lower total margin from Gas Utility ($9.1 million) attributable toduring the impact of the $13.5 million reduction in revenues resulting from the TCJA, partially offset by higher Electric Utility total margin ($1.0 million). Excluding the reduction in Gas Utility total margin resulting from the TCJA, Gas Utility total margin increased $4.4 million principally2019 three-month period reflecting higher total margin from Gas Utility core market customers ($2.19.2 million) and higher other margin ($1.9 million) primarily reflectingincluding the margin impactsimpact of the presentation of certain revenues in accordance with the adoption

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of ASC 606. The increase in Electric Utility margin principally reflects 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 transmission revenuelarge firm and to a lesser extent, the higher distribution volumes sold.interruptible delivery service total margin ($1.0 million).

UGI Utilities operating income decreased $19.9and earnings before interest expense and income taxes increased $14.8 million and $14.2 million, respectively, during the 2019 three-month period principally reflecting the decreasepreviously mentioned increase in total margin ($8.114.7 million), higher Gas Utility and Electric Utilitylower operating and administrative expenses ($8.3 million), greater depreciation expense ($2.1 million), and higher other operating expense ($1.23.1 million). The increasedecrease in UGI Utilities operating and administrative expenses principally reflects, the absence of a favorable payroll tax adjustment recorded in the prior-year period ($2.1 million) and higher general and administrative costs including an increase inamong other things, lower uncollectible accounts expense ($1.6 million), higher IT maintenance and consulting expense ($1.2 million), higher contractor and outside services expense ($1.11.8 million) and higherlower compensation and benefits expenseexpenses ($0.91.2 million). The increase ineffect of these increases was partially offset by greater depreciation expense reflects($3.2 million) attributable to increased IT and distribution system and IT capital expenditure activity. UGI Utilities income before income taxes decreased $19.7 million principally reflecting the decrease in UGI Utilities operating income.

Interest Expense and Income Taxes


Our consolidated interest expense during the 20182019 three-month period was $84.1 million, compared to $60.2 million slightly higher than the $58.2 million of interest expense recorded during the 20172018 three-month period. The highersignificant increase in interest expense principally reflects higher short-term interest expense on credit agreementlong-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 interest on short-term borrowings.


OurThe higher effective income tax rate infor the 2019 three-month period reflects income taxes on our 100% ownership of the Partnerships compared to income taxes on our approximately 26% ownership interest during the 2018 three-month period reflects a U.S. federal income tax rate of 21%. Our effective income tax rate in the 2017 three-month period reflects a blended U.S. federal income tax rate of 24.5%.period.

As previously mentioned, our consolidated income taxes for the three months ended December 31, 2017, 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 2017 three-month period we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. 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 three months ended December 31, 2017, was reduced by remeasurement adjustments to tax-related accounts as a result of the enactment of the TCJA totaling $166.0 million, and was reduced by remeasurement adjustments to net deferred income tax liabilities as a result of the December 2017 French Finance Bills totaling $17.3 million. For further information on these tax law changes, 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 $477.6$333.4 million at December 31, 2018,2019, 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 December 31, 20182019 and September 30, 2018,2019, UGI had $218.5$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 December 31, 20182019 and September 30, 2018,2019, comprises the following:
December 31, 2018 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$368.5
 $1.8
 $10.0
 $296.0
 $—
 $676.3
 $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
 $401.4
 $—
 $675.0
 $—
 $3,651.4
 $3,250.0
$2,575.0
 $392.5
 $—
 $825.0
 $—
 $3,792.5
 $3,781.5
Term loans and notes—
 344.1
 —
 158.8
 —
 502.9
 890.4
Term loans—
 336.4
 696.5
 152.5
 550.0
 1,735.4
 1,729.4
Other long-term debt20.5
 20.4
 0.4
 6.6
 8.8
 56.7
 59.0
12.0
 22.5
 41.3
(a)4.2
 297.9
 377.9
 345.7
Unamortized debt issuance costs(26.5) (9.5) —
 (4.8) —
 (40.8) (34.1)(22.7) (7.9) (11.5) (4.5) (3.8) (50.4) (52.6)
Total long-term debt$2,569.0
 $756.4
 $0.4
 $835.6
 $8.8
 $4,170.2
 $4,165.3
$2,564.3
 $743.5
 $726.3
 $977.2
 $844.1
 $5,855.4
 $5,804.0
Total debt$2,937.5
 $758.2
 $10.4
 $1,131.6
 $8.8
 $4,846.5
 $4,590.2
$2,885.3
 $924.8
 $814.7
 $1,256.2
 $844.1
 $6,725.1
 $6,600.3


(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.
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 Subsequent Event. 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.


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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 December 31, 20182019 and 2017,2018, 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 December 31, 2018        
As of December 31, 2019        
AmeriGas OLP $600.0
 $368.5
 $63.5
 $168.0
 $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 $450.0
 $296.0
 $2.0
 $152.0
 $350.0
 $279.0
 $—
 $71.0
As of December 31, 2017        
UGI Corporation (b) $300.0
 $290.0
 $—
 $10.0
As of December 31, 2018        
AmeriGas OLP $600.0
 $263.5
 $67.2
 $269.3
 $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
 $55.0
 $—
 $185.0
 $240.0
 $—
 $—
 $240.0
UGI Utilities $300.0
 $181.5
 $2.0
 $116.5
 $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)Borrowings outstanding have been classified as “Long-term debt” on the Condensed Consolidated Balance Sheets.


The average daily and peak short-term borrowings under the Company’s principal credit agreements during the three months ended December 31, 20182019 and 20172018 are as follows:
 For the three months ended
December 31, 2018		 For the three months ended
December 31, 2017		 For the three months ended For the three months ended
(Currency in millions) Average Peak Average Peak
 December 31, 2019 December 31, 2018
(Millions of dollars or euros) Average Peak Average Peak
AmeriGas OLP $306.3
 $401.0
 $199.0
 $286.0
 $322.0
 $359.0
 $306.3
 $401.0
UGI International, LLC €—
 €—
 €—
 €—
 €187.0
 €187.3
 €—
 €—
Energy Services $—
 $—
 $44.7
 $79.0
 $40.5
 $76.5
 $—
 $—
UGI Utilities $250.7
 $311.0
 $168.1
 $205.0
 $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 a €300 million senior unsecured multicurrency revolving credit facility agreement. For further information on this transaction, see “Long-term Debt” above.

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 December 31, 2019, the outstanding balance of ESFC trade receivables was $86.0 million, of which $68.4 million was sold to the bank. At December 31, 2018, the outstanding balance of ESFC trade receivables was $135.4 million, of which $10.0 million were sold to the bank. At December 31, 2017, the outstanding balance of ESFC trade receivables was $101.0 million, of which $45.0 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 three months ended December 31, 20182019 and 2017,2018, peak sales of receivables were $15.0$68.4 million and $45.0$15.0 million, respectively, and average daily amounts sold were $49.8 million and $1.5 million, and $28.6 million, respectively. For additional information regarding the Receivables Facility, see Note 9 to the Condensed Consolidated Financial Statements.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
AmeriGas Partners has a Standby Equity Commitment Agreement with the General Partner and UGI under which UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019. UGI’s capital contributions may be made from time to time through July 1, 2019, upon request of the Partnership. In consideration for any capital contributions pursuant to the Standby Equity Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new

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AmeriGas Partners Class B Common Units representing limited partner interests in the Partnership. There have been no capital contributions made to the Partnership under the Standby Equity Commitment Agreement.


Dividends and Distributions


On November 16, 2018,22, 2019, UGI’s Board of Directors declared a cash dividend equal to $0.26$0.325 per common share. The dividend was paid on January 1, 2019,2020, to shareholders of record on December 14, 2018.16, 2019. On January 30, 2019,22, 2020, UGI’s Board of Directors declared a quarterly dividend of $0.26$0.325 per common share. The dividend is payable April 1, 2019,2020, to shareholders of record on March 15, 2019.16, 2020.

During the three months ended December 31, 2018, the General Partner’s Board of Directors declared and the Partnership paid a quarterly distribution on all limited partner units at a rate of $0.95 per Common Unit for the quarter ended September 30, 2018. On January 29, 2019, the General Partner’s Board of Directors approved a quarterly distribution of $0.95 per limited partner unit for the quarter ended December 31, 2018. The distribution will be paid on February 19, 2019, to unitholders of record on February 11, 2019.


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 $118.4 million in the 2019 three-month period compared to $96.6 million in the 2018 three-month period compared to $31.4 million in the 2017 three-month period. Cash flow from operating activities before changes in operating working capital was $355.6 million in the 2019 three-month period compared to $372.2 million in the 2018 three-month period compared to $380.9 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 $275.6$237.2 million in the 20182019 three-month period compared to $349.5$275.6 million in the prior-year period. The lower net cash used to fund changes in operating working capital in the 20182019 three-month period reflects, among other things, higher cash receiptscollateral deposits received from customers due to timing of sales. Sales and associated revenues occurred earliercommodity derivative instrument counterparties in the 2018 three-month periodcurrent year compared with sales and associated revenues that occurred latercollateral deposits paid in the 2017 three-month period asprior year, and net recoveries of Gas Utility purchased gas costs in the prior-year period experienced extreme cold weather in late December 2017. The greater cash received from changes in inventory principally reflects the impacts of lower and declining propane product costs at AmeriGas Propane during the 2018 three-month periodcurrent year compared to more moderatenet repayments in the prior year. These positive cash flow effects of higher and more stable propane product costs experiencedwere partially offset by greater cash used to fund net changes in the prior-year period. These increases inother operating working capital accounts including, among other things, lower cash flow from changes in operating working capital were partially offset by, among other things, net refunds of utility PGC costs during the current-year period compared to net recoveries of such costs during the prior-year period,inventories and commodity derivative instrument collateral deposits paid in the current-year three-month period compared to collateral deposits received in the prior-year period.accounts payable.


Investing Activities.Cash flow used by investing activities was $194.0$175.9 million in the 20182019 three-month period compared with $318.0$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 paymentsexpenditures for property, plant and equipment were $182.0 million in the 2019 three-month period compared to $183.3 million in the 2018 three-month period compared to $147.5 million in the prior-year period reflecting, in part, higher IT expenditures associated with Enterprise Resource Planning systems and slightly higher UGI Utilities main replacement and new business capital expenditures.period. Cash used for acquisitions of businesses and assets in the 2018 three-month period reflects Energy Services’ acquisition of South Jersey Energy Company’s natural gas marketing business locatedbusiness.

Financing Activities. Cash flow used by financing activities was $32.6 million in the Mid-Atlantic region. Cash used for acquisitions of businesses and assets in the 20172019 three-month period principally reflects UGI International’s acquisition of UniverGas and Midstream & Marketing’s acquisition of the Texas Creek natural gas gathering assets.

Financing Activities. Cashcompared with cash flow provided by financing activities wasof $134.0 million in the 2018 three-month period compared with $181.1 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;

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€45.8 €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.


UTILITY 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, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged 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, UGI2020, 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, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 million of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas is requestingUtility requested that the new gas rates become effective March 29, 2019.28, 2020. However, the PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for investigation and public hearings. UGI Utilities 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 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.On January 15, 2020,

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, the 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.



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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 December 31, 2018, 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 December 31, 2018,2019, 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 December 31, 2018, 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.


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Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.


The fair value
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Table of unsettled commodity price risk sensitive derivative instruments held at December 31, 2018 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a loss of $14.4 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 $91.2 million at December 31, 2018.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 December 31, 2018,2019, 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 fixesswap 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. UGI Utilities has entered intoloans’ principal balances and all or a forward starting, amortizing, pay-fixed, receive-variable interest rate swap that generally fixessignificant portion of the underlying prevailing market interest rates on its variable-rate term loan at 3.00% beginning September 30, 2019 through July 2022.loans’ tenor. We have designated this forward-startingthese interest rate swapswaps as a cash flow hedge.hedges. At December 31, 2018,2019, combined borrowings outstanding under variable-rate debt agreements, excluding UGI International’sthe previously mentioned effectively fixed-rate debt, totaled $795.1$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 December 31, 2018 (including pay-fixed, receive-variable interest rate swaps) was a loss of $3.7 million. A 50 basis point adverse change in short-term market interest rates would result in a decrease in fair value of approximately $3.2 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 December 31, 2018,2019, 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 addition, 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.

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 December 31, 2018, wascontracts over a gainmulti-year period to eventually equal approximately 90% of $15.6 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 $39.4 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 December 31, 2018,2019, restricted cash in brokerage accounts totaled $17.4$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 December 31, 2018.2019. 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 December 31, 2018,2019, 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
No changeEffective October 1, 2019, the Company adopted ASU 2016-02, “Leases” (Topic 842), which required changes in the Company’s internal control over financial reporting, occurredincluding implementation of new software to track and account for leases.
No changes in the Company’s internal control over financial reporting during the Company’s most recent fiscal quarter that hashave materially affected, or isare 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, which could materially affect our business, financial condition or future results. The risks described in our 20182019 Annual Report are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.


ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


The following table sets forth information with respect to the Company’s repurchases of its common stock during the quarter ended December 31, 2018.2019.
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, 2018 to October 31, 2018 — $0.00 — 7.10 million
November 1, 2018 to November 30, 2018 — $0.00 — 7.10 million
December 1, 2018 to December 31, 2018 300,000 $56.15 300,000 6.80 million
Total 300,000   300,000  
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  
(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
4.1 
Form of Note Purchase Agreement dated December 21, 2018 between the Company and the purchasers listed as signatories thereto.
 Utilities Form 8-K (12/21/18) 4.1
         
4.2 
Indenture, dated as of October 25, 2018, by and among International, the guarantors named therein, U.S. Bank National Association, as trustee, Elavon Financial Services DAC, as registrar and transfer agent, and Elavon Financial Services DAC, UK Branch, as paying agent (including the form of Note).
 UGI Form 8-K (10/25/18) 4.1
         
4.3 
Multicurrency Facilities Agreement, effective October 25, 2018, among International, as borrower, Natixis, as agent, mandated lead arranger, bookrunner and coordinator, Barclays Bank Plc, BNP Paribas, Credit Agricole Corporate and Investment Bank, HSBC France, ING Bank N.V., French Branch, Mediobanca International (Luxembourg) S.A., Raiffeisen Bank International AG and Societe Generale Corporate and Investment Banking, as mandated lead arrangers, and certain other lenders.
 UGI Form 8-K (10/25/18) 4.2
         
10.1 
Form of Change in Control Agreement between UGI Utilities, Inc. and Mr. Robert Beard.
      
         
10.2 
Amendment No. 19, dated as of October 26, 2018, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, and PNC Bank, National Association, as issuer and administrator.
 UGI Form 8-K (10/26/18) 10.1
         
31.1  
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2018, 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, 2018, 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, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
      
         
101.INS  XBRL Instance      
         
101.SCH  XBRL Taxonomy Extension Schema      
         
101.CAL  XBRL Taxonomy Extension Calculation Linkbase      
         
101.DEF  XBRL Taxonomy Extension Definition Linkbase      
         
101.LAB  XBRL Taxonomy Extension Labels Linkbase      
         
101.PRE  XBRL Taxonomy Extension Presentation Linkbase      


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EXHIBIT INDEX
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 
Form ofAmended and Restated Change in Control Agreement, dated December 6, 2019, between UGI Utilities, Inc.Corporation and Mr. Robert Beard.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, 2018,2019, 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, 2018,2019, 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, 2018,2019, 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 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.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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES


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:February 7, 20196, 2020By:/s/ Ted J. Jastrzebski
   Ted J. Jastrzebski
   Chief Financial Officer
    
    
Date:February 7, 20196, 2020By:/s/ Ann P. KellyLaurie A. Bergman
   Ann P. KellyLaurie A. Bergman
   Vice President, Chief Accounting Officer
   and Corporate Controller


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