10-Q 1 ugicorpq3630201810-q.htm 10-Q
Table of Contents

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 June 30, 2018
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, PA |  | 19406
(Address of principal executive offices) |  | (Zip Code)

(610) 337-1000
(Registrant’s telephone number, including area code)
______________________________________
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 filer | ý |  | 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 July 31, 2018, there were 173,861,984 shares of UGI Corporation Common Stock, without par value, outstanding.

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS

| Page
Part I Financial Information |
Item 1. Financial Statements (unaudited) |
Condensed Consolidated Balance Sheets as of June 30, 2018, September 30, 2017 and June 30, 2017 | 1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2018 and 2017 | 2
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2018 and 2017 | 3
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2018 and 2017 | 4
Condensed Consolidated Statements of Changes in Equity for the nine months ended June 30, 2018 and 2017 | 5
Notes to Condensed Consolidated Financial Statements | 6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 34
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 59
Item 4. Controls and Procedures | 61
Part II Other Information |
Item 1A. Risk Factors | 62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 62
Item 6. Exhibits | 63
Signatures | 65

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
ASSETS |  |  |  |  |  |
Current assets: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 506.7 |  |  | $ | 558.4 |  |  | $ | 604.3 |
Restricted cash |  | 7.7 |  |  | 10.3 |  |  | 6.7 |
Accounts receivable (less allowances for doubtful accounts of $43.4, $26.9 and $33.0, respectively) |  | 813.3 |  |  | 626.8 |  |  | 628.2 |
Accrued utility revenues |  | 14.4 |  |  | 13.3 |  |  | 5.9 |
Inventories |  | 253.2 |  |  | 278.6 |  |  | 216.1 |
Utility regulatory assets |  | 2.2 |  |  | 8.3 |  |  | 7.8 |
Derivative instruments |  | 93.7 |  |  | 63.1 |  |  | 13.3 |
Prepaid expenses and other current assets |  | 117.0 |  |  | 138.7 |  |  | 85.0 |
Total current assets |  | 1,808.2 |  |  | 1,697.5 |  |  | 1,567.3 |
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,131.0, $3,312.9 and $3,337.5, respectively) |  | 5,699.1 |  |  | 5,537.0 |  |  | 5,422.1 |
Goodwill |  | 3,169.0 |  |  | 3,107.2 |  |  | 3,032.3 |
Intangible assets, net |  | 529.8 |  |  | 611.7 |  |  | 571.2 |
Utility regulatory assets |  | 357.9 |  |  | 360.6 |  |  | 391.0 |
Derivative instruments |  | 23.1 |  |  | 9.2 |  |  | 3.1 |
Other assets |  | 289.6 |  |  | 259.0 |  |  | 259.4 |
Total assets |  | $ | 11,876.7 |  |  | $ | 11,582.2 |  |  | $ | 11,246.4 |
LIABILITIES AND EQUITY |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Current maturities of long-term debt |  | $ | 86.4 |  |  | $ | 177.5 |  |  | $ | 119.1 |
Short-term borrowings |  | 299.1 |  |  | 366.9 |  |  | 163.9 |
Accounts payable |  | 443.4 |  |  | 439.6 |  |  | 359.0 |
Derivative instruments |  | 12.0 |  |  | 25.0 |  |  | 20.1 |
Other current liabilities |  | 725.4 |  |  | 681.1 |  |  | 617.5 |
Total current liabilities |  | 1,566.3 |  |  | 1,690.1 |  |  | 1,279.6 |
Long-term debt |  | 4,088.6 |  |  | 3,994.6 |  |  | 4,014.6 |
Deferred income taxes |  | 893.7 |  |  | 1,357.0 |  |  | 1,279.8 |
Deferred investment tax credits |  | 2.7 |  |  | 3.0 |  |  | 3.0 |
Derivative instruments |  | 12.3 |  |  | 21.8 |  |  | 15.6 |
Other noncurrent liabilities |  | 1,085.3 |  |  | 774.8 |  |  | 812.7 |
Total liabilities |  | 7,648.9 |  |  | 7,841.3 |  |  | 7,405.3 |
Commitments and contingencies (Note 10) |  |  |  |  |  |
Equity: |  |  |  |  |  |
UGI Corporation stockholders’ equity: |  |  |  |  |  |
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,111,691, 173,987,691 and 173,960,691 shares, respectively) |  | 1,198.5 |  |  | 1,188.6 |  |  | 1,187.8 |
Retained earnings |  | 2,637.2 |  |  | 2,106.7 |  |  | 2,151.9 |
Accumulated other comprehensive loss |  | (111.6 | ) |  | (93.4 | ) |  | (135.9 | )
Treasury stock, at cost |  | (12.8 | ) |  | (38.6 | ) |  | (27.1 | )
Total UGI Corporation stockholders’ equity |  | 3,711.3 |  |  | 3,163.3 |  |  | 3,176.7 |
Noncontrolling interests, principally in AmeriGas Partners |  | 516.5 |  |  | 577.6 |  |  | 664.4 |
Total equity |  | 4,227.8 |  |  | 3,740.9 |  |  | 3,841.1 |
Total liabilities and equity |  | $ | 11,876.7 |  |  | $ | 11,582.2 |  |  | $ | 11,246.4 |

See accompanying notes to condensed consolidated financial statements.
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)

|  | Three Months Ended June 30, |  | Nine Months Ended June 30,
|  | 2018 |  | 2017 |  | 2018 |  | 2017
Revenues |  | $ | 1,440.9 |  |  | $ | 1,153.5 |  |  | $ | 6,378.1 |  |  | $ | 5,006.8 |
Costs and expenses: |  |  |  |  |  |  |  |
Cost of sales (excluding depreciation shown below) |  | 732.5 |  |  | 618.5 |  |  | 3,430.1 |  |  | 2,337.1 |
Operating and administrative expenses |  | 496.1 |  |  | 449.4 |  |  | 1,542.4 |  |  | 1,409.0 |
Impairment of Partnership tradenames and trademarks |  | 75.0 |  |  | — |  |  | 75.0 |  |  | — |
Depreciation |  | 103.9 |  |  | 89.6 |  |  | 297.9 |  |  | 258.1 |
Amortization |  | 14.9 |  |  | 14.5 |  |  | 43.4 |  |  | 43.4 |
Other operating income, net |  | (10.0 | ) |  | (15.7 | ) |  | (20.5 | ) |  | (17.4 | )
|  | 1,412.4 |  |  | 1,156.3 |  |  | 5,368.3 |  |  | 4,030.2 |
Operating income (loss) |  | 28.5 |  |  | (2.8 | ) |  | 1,009.8 |  |  | 976.6 |
Income from equity investees |  | 1.3 |  |  | 0.9 |  |  | 3.0 |  |  | 3.0 |
Loss on extinguishments of debt |  | — |  |  | (4.4 | ) |  | — |  |  | (59.7 | )
Gain (loss) on foreign currency contracts, net |  | 25.6 |  |  | (16.2 | ) |  | 9.8 |  |  | (16.1 | )
Interest expense |  | (56.5 | ) |  | (56.8 | ) |  | (172.8 | ) |  | (168.0 | )
(Loss) income before income taxes |  | (1.1 | ) |  | (79.3 | ) |  | 849.8 |  |  | 735.8 |
Income tax (expense) benefit |  | (10.6 | ) |  | 17.1 |  |  | (19.6 | ) |  | (195.3 | )
Net (loss) income including noncontrolling interests |  | (11.7 | ) |  | (62.2 | ) |  | 830.2 |  |  | 540.5 |
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners |  | 64.1 |  |  | 43.2 |  |  | (135.9 | ) |  | (108.9 | )
Net income (loss) attributable to UGI Corporation |  | $ | 52.4 |  |  | $ | (19.0 | ) |  | $ | 694.3 |  |  | $ | 431.6 |
Earnings (loss) per common share attributable to UGI Corporation stockholders |  |  |  |  |  |  |  |
Basic |  | $ | 0.30 |  |  | $ | (0.11 | ) |  | $ | 4.00 |  |  | $ | 2.49 |
Diluted |  | $ | 0.30 |  |  | $ | (0.11 | ) |  | $ | 3.93 |  |  | $ | 2.44 |
Weighted average common shares outstanding (thousands) |  |  |  |  |  |  |  |
Basic |  | 173,991 |  |  | 173,742 |  |  | 173,744 |  |  | 173,625 |
Diluted |  | 176,807 |  |  | 173,742 |  |  | 176,702 |  |  | 177,125 |
Dividends declared per common share |  | $ | 0.2600 |  |  | $ | 0.2500 |  |  | $ | 0.7600 |  |  | $ | 0.7250 |

See accompanying notes to condensed consolidated financial statements.
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UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Millions of dollars)

|  | Three Months Ended June 30, |  | Nine Months Ended June 30,
|  | 2018 |  | 2017 |  | 2018 |  | 2017
Net (loss) income including noncontrolling interests |  | $ | (11.7 | ) |  | $ | (62.2 | ) |  | $ | 830.2 |  |  | $ | 540.5 |
Other comprehensive income (loss): |  |  |  |  |  |  |  |
Net gains (losses) on derivative instruments (net of tax of $(1.5), $3.4, $(0.6) and $(2.3), respectively) |  | 3.7 |  |  | (6.6 | ) |  | 1.7 |  |  | 5.2 |
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.2), $(0.2), $(1.6) and $4.4, respectively) |  | 0.2 |  |  | (0.2 | ) |  | 2.6 |  |  | (10.1 | )
Foreign currency adjustments |  | (82.0 | ) |  | 75.5 |  |  | (23.8 | ) |  | 22.4 |
Benefit plans (net of tax of $(0.2), $0.0, $(0.5) and $(0.9), respectively) |  | 0.6 |  |  | (0.1 | ) |  | 1.3 |  |  | 1.3 |
Other comprehensive (loss) income |  | (77.5 | ) |  | 68.6 |  |  | (18.2 | ) |  | 18.8 |
Comprehensive (loss) income including noncontrolling interests |  | (89.2 | ) |  | 6.4 |  |  | 812.0 |  |  | 559.3 |
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners |  | 64.1 |  |  | 43.2 |  |  | (135.9 | ) |  | (108.9 | )
Comprehensive (loss) income attributable to UGI Corporation |  | $ | (25.1 | ) |  | $ | 49.6 |  |  | $ | 676.1 |  |  | $ | 450.4 |

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)

|  | Nine Months Ended June 30,
|  | 2018 |  | 2017
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |
Net income including noncontrolling interests |  | $ | 830.2 |  |  | $ | 540.5 |
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |  |  |  |
Depreciation and amortization |  | 341.3 |  |  | 301.5 |
Deferred income tax (benefit) expense |  | (182.5 | ) |  | 46.9 |
Provision for uncollectible accounts |  | 30.9 |  |  | 19.3 |
Change in unrealized gains and losses on derivative instruments |  | (54.0 | ) |  | (28.9 | )
Impairment of Partnership tradenames and trademarks |  | 75.0 |  |  | — |
Loss on extinguishments of debt |  | — |  |  | 59.7 |
Other, net |  | 2.9 |  |  | 37.7 |
Net change in: |  |  |  |
Accounts receivable and accrued utility revenues |  | (202.1 | ) |  | (86.7 | )
Inventories |  | 28.1 |  |  | (4.4 | )
Utility deferred fuel and power costs, net of changes in unsettled derivatives |  | 39.8 |  |  | (12.5 | )
Accounts payable |  | (17.7 | ) |  | 5.1 |
Other current assets |  | (0.5 | ) |  | 3.1 |
Other current liabilities |  | 35.4 |  |  | (35.3 | )
Net cash provided by operating activities |  | 926.8 |  |  | 846.0 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |
Expenditures for property, plant and equipment |  | (394.2 | ) |  | (471.9 | )
Acquisitions of businesses and assets, net of cash acquired |  | (190.7 | ) |  | (52.8 | )
Decrease in restricted cash |  | 2.5 |  |  | 8.9 |
Other, net |  | 9.5 |  |  | (15.9 | )
Net cash used by investing activities |  | (572.9 | ) |  | (531.7 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |
Dividends on UGI Common Stock |  | (131.8 | ) |  | (125.6 | )
Distributions on AmeriGas Partners publicly held Common Units |  | (197.3 | ) |  | (195.8 | )
Issuances of debt, net of issuance costs |  | 124.4 |  |  | 1,307.1 |
Repayments of debt, including redemption premiums |  | (141.3 | ) |  | (1,056.2 | )
Decrease in short-term borrowings |  | (32.0 | ) |  | (132.6 | )
Receivables Facility net (repayments) borrowings |  | (39.0 | ) |  | 4.5 |
Issuances of UGI Common Stock |  | 60.5 |  |  | 11.0 |
Repurchases of UGI Common Stock |  | (43.5 | ) |  | (28.7 | )
Other |  | (2.3 | ) |  | (0.8 | )
Net cash used by financing activities |  | (402.3 | ) |  | (217.1 | )
EFFECT OF EXCHANGE RATE CHANGES ON CASH |  | (3.3 | ) |  | 4.3 |
Cash and cash equivalents (decrease) increase |  | $ | (51.7 | ) |  | $ | 101.5 |
CASH AND CASH EQUIVALENTS |  |  |  |
End of period |  | $ | 506.7 |  |  | $ | 604.3 |
Beginning of period |  | 558.4 |  |  | 502.8 |
(Decrease) increase |  | $ | (51.7 | ) |  | $ | 101.5 |

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)

| Nine Months Ended June 30,
| 2018 |  | 2017
Common stock, without par value |  |  |
Balance, beginning of period | $ | 1,188.6 |  |  | $ | 1,201.6 |
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld | (1.7 | ) |  | (26.4 | )
Equity-based compensation expense | 11.6 |  |  | 11.2 |
Gain on sale of treasury stock | — |  |  | 1.4 |
Balance, end of period | $ | 1,198.5 |  |  | $ | 1,187.8 |
Retained earnings |  |  |
Balance, beginning of period | $ | 2,106.7 |  |  | $ | 1,840.9 |
Cumulative effect of change in accounting for employee share-based payments | — |  |  | 5.0 |
Losses on treasury stock transactions in connection with employee and director plans | (32.0 | ) |  | — |
Net income attributable to UGI Corporation | 694.3 |  |  | 431.6 |
Cash dividends on Common Stock | (131.8 | ) |  | (125.6 | )
Balance, end of period | $ | 2,637.2 |  |  | $ | 2,151.9 |
Accumulated other comprehensive income (loss) |  |  |
Balance, beginning of period | $ | (93.4 | ) |  | $ | (154.7 | )
Net gains on derivative instruments | 1.7 |  |  | 5.2 |
Reclassification of net losses (gains) on derivative instruments | 2.6 |  |  | (10.1 | )
Benefit plans | 1.3 |  |  | 1.3 |
Foreign currency adjustments | (23.8 | ) |  | 22.4 |
Balance, end of period | $ | (111.6 | ) |  | $ | (135.9 | )
Treasury stock |  |  |
Balance, beginning of period | $ | (38.6 | ) |  | $ | (36.9 | )
Common stock issued in connection with employee and director plans, net of tax withheld | 75.4 |  |  | 44.7 |
Repurchases of Common Stock | (43.5 | ) |  | (28.7 | )
Reacquired common stock — employee and director plans | (6.1 | ) |  | (6.4 | )
Sale of treasury stock | — |  |  | 0.2 |
Balance, end of period | $ | (12.8 | ) |  | $ | (27.1 | )
Total UGI Corporation stockholders’ equity | $ | 3,711.3 |  |  | $ | 3,176.7 |
Noncontrolling interests |  |  |
Balance, beginning of period | $ | 577.6 |  |  | $ | 750.9 |
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | 135.9 |  |  | 108.9 |
Dividends and distributions | (197.5 | ) |  | (195.8 | )
Other | 0.5 |  |  | 0.4 |
Balance, end of period | $ | 516.5 |  |  | $ | 664.4 |
Total equity | $ | 4,227.8 |  |  | $ | 3,841.1 |

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 Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”) and market energy products and services. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary, AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At June 30, 2018, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.0% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 14 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2017 (the “Company’s 2017 Annual Report”). Incentive distributions received by the General Partner during the nine months ended June 30, 2018 and 2017 were $34.0 and $32.2, respectively.
Our wholly owned subsidiary, UGI Enterprises, LLC (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business throughout much of Europe, (2) a natural gas marketing business in France, Belgium and the United Kingdom, and (3) a natural gas and electricity marketing business in the Netherlands. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH (“Flaga”), AvantiGas Limited, UniverGas Italia S.r.l. (“UniverGas”) and DVEP Investeringen B.V. (“DVEP”). We refer to our foreign operations collectively as “UGI International.”
UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.”
UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission (“MD PSC”). Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.
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 U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider
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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)
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, 2017, condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”).
These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2017 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.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:

|  | Three Months Ended June 30, |  | Nine Months Ended June 30,
|  | 2018 |  | 2017 |  | 2018 |  | 2017
Denominator (thousands of shares): |  |  |  |  |  |  |  |
Weighted-average common shares outstanding — basic |  | 173,991 |  |  | 173,742 |  |  | 173,744 |  |  | 173,625 |
Incremental shares issuable for stock options and awards (a) |  | 2,816 |  |  | — |  |  | 2,958 |  |  | 3,500 |
Weighted-average common shares outstanding — diluted |  | 176,807 |  |  | 173,742 |  |  | 176,702 |  |  | 177,125 |

(a) | For the three months ended June 30, 2018 and the nine months ended June 30, 2018 and 2017, there were no shares associated with outstanding stock option awards that were excluded in the computation of diluted earnings per share above because their effect was antidilutive. For the three months ended June 30, 2017, incremental shares of 3,556 have been excluded due to the net loss for the period.

Derivative Instruments. Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the normal purchase and normal sale (“NPNS”) exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it qualifies and is designated as a hedge for accounting purposes.
Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“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. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. 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 AOCI until such foreign net investment is sold or liquidated.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Gain (loss) on foreign currency contracts, 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.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
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 13.
Intangible Assets. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. In April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years. As a result, during the three months ended June 30, 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and, in accordance with GAAP associated with intangible assets, adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values. For further information, see Notes 6 and 12.
Impairment of Cost Basis Investments. We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. During the second quarter of Fiscal 2017, we recorded a pre-tax loss of $7.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “Other operating income, net” on the Condensed Consolidated Statements of Income.
Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.
See Note 5 for discussions regarding the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”) in the U.S. and changes in French tax laws.
Use of Estimates. The preparation of financial statements 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 prior period amounts have been reclassified to conform to the current-period presentation.
Note 3 — Accounting Changes
Accounting Standards Not Yet Adopted
Other Comprehensive Income. In February 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 TCJA may be reclassified to retained earnings, at the election of the entity, in the period of adoption. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but does not expect its adoption will have a material impact on its consolidated financial statements.
Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
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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)
Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of 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, however, 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 amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. We will adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but does not expect its adoption will have a material impact on its consolidated financial statements.
Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. The ASU is effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but does not expect its adoption will have a material impact on its consolidated financial statements.
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. In July 2018, the FASB issued ASU No. 2018-11, “Leases: Targeted Improvements.” Among other things, this ASU 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 rather than the earliest period presented in the financial statements. We currently expect to adopt ASU No. 2016-02, as updated, effective October 1, 2019. The Company has not yet selected a transition method and is currently in the process of assessing the impact on its financial statements from the adoption of ASU No. 2016-02 but anticipates an increase in the recognition of right-of-use assets and lease liabilities.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.
The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements.
The Company anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 4 — Inventories
Inventories comprise the following:

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Non-utility LPG and natural gas |  | $ | 177.0 |  |  | $ | 188.4 |  |  | $ | 135.4 |
Gas Utility natural gas |  | 18.6 |  |  | 39.5 |  |  | 21.8 |
Materials, supplies and other |  | 57.6 |  |  | 50.7 |  |  | 58.9 |
Total inventories |  | $ | 253.2 |  |  | $ | 278.6 |  |  | $ | 216.1 |

At June 30, 2018, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
As of June 30, 2018, UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at June 30, 2018, September 30, 2017 and June 30, 2017, comprising 1.2 billion cubic feet (“bcf”), 2.3 bcf and 1.1 bcf of natural gas, was $2.7, $6.7, and $3.5, respectively.
Note 5 — Income Tax Reform
U.S. Tax Reform
On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, 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. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities and applies a broader application of compensation limitations.
In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and nine months ended June 30, 2018, contain provisional estimates of the impact of the TCJA. Provisional amounts recorded in the quarter ended December 31, 2017, were adjusted in the quarters ended March 31, 2018 and June 30, 2018 to reflect the effects of items finalized by the filing of tax returns or by changes in estimates and judgments. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 118, we will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by SAB No. 118, these adjustments may occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment.
As a result of the TCJA, during the three and nine months ended June 30, 2018, we reduced our net deferred income tax liabilities by $0.8 and $389.6, respectively, due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment of the TCJA on December 22, 2017, and as a result of adjusting prior provisional amounts during the quarter ended June 30, 2018. Because part of the reduction to our net deferred income taxes relates to UGI Utilities’ regulated utility plant assets, as further described below, most of UGI Utilities’ reduction in deferred income taxes is not being recognized immediately in income tax expense.
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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)
Discrete deferred income tax adjustments recorded during the three and nine months ended June 30, 2018, which reduced (increased) income tax expense consisted primarily of the following items:

|  | Provisional amounts - Six months ended March 31, 2018 |  | Changes to provisional amounts - Three months ended June 30, 2018 |  | Provisional amounts - Nine months ended June 30, 2018
Reduction in net deferred tax liabilities in the U.S. from the reduction of the U.S. tax rate |  | $ | 180.3 |  |  | $ | 0.8 |  |  | $ | 181.1 |
Establishment of valuation allowances related to deferred tax assets impacted by TCJA |  | (7.6 | ) |  | — |  |  | (7.6 | )
Toll-tax on un-repatriated earnings |  | (1.4 | ) |  | — |  |  | (1.4 | )
Total discrete deferred income tax adjustments |  | $ | 171.3 |  |  | $ | 0.8 |  |  | $ | 172.1 |
Impact on earnings per share: |  |  |  |  |  |
Basic earnings per share |  | $ | 0.99 |  |  | $ | — |  |  | $ | 0.99 |
Diluted earnings per share |  | $ | 0.97 |  |  | $ | — |  |  | $ | 0.97 |

In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. As a result of the TCJA, in December 2017, UGI Utilities recorded a regulatory liability of $216.1 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $87.8 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 7.
For the three and nine months ended June 30, 2018, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21%. As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on the 24.5% blended rate for Fiscal 2018. For the three and nine months ended June 30, 2018, the effects of the tax law changes on current-period results (excluding the one-time impacts described above) decreased income tax expense by approximately $6.1 and $60.6, respectively.
As further described in Note 7, on May 17, 2018, the PUC issued a Temporary Rates Order for all PUC-regulated utilities with regard to federal tax reform. Among other things, the Temporary Rates Order requires Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the change in the federal income tax rate from 35% to 21%. During the three months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $22.7 (which is in addition to a $1.4 reduction previously recorded in March 2018), and recorded a regulatory liability in an equal amount. The total reduction in revenues for the nine months ended June 30, 2018 of $24.1 reflects (1) $17.1 of tax benefits accrued during the period January 1, 2018 to June 30, 2018, plus (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability.
Changes in French Corporate Income Tax Rates
In December 2017, the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the December 2017 French Finance Bills, 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 to reflect the estimated impact of the previously mentioned corporate income tax rate reduction effective in Fiscal 2023. During the three months ended March 31, 2018 and June 30, 2018, this estimated deferred income tax benefit was reduced by $3.7 and $0.1, respectively, to 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)
benefit of $13.5 (equal to $0.08 per basic and diluted share) for the nine months ended June 30, 2018. In addition, the Company’s estimated annual effective income tax rate used in determining income taxes for the nine months ended June 30, 2018, reflects the impact of the higher Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills, which (decreased) increased income tax expense for the three and nine months ended June 30, 2018, by approximately $(0.2) and $4.7, respectively.
In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively, the “December 2016 French Finance Bills”). The December 2016 French Finance Bills, among other things, will reduce UGI France’s corporate income tax rate from the then-current 34.4% to 28.9%, effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of this future income tax rate reduction, during the three months ended December 31, 2016, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $27.4 (equal to $0.15 per basic and diluted share).
Note 6 — Goodwill and Intangible Assets
Goodwill and intangible assets comprise the following:

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Goodwill (not subject to amortization) |  | $ | 3,169.0 |  |  | $ | 3,107.2 |  |  | $ | 3,032.3 |
Intangible assets: |  |  |  |  |  |
Customer relationships, noncompete agreements and other |  | $ | 852.5 |  |  | $ | 817.8 |  |  | $ | 801.6 |
Trademarks and tradenames |  | 7.9 |  |  | — |  |  | — |
Accumulated amortization |  | (381.2 | ) |  | (340.2 | ) |  | (362.8 | )
Intangible assets, net (definite-lived) |  | 479.2 |  |  | 477.6 |  |  | 438.8 |
Trademarks and tradenames (indefinite-lived) |  | 50.6 |  |  | 134.1 |  |  | 132.4 |
Total intangible assets, net |  | $ | 529.8 |  |  | $ | 611.7 |  |  | $ | 571.2 |

The changes in goodwill and intangible assets are primarily due to acquisitions, an impairment of Partnership tradenames and trademarks (see below) and the effects of foreign currency translation. Amortization expense of intangible assets was $14.9 and $12.6 for the three months ended June 30, 2018 and 2017, respectively. Amortization expense of intangible assets was $43.4 and $37.5 for the nine months ended June 30, 2018 and 2017, 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 2018 and for the next four fiscal years is as follows: remainder of Fiscal 2018 — $14.7; Fiscal 2019 — $57.2; Fiscal 2020 — $55.8; Fiscal 2021 — $52.5; Fiscal 2022 — $49.5.
In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with its January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over a period of approximately three years. As a result, during the three months ended June 30, 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and, in accordance with GAAP associated with intangible assets, adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9. During the three months ended June 30, 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Condensed Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. See Note 12 for further information on the determination of fair values for the affected tradenames and trademarks.
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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 7 — 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 2017 Annual Report. Other than removal costs, UGI Utilities currently 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:

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Regulatory assets: |  |  |  |  |  |
Income taxes recoverable |  | $ | 130.0 |  |  | $ | 121.4 |  |  | $ | 122.7 |
Underfunded pension and postretirement plans |  | 132.2 |  |  | 141.3 |  |  | 171.8 |
Environmental costs |  | 59.8 |  |  | 61.6 |  |  | 61.6 |
Deferred fuel and power costs |  | 0.2 |  |  | 7.7 |  |  | 7.0 |
Removal costs, net |  | 31.0 |  |  | 31.0 |  |  | 29.4 |
Other |  | 6.9 |  |  | 5.9 |  |  | 6.3 |
Total regulatory assets |  | $ | 360.1 |  |  | $ | 368.9 |  |  | $ | 398.8 |
Regulatory liabilities (a): |  |  |  |  |  |
Postretirement benefits |  | $ | 16.9 |  |  | $ | 17.5 |  |  | $ | 16.7 |
Deferred fuel and power refunds |  | 44.5 |  |  | 10.6 |  |  | 12.6 |
State tax benefits — distribution system repairs |  | 20.7 |  |  | 18.4 |  |  | 16.7 |
PUC Temporary Rates Order (b) |  | 24.1 |  |  | — |  |  | — |
Excess federal deferred income taxes (c) |  | 301.2 |  |  | — |  |  | — |
Other |  | 5.1 |  |  | 2.7 |  |  | 2.7 |
Total regulatory liabilities |  | $ | 412.5 |  |  | $ | 49.2 |  |  | $ | 48.7 |

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

(b) | Balance at June 30, 2018, comprises tax savings for the period January 1, 2018 to June 30, 2018 resulting from the enactment of the TCJA (see “PUC Temporary Rates Order” below and Note 5).

(c) | Balance at June 30, 2018, comprises excess federal deferred income taxes resulting from the enactment of the TCJA (see “Excess federal deferred income taxes” below and Note 5).

Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.
Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2018, September 30, 2017 and June 30, 2017 were $1.9, $0.1 and $(0.1), respectively.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility, from time to time, obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2017 and June 30, 2017, were not material. There were no open FTR positions as of June 30, 2018.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
PUC Temporary Rates Order. By Secretarial Letter dated January 12, 2018, the PUC initiated a review into whether public utility rates should be adjusted to reflect the tax savings from the change in the federal income tax rate from 35% to 21% for the period beginning January 1, 2018. Thereafter, on March 15, 2018, the PUC entered a Temporary Rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of no more than 12 months while the PUC reviewed the data and comments in response to the Secretarial Letter.
On May 17, 2018, the PUC 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. 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 UGI Gas, PNG and CPG, such negative surcharge will reduce base rate revenues by 5.78%, 3.90% and 8.19%, respectively.
In its May 17, 2018 Order, the PUC 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. For UGI Gas, PNG and CPG, during the three months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $22.7 (which is in addition to a $1.4 reduction previously recorded in March 2018), and recorded a regulatory liability in an equal amount. The total reduction in revenues for the nine months ended June 30, 2018 reflects (1) $17.1 of tax benefits accrued during the previously mentioned six-month period plus (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability. The rate treatment of this regulatory liability, including accrued interest, for each of UGI Gas, PNG and CPG will be addressed in a future proceeding. Like other similarly situated utilities, if UGI Gas, PNG or CPG have not filed a general base rate proceeding within three years of the Temporary Rates Order, UGI Gas, PNG and CPG will be required to file a petition to propose how to distribute the balance of these regulatory liabilities.
For Pennsylvania utilities currently in a general base rate proceeding, including Electric Utility, no negative surcharge will apply, and such tax benefits will be handled through that proceeding, including the benefits that accrue during the period beginning January 1, 2018 until the effective date of new base rates established in the proceeding. At June 30, 2018, such amount for Electric Utility was not material.
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 5). 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 will be amortized and credited to tax expense.
Other Regulatory Matters
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9.2, which was later reduced by the Company to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March 27, 2018. The PUC entered an Order dated March 1, 2018, suspending the effective date for the rate increase to allow for investigation and public hearings in a review process that is expected to last up to nine months from the date of filing. The matter is currently pending before two PUC administrative law judges who are expected to issue a recommended decision that will be the subject of a final decision by the PUC. Although the Company expects to receive a final decision from the PUC in October 2018, the Company cannot predict the timing or the ultimate outcome of the rate case review process.
On August 31, 2017, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 annual base distribution rate increase for PNG. The increase became effective on October 20, 2017.
On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.
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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)
Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-Term Infrastructure Improvement Plan filing. PNG’s DSIC has been reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate case.
In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018, for the amount of DSIC-eligible plant placed into service as it exceeded the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case during the third quarter of Fiscal 2018.
Utilities Merger Request. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PUC and MD PSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. There are no expected changes to annual base distribution rates for the combined utilities or to existing regulatory assets and liabilities as a result of the proposed merger. On July 20, 2018, UGI Utilities filed a Joint Petition for Settlement among the parties to the proceeding for approval by two administrative law judges by recommended decision that will be the subject of a final decision by the PUC. On July 25, 2018 the MD PSC issued an order approving UGI Utilities’ merger request. UGI Utilities cannot predict the timing or the ultimate outcome of the PUC review of the merger request. On August 3, 2018, FERC approved requests made by CPG, PNG, and UGI Utilities in May 2018 relating to the transfer of certain FERC authorizations from PNG and CPG to UGI Utilities, to ensure continuity of certain interstate gas transportation services currently conducted by CPG and PNG after the effective date of the proposed merger. With the receipt of these FERC approvals, the approval of an application to transfer CPG’s service territory designation to UGI Utilities remains the only FERC approval yet to be received in connection with the proposed merger.
Note 8 — Energy Services Accounts Receivable Securitization Facility
Energy Services, LLC has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April and up to $75 of eligible receivables during the period May to October. Energy Services, LLC uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services, LLC transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time, sell an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on Energy Services, LLC’s balance sheet and Energy Services, LLC reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services, LLC continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three and nine months ended June 30, 2018 and 2017, which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material.
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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)
Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the nine months ended June 30, 2018 and 2017, as well as the balance of ESFC trade receivables at June 30, 2018, September 30, 2017 and June 30, 2017, is as follows:

|  | Nine Months Ended June 30,
|  | 2018 |  | 2017
Trade receivables transferred to ESFC during the period |  | $ | 1,051.7 |  |  | $ | 848.3 |
ESFC trade receivables sold to the bank during the period |  | $ | 176.0 |  |  | $ | 186.0 |

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
ESFC trade receivables — end of period (a) |  | $ | 58.3 |  |  | $ | 44.8 |  |  | $ | 51.6 |

(a) | At June 30, 2018, there were no ESFC trade receivables sold to the bank. At September 30, 2017 and June 30, 2017, the amounts of ESFC trade receivables sold to the bank were $39.0 and $30.0, respectively. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets.

Note 9 — Debt
AmeriGas Propane. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%. The aforementioned margins on borrowings are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Credit Agreement).
During the three and nine months ended June 30, 2017, the Partnership recognized pre-tax losses of $4.4 and $59.7, respectively, in connection with early repayments of AmeriGas Partners’ 7.00% Senior Notes. These losses are reflected in “Loss on extinguishments of debt” on the Condensed Consolidated Statements of Income.
UGI International. In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "UGI International Credit Agreement") with a group of banks providing for borrowings up to €300. The UGI International Credit Agreement is scheduled to expire in April 2020. Under the UGI International Credit 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 1.45% to 2.35%. Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon certain indebtedness at UGI International, LLC. The UGI International Credit Agreement requires UGI International, LLC not to exceed a ratio of total net indebtedness to EBITDA, as defined, of 3.50 to 1.00.
Also in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amends and restates the previous agreement to provide for a principal balance of $49.9 and extends the maturity of the term loan to April 2020 (“Flaga U.S. Dollar Term Loan”). The outstanding principal bears interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank. Because a portion of the cash flows related to the Flaga U.S. Dollar Term Loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Condensed Consolidated Statement of Cash Flows.
UGI Utilities. In October 2017, UGI Utilities entered into a $125 unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings
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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)
and for general corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6 commencing March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities Term Loan requires that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.
Note 10 — 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 (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the 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 (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20-day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one-for-one basis.
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 manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.
Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5, $1.8, and $1.1, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are currently scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At June 30, 2018, September 30, 2017 and June 30, 2017, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $52.2, $54.3 and $55.2, respectively. UGI Utilities, CPG and
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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)
PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that, under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At June 30, 2018, September 30, 2017 and June 30, 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.
AmeriGas Propane
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that the DEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the DEC disclosed contamination related to a former MGP. At that time, AmeriGas OLP reviewed the study and researched the history of the site, including the extent of AmeriGas OLP’s ownership. In its written response to the DEC in early 2009, AmeriGas OLP disputed DEC’s contention it was a potentially responsible party (“PRP”) as it did not operate the MGP and appeared to only own a portion of the site. The DEC did not respond to the 2009 communication. In March 2017, the DEC communicated to AmeriGas OLP that the DEC had previously issued three Records of Decision (“RODs”) related to remediation of the site and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing its challenge to designation as a PRP and identifying potential defenses. In October 2017, the DEC identified a third party PRP with respect to the site. The DEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information, the Partnership accrued an environmental remediation liability of $7.5 related to the site during the third quarter of Fiscal 2017. 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 Division of the United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers. In June 2017, the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) ruled en banc to reverse the dismissal by the District Court, which had previously been affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. The petition was denied in January 2018 and, as a result, the case was transferred back to the District Court for further proceedings.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
In July 2015, the District Court also dismissed all claims brought by the indirect customers other than claims for injunctive relief. The indirect customers filed an amended complaint with the District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect customers appealed this decision to the Eighth Circuit. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal then pending in the Eighth Circuit. In June 2018, the Eighth Circuit issued its decision affirming the District Court’s decision dismissing the federal antitrust claims, and remanded the case back to the District Court for further proceedings related to the state law claims.
We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them.
In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.
Note 11 — Defined Benefit Pension and Other Postretirement Plans
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, employees of UGI France SAS and its subsidiaries are covered by certain defined benefit pension and postretirement plans.
Net periodic pension expense and other postretirement benefit costs include the following components:

|  | Pension Benefits |  | Other Postretirement Benefits
Three Months Ended June 30, |  | 2018 |  | 2017 |  | 2018 |  | 2017
Service cost |  | $ | 2.8 |  |  | $ | 3.0 |  |  | $ | 0.2 |  |  | $ | 0.3 |
Interest cost |  | 6.5 |  |  | 6.2 |  |  | 0.3 |  |  | 0.2 |
Expected return on assets |  | (8.7 | ) |  | (8.4 | ) |  | (0.2 | ) |  | (0.2 | )
Amortization of: |  |  |  |  |  |  |  |
Prior service cost (benefit) |  | — |  |  | 0.1 |  |  | — |  |  | (0.2 | )
Actuarial loss |  | 3.4 |  |  | 4.2 |  |  | — |  |  | 0.1 |
Net benefit cost |  | 4.0 |  |  | 5.1 |  |  | 0.3 |  |  | 0.2 |
Change in associated regulatory liabilities |  | — |  |  | — |  |  | (0.1 | ) |  | (0.1 | )
Net benefit cost after change in regulatory liabilities |  | $ | 4.0 |  |  | $ | 5.1 |  |  | $ | 0.2 |  |  | $ | 0.1 |
|  | Pension Benefits |  | Other Postretirement Benefits
Nine Months Ended June 30, |  | 2018 |  | 2017 |  | 2018 |  | 2017
Service cost |  | $ | 8.4 |  |  | $ | 9.0 |  |  | $ | 0.6 |  |  | $ | 0.7 |
Interest cost |  | 19.5 |  |  | 18.5 |  |  | 0.7 |  |  | 0.6 |
Expected return on assets |  | (25.9 | ) |  | (25.0 | ) |  | (0.6 | ) |  | (0.5 | )
Amortization of: |  |  |  |  |  |  |  |
Prior service cost (benefit) |  | 0.2 |  |  | 0.2 |  |  | (0.2 | ) |  | (0.5 | )
Actuarial loss |  | 10.0 |  |  | 12.5 |  |  | — |  |  | 0.2 |
Net benefit cost |  | 12.2 |  |  | 15.2 |  |  | 0.5 |  |  | 0.5 |
Change in associated regulatory liabilities |  | — |  |  | — |  |  | (0.4 | ) |  | (0.4 | )
Net benefit cost after change in regulatory liabilities |  | $ | 12.2 |  |  | $ | 15.2 |  |  | $ | 0.1 |  |  | $ | 0.1 |

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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)
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 nine months ended June 30, 2018 and 2017, the Company made cash contributions to the U.S. Pension Plan of $10.1 and $8.5, respectively. The Company expects to make additional cash contributions of approximately $5.0 to the U.S. Pension Plan during the remainder of Fiscal 2018.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any. The difference between such cash deposits or expense recorded and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the nine months ended June 30, 2018 and 2017.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three and nine months ended June 30, 2018 and 2017, were not material.
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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 12 — 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 June 30, 2018, September 30, 2017 and June 30, 2017:

|  | Asset (Liability)
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total
June 30, 2018: |  |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | 58.5 |  |  | $ | 70.0 |  |  | $ | — |  |  | $ | 128.5 |
Foreign currency contracts |  | $ | — |  |  | $ | 18.4 |  |  | $ | — |  |  | $ | 18.4 |
Cross-currency contracts |  | $ | — |  |  | $ | 0.7 |  |  | $ | — |  |  | $ | 0.7 |
Liabilities: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | (25.3 | ) |  | $ | (8.9 | ) |  | $ | — |  |  | $ | (34.2 | )
Foreign currency contracts |  | $ | — |  |  | $ | (17.9 | ) |  | $ | — |  |  | $ | (17.9 | )
Interest rate contracts |  | $ | — |  |  | $ | (1.5 | ) |  | $ | — |  |  | $ | (1.5 | )
Non-qualified supplemental postretirement grantor trust investments (a) |  | $ | 38.4 |  |  | $ | — |  |  | $ | — |  |  | $ | 38.4 |
September 30, 2017: |  |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | 27.2 |  |  | $ | 76.9 |  |  | $ | — |  |  | $ | 104.1 |
Foreign currency contracts |  | $ | — |  |  | $ | 12.2 |  |  | $ | — |  |  | $ | 12.2 |
Liabilities: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | (27.7 | ) |  | $ | (11.4 | ) |  | $ | — |  |  | $ | (39.1 | )
Foreign currency contracts |  | $ | — |  |  | $ | (38.2 | ) |  | $ | — |  |  | $ | (38.2 | )
Interest rate contracts |  | $ | — |  |  | $ | (2.3 | ) |  | $ | — |  |  | $ | (2.3 | )
Cross-currency contracts |  | $ | — |  |  | $ | (2.9 | ) |  | $ | — |  |  | $ | (2.9 | )
Non-qualified supplemental postretirement grantor trust investments (a) |  | $ | 35.6 |  |  | $ | — |  |  | $ | — |  |  | $ | 35.6 |
June 30, 2017: |  |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | 29.3 |  |  | $ | 10.5 |  |  | $ | — |  |  | $ | 39.8 |
Foreign currency contracts |  | $ | — |  |  | $ | 11.3 |  |  | $ | — |  |  | $ | 11.3 |
Liabilities: |  |  |  |  |  |  |  |
Commodity contracts |  | $ | (25.6 | ) |  | $ | (17.3 | ) |  | $ | — |  |  | $ | (42.9 | )
Foreign currency contracts |  | $ | — |  |  | $ | (24.3 | ) |  | $ | — |  |  | $ | (24.3 | )
Interest rate contracts |  | $ | — |  |  | $ | (2.2 | ) |  | $ | — |  |  | $ | (2.2 | )
Cross-currency contracts |  | $ | — |  |  | $ | (0.9 | ) |  | $ | — |  |  | $ | (0.9 | )
Non-qualified supplemental postretirement grantor trust investments (a) |  | $ | 35.8 |  |  | $ | — |  |  | $ | — |  |  | $ | 35.8 |

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

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
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Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.
Nonrecurring Fair Value Measurements
As discussed in Note 6, in April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years. This action required the Partnership to remeasure the fair values of these tradenames and trademarks based upon their remaining period of benefit. The Partnership used the relief from royalty method to estimate the fair values of the tradenames and trademarks, which method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions reflect current economic conditions, management expectations and projected future cash flows expected to be generated from these tradenames and trademarks. The Partnership has determined that the lowest level of the input that is significant to the fair value measurement are unobservable inputs that fall within Level 3 of the fair value hierarchy. As of the April 2018 measurement date, these tradenames and trademarks had an estimated fair value of $7.9.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at June 30, 2018, September 30, 2017 and June 30, 2017 were as follows:

| June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Carrying amount | $ | 4,210.9 |  |  | $ | 4,211.9 |  |  | $ | 4,175.3 |
Estimated fair value | $ | 4,143.1 |  |  | $ | 4,346.8 |  |  | $ | 4,267.0 |

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 13. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value. See Note 2 for additional information on this cost method investment.
Note 13 — 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.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Commodity Price Risk
Regulated Utility Operations
Natural Gas
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. 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 7).
Electricity
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2018, September 30, 2017 and June 30, 2017, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 7).
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, certain other domestic businesses and our UGI International operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership, from time to time, enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, 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 natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.
Electricity
In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
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
UGI France SAS’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on their variable-rate term loans.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for interest rate swaps and IRPAs as cash flow hedges.
At June 30, 2018, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.
Foreign Currency Exchange Rate Risk
Forward Foreign Currency Exchange Contracts
In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At June 30, 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 $0.5.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Gain (loss) on foreign currency contracts, net” on the Condensed Consolidated Statements of Income.
From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. At June 30, 2018, September 30, 2017 and June 30, 2017, there were no unsettled net investment hedges outstanding.
Cross-currency Swaps
From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges.
At June 30, 2018, the amount of net gains associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material.
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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)
Quantitative Disclosures Related to Derivative Instruments
The following table summarizes, by derivative type, the gross notional amounts related to open derivative contracts as of June 30, 2018, September 30, 2017 and June 30, 2017, and the final settlement date of the Company's open derivative transactions as of June 30, 2018, excluding those derivatives that qualified for the NPNS exception:

|  |  |  |  |  | Notional Amounts (in millions)
Type |  | Units |  | Settlements Extending Through |  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Commodity Price Risk: |  |  |  |  |  |  |  |  |  |
Regulated Utility Operations |  |  |  |  |  |  |  |  |  |
Gas Utility NYMEX natural gas futures and option contracts |  | Dekatherms |  | October 2019 |  | 16.8 |  |  | 14.8 |  |  | 12.7 |
FTRs contracts |  | Kilowatt hours |  | N/A |  | — |  |  | 101.2 |  |  | 139.4 |
Non-utility Operations |  |  |  |  |  |  |  |  |  |
LPG swaps & options |  | Gallons |  | July 2020 |  | 339.7 |  |  | 325.5 |  |  | 284.9 |
Natural gas futures, forward and pipeline contracts (a) |  | Dekatherms |  | October 2022 |  | 139.6 |  |  | 75.9 |  |  | 55.5 |
Natural gas basis swap contracts |  | Dekatherms |  | March 2022 |  | 64.1 |  |  | 104.2 |  |  | 113.2 |
NYMEX natural gas storage |  | Dekatherms |  | May 2019 |  | 1.4 |  |  | 1.9 |  |  | 1.6 |
NYMEX propane storage |  | Gallons |  | March 2019 |  | 1.1 |  |  | 0.3 |  |  | 0.3 |
Electricity long forward and futures contracts (a) |  | Kilowatt hours |  | January 2022 |  | 4,283.0 |  |  | 4,440.3 |  |  | 686.3 |
Electricity short forward and futures contracts |  | Kilowatt hours |  | September 2021 |  | 424.2 |  |  | 447.0 |  |  | 471.4 |
Interest Rate Risk: |  |  |  |  |  |  |  |  |  |
Interest rate swaps |  | Euro |  | October 2020 |  | € | 585.8 |  |  | € | 645.8 |  |  | € | 645.8 |
Foreign Currency Exchange Rate Risk: |  |  |  |  |  |  |  |  |  |
Forward foreign currency exchange contracts |  | USD |  | September 2021 |  | $ | 492.7 |  |  | $ | 424.8 |  |  | $ | 467.4 |
Cross-currency contracts |  | USD |  | April 2020 |  | $ | 49.9 |  |  | $ | 59.1 |  |  | $ | 59.1 |

(a) | Amounts at June 30, 2018 and September 30, 2017, include derivative contracts held by DVEP which was acquired on August 31, 2017.

Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2018, September 30, 2017 and June 30, 2017, restricted cash in brokerage accounts totaled $7.7, $10.3 and $6.7, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at June 30, 2018. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2018, 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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
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 June 30, 2018, September 30, 2017 and June 30, 2017:

|  | June 30, 2018 |  | September 30, 2017 |  | June 30, 2017
Derivative assets: |  |  |  |  |  |
Derivatives designated as hedging instruments: |  |  |  |  |  |
Foreign currency contracts |  | $ | 1.1 |  |  | $ | 3.2 |  |  | $ | 5.2 |
Cross-currency contracts |  | 0.7 |  |  | — |  |  | — |
|  | 1.8 |  |  | 3.2 |  |  | 5.2 |
Derivatives subject to PGC and DS mechanisms: |  |  |  |  |  |
Commodity contracts |  | 2.0 |  |  | 1.7 |  |  | 1.2 |
Derivatives not designated as hedging instruments: |  |  |  |  |  |
Commodity contracts |  | 126.5 |  |  | 102.4 |  |  | 38.6 |
Foreign currency contracts |  | 17.3 |  |  | 9.0 |  |  | 6.1 |
|  | 143.8 |  |  | 111.4 |  |  | 44.7 |
Total derivative assets — gross |  | 147.6 |  |  | 116.3 |  |  | 51.1 |
Gross amounts offset in the balance sheet |  | (29.3 | ) |  | (35.7 | ) |  | (34.6 | )
Cash collateral received |  | (1.5 | ) |  | (8.3 | ) |  | (0.1 | )
Total derivative assets — net |  | $ | 116.8 |  |  | $ | 72.3 |  |  | $ | 16.4 |
Derivative liabilities: |  |  |  |  |  |
Derivatives designated as hedging instruments: |  |  |  |  |  |
Foreign currency contracts |  | $ | (0.8 | ) |  | $ | (5.5 | ) |  | $ | (2.1 | )
Cross-currency contracts |  | — |  |  | (2.9 | ) |  | (0.9 | )
Interest rate contracts |  | (1.5 | ) |  | (2.3 | ) |  | (2.2 | )
|  | (2.3 | ) |  | (10.7 | ) |  | (5.2 | )
Derivatives subject to PGC and DS mechanisms: |  |  |  |  |  |
Commodity contracts |  | (0.1 | ) |  | (1.5 | ) |  | (1.2 | )
Derivatives not designated as hedging instruments: |  |  |  |  |  |
Commodity contracts |  | (34.1 | ) |  | (37.6 | ) |  | (41.7 | )
Foreign currency contracts |  | (17.1 | ) |  | (32.7 | ) |  | (22.2 | )
|  | (51.2 | ) |  | (70.3 | ) |  | (63.9 | )
Total derivative liabilities — gross |  | (53.6 | ) |  | (82.5 | ) |  | (70.3 | )
Gross amounts offset in the balance sheet |  | 29.3 |  |  | 35.7 |  |  | 34.6 |
Total derivative liabilities — net |  | $ | (24.3 | ) |  | $ | (46.8 | ) |  | $ | (35.7 | )

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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)
Effect of Derivative Instruments
The following tables provide information on the effects of derivative instruments on the condensed consolidated statements of income and changes in AOCI for the three and nine months ended June 30, 2018 and 2017:

Three Months Ended June 30,: |  |  |  |  |  |  |  |  |  |
|  | Gain (Loss) Recognized in AOCI |  | Gain (Loss) Reclassified from AOCI into Income |  | Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges: |  | 2018 |  | 2017 |  | 2018 |  | 2017 |
Foreign currency contracts |  | $ | 3.9 |  |  | $ | (10.2 | ) |  | $ | — |  |  | $ | 0.8 |  |  | Cost of sales
Cross-currency contracts |  | 0.5 |  |  | 0.3 |  |  | 0.3 |  |  | 0.1 |  |  | Interest expense/other operating income, net
Interest rate contracts |  | 0.8 |  |  | (0.1 | ) |  | (0.7 | ) |  | (0.9 | ) |  | Interest expense
Total |  | $ | 5.2 |  |  | $ | (10.0 | ) |  | $ | (0.4 | ) |  | $ | — |  |  |
|  | Gain (Loss) Recognized in Income |  | Location of Gain (Loss) Recognized in Income |  |
Derivatives Not Designated as Hedging Instruments: |  | 2018 |  | 2017 |  |  |
Commodity contracts |  | $ | 80.9 |  |  | $ | (25.2 | ) |  | Cost of sales |  |
Commodity contracts |  | (1.1 | ) |  | 0.6 |  |  | Revenues |  |
Foreign currency contracts |  | 25.6 |  |  | (16.2 | ) |  | Gain (loss) on foreign currency contracts, net |  |
Total |  | $ | 105.4 |  |  | $ | (40.8 | ) |  |  |  |  |  |
Nine Months Ended June 30,: |  |  |  |  |  |  |  |  |  |
|  | Gain (Loss) Recognized in AOCI |  | Gain (Loss) Reclassified from AOCI into Income |  | Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges: |  | 2018 |  | 2017 |  | 2018 |  | 2017 |
Foreign currency contracts |  | $ | (0.6 | ) |  | $ | 5.3 |  |  | $ | (3.1 | ) |  | $ | 17.6 |  |  | Cost of sales
Cross-currency contracts |  | 0.9 |  |  | 0.5 |  |  | 0.8 |  |  | (0.2 | ) |  | Interest expense/other operating income, net
Interest rate contracts |  | 2.0 |  |  | 1.7 |  |  | (1.9 | ) |  | (2.9 | ) |  | Interest expense
Total |  | $ | 2.3 |  |  | $ | 7.5 |  |  | $ | (4.2 | ) |  | $ | 14.5 |  |  |
|  | Gain (Loss) Recognized in Income |  | Location of Gain (Loss) Recognized in Income |  |
Derivatives Not Designated as Hedging Instruments: |  | 2018 |  | 2017 |  |  |
Commodity contracts |  | $ | 63.5 |  |  | $ | 105.3 |  |  | Cost of sales |  |
Commodity contracts |  | (2.6 | ) |  | 1.5 |  |  | Revenues |  |
Commodity contracts |  | 0.2 |  |  | — |  |  | Operating and administrative expenses |  |
Foreign currency contracts |  | 9.8 |  |  | (16.1 | ) |  | Gain (loss) on foreign currency contracts, net |  |
Total |  | $ | 70.9 |  |  | $ | 90.7 |  |  |  |  |  |  |

For the three and nine months ended June 30, 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.
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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 are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Note 14 — Accumulated Other Comprehensive Income
The tables below present changes in AOCI during the three and nine months ended June 30, 2018 and 2017:

Three Months Ended June 30, 2018 |  | Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency |  | Total
AOCI — March 31, 2018 |  | $ | (18.5 | ) |  | $ | (21.0 | ) |  | $ | 5.4 |  |  | $ | (34.1 | )
Other comprehensive income (loss) before reclassification adjustments (after-tax) |  | — |  |  | 3.7 |  |  | (82.0 | ) |  | (78.3 | )
Amounts reclassified from AOCI: |  |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) |  | 0.8 |  |  | 0.4 |  |  | — |  |  | 1.2 |
Reclassification adjustments tax benefit |  | (0.2 | ) |  | (0.2 | ) |  | — |  |  | (0.4 | )
Reclassification adjustments (after-tax) |  | 0.6 |  |  | 0.2 |  |  | — |  |  | 0.8 |
Other comprehensive income (loss) attributable to UGI |  | 0.6 |  |  | 3.9 |  |  | (82.0 | ) |  | (77.5 | )
AOCI — June 30, 2018 |  | $ | (17.9 | ) |  | $ | (17.1 | ) |  | $ | (76.6 | ) |  | $ | (111.6 | )
Three Months Ended June 30, 2017 |  | Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency |  | Total
AOCI — March 31, 2017 |  | $ | (27.7 | ) |  | $ | (11.5 | ) |  | $ | (165.3 | ) |  | $ | (204.5 | )
Other comprehensive (loss) income before reclassification adjustments (after-tax) |  | — |  |  | (6.6 | ) |  | 75.5 |  |  | 68.9 |
Amounts reclassified from AOCI: |  |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) |  | (0.1 | ) |  | — |  |  | — |  |  | (0.1 | )
Reclassification adjustments tax benefit |  | — |  |  | (0.2 | ) |  | — |  |  | (0.2 | )
Reclassification adjustments (after-tax) |  | (0.1 | ) |  | (0.2 | ) |  | — |  |  | (0.3 | )
Other comprehensive (loss) income attributable to UGI |  | (0.1 | ) |  | (6.8 | ) |  | 75.5 |  |  | 68.6 |
AOCI — June 30, 2017 |  | $ | (27.8 | ) |  | $ | (18.3 | ) |  | $ | (89.8 | ) |  | $ | (135.9 | )

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

Nine Months Ended June 30, 2018 |  | Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency |  | Total
AOCI — September 30, 2017 |  | $ | (19.2 | ) |  | $ | (21.4 | ) |  | $ | (52.8 | ) |  | $ | (93.4 | )
Other comprehensive income (loss) before reclassification adjustments (after-tax) |  | — |  |  | 1.7 |  |  | (23.8 | ) |  | (22.1 | )
Amounts reclassified from AOCI: |  |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) |  | 1.8 |  |  | 4.2 |  |  | — |  |  | 6.0 |
Reclassification adjustments tax benefit |  | (0.5 | ) |  | (1.6 | ) |  | — |  |  | (2.1 | )
Reclassification adjustments (after-tax) |  | 1.3 |  |  | 2.6 |  |  | — |  |  | 3.9 |
Other comprehensive income (loss) attributable to UGI |  | 1.3 |  |  | 4.3 |  |  | (23.8 | ) |  | (18.2 | )
AOCI — June 30, 2018 |  | $ | (17.9 | ) |  | $ | (17.1 | ) |  | $ | (76.6 | ) |  | $ | (111.6 | )
Nine Months Ended June 30, 2017 |  | Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency |  | Total
AOCI — September 30, 2016 |  | $ | (29.1 | ) |  | $ | (13.4 | ) |  | $ | (112.2 | ) |  | $ | (154.7 | )
Other comprehensive income before reclassification adjustments (after-tax) |  | — |  |  | 5.2 |  |  | 22.4 |  |  | 27.6 |
Amounts reclassified from AOCI: |  |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) |  | 2.2 |  |  | (14.5 | ) |  | — |  |  | (12.3 | )
Reclassification adjustments tax (benefit) expense |  | (0.9 | ) |  | 4.4 |  |  | — |  |  | 3.5 |
Reclassification adjustments (after-tax) |  | 1.3 |  |  | (10.1 | ) |  | — |  |  | (8.8 | )
Other comprehensive income (loss) attributable to UGI |  | 1.3 |  |  | (4.9 | ) |  | 22.4 |  |  | 18.8 |
AOCI — June 30, 2017 |  | $ | (27.8 | ) |  | $ | (18.3 | ) |  | $ | (89.8 | ) |  | $ | (135.9 | )

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 13.
Note 15 — Segment Information
Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities.
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 addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our chief operating decision maker (“CODM”) in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.
The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2017 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned.
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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 June 30, 2018 |  | Total |  | Eliminations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (b)
Revenues |  | $ | 1,440.9 |  |  | $ | — |  |  | $ | 528.4 |  |  | $ | 533.6 |  |  | $ | 229.6 |  |  | $ | 150.3 |  |  | $ | (1.0 | )
Intersegment revenues |  | $ | — |  |  | $ | (44.4 | ) | (c) | $ | — |  |  | $ | — |  |  | $ | 34.2 |  |  | $ | 9.6 |  |  | $ | 0.6 |
Cost of sales |  | $ | 732.5 |  |  | $ | (43.5 | ) | (c) | $ | 244.5 |  |  | $ | 314.3 |  |  | $ | 215.0 |  |  | $ | 72.5 |  |  | $ | (70.3 | )
Segment profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating income (loss) |  | $ | 28.5 |  |  | $ | (0.3 | ) |  | $ | (54.7 | ) | (e) | $ | 9.0 |  |  | $ | 7.4 |  |  | $ | 3.9 |  |  | $ | 63.2 |
Income from equity investees |  | 1.3 |  |  | — |  |  | — |  |  | — |  |  | 1.3 |  | (d) | — |  |  | — |
Gain (loss) on foreign currency contracts, net |  | 25.6 |  |  | — |  |  | — |  |  | (0.5 | ) |  | — |  |  | — |  |  | 26.1 |
Interest expense |  | (56.5 | ) |  | — |  |  | (40.4 | ) |  | (5.5 | ) |  | (0.5 | ) |  | (10.0 | ) |  | (0.1 | )
(Loss) income before income taxes |  | $ | (1.1 | ) |  | $ | (0.3 | ) |  | $ | (95.1 | ) |  | $ | 3.0 |  |  | $ | 8.2 |  |  | $ | (6.1 | ) |  | $ | 89.2 |
Partnership Adjusted EBITDA (a) |  |  |  |  |  | $ | 67.2 |  |  |  |  |  |  |  |  |
Noncontrolling interests’ net (loss) income |  | $ | (64.1 | ) |  | $ | — |  |  | $ | (78.1 | ) |  | $ | (0.8 | ) |  | $ | — |  |  | $ | — |  |  | $ | 14.8 |
Depreciation and amortization |  | $ | 118.8 |  |  | $ | (0.1 | ) |  | $ | 46.4 |  |  | $ | 39.8 |  |  | $ | 11.1 |  |  | $ | 21.4 |  |  | $ | 0.2 |
Capital expenditures (including the effects of accruals) |  | $ | 142.7 |  |  | $ | — |  |  | $ | 25.7 |  |  | $ | 27.3 |  |  | $ | 9.9 |  |  | $ | 79.7 |  |  | $ | 0.1 |

Three Months Ended June 30, 2017 |  | Total |  | Eliminations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (b)
Revenues |  | $ | 1,153.5 |  |  | $ | — |  |  | $ | 467.5 |  |  | $ | 351.3 |  |  | $ | 195.4 |  |  | $ | 138.0 |  |  | $ | 1.3 |
Intersegment revenues |  | $ | — |  |  | $ | (36.9 | ) | (c) | $ | — |  |  | $ | — |  |  | $ | 27.4 |  |  | $ | 8.6 |  |  | $ | 0.9 |
Cost of sales |  | $ | 618.5 |  |  | $ | (36.2 | ) | (c) | $ | 197.5 |  |  | $ | 178.2 |  |  | $ | 189.4 |  |  | $ | 52.0 |  |  | $ | 37.6 |
Segment profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating (loss) income |  | $ | (2.8 | ) |  | $ | 0.1 |  |  | $ | 4.6 |  |  | $ | 0.5 |  |  | $ | 2.8 |  |  | $ | 27.7 |  |  | $ | (38.5 | )
Income from equity investees |  | 0.9 |  |  | — |  |  | — |  |  | 0.1 |  |  | 0.8 |  | (d) | — |  |  | — |
Loss on extinguishments of debt |  | (4.4 | ) |  | — |  |  | (4.4 | ) |  | — |  |  | — |  |  | — |  |  | — |
Loss on foreign currency contracts, net |  | (16.2 | ) |  | — |  |  | — |  |  | (0.2 | ) |  | — |  |  | — |  |  | (16.0 | )
Interest expense |  | (56.8 | ) |  | — |  |  | (40.6 | ) |  | (5.6 | ) |  | (0.3 | ) |  | (10.2 | ) |  | (0.1 | )
(Loss) income before income taxes |  | $ | (79.3 | ) |  | $ | 0.1 |  |  | $ | (40.4 | ) |  | $ | (5.2 | ) |  | $ | 3.3 |  |  | $ | 17.5 |  |  | $ | (54.6 | )
Partnership Adjusted EBITDA (a) |  |  |  |  |  | $ | 58.4 |  |  |  |  |  |  |  |  |
Noncontrolling interests’ net loss |  | $ | (43.2 | ) |  | $ | — |  |  | $ | (38.5 | ) |  | $ | (0.3 | ) |  | $ | — |  |  | $ | — |  |  | $ | (4.4 | )
Depreciation and amortization |  | $ | 104.1 |  |  | $ | (0.1 | ) |  | $ | 46.2 |  |  | $ | 31.1 |  |  | $ | 8.8 |  |  | $ | 17.9 |  |  | $ | 0.2 |
Capital expenditures (including the effects of accruals) |  | $ | 140.9 |  |  | $ | — |  |  | $ | 20.9 |  |  | $ | 19.1 |  |  | $ | 21.7 |  |  | $ | 79.1 |  |  | $ | 0.1 |

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

Nine Months Ended June 30, 2018 |  | Total |  | Eliminations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (b)
Revenues |  | $ | 6,378.1 |  |  | $ | — |  |  | $ | 2,356.0 |  |  | $ | 2,227.4 |  |  | $ | 915.6 |  |  | $ | 880.3 |  |  | $ | (1.2 | )
Intersegment revenues |  | $ | — |  |  | $ | (330.4 | ) | (c) | $ | — |  |  | $ | — |  |  | $ | 241.4 |  |  | $ | 86.0 |  |  | $ | 3.0 |
Cost of sales |  | $ | 3,430.1 |  |  | $ | (327.4 | ) | (c) | $ | 1,094.3 |  |  | $ | 1,340.2 |  |  | $ | 872.6 |  |  | $ | 481.6 |  |  | $ | (31.2 | )
Segment profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating income |  | $ | 1,009.8 |  |  | $ | 0.2 |  |  | $ | 359.8 |  | (e) | $ | 233.9 |  |  | $ | 167.2 |  |  | $ | 235.3 |  |  | $ | 13.4 |
Income (loss) from equity investees |  | 3.0 |  |  | — |  |  | — |  |  | (0.3 | ) |  | 3.3 |  | (d) | — |  |  | — |
Gain (loss) on foreign currency contracts, net |  | 9.8 |  |  | — |  |  | — |  |  | (14.2 | ) |  | — |  |  | — |  |  | 24.0 |
Interest expense |  | (172.8 | ) |  | — |  |  | (122.0 | ) |  | (16.3 | ) |  | (2.1 | ) |  | (32.0 | ) |  | (0.4 | )
Income before income taxes |  | $ | 849.8 |  |  | $ | 0.2 |  |  | $ | 237.8 |  |  | $ | 203.1 |  |  | $ | 168.4 |  |  | $ | 203.3 |  |  | $ | 37.0 |
Partnership Adjusted EBITDA (a) |  |  |  |  |  | $ | 570.8 |  |  |  |  |  |  |  |  |
Noncontrolling interests’ net income (loss) |  | $ | 135.9 |  |  | $ | — |  |  | $ | 145.6 |  |  | $ | (2.3 | ) |  | $ | — |  |  | $ | — |  |  | $ | (7.4 | )
Depreciation and amortization |  | $ | 341.3 |  |  | $ | (0.2 | ) |  | $ | 139.0 |  |  | $ | 106.9 |  |  | $ | 32.0 |  |  | $ | 62.9 |  |  | $ | 0.7 |
Capital expenditures (including the effects of accruals) |  | $ | 381.3 |  |  | $ | — |  |  | $ | 72.9 |  |  | $ | 75.1 |  |  | $ | 25.5 |  |  | $ | 206.5 |  |  | $ | 1.3 |
As of June 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 11,876.7 |  |  | $ | (74.2 | ) |  | $ | 3,932.7 |  |  | $ | 3,232.5 |  |  | $ | 1,316.5 |  |  | $ | 3,194.0 |  |  | $ | 275.2 |
Short-term borrowings |  | $ | 299.1 |  |  | $ | — |  |  | $ | 177.0 |  |  | $ | 3.6 |  |  | $ | — |  |  | $ | 118.5 |  |  | $ | — |
Goodwill |  | $ | 3,169.0 |  |  | $ | — |  |  | $ | 2,005.5 |  |  | $ | 969.9 |  |  | $ | 11.5 |  |  | $ | 182.1 |  |  | $ | — |

Nine Months Ended June 30, 2017 |  | Total |  | Eliminations |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other (b)
Revenues |  | $ | 5,006.8 |  |  | $ | — |  |  | $ | 2,008.3 |  |  | $ | 1,511.1 |  |  | $ | 752.5 |  |  | $ | 733.1 |  |  | $ | 1.8 |
Intersegment revenues |  | $ | — |  |  | $ | (201.2 | ) | (c) | $ | — |  |  | $ | — |  |  | $ | 163.8 |  |  | $ | 34.9 |  |  | $ | 2.5 |
Cost of sales |  | $ | 2,337.1 |  |  | $ | (198.8 | ) | (c) | $ | 814.0 |  |  | $ | 749.3 |  |  | $ | 691.0 |  |  | $ | 326.0 |  |  | $ | (44.4 | )
Segment profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating income |  | $ | 976.6 |  |  | $ | 0.2 |  |  | $ | 373.8 |  |  | $ | 210.4 |  |  | $ | 134.6 |  |  | $ | 226.3 |  |  | $ | 31.3 |
Income (loss) from equity investees |  | 3.0 |  |  | — |  |  | — |  |  | (0.2 | ) |  | 3.2 |  | (d) | — |  |  | — |
Loss on extinguishments of debt |  | (59.7 | ) |  | — |  |  | (59.7 | ) |  | — |  |  | — |  |  | — |  |  | — |
Loss on foreign currency contracts, net |  | (16.1 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (16.1 | )
Interest expense |  | (168.0 | ) |  | — |  |  | (120.6 | ) |  | (15.2 | ) |  | (1.6 | ) |  | (30.5 | ) |  | (0.1 | )
Income before income taxes |  | $ | 735.8 |  |  | $ | 0.2 |  |  | $ | 193.5 |  |  | $ | 195.0 |  |  | $ | 136.2 |  |  | $ | 195.8 |  |  | $ | 15.1 |
Partnership Adjusted EBITDA (a) |  |  |  |  |  | $ | 514.7 |  |  |  |  |  |  |  |  |
Noncontrolling interests’ net income (loss) |  | $ | 108.9 |  |  | $ | — |  |  | $ | 115.4 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (6.5 | )
Depreciation and amortization |  | $ | 301.5 |  |  | $ | (0.2 | ) |  | $ | 135.8 |  |  | $ | 86.6 |  |  | $ | 25.6 |  |  | $ | 53.0 |  |  | $ | 0.7 |
Capital expenditures (including the effects of accruals) |  | $ | 440.7 |  |  | $ | — |  |  | $ | 74.5 |  |  | $ | 62.1 |  |  | $ | 104.0 |  |  | $ | 199.7 |  |  | $ | 0.4 |
As of June 30, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 11,246.4 |  |  | $ | (53.0 | ) |  | $ | 4,045.7 |  |  | $ | 2,887.7 |  |  | $ | 1,171.5 |  |  | $ | 2,904.5 |  |  | $ | 290.0 |
Short-term borrowings |  | $ | 163.9 |  |  | $ | — |  |  | $ | 75.5 |  |  | $ | 8.4 |  |  | $ | 30.0 |  |  | $ | 50.0 |  |  | $ | — |
Goodwill |  | $ | 3,032.3 |  |  | $ | — |  |  | $ | 2,001.4 |  |  | $ | 837.3 |  |  | $ | 11.5 |  |  | $ | 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 (loss) before income taxes:

|  | Three Months Ended June 30, |  | Nine Months Ended June 30,
|  | 2018 |  | 2017 |  | 2018 |  | 2017
Partnership Adjusted EBITDA |  | $ | 67.2 |  |  | $ | 58.4 |  |  | $ | 570.8 |  |  | $ | 514.7 |
Depreciation and amortization |  | (46.4 | ) |  | (46.2 | ) |  | (139.0 | ) |  | (135.8 | )
Interest expense |  | (40.4 | ) |  | (40.6 | ) |  | (122.0 | ) |  | (120.6 | )
Impairment of Partnership tradenames and trademarks |  | (75.0 | ) |  | — |  |  | (75.0 | ) |  | — |
Loss on extinguishments of debt |  | — |  |  | (4.4 | ) |  | — |  |  | (59.7 | )
MGP environmental remediation accrual |  | — |  |  | (7.5 | ) |  | — |  |  | (7.5 | )
Noncontrolling interest (i) |  | (0.5 | ) |  | (0.1 | ) |  | 3.0 |  |  | 2.4 |
(Loss) income before income taxes |  | $ | (95.1 | ) |  | $ | (40.4 | ) |  | $ | 237.8 |  |  | $ | 193.5 |

(i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

(b) | Includes net pre-tax gains (losses) on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $95.5 and $(52.7) during the three months ended June 30, 2018 and 2017, respectively, and $54.0 and $28.9 during the nine months ended June 30, 2018 and 2017, respectively. Corporate & Other results for the nine months ended June 30, 2017, also include a pre-tax loss of $7.0 associated with the impairment of a cost basis investment (see Note 2).

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

(d) | Represents allowance for funds used during construction (“AFUDC”) associated with our PennEast Pipeline equity investment.

(e) | Includes a pre-tax impairment charge of $75.0 for the three and nine months ended June 30, 2018, as a result of a plan to discontinue the use of certain tradenames and trademarks primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane (see Note 6).

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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 Securities Exchange Act of 1934, as amended (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; (2) cost volatility and availability of propane and other liquefied petroleum gases (“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, environmental and accounting matters; (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 and 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, 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 and in foreign countries, including the current conflicts in the Middle East, 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 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 breach of our information technology systems, including due to cyber attack; and (22) continued analysis of recent tax legislation.
These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s 2017 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 analyses compare the Company’s results of operations for the three months ended June 30, 2018 (“2018 three-month period”) with the three months ended June 30, 2017 (“2017 three-month period”) and the nine months ended June 30, 2018 (“2018 nine-month period”) with the nine months ended June 30, 2017 (“2017 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 15 to the condensed consolidated financial statements.
Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the heating-season months of October through March. As a result, our operating results, excluding the effects of gains and losses on commodity derivative instruments not associated with current-period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.
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
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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 to the most directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.
Our net income for the three and nine months ended June 30, 2018, was affected by the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”), including a ratemaking Order issued by the PUC on May 17, 2018, in response to the TCJA, and the December 2017 French Finance Bills. The impact of these tax reforms is discussed below and in Notes 5 and 7 to condensed consolidated financial statements. Our financial results include two types of impacts from the enactment of the TCJA and the December 2017 French Finance Bills.
The first impact comprises “one-time” discrete adjustments to our deferred income tax assets and liabilities, accrued income taxes and deferred tax valuation allowances existing as of the dates the tax laws were enacted. These “one-time” adjustments to our income tax assets and liabilities have been excluded from our non-GAAP financial measures below.
The second impact of the TCJA and the December 2017 French Finance Bills primarily comprises the effects of the tax law changes on current-period results. With respect to the TCJA, the impact on current-period results principally reflects the lower U.S. corporate income tax rate, which for Fiscal 2018 consists of a blended federal corporate income tax rate of 24.5% compared to 35% in the prior year. With respect to the December 2017 French Finance Bills, the impact on current-period results principally reflects the higher Fiscal 2018 French corporate income tax rate of 39.4% compared to 34.4% in the prior year. These impacts of the TCJA and the December 2017 French Finance Bills on current-period results have been included in our non-GAAP financial measures below.
EXECUTIVE OVERVIEW
THREE MONTHS ENDED JUNE 30, 2018 AND 2017
Net Income Attributable to UGI Corporation by Business Unit (GAAP):
Net income (loss) attributable to UGI Corporation for the three months ended June 30, 2018 and 2017 is as follows:

For the three months ended June 30, |  | 2018 |  | 2017 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount (a) |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane (b)(c) |  | $ | (11.2 | ) |  | (21.4 | )% |  | $ | (1.4 | ) |  | 7.4 | % |  | $ | (9.8 | ) |  | (700.0 | )%
UGI International (d)(e) |  | 6.5 |  |  | 12.4 | % |  | (2.0 | ) |  | 10.5 | % |  | 8.5 |  |  | 425.0 | %
Midstream & Marketing |  | 5.8 |  |  | 11.1 | % |  | 3.0 |  |  | (15.8 | )% |  | 2.8 |  |  | 93.3 | %
UGI Utilities (f) |  | (3.0 | ) |  | (5.7 | )% |  | 10.7 |  |  | (56.3 | )% |  | (13.7 | ) |  | (128.0 | )%
Corporate & Other (g) |  | 54.3 |  |  | 103.6 | % |  | (29.3 | ) |  | 154.2 | % |  | 83.6 |  |  | N.M. |
Net income (loss) attributable to UGI Corporation |  | $ | 52.4 |  |  | 100.0 | % |  | $ | (19.0 | ) |  | 100.0 | % |  | $ | 71.4 |  |  | (375.8 | )%

(a) | Net income attributable to UGI Corporation for the three months ended June 30, 2018, includes changes to provisional one-time adjustments recorded in prior periods as a result of the enactment of the TCJA, which decreased income taxes and increased net income attributable to UGI by business unit as follows:

AmeriGas Propane | $ | 0.2 |
UGI International | 0.5 |
Midstream & Marketing | (0.5 | )
UGI Utilities | 1.1 |
Corporate & Other | (0.5 | )
Net income attributable to UGI Corporation | $ | 0.8 |

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In addition to these changes to provisional one-time adjustments from the TCJA, net income attributable to UGI for the three months ended June 30, 2018, also reflects the current-period impact of the TCJA, which increased net income attributable to UGI by approximately $6.1 million.

(b) | Three months ended June 30, 2018, includes after-tax impairment charge of $14.5 million as a result of a plan to discontinue use of certain tradenames and trademarks.

(c) | Three months ended June 30, 2017, includes net after-tax loss of $0.7 million from extinguishments of debt.

(d) | Net income attributable to UGI for the three months ended June 30, 2018 reflects the current-period impact of the December 2017 French Finance Bills, which increased net income attributable to UGI by approximately $0.2 million.

(e) | Includes after-tax integration expenses associated with Finagaz acquired on May 29, 2015 of $4.6 million for each of the three-month periods ended June 30, 2018 and 2017.

(f) | Three months ended June 30, 2018, includes reduction in net income of $16.2 million to reflect the establishment of a regulatory liability and associated deferred income taxes from tax savings as a result of the TCJA during the period January 1, 2018 to June 30, 2018.

(g) | Includes net after-tax gains (losses) on commodity derivative instruments not associated with current-period transactions of $38.0 million and $(19.8) million for the three months ended June 30, 2018 and 2017, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $17.7 million and $(10.5) million for the three months ended June 30, 2018 and 2017, respectively.

N.M. — Variance is not meaningful.
Adjusted Net Income (Loss) Attributable to UGI Corporation by Business Unit (Non-GAAP):
Adjusted net income (loss) attributable to UGI Corporation for the three months ended June 30, 2018 and 2017 is as follows:

For the three months ended June 30, |  | 2018 |  | 2017 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 3.1 |  |  | 20.5 | % |  | $ | (0.7 | ) |  | (4.2 | )% |  | $ | 3.8 |  |  | (542.9 | )%
UGI International |  | 10.7 |  |  | 70.9 | % |  | 2.6 |  |  | 15.7 | % |  | 8.1 |  |  | 311.5 | %
Midstream & Marketing |  | 6.3 |  |  | 41.7 | % |  | 3.0 |  |  | 18.1 | % |  | 3.3 |  |  | 110.0 | %
UGI Utilities |  | (4.1 | ) |  | (27.2 | )% |  | 10.7 |  |  | 64.5 | % |  | (14.8 | ) |  | (138.3 | )%
Corporate & Other |  | (0.9 | ) |  | (5.9 | )% |  | 1.0 |  |  | 5.9 | % |  | (1.9 | ) |  | N.M. |
Adjusted net income attributable to UGI Corporation |  | $ | 15.1 |  |  | 100.0 | % |  | $ | 16.6 |  |  | 100.0 | % |  | $ | (1.5 | ) |  | (9.0 | )%

Discussion. Adjusted net income attributable to UGI Corporation for the 2018 three-month period was $15.1 million (equal to $0.09 per diluted share) compared to $16.6 million (equal to $0.09 per diluted share) for the 2017 three-month period.
Our adjusted operating results for the three months ended June 30, 2018, reflect the benefits at each of our U.S. business units from weather that was colder than the prior-year three-month period. The colder weather in the U.S. occurred principally during the month of April. Weather at our UGI International service territories in the 2018 three-month period was significantly warmer than normal and warmer than the prior-year period. Notwithstanding the warmer weather, our UGI International LPG volumes were affected by the carryover effects of cold late-March weather particularly in France. Our UGI International 2018 three-month period includes the results of our October 2017 acquisition of Total’s retail LPG operations in Italy (now known as “UniverGas”) and the August 2017 acquisition of an electricity and natural gas marketing business in the Netherlands (“DVEP”). In addition to the benefits from the colder U.S. weather, Midstream & Marketing net income in the 2018 three-month period also benefited from recent investments in natural gas gathering assets and higher capacity values. UGI Utilities 2018 three-month period results reflect the volume impacts of the colder April weather and customer growth but revenues and margin were reduced as a result of the PUC’s Order regarding the TCJA (as further described below).
Our income tax expense for the three months ended June 30, 2018, reflects the current-period tax effects of the TCJA and the December 2017 French Finance Bills. For the three months ended June 30, 2018, the current-period tax effects of the TCJA decreased consolidated income tax expense by approximately $6.1 million including the tax effects of the TCJA at UGI Utilities. As more fully described in Notes 5 and 7 to condensed consolidated financial statements, in June 2018 UGI Utilities reduced its revenues by $22.7 million, and established an associated regulatory liability, related to $16.2 million ($0.09 per diluted share) of tax savings (which revenue reduction is in addition to a $1.4 million reduction previously recorded in March 2018) resulting from the change in the federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. The reduction in revenues reflects the impact of the PUC’s May 17, 2018, Order addressing the effects of the TCJA on Pennsylvania utilities. Approximately $14.9 million (equal to $0.08 per diluted share) of the $16.2 million of tax savings recorded during the 2018 three-month period
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relates to the period January 1, 2018 to March 31, 2018. The rate treatment of this regulatory liability will be addressed in a future proceeding.
Our current-period adjusted results also include the effects of the December 2017 French Finance Bills. The December 2017 French Finance Bills did not have a material impact on the results for the 2018 three-month period.
NINE MONTHS ENDED JUNE 30, 2018 AND 2017
Net Income Attributable to UGI Corporation by Business Unit (GAAP):
Net income attributable to UGI Corporation for the nine months ended June 30, 2018 and 2017 is as follows:

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount (a) |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane (b)(c) |  | $ | 180.2 |  |  | 26.0 | % |  | $ | 47.2 |  |  | 10.9 | % |  | $ | 133.0 |  |  | 281.8 | %
UGI International (d)(e) |  | 145.0 |  |  | 20.9 | % |  | 165.6 |  |  | 38.4 | % |  | (20.6 | ) |  | (12.4 | )%
Midstream & Marketing |  | 194.4 |  |  | 28.0 | % |  | 83.1 |  |  | 19.3 | % |  | 111.3 |  |  | 133.9 | %
UGI Utilities (f) |  | 154.5 |  |  | 22.3 | % |  | 120.1 |  |  | 27.8 | % |  | 34.4 |  |  | 28.6 | %
Corporate & Other (g)(h) |  | 20.2 |  |  | 2.8 | % |  | 15.6 |  |  | 3.6 | % |  | 4.6 |  |  | N.M. |
Net income attributable to UGI Corporation |  | $ | 694.3 |  |  | 100.0 | % |  | $ | 431.6 |  |  | 100.0 | % |  | $ | 262.7 |  |  | 60.9 | %

(a) | Net income attributable to UGI Corporation for the nine months ended June 30, 2018, includes income (loss) from one-time adjustments to tax-related accounts as a result of the enactment of the TCJA as follows:

AmeriGas Propane | $ | 113.3 |
UGI International | (8.6 | )
Midstream & Marketing | 73.8 |
UGI Utilities | 9.3 |
Corporate & Other | (15.7 | )
Net income attributable to UGI Corporation | $ | 172.1 |

In addition to these one-time adjustments from the TCJA, net income attributable to UGI for the nine months ended June 30, 2018, also reflects the current-period beneficial impact of the TCJA principally due to the lower federal income tax rate in Fiscal 2018 of approximately $60.6 million.

(b) | Nine months ended June 30, 2018, includes after-tax impairment charge of $14.5 million as a result of the plan to discontinue use of certain tradenames and trademarks.

(c) | Nine months ended June 30, 2017, includes net after-tax loss of $9.6 million from extinguishments of debt.

(d) | Nine months ended June 30, 2018, includes beneficial impact of a $13.5 million adjustment to net deferred income tax liabilities associated with the enactment of the December 2017 French Finance Bills. Nine months ended June 30, 2017, includes beneficial impact of a $27.4 million adjustment to net deferred income tax liabilities associated with a change in French income tax rate and an income tax settlement refund of $6.7 million, plus interest, in France. In addition to these one-time adjustments, net income attributable to UGI for the nine months ended June 30, 2018, also reflects the current-period negative impact of the December 2017 French Finance Bills which decreased net income attributable to UGI by approximately $4.7 million.

(e) | Includes after-tax integration expenses associated with Finagaz of $12.6 million and $14.3 million for the nine months ended June 30, 2018 and 2017, respectively.

(f) | Nine months ended June 30, 2018, includes reduction in net income of $17.1 million to reflect the establishment of a regulatory liability and associated deferred income taxes from tax savings during the period January 1, 2018 to June 30, 2018 as a result of the TCJA.

(g) | Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $26.9 million and $29.3 million for the nine months ended June 30, 2018 and 2017, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $16.3 million and $(10.5) million for the nine months ended June 30, 2018 and 2017, respectively.

(h) | Nine months ended June 30, 2017, includes a $4.5 million after-tax loss associated with the impairment of a cost basis investment (see Note 2 to condensed consolidated financial statements).

N.M. — Variance is not meaningful.
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Adjusted Net Income (Loss) Attributable to UGI Corporation by Business Unit (Non-GAAP):
Adjusted net income (loss) attributable to UGI Corporation for the nine months ended June 30, 2018 and 2017 is as follows:

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 81.4 |  |  | 16.5 | % |  | $ | 56.8 |  |  | 13.9 | % |  | $ | 24.6 |  |  | 43.3 | %
UGI International |  | 152.7 |  |  | 31.0 | % |  | 152.5 |  |  | 37.3 | % |  | 0.2 |  |  | 0.1 | %
Midstream & Marketing |  | 120.6 |  |  | 24.5 | % |  | 83.1 |  |  | 20.3 | % |  | 37.5 |  |  | 45.1 | %
UGI Utilities |  | 145.2 |  |  | 29.5 | % |  | 120.1 |  |  | 29.3 | % |  | 25.1 |  |  | 20.9 | %
Corporate & Other |  | (7.3 | ) |  | (1.5 | )% |  | (3.2 | ) |  | (0.8 | )% |  | (4.1 | ) |  | N.M. |
Adjusted net income attributable to UGI Corporation |  | $ | 492.6 |  |  | 100.0 | % |  | $ | 409.3 |  |  | 100.0 | % |  | $ | 83.3 |  |  | 20.4 | %

Discussion. Adjusted net income attributable to UGI Corporation for the 2018 nine-month period was $492.6 million (equal to $2.79 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2017 nine-month period of $409.3 million (equal to $2.31 per diluted share).
Temperatures in our U.S. business units during the nine months ended June 30, 2018, were colder than the significantly warmer-than-normal temperatures experienced during the prior-year nine-month period. Temperatures at UGI International were warmer than normal and warmer than the prior-year period. UGI Utilities improved results reflect, among other things, the impact of the colder weather as well as higher base rates at PNG, which became effective on October 20, 2017. Midstream & Marketing results benefited from colder and more volatile weather principally in late December and January, higher net income from the recent expansion of natural gas gathering, pipeline, LNG storage and peaking assets, and higher electric generation net income. AmeriGas Propane retail volumes sold were higher during the 2018 nine-month period principally reflecting the effects of colder weather on heating-related retail volumes. Our UGI International 2018 nine-month period results reflect incremental net income from the recent acquisitions of UniverGas and DVEP.
Our income tax expense for the nine months ended June 30, 2018, reflects the current-period tax effects of the TCJA and the December 2017 French Finance Bills. For the nine months ended June 30, 2018, the current-period tax effects of the TCJA decreased consolidated income tax expense by approximately $60.6 million (equal to $0.34 per diluted share). In accordance with the PUC Order issued May 17, 2018, during the 2018 nine-month period, UGI Utilities reduced its revenues and established a regulatory liability related to $17.1 million (equal to $0.10 per diluted share) of tax benefits resulting from the change in the federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. Our results for the nine months ended June 30, 2018 also reflect the current-period effects of the December 2017 French Finance Bills which increased income tax expense by approximately $4.7 million (equal to $0.03 per diluted share).
On a combined basis, the impact on income tax expense resulting from the U.S. and French tax law changes noted above, and the effects of the establishment of the regulatory liability related to the tax savings at UGI Utilities for the period January 1, 2018 to June 30, 2018, increased adjusted net income attributable to UGI by approximately $38.8 million (equal to $0.22 per diluted share) for the nine months ended June 30, 2018.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted 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- and nine-month periods, adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding (1) net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments); (2) Finagaz integration expenses; (3) losses associated with extinguishments of debt at AmeriGas Propane; (4) impairment of tradenames and trademarks at AmeriGas Propane; and (5) one-time impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills. UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under U.S. generally accepted accounting principles (“GAAP”). Volatility in net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and losses result principally from recording
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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 (loss) attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation, and reconcile diluted earnings (loss) per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above:

Three Months Ended June 30, 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 |  | $ | 52.4 |  |  | $ | (11.2 | ) |  | $ | 6.5 |  |  | $ | 5.8 |  |  | $ | (3.0 | ) |  | $ | 54.3 |
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $16.5) (a) |  | (38.0 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (38.0 | )
Unrealized gains on foreign currency derivative instruments (net of tax of $8.4) (a) |  | (17.7 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (17.7 | )
Integration expenses associated with Finagaz (net of tax of $(3.0)) (a) |  | 4.6 |  |  | — |  |  | 4.6 |  |  | — |  |  | — |  |  | — |
Impairment of Partnership tradenames and trademarks (net of tax of $(5.8)) (a) |  | 14.5 |  |  | 14.5 |  |  | — |  |  | — |  |  | — |  |  | — |
Impact of December 2017 French Finance Bills |  | 0.1 |  |  | — |  |  | 0.1 |  |  | — |  |  | — |  |  | — |
Impact from TCJA |  | (0.8 | ) |  | (0.2 | ) |  | (0.5 | ) |  | 0.5 |  |  | (1.1 | ) |  | 0.5 |
Adjusted net income (loss) attributable to UGI Corporation |  | $ | 15.1 |  |  | $ | 3.1 |  |  | $ | 10.7 |  |  | $ | 6.3 |  |  | $ | (4.1 | ) |  | $ | (0.9 | )
Adjusted diluted earnings per share: |  |  |  |  |  |  |  |  |  |  |  |
UGI Corporation earnings (loss) per share — diluted |  | $ | 0.30 |  |  | $ | (0.06 | ) |  | $ | 0.04 |  |  | $ | 0.03 |  |  | $ | (0.02 | ) |  | $ | 0.31 |
Net gains on commodity derivative instruments not associated with current-period transactions (b) |  | (0.21 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.21 | )
Unrealized gains on foreign currency derivative instruments |  | (0.10 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.10 | )
Integration expenses associated with Finagaz (b) |  | 0.02 |  |  | — |  |  | 0.02 |  |  | — |  |  | — |  |  | — |
Impairment of Partnership tradenames and trademarks |  | 0.08 |  |  | 0.08 |  |  | — |  |  | — |  |  | — |  |  | — |
Impact of December 2017 French Finance Bills |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Impact from TCJA |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Adjusted diluted earnings (loss) per share |  | $ | 0.09 |  |  | $ | 0.02 |  |  | $ | 0.06 |  |  | $ | 0.03 |  |  | $ | (0.02 | ) |  | $ | — |

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Three Months Ended June 30, 2017 |  | Total |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other
Adjusted net income attributable to UGI Corporation (millions): |  |  |  |  |  |  |  |  |  |  |  |
Net (loss) income attributable to UGI Corporation |  | $ | (19.0 | ) |  | $ | (1.4 | ) |  | $ | (2.0 | ) |  | $ | 3.0 |  |  | $ | 10.7 |  |  | $ | (29.3 | )
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(12.6)) (a) |  | 19.8 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 19.8 |
Unrealized losses on foreign currency derivative instruments (net of tax of $(5.5)) (a) |  | 10.5 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10.5 |
Loss on extinguishment of debt (net of tax of $(0.4)) (a) |  | 0.7 |  |  | 0.7 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz (net of tax of $(2.4)) (a) |  | 4.6 |  |  | — |  |  | 4.6 |  |  | — |  |  | — |  |  | — |
Adjusted net income (loss) attributable to UGI Corporation |  | $ | 16.6 |  |  | $ | (0.7 | ) |  | $ | 2.6 |  |  | $ | 3.0 |  |  | $ | 10.7 |  |  | $ | 1.0 |
Adjusted diluted earnings per share: |  |  |  |  |  |  |  |  |  |  |  |
UGI Corporation earnings (loss) per share - diluted |  | $ | (0.11 | ) |  | $ | (0.01 | ) |  | $ | (0.01 | ) |  | $ | 0.02 |  |  | $ | 0.06 |  |  | $ | (0.17 | )
Net losses on commodity derivative instruments not associated with current-period transactions |  | 0.10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.10 |
Unrealized losses on foreign currency derivative instruments (b) |  | 0.06 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.06 |
Loss on extinguishment of debt |  | 0.01 |  |  | 0.01 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz |  | 0.03 |  |  | — |  |  | 0.03 |  |  | — |  |  | — |  |  | — |
Adjusted diluted earnings (loss) per share (c) |  | $ | 0.09 |  |  | $ | — |  |  | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.06 |  |  | $ | (0.01 | )

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Nine Months Ended June 30, 2018 |  | Total |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other
Adjusted net income attributable to UGI Corporation (millions): |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 694.3 |  |  | $ | 180.2 |  |  | $ | 145.0 |  |  | $ | 194.4 |  |  | $ | 154.5 |  |  | $ | 20.2 |
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $10.4) (a) |  | (26.9 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (26.9 | )
Unrealized gains on foreign currency derivative instruments (net of tax of $7.7) (a) |  | (16.3 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (16.3 | )
Integration expenses associated with Finagaz (net of tax of $(8.2)) (a) |  | 12.6 |  |  | — |  |  | 12.6 |  |  | — |  |  | — |  |  | — |
Impairment of Partnership tradenames and trademarks (net of tax of $(5.8)) (a) |  | 14.5 |  |  | 14.5 |  |  | — |  |  | — |  |  | — |  |  | — |
Impact of December 2017 French Finance Bills |  | (13.5 | ) |  | — |  |  | (13.5 | ) |  | — |  |  | — |  |  | — |
Impact from TCJA |  | (172.1 | ) |  | (113.3 | ) |  | 8.6 |  |  | (73.8 | ) |  | (9.3 | ) |  | 15.7 |
Adjusted net income (loss) attributable to UGI Corporation |  | $ | 492.6 |  |  | $ | 81.4 |  |  | $ | 152.7 |  |  | $ | 120.6 |  |  | $ | 145.2 |  |  | $ | (7.3 | )
Adjusted diluted earnings per share: |  |  |  |  |  |  |  |  |  |  |  |
UGI Corporation earnings per share — diluted |  | $ | 3.93 |  |  | $ | 1.02 |  |  | $ | 0.82 |  |  | $ | 1.10 |  |  | $ | 0.87 |  |  | $ | 0.12 |
Net gains on commodity derivative instruments not associated with current-period transactions |  | (0.15 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.15 | )
Unrealized gains on foreign currency derivative instruments |  | (0.09 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.09 | )
Integration expenses associated with Finagaz |  | 0.07 |  |  | — |  |  | 0.07 |  |  | — |  |  | — |  |  | — |
Impairment of Partnership tradenames and trademarks |  | 0.08 |  |  | 0.08 |  |  | — |  |  | — |  |  | — |  |  | — |
Impact of December 2017 French Finance Bills |  | (0.08 | ) |  | — |  |  | (0.08 | ) |  | — |  |  | — |  |  | — |
Impact from TCJA |  | (0.97 | ) |  | (0.64 | ) |  | 0.05 |  |  | (0.42 | ) |  | (0.05 | ) |  | 0.09 |
Adjusted diluted earnings (loss) per share |  | $ | 2.79 |  |  | $ | 0.46 |  |  | $ | 0.86 |  |  | $ | 0.68 |  |  | $ | 0.82 |  |  | $ | (0.03 | )

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Nine Months Ended June 30, 2017 |  | Total |  | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Corporate & Other
Adjusted net income attributable to UGI Corporation (millions): |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 431.6 |  |  | $ | 47.2 |  |  | $ | 165.6 |  |  | $ | 83.1 |  |  | $ | 120.1 |  |  | $ | 15.6 |
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $22.2) (a) |  | (29.3 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (29.3 | )
Unrealized losses on foreign currency derivative instruments (net of tax of $(5.6)) (a) |  | 10.5 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10.5 |
Loss on extinguishments of debt (net of tax of $(6.1)) (a) |  | 9.6 |  |  | 9.6 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz (net of tax of $(7.5)) (a) |  | 14.3 |  |  | — |  |  | 14.3 |  |  | — |  |  | — |  |  | — |
Impact from December 2016 French Finance Bills |  | (27.4 | ) |  | — |  |  | (27.4 | ) |  | — |  |  | — |  |  | — |
Adjusted net income (loss) attributable to UGI Corporation |  | $ | 409.3 |  |  | $ | 56.8 |  |  | $ | 152.5 |  |  | $ | 83.1 |  |  | $ | 120.1 |  |  | $ | (3.2 | )
Adjusted diluted earnings per share: |  |  |  |  |  |  |  |  |  |  |  |
UGI Corporation earnings per share - diluted |  | $ | 2.44 |  |  | $ | 0.27 |  |  | $ | 0.93 |  |  | $ | 0.47 |  |  | $ | 0.68 |  |  | $ | 0.09 |
Net gains on commodity derivative instruments not associated with current-period transactions |  | (0.17 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.17 | )
Unrealized losses on foreign currency derivative instruments |  | 0.06 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.06 |
Loss on extinguishments of debt |  | 0.05 |  |  | 0.05 |  |  | — |  |  | — |  |  | — |  |  | — |
Integration expenses associated with Finagaz |  | 0.08 |  |  | — |  |  | 0.08 |  |  | — |  |  | — |  |  | — |
Impact from December 2016 French Finance Bills |  | (0.15 | ) |  | — |  |  | (0.15 | ) |  | — |  |  | — |  |  | — |
Adjusted diluted earnings (loss) per share |  | $ | 2.31 |  |  | $ | 0.32 |  |  | $ | 0.86 |  |  | $ | 0.47 |  |  | $ | 0.68 |  |  | $ | (0.02 | )

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

(b) | Includes the effects of rounding associated with per share amounts.

(c) | Adjusted diluted earnings per share for the three months ended June 30, 2017, is based upon fully diluted shares of 177.298 million.

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SEGMENT RESULTS OF OPERATIONS
Note - Average temperatures based upon heating degree days for all of our business segments presented below are now based upon recent 15-year periods (rather than recent 30-year periods) as we believe more recent temperatures are a better indication of normal heating degree days. Prior-period weather statistics have been restated, as appropriate, to conform to the new periods.
2018 Three-Month Period Compared to the 2017 Three-Month Period
AmeriGas Propane

For the three months ended June 30, |  | 2018 |  | 2017 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 528.4 |  |  | $ | 467.5 |  |  | $ | 60.9 |  |  | 13.0 | %
Total margin (a) |  | $ | 283.9 |  |  | $ | 270.0 |  |  | $ | 13.9 |  |  | 5.1 | %
Partnership operating and administrative expenses (b) |  | $ | 222.4 |  |  | $ | 227.4 |  |  | $ | (5.0 | ) |  | (2.2 | )%
Impairment of Partnership tradenames and trademarks (c) |  | $ | 75.0 |  |  | $ | — |  |  | $ | 75.0 |  |  | N.M. |
Partnership Adjusted EBITDA (d) |  | $ | 67.2 |  |  | $ | 58.4 |  |  | $ | 8.8 |  |  | 15.1 | %
Operating (loss) income (c)(e) |  | $ | (54.7 | ) |  | $ | 4.6 |  |  | $ | (59.3 | ) |  | N.M. |
Retail gallons sold (millions) |  | 202.0 |  |  | 195.0 |  |  | $ | 7.0 |  |  | 3.6 | %
Heating degree days—% colder (warmer) than normal (f) |  | 9.6 | % |  | (9.6 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended June 30, 2018 and 2017 excludes net pre-tax gains (losses) of $20.3 million and $(6.0) million, respectively, on commodity derivative instruments not associated with current-period transactions.

(b) | Operating and administrative expenses in the 2017 three-month period include a $7.5 million environmental accrual associated with the site of a former MGP obtained in a prior year acquisition.

(c) | The 2018 three-month period includes the impact of a $75.0 million impairment charge associated with the plan to discontinue the use of certain tradenames and trademarks (see Note 6 to condensed consolidated financial statements).

(d) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 15 to condensed consolidated financial statements).

(e) | Operating (loss) income includes certain operating and administrative expenses of the General Partner.

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

N.M. - Variance is not meaningful.
The Partnership’s retail gallons sold during the 2018 three-month period increased 3.6% compared with the prior-year period. The increase in retail gallons sold reflects average temperatures based upon heating degree days that were 9.6% colder than normal and 21.3% colder than the prior-year period. The colder average weather during the 2018 three-month period resulted from average temperatures during April 2018 that were nearly 36% colder than normal compared to average temperatures during April 2017 that were approximately 14% warmer than normal. The benefits from the colder April weather were tempered by significantly warmer temperatures during May.
Retail propane revenues increased $53.6 million during the 2018 three-month period reflecting the effects of higher average retail selling prices ($39.2 million) and the higher retail volumes sold ($14.4 million). Wholesale propane revenues increased $4.4 million reflecting higher wholesale volumes sold ($2.4 million) and the effects of higher average wholesale selling prices ($2.0 million). Average daily wholesale propane commodity prices during the 2018 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were nearly 40% higher than such prices during the 2017 three-month period. Other revenues in the 2018 three-month period were $2.9 million higher than in the prior-year period principally reflecting higher service and ancillary revenues. Total cost of sales increased $47.0 million principally reflecting the effects of higher Partnership average propane product costs ($36.6 million) and the higher propane volumes sold ($8.4 million).
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AmeriGas Propane total margin increased $13.9 million in the 2018 three-month period principally reflecting higher retail propane total margin. The increase in retail propane total margin principally reflects the higher retail volumes sold as a result of the colder early spring weather and slightly higher retail propane unit margins.
Partnership Adjusted EBITDA increased $8.8 million in the 2018 three-month period principally reflecting the effects of the higher total margin ($13.9 million) partially offset by lower gains on sales of assets ($3.1 million) and, excluding the effects of the $7.5 million MGP accrual recorded in the prior-year period, a $2.5 million increase in Partnership operating and administrative expenses. The increase in the Partnership operating and administrative expenses, excluding the effects of the MGP accrual in the prior year, reflects, among other things, higher total compensation and benefits ($5.2 million) and higher vehicle expenses ($3.5 million) offset by lower general insurance and self-insured casualty and liability expense principally reflecting the absence of a settlement with an insurance carrier recorded in the prior-year period.
AmeriGas Propane operating income decreased $59.3 million in the 2018 three-month period as the $13.9 million increase in Partnership total margin and a $5.0 million decrease in operating and administrative costs (including the effects of the $7.5 million MGP accrual in the prior year) were more than offset by the $75.0 million impairment of Partnership tradenames and trademarks and the lower gains on asset sales ($3.1 million).
During the 2017 three-month period, AmeriGas Partners recognized a pre-tax loss of $4.4 million associated with an early repayment of $102.5 million principal amount of AmeriGas Partners’ 7.00% Senior Notes comprising early redemption premiums and the write-off of unamortized debt issuance costs. AmeriGas Propane’s net loss attributable to UGI in the 2017 three-month period includes an after-tax loss of $0.7 million associated with this early extinguishment of debt (see Note 9 to condensed consolidated financial statements).
UGI International

For the three months ended June 30, |  | 2018 |  | 2017 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 533.6 |  |  | $ | 351.3 |  |  | $ | 182.3 |  |  | 51.9 | %
Total margin (a) |  | $ | 219.3 |  |  | $ | 173.1 |  |  | $ | 46.2 |  |  | 26.7 | %
Operating and administrative expenses (b) |  | $ | 173.3 |  |  | $ | 141.1 |  |  | $ | 32.2 |  |  | 22.8 | %
Operating income (b) |  | $ | 9.0 |  |  | $ | 0.5 |  |  | $ | 8.5 |  |  | 1,700.0 | %
Income (loss) before income taxes (b) (c) |  | $ | 3.0 |  |  | $ | (5.2 | ) |  | $ | (8.2 | ) |  | (157.7 | )%
LPG retail gallons sold (millions) |  | 180.0 |  |  | 158.6 |  |  | $ | 21.4 |  |  | 13.5 | %
UGI International degree days—% (warmer) than normal (d) |  | (34.6 | )% |  | (2.7 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended June 30, 2018 and 2017 excludes net pre-tax gains (losses) of $42.9 million and $(5.6) million, respectively, on commodity derivative instruments not associated with current-period transactions.

(b) | Reflects impacts of Finagaz integration expenses for the three months ended June 30, 2018 and 2017, of $7.6 million and $7.0 million, respectively.

(c) | Income before income taxes for the three months ended June 30, 2018 and 2017 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $26.2 million and $(16.0) million, respectively.

(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 2018 three-month period were 34.6% warmer than normal and 32.6% warmer than the prior-year period. Total retail gallons sold during the 2018 three-month period were higher than the prior-year period reflecting incremental volumes sold from our October 2017 acquisition of UniverGas in Italy and the carry-over effects on bulk LPG volumes of cold late-March 2018 weather principally at our legacy operations in France. During the 2018 three-month period, average wholesale prices for propane and butane in northwest Europe were approximately 31% and 37% higher than in the prior-year period, respectively.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During the 2018 and 2017 three-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.19 and $1.11, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.36 and $1.29, respectively. Although the euro and British pound sterling were stronger during the 2018
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three-month period and affected the comparison of line item amounts presented in the table above, the beneficial impact of the stronger currencies on net income was substantially offset by net losses on foreign currency exchange contracts.
UGI International revenues increased $182.3 million during the 2018 three-month period reflecting approximately $82 million of combined incremental revenues from UniverGas and DVEP, the effects of higher LPG selling prices, and the translation effects of the stronger euro and British pound sterling. To a lesser extent, the increase in revenues also reflects the slight increase in our legacy business retail volumes sold. UGI International cost of sales increased $136.1 million during the 2018 three-month period principally reflecting approximately $72 million of incremental cost of sales associated with UniverGas and DVEP, higher LPG commodity costs and the translation effects of the stronger euro and British pound sterling. To a much lesser extent, the increase in cost of sales reflects the slightly higher volumes sold at our legacy operations.
UGI International total margin increased $46.2 million primarily reflecting higher average LPG retail bulk unit margins, the translation effects of the stronger euro and British pound sterling, approximately $10 million of incremental margin from UniverGas and DVEP and, to a lesser extent, the slightly higher legacy business LPG retail volumes sold. The increase in total margin also reflects higher total margin from our legacy natural gas marketing business reflecting higher subscription fee revenue.
The $8.5 million increase in UGI International operating income principally reflects the previously mentioned $46.2 million increase in total margin and slightly higher other non-operating income partially offset by a $32.2 million increase in operating and administrative costs and an $8.7 million increase in depreciation and amortization expense. The increase in operating and administrative costs principally reflects the translation effects of the stronger euro and British pound sterling on legacy business local currency expenses, approximately $9.0 million of incremental expenses from UniverGas and DVEP and higher legacy business operating expenses. The increase in our legacy businesses’ operating and administrative costs reflects, among other things, higher distribution costs and higher compliance costs associated with energy conservation and operational safety requirements. Operating and administrative costs in the 2018 and 2017 three-month periods include $7.6 million and $7.0 million of Finagaz integration costs, respectively. These increases in operating and administrative expenses were partially offset by expense synergies from Finagaz integration activities and lower tank and cylinder repairs and maintenance expense. The higher depreciation and amortization expense reflects the translation effects of the stronger currencies, the net impact of changes in estimated book lives of certain tanks and cylinders, and approximately $2.5 million of incremental depreciation and amortization associated with UniverGas and DVEP. UGI International income before income taxes was $8.2 million higher principally reflecting the previously mentioned $8.5 million increase in UGI International operating income reduced by slightly higher realized losses on foreign currency exchange contracts.
Midstream & Marketing

For the three months ended June 30, |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 263.8 |  |  | $ | 222.8 |  |  | $ | 41.0 |  |  | 18.4 | %
Total margin (a) |  | $ | 48.8 |  |  | $ | 33.4 |  |  | $ | 15.4 |  |  | 46.1 | %
Operating and administrative expenses |  | $ | 30.4 |  |  | $ | 23.1 |  |  | $ | 7.3 |  |  | 31.6 | %
Operating income |  | $ | 7.4 |  |  | $ | 2.8 |  |  | $ | 4.6 |  |  | 164.3 | %
Income before income taxes |  | $ | 8.2 |  |  | $ | 3.3 |  |  | $ | 4.9 |  |  | 148.5 | %

(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended June 30, 2018 and 2017 excludes net pre-tax gains (losses) of $6.2 million and $(25.0) million, respectively, on commodity derivative instruments not associated with current-period transactions.

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 5.1% colder than normal and 26.8% colder than in the prior-year period. Midstream & Marketing 2018 three-month period revenues were $41.0 million higher than the prior year principally reflecting higher natural gas ($19.1 million) and retail power marketing ($3.8 million) revenues, and higher natural gas gathering ($7.9 million) and peaking ($3.6 million) revenues. The increase in natural gas and retail power marketing revenues principally reflects the effects of higher natural gas and retail power volumes resulting from the colder 2018 three-month period temperatures and customer growth. The increase in peaking revenues principally reflects an increase in the number of peaking contracts. The higher natural gas gathering revenues reflects incremental revenues from the Sunbury Pipeline placed in service in August 2017 and incremental revenues from the October 31, 2017 acquisition of the Texas Creek natural gas gathering assets located in north-central Pennsylvania. Electric generation revenues also were higher reflecting higher volumes generated principally from the Hunlock natural-gas fired generation station. Midstream & Marketing cost of sales were $215.0 million in the 2018 three-month period compared to $189.4 million in the 2017 three-month period, an increase of $25.6 million,
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principally reflecting higher natural gas and retail power volumes and prices and higher cost of sales associated with peaking activities.
Midstream & Marketing total margin increased $15.4 million in the 2018 three-month period reflecting higher total margin from our midstream assets ($12.7 million), principally the result of higher natural gas gathering and capacity management total margin, and slightly higher total margin from retail natural gas and power marketing ($1.9 million). The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, incremental margin from the Texas Creek natural gas gathering assets. The increase in capacity management total margin reflects higher capacity values in the current-year period while the increase in retail natural gas and power marketing total margin reflects higher volumes sold in the 2018 three-month period from colder weather early in the period.
Midstream & Marketing operating income and income before income taxes during the 2018 three-month period increased $4.6 million and $4.9 million, respectively. The increase in operating income principally reflects the previously mentioned increase in total margin ($15.4 million) partially offset by higher operating and administrative expenses ($7.3 million), higher depreciation expense ($2.3 million), and a decrease in other operating income primarily from the absence of AFUDC income associated with the Sunbury Pipeline project recorded in the prior-year period. The $7.3 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The $4.9 million increase in income before income taxes in the 2018 three-month period reflects the higher operating income and higher AFUDC income from our PennEast equity investment.
UGI Utilities

For the three months ended June 30, |  | 2018 |  | 2017 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 159.9 |  |  | $ | 146.6 |  |  | $ | 13.3 |  |  | 9.1 | %
Total margin (a)(b) |  | $ | 86.3 |  |  | $ | 93.6 |  |  | $ | (7.3 | ) |  | (7.8 | )%
Operating and administrative expenses (b) |  | $ | 61.6 |  |  | $ | 54.7 |  |  | $ | 6.9 |  |  | 12.6 | %
Operating income |  | $ | 3.9 |  |  | $ | 27.7 |  |  | $ | (23.8 | ) |  | (85.9 | )%
(Loss) income before income taxes |  | $ | (6.1 | ) |  | $ | 17.5 |  |  | $ | (23.6 | ) |  | (134.9 | )%
Gas Utility system throughput—billions of cubic feet (“bcf”) |  |  |  |  |  |  |  |
Core market |  | 11.4 |  |  | 8.7 |  |  | 2.7 |  |  | 31.0 | %
Total |  | 53.7 |  |  | 46.5 |  |  | 7.2 |  |  | 15.5 | %
Electric Utility distribution sales - millions of kilowatt hours (“gwh”) |  | 221.7 |  |  | 209.5 |  |  | 12.2 |  |  | 5.8 | %
Gas Utility heating degree days—% colder (warmer) than normal (c) |  | 5.1 | % |  | (21.2 | )% |  | — |  |  | — |

(a) | In accordance with a PUC Order issued May 17, 2018, revenues and total margin for the three months ended June 30, 2018, have been reduced by $22.7 million to record a regulatory liability related to tax savings for the period January 1, 2018 to June 30, 2018 as a result of the TCJA (see Notes 5 and 7 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 $1.1 million and $1.0 million during the three months ended June 30, 2018 and 2017, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating expenses presented above).

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

Temperatures in Gas Utility’s service territory during the three months ended June 30, 2018, were 5.1% colder than normal and 33.3% colder than during the three months ended June 30, 2017. The colder weather occurred during the month of April, which was 33.6% colder than normal. Gas Utility core market volumes increased 2.7 bcf (31.0%) principally reflecting the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 7.2 bcf principally reflecting higher large firm and interruptible delivery service volumes and higher core market volumes. Electric Utility kilowatt-hour sales were 5.8% higher than the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.
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UGI Utilities revenues increased $13.3 million reflecting a $10.8 million increase in Gas Utility revenues and higher Electric Utility revenues. In accordance with a PUC Order issued May 17, 2018, Gas Utility’s revenues were reduced by $22.7 million, and an associated regulatory liability established, to record tax savings that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $33.5 million principally reflecting an increase in core market revenues ($27.1 million) and higher large firm delivery service revenues ($5.9 million).
The $27.1 million increase in Gas Utility core market revenues reflects the effects of the higher core market throughput ($19.5 million), higher average retail core market PGC rates ($6.5 million) and the increase in PNG base rates effective October 20, 2017 ($1.1 million). The increase in Electric Utility revenues principally reflects the higher distribution system sales and slightly higher average DS rates ($2.3 million). UGI Utilities cost of sales was $72.5 million in the three months ended June 30, 2018 compared with $52.0 million in the three months ended June 30, 2017, principally reflecting higher Gas Utility cost of sales ($18.7 million) and higher Electric Utility cost of sales ($1.9 million) from higher distribution system sales and the slightly higher DS rates. The higher Gas Utility cost of sales reflects higher retail core-market volumes ($9.8 million), higher average retail core-market PGC rates ($6.5 million) and, to a lesser extent, higher large firm delivery service cost of sales.
UGI Utilities total margin decreased $7.3 million reflecting the impact of the $22.7 million reduction in revenues resulting from the previously mentioned PUC Order. Excluding this reduction, UGI Utilities total margin increased $15.4 million principally reflecting higher total margin from Gas Utility core market customers ($11.0 million) and higher large firm delivery service total margin ($3.1 million). The increase in Gas Utility core market margin reflects, among other things, the higher core market throughput ($10.1 million) and the increase in PNG base rates effective October 20, 2017 ($0.9 million). Electric Utility total margin increased slightly principally reflecting the higher distribution volumes sold.
UGI Utilities operating income decreased $23.8 million, principally reflecting the decrease in total margin ($7.3 million), higher Gas Utility and Electric Utility operating and administrative expenses ($6.9 million), greater depreciation and amortization expense ($3.5 million), and lower other operating income ($6.1 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher general and administrative costs including higher information technology (“IT”) maintenance and consulting expenses ($2.4 million), higher distribution system expenses ($1.7 million), and higher uncollectible accounts expense ($1.5 million). The increase in depreciation and amortization expense reflects increased distribution system and IT capital expenditure activity. The decrease in other operating income principally reflects the absence of $5.8 million of income from an environmental insurance settlement recorded in the prior-year three-month period. UGI Utilities income before income taxes decreased $23.6 million reflecting the decrease in UGI Utilities operating income.
Interest Expense and Income Taxes
Our consolidated interest expense during the 2018 three-month period was $56.5 million, comparable to the $56.8 million of interest expense recorded during the 2017 three-month period.
As previously mentioned, our consolidated income taxes for the three months ended June 30, 2018, were impacted by the enactment of the TCJA and the December 2017 French Finance Bills. Accordingly, our effective tax rate as calculated based upon amounts on our condensed consolidated statement of income for the 2018 three-month period includes the effects of the lower U.S. federal income tax rate of 24.5% in the 2018 three-month period compared with 35% in the prior-year period. These changes from the TCJA decreased income taxes for the 2018 three-month period by approximately $6.1 million. Substantially all of this decrease in income taxes resulting from the TCJA relates to our non-utility businesses. The December 2017 French Finance Bills did not have a material impact on results for the 2018 three-month period. Income taxes in the 2018 three-month period also reflect higher excess tax benefits ($5.0 million) from share-based awards.
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2018 Nine-Month Period Compared to the 2017 Nine-Month Period
AmeriGas Propane

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,356.0 |  |  | $ | 2,008.3 |  |  | $ | 347.7 |  |  | 17.3 | %
Total margin (a) |  | $ | 1,261.7 |  |  | $ | 1,194.3 |  |  | $ | 67.4 |  |  | 5.6 | %
Partnership operating and administrative expenses (b) |  | $ | 704.1 |  |  | $ | 694.2 |  |  | $ | 9.9 |  |  | 1.4 | %
Impairment of Partnership tradenames and trademarks (c) |  | $ | 75.0 |  |  | $ | — |  |  | $ | 75.0 |  |  | N.M. |
Partnership Adjusted EBITDA (d) |  | $ | 570.8 |  |  | $ | 514.7 |  |  | $ | 56.1 |  |  | 10.9 | %
Operating income (c)(e)(f) |  | $ | 359.8 |  |  | $ | 373.8 |  |  | $ | (14.0 | ) |  | (3.7 | )%
Retail gallons sold (millions) |  | 905.5 |  |  | 863.4 |  |  | $ | 42.1 |  |  | 4.9 | %
Heating degree days—% colder (warmer) than normal (g) |  | 0.4 | % |  | (11.5 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2018 and 2017 excludes net pre-tax losses of $10.1 million and $8.9 million, respectively, on commodity derivative instruments not associated with current-period transactions.

(b) | Operating and administrative expenses in the 2017 nine-month period include a $7.5 million environmental accrual associated with the site of a former MGP obtained in a prior year acquisition.

(c) | The 2018 nine-month period includes the impact of the $75.0 million impairment charge associated with the plan to discontinue the use of certain tradenames and trademarks (see Note 6 to condensed consolidated financial statements).

(d) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 15 to condensed consolidated financial statements).

(e) | Amounts for the nine months ended June 30, 2017, reflect adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which adjustments reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.

(f) | Operating income reflects certain operating and administrative expenses of the General Partner.

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

N.M. - Variance is not meaningful.
AmeriGas Propane’s retail gallons sold during the 2018 nine-month period were 4.9% higher than in the prior-year period. Average temperatures based upon heating degree days during the 2018 nine-month period were 0.4% colder than normal and 13.5% colder than the prior-year period.
AmeriGas Propane retail propane revenues increased $317.4 million during the 2018 nine-month period reflecting the effects of higher average retail selling prices ($231.0 million) and higher retail volumes sold ($86.4 million). Wholesale propane revenues increased $20.0 million reflecting the effects of higher average wholesale selling prices ($11.3 million) and higher wholesale volumes sold ($8.7 million). Average daily wholesale propane commodity prices during the 2018 nine-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were nearly 40% higher than such prices during the 2017 nine-month period. Other revenues in the 2018 nine-month period were slightly higher than in the prior-year period principally reflecting higher service and ancillary revenues. AmeriGas Propane cost of sales increased $280.3 million principally reflecting the effects on propane cost of sales of higher average total propane product costs ($232.3 million) and, to a much lesser extent, the effects of the higher retail and wholesale propane volumes sold ($43.5 million).
AmeriGas Propane total margin increased $67.4 million principally reflecting slightly higher retail propane total margin ($61.6 million) and slightly higher non-propane total margin ($5.8 million). The increase in retail propane total margin reflects the higher retail volumes sold and, to a much lesser extent, slightly higher average retail propane unit margins.
Partnership Adjusted EBITDA increased $56.1 million in the 2018 nine-month period principally reflecting the effects of the higher total margin ($67.4 million) and higher other operating income ($6.7 million) partially offset by a $17.4 million increase in Partnership operating and administrative expenses excluding the effects of the $7.5 million MGP accrual in the prior-year period. The increase in other operating income reflects the absence of an $8.8 million adjustment recorded in the prior-year period to
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correct previously recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012. The previously mentioned increase in operating and administrative expenses reflects, among other things, higher total compensation and benefits cost ($15.6 million), principally higher labor, overtime and incentive compensation costs associated with the increased activity and improved performance; higher vehicle expenses ($8.7 million); and higher outside services expense ($5.9 million). These increases in operating expenses were partially offset principally by lower general insurance and self-insured casualty and liability expense.
AmeriGas Propane operating income decreased $14.0 million in the 2018 nine-month period as the $67.4 million increase in Partnership total margin and the higher other operating income ($6.7 million) were more than offset by the $75.0 million impairment of Partnership tradenames and trademarks, a $9.9 million increase in operating and administrative costs (including the effects of the $7.5 million MGP accrual in the prior year), and a $3.2 million increase in depreciation and amortization expense.
During the 2017 nine-month period, AmeriGas Partners recognized a pre-tax loss of $59.7 million associated with early repayments of $980.8 million principal amount of AmeriGas Partners’ 7.00% Senior Notes comprising early redemption premiums and the write-off of unamortized debt issuance costs. AmeriGas Propane’s net income attributable to UGI in the 2017 nine-month period includes an after-tax loss of $9.6 million associated with this early redemption of debt (see Note 9 to condensed consolidated financial statements)
UGI International

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,227.4 |  |  | $ | 1,511.1 |  |  | $ | 716.3 |  |  | 47.4 | %
Total margin (a) |  | $ | 887.2 |  |  | $ | 761.8 |  |  | $ | 125.4 |  |  | 16.5 | %
Operating and administrative expenses (b) |  | $ | 546.7 |  |  | $ | 466.3 |  |  | $ | 80.4 |  |  | 17.2 | %
Operating income (b) |  | $ | 233.9 |  |  | $ | 210.4 |  |  | $ | 23.5 |  |  | 11.2 | %
Income before income taxes (b) (c) |  | $ | 203.1 |  |  | $ | 195.0 |  |  | $ | 8.1 |  |  | 4.2 | %
LPG retail gallons sold (millions) |  | 721.7 |  |  | 665.9 |  |  | $ | 55.8 |  |  | 8.4 | %
UGI International degree days—% (warmer) colder than normal (d) |  | (4.1 | )% |  | 0.1 | % |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2018 and 2017 excludes net pre-tax gains (losses) of $39.3 million and $(7.1) million, respectively, on commodity derivative instruments not associated with current-period transactions.

(b) | Reflects impacts of Finagaz integration expenses for the nine months ended June 30, 2018 and 2017, of $20.8 million and $21.8 million, respectively.

(c) | Income before income taxes for the nine months ended June 30, 2018 and 2017 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $24.1 million and $(16.1) million, respectively.

(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 2018 nine-month period were approximately 4.1% warmer than normal and the prior-year period. Total retail gallons sold during the 2018 nine-month period were higher than the prior-year period principally reflecting retail LPG gallons sold as a result of our October 2017 acquisition of UniverGas and slightly higher legacy business retail LPG bulk volumes partially offset by slightly lower crop-drying volumes early in the 2018 nine-month period. During the 2018 nine-month period, average wholesale prices for propane and butane in northwest Europe were slightly 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. 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 2018 and 2017 nine-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.20 and $1.08, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.36 and $1.26, respectively. Although the euro and British pound sterling were stronger during the 2018 nine-month period and affected the comparison of line item amounts presented in the table above, the beneficial impact of the stronger currencies on net income was substantially offset by net losses on foreign currency exchange contracts.
UGI International revenues increased $716.3 million during the 2018 nine-month period reflecting approximately $355 million of combined incremental revenues from UniverGas and DVEP, the translation effects on legacy business revenues of the stronger euro and British pound sterling, and higher LPG selling prices. The higher LPG selling prices reflect in large part the effects of
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slightly higher LPG product costs. During the 2018 nine-month period, average unweighted wholesale commodity prices for propane and butane in northwest Europe were approximately 20% and 14% higher than in the prior-year period, respectively. UGI International cost of sales increased $590.9 million during the 2018 nine-month period reflecting approximately $306 million of incremental cost of sales associated with UniverGas and DVEP, the effects on cost of sales from the higher average LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.
UGI International total margin increased $125.4 million. The increase in total margin principally reflects the translation effects of the stronger euro and British pound sterling and approximately $49 million of incremental margin from UniverGas and DVEP.
The $23.5 million increase in UGI International operating income principally reflects the previously mentioned $125.4 million increase in total margin partially offset by an $80.4 million increase in operating and administrative expenses and a $20.3 million increase in depreciation and amortization expense. The increase in operating and administrative costs principally reflects the translation effects of the stronger euro and British pound sterling on local currency expenses and approximately $29 million of incremental expenses from UniverGas and DVEP. The increase in operating and administrative costs also reflects, among other things, higher compliance costs associated with energy conservation and operational safety requirements and slightly higher distribution costs offset by lower tank and cylinder repair costs. Operating and administrative costs in the 2018 and 2017 nine-month periods include $20.8 million and $21.8 million of Finagaz integration costs, respectively. The increase in depreciation and amortization reflects the translation effects of the stronger currencies, incremental amounts associated with UniverGas and DVEP ($7.5 million), and the impact of changes in estimated book lives of certain tanks and cylinders. UGI International income before income taxes increased $8.1 million principally reflecting the previously mentioned $23.5 million increase in UGI International operating income reduced by higher realized losses on foreign currency exchange contracts ($14.2 million) and slightly higher interest expense due to the effects of the stronger euro.
Midstream & Marketing

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 1,157.0 |  |  | $ | 916.3 |  |  | $ | 240.7 |  |  | 26.3 | %
Total margin (a) |  | $ | 284.4 |  |  | $ | 225.3 |  |  | $ | 59.1 |  |  | 26.2 | %
Operating and administrative expenses |  | $ | 85.5 |  |  | $ | 70.1 |  |  | $ | 15.4 |  |  | 22.0 | %
Operating income |  | $ | 167.2 |  |  | $ | 134.6 |  |  | $ | 32.6 |  |  | 24.2 | %
Income before income taxes |  | $ | 168.4 |  |  | $ | 136.2 |  |  | $ | 32.2 |  |  | 23.6 | %

(a) | Total margin represents total revenues less total cost of sales. Total margin for the nine months ended June 30, 2018, 2018 and 2017 excludes net pre-tax gains of $0.8 million and $61.1 million, respectively, on commodity derivative instruments not associated with current-period transactions.

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1% warmer than normal during the 2018 nine-month period but 12.6% colder than in the prior-year period. Midstream & Marketing 2018 nine-month period revenues were $240.7 million higher reflecting higher natural gas ($165.2 million) and retail power marketing ($11.3 million) revenues; higher revenues from midstream assets ($53.3 million), principally higher natural gas gathering, peak shaving, and capacity management revenues; and higher electric generation revenues ($13.1 million). The increase in natural gas revenues principally reflects the effects of higher natural gas volumes on colder 2018 nine-month period temperatures and customer growth. The increase in capacity management and peaking revenues reflects the effects of colder weather primarily in January and, with respect to peaking revenues, also an increase in the number of peaking contracts. The higher natural gas gathering revenues reflects incremental revenues from the Sunbury Pipeline and from the Texas Creek natural gas gathering assets acquired October 31, 2017. Electric generation revenues reflect higher volumes generated principally from the Hunlock natural-gas fired generation station and slightly higher average selling prices. Midstream & Marketing cost of sales were $872.6 million in the 2018 nine-month period compared to $691.0 million in the 2017 nine-month period, an increase of $181.6 million, principally reflecting higher natural gas and retail power cost of sales primarily a result of the higher natural gas volumes and higher average natural gas and retail power costs.
Midstream & Marketing total margin increased $59.1 million in the 2018 nine-month period reflecting higher total margin from our midstream assets ($47.7 million), principally the result of higher natural gas gathering, capacity management and peaking total margin, higher electricity generation total margin ($8.0 million) and, to a much lesser extent, higher natural gas marketing total margin on higher volumes sold. The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, margin from the Texas Creek natural gas gathering assets. The increase in capacity management and peaking total margin reflects in large part the effects of extremely cold weather primarily in January, higher capacity values
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during the third quarter of Fiscal 2018 and, with respect to peaking margin, an increase in the number of peaking contracts. The higher electricity generation total margin reflects higher electric generation volumes principally at our Hunlock Station generating facility and higher electricity unit margins.
Midstream & Marketing operating income and income before income taxes during the 2018 nine-month period increased $32.6 million and $32.2 million, respectively. The increase in operating income principally reflects the previously mentioned increase in total margin ($59.1 million) partially offset by higher operating and administrative expenses ($15.4 million), higher depreciation expense ($6.4 million), and a decrease in other operating income primarily from the absence of AFUDC income associated with the Sunbury Pipeline project recorded in the prior-year period ($4.9 million). The $15.4 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The $32.2 million increase in income before income taxes in the 2018 nine-month period principally reflects the higher operating income partially offset by higher interest expense.
UGI Utilities

For the nine months ended June 30, |  | 2018 |  | 2017 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 966.3 |  |  | $ | 768.0 |  |  | $ | 198.3 |  |  | 25.8 | %
Total margin (a)(b) |  | $ | 481.0 |  |  | $ | 438.5 |  |  | $ | 42.5 |  |  | 9.7 | %
Operating and administrative expenses (b) |  | $ | 184.3 |  |  | $ | 167.0 |  |  | $ | 17.3 |  |  | 10.4 | %
Operating income |  | $ | 235.3 |  |  | $ | 226.3 |  |  | $ | 9.0 |  |  | 4.0 | %
Income before income taxes |  | $ | 203.3 |  |  | $ | 195.8 |  |  | $ | 7.5 |  |  | 3.8 | %
Gas Utility system throughput—bcf |  |  |  |  |  |  |  |
Core market |  | 75.8 |  |  | 65.4 |  |  | 10.4 |  |  | 15.9 | %
Total |  | 210.2 |  |  | 194.6 |  |  | 15.6 |  |  | 8.0 | %
Electric Utility distribution sales - gwh |  | 747.0 |  |  | 710.5 |  |  | 36.5 |  |  | 5.1 | %
Gas Utility heating degree days—% (warmer) than normal (c) |  | (1.3 | )% |  | (11.3 | )% |  | — |  |  | — |

(a) | In accordance with a PUC Order issued May 17, 2018, revenues and total margin for the nine months ended June 30, 2018, have been reduced by $24.1 million to record a regulatory liability related to tax savings for the period January 1, 2018 to June 30, 2018 as a result of the TCJA (see Notes 5 and 7 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 $3.7 million and $3.5 million during the nine months ended June 30, 2018 and 2017, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating expenses presented above).

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

Temperatures in Gas Utility’s service territory during the nine months ended June 30, 2018, were 1.3% warmer than normal but 11.3% colder than during the nine months ended June 30, 2017. Gas Utility core market volumes increased 10.4 bcf (15.9%) reflecting, among other things, the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 15.6 bcf principally reflecting the higher core market volumes and slightly higher large firm delivery service volumes. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 5.1% higher than the prior-year period, principally reflecting the impact of the colder weather on Electric Utility heating-related sales.
UGI Utilities revenues increased $198.3 million reflecting a $193.7 million increase in Gas Utility revenues and higher Electric Utility revenues. In accordance with a PUC Order issued May 17, 2018, during the 2018 nine-month period Gas Utility’s revenues were reduced by $24.1 million, and an associated regulatory liability established, to record tax savings that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $217.8 million principally reflecting an increase in core market revenues ($148.4 million), higher off-system sales revenues ($52.7 million), and higher large firm delivery service revenues ($17.6 million).
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The $148.4 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput ($72.1 million), higher average retail core market PGC rates ($64.3 million) and the increase in PNG base rates effective October 20, 2017 ($12.0 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system sales ($4.9 million). UGI Utilities cost of sales was $481.6 million in the nine months ended June 30, 2018 compared with $326.0 million in the nine months ended June 30, 2017, principally reflecting higher Gas Utility cost of sales ($152.1 million) and higher Electric Utility cost of sales ($3.5 million) reflecting the higher electricity sales. The higher Gas Utility cost of sales principally reflects higher average retail core market PGC rates ($64.3 million), higher cost of sales associated with Gas Utility off-system sales ($52.7 million), and higher retail core-market volumes ($37.0 million).
UGI Utilities total margin increased $42.5 million principally reflecting higher total margin from Gas Utility core market customers ($53.3 million) and higher large firm delivery service total margin ($11.0 million) partially offset by the previously mentioned impact of a $24.1 million reduction in revenues resulting from the previously mentioned PUC Order. The increase in Gas Utility core market margin principally reflects the higher core market throughput ($42.7 million) and the increase in PNG base rates effective October 20, 2017 ($10.6 million). Electric Utility total margin increased $0.9 million principally reflecting the higher distribution system sales.
UGI Utilities operating income increased $9.0 million, principally reflecting the increase in total margin ($42.5 million) partially offset by higher operating and administrative expenses ($17.3 million), greater depreciation and amortization expense ($9.9 million) associated with increased distribution system and IT capital expenditure activity, and lower other operating income ($6.2 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($8.5 million), higher contractor and outside services expenses ($4.3 million), higher compensation and benefits expenses ($3.5 million) and higher IT maintenance and consulting expenses ($3.2 million). The decrease in other operating income principally reflects the absence of $5.8 million of income from an environmental insurance settlement recorded in the prior-year nine-month period. UGI Utilities income before income taxes increased $7.5 million reflecting the increase in UGI Utilities operating income ($9.0 million) partially offset by slightly higher interest expense.
Although the increase in UGI Utilities’ income before income taxes for the 2018 nine-month period was only $7.5 million (3.8%), UGI Utilities’ adjusted net income attributable to UGI increased $25.1 million (20.9%). UGI Utilities’ income before income taxes for the 2018 nine-month period was negatively impacted by the previously mentioned $24.1 million reduction in revenues pursuant to the PUC Order regarding income tax savings for the period January 1, 2018 to June 30, 2018. UGI Utilities’ net income, however, reflects the benefits of a $24.1 million reduction in income taxes principally as a result of the lower blended federal income tax rate in the 2018 nine-month period.
Interest Expense and Income Taxes
Our consolidated interest expense during the 2018 nine-month period was $172.8 million, $4.8 million higher than the $168.0 million of interest expense recorded during the 2017 nine-month period. The higher interest expense principally reflects the effects of higher long-term debt outstanding at AmeriGas Propane and UGI Utilities and the effects of the stronger euro on UGI International interest expense. These increases were partially offset by lower average interest rates on long-term debt at AmeriGas Propane and lower average debt outstanding at UGI International.
As previously mentioned, our consolidated income taxes for the nine months ended June 30, 2018, were impacted by the enactment of the TCJA and the December 2017 French Finance Bills. Accordingly, the effective tax rate as calculated based upon amounts reflected on our condensed consolidated statement of income for the 2018 nine-month period includes the one-time effects of the TCJA and the December 2017 French Finance Bills on deferred income taxes and deferred tax valuation allowances which reduced income tax expense by $185.6 million.
The effective income tax rate in the 2017 nine-month period reflects the impact of a December 2016 change in the French corporate income tax rate for future years which reduced consolidated income tax expense by $27.4 million and, to a much lesser extent, the effects of an income tax settlement refund of $6.7 million, plus interest, in France.
Excluding the impacts of the one-time, discrete adjustments from the TCJA and French tax rate changes in the 2018 and 2017 nine-month periods noted above, our effective income tax rate for the 2018 nine-month period was lower than in the prior-year period principally reflecting the lower blended U.S. tax rate of 24.5% in the 2018 nine-month period compared with 35% in the prior-year period. This benefit was partially offset by the slightly higher Fiscal 2018 income tax rate in France resulting from the 2017 French Finance Bills. The TCJA and the December 2017 French Finance Bills (decreased) increased 2018 nine-month period income taxes by $(60.6) million and $4.7 million, respectively. On a combined basis, these tax law changes increased adjusted net income attributable to UGI by $55.9 million (equal to $0.32 per diluted share). In accordance with the PUC Order issued May 17, 2018, during the 2018 nine-month period, UGI Utilities reduced its revenues and established a regulatory liability associated
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with $17.1 million (equal to $0.10 per diluted share) of tax benefits resulting from the change in the federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. The rate treatment of this regulatory liability will be addressed in a future proceeding.
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 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 Receivable Facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents totaled $506.7 million at June 30, 2018, compared with $558.4 million at September 30, 2017. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at June 30, 2018 and September 30, 2017, UGI had $184.3 million and $291.1 million of cash and cash equivalents, respectively, most of which are located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
Long-term Debt and Short-term Borrowings
Long-term Debt
The Company’s debt outstanding at June 30, 2018 and September 30, 2017, comprises the following:

| June 30, 2018 |  | September 30, 2017
(Millions of dollars) | AmeriGas Propane |  | UGI International |  | Midstream & Marketing |  | UGI Utilities |  | Other |  | Total |  | Total
Short-term borrowings | $ | 177.0 |  |  | $ | 3.6 |  |  | $ | — |  |  | $ | 118.5 |  |  | $ | — |  |  | $ | 299.1 |  |  | $ | 366.9 |
Long-term debt (including current maturities): |  |  |  |  |  |  |  |  |  |  |  |  |
Senior notes | $ | 2,575.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 675.0 |  |  | $ | — |  |  | $ | 3,250.0 |  |  | $ | 3,250.0 |
Term loans and notes | — |  |  | 732.5 |  |  | — |  |  | 161.9 |  |  | — |  |  | 894.4 |  |  | 902.1 |
Other long-term debt | 27.8 |  |  | 21.4 |  |  | 0.5 |  |  | 7.8 |  |  | 9.0 |  |  | 66.5 |  |  | 59.8 |
Unamortized debt issuance costs | (28.5 | ) |  | (3.1 | ) |  | — |  |  | (4.2 | ) |  | (0.1 | ) |  | (35.9 | ) |  | (39.8 | )
Total long-term debt | $ | 2,574.3 |  |  | $ | 750.8 |  |  | $ | 0.5 |  |  | $ | 840.5 |  |  | $ | 8.9 |  |  | $ | 4,175.0 |  |  | $ | 4,172.1 |
Total debt | $ | 2,751.3 |  |  | $ | 754.4 |  |  | $ | 0.5 |  |  | $ | 959.0 |  |  | $ | 8.9 |  |  | $ | 4,474.1 |  |  | $ | 4,539.0 |

UGI International. In December 2017, Flaga repaid $9.2 million of the outstanding principal amount of its then-existing $59.1 million U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amends and restates the previous agreement to provide for a principal balance of $49.9 million and extends the maturity of the term loan to April 2020 (the “Flaga U.S. Dollar Term Loan”). The outstanding principal bears interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
UGI Utilities. In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6 million, commencing March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus
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a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. In July 2018, UGI Utilities entered into forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge.
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 5 to the Consolidated Financial Statements in the Company’s 2017 Annual Report.
Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of June 30, 2018 and 2017, is presented in the table below.

(Currency in millions) |  | Total Capacity |  | Borrowings Outstanding |  | Letters of Credit and Guarantees Outstanding |  | Available Borrowing Capacity
As of June 30, 2018 |  |  |  |  |  |  |  |
AmeriGas OLP |  | $ | 600.0 |  |  | $ | 177.0 |  |  | $ | 67.2 |  |  | $ | 355.8 |
UGI International, LLC |  | € | 300.0 |  |  | € | — |  |  | € | — |  |  | € | 300.0 |
UGI France SAS |  | € | 60.0 |  |  | € | — |  |  | € | — |  |  | € | 60.0 |
Flaga (a) |  | € | 55.0 |  |  | € | — |  |  | € | 1.0 |  |  | € | 54.0 |
Energy Services, LLC |  | $ | 240.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 240.0 |
UGI Utilities |  | $ | 300.0 |  |  | $ | 118.5 |  |  | $ | 2.0 |  |  | $ | 179.5 |
As of June 30, 2017 |  |  |  |  |  |  |  |
AmeriGas OLP |  | $ | 525.0 |  |  | $ | 75.5 |  |  | $ | 67.2 |  |  | $ | 382.3 |
UGI France SAS |  | € | 60.0 |  |  | € | — |  |  | € | — |  |  | € | 60.0 |
Flaga (a) |  | € | 55.0 |  |  | € | — |  |  | € | 7.0 |  |  | € | 48.0 |
Energy Services, LLC |  | $ | 240.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 240.0 |
UGI Utilities |  | $ | 300.0 |  |  | $ | 50.0 |  |  | $ | 2.0 |  |  | $ | 248.0 |

(a) | Total capacity comprises a €25 million multi-currency revolving credit facility, a €5 million overdraft facility and a €25 million guarantee facility. Guarantees outstanding reduce the available capacity on the €25 million guarantee facility.

The average daily and peak short-term borrowings under the Company’s principal credit agreements during the nine months ended June 30, 2018 and 2017 are as follows:

|  | For the nine months ended June 30, 2018 |  | For the nine months ended June 30, 2017
(Currency in millions) |  | Average |  | Peak |  | Average |  | Peak
AmeriGas OLP |  | $ | 186.3 |  |  | $ | 349.0 |  |  | $ | 83.0 |  |  | $ | 292.5 |
UGI International, LLC |  | € | — |  |  | € | — |  |  | € | — |  |  | € | — |
UGI France SAS |  | € | — |  |  | € | — |  |  | € | — |  |  | € | — |
Flaga |  | € | — |  |  | € | — |  |  | € | — |  |  | € | — |
Energy Services, LLC |  | $ | 20.7 |  |  | $ | 79.0 |  |  | $ | 8.4 |  |  | $ | 28.0 |
UGI Utilities |  | $ | 150.0 |  |  | $ | 215.0 |  |  | $ | 74.5 |  |  | $ | 137.0 |

AmeriGas Partners. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 million (including a $150 million sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings
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ranges from 1.50% to 2.75%. For additional information regarding the AmeriGas Credit Agreement, see Note 9 to the condensed consolidated financial statements.
UGI International. In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "UGI International Credit Agreement") with a group of banks providing for borrowings up to €300 million. The UGI International Credit Agreement is scheduled to expire in April 2020. Under the UGI International Credit 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 1.45% to 2.35%. Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%. For additional information regarding the UGI International Credit Agreement, see Note 9 to the condensed consolidated financial statements.
Midstream & Marketing. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. Energy Services, LLC intends to extend the Receivables Facility prior to its scheduled expiration. At June 30, 2018, the outstanding balance of ESFC trade receivables was $58.3 million, of which none were sold to the bank. At June 30, 2017, the outstanding balance of ESFC trade receivables was $51.6 million and there were $30.0 million amounts sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. During the nine months ended June 30, 2018 and 2017, peak sales of receivables were $68.0 million and $49.0 million, respectively, and average daily amounts sold were $14.8 million and $10.9 million, respectively. For additional information regarding the Receivables Facility, see Note 8 to the condensed consolidated financial statements.
Dividends and Distributions
On July 24, 2018, UGI’s Board of Directors approved a quarterly dividend of $0.26 per Common Share payable October 1, 2018, to shareholders of record on September 14, 2018. On April 24, 2018, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26 per Common Share, or $1.04 on an annual basis. The new dividend rate reflects an approximate 4% increase from the previous quarterly rate of $0.25. The new quarterly dividend rate was effective with the dividend payable on July 1, 2018, to shareholders of record on June 15, 2018.
On July 23, 2018, the General Partner’s Board of Directors approved a quarterly distribution of $0.95 per Common Unit payable August 17, 2018, to unitholders of record on August 10, 2018. During the nine months ended June 30, 2018, AmeriGas Partners declared and paid quarterly distributions on all limited partner units at a rate of $0.95 per Common Unit for the quarters ended March 31, 2018, December 31, 2017 and September 30, 2017.
Repurchase of Common Stock
In January 2014, UGI’s Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, expiring in January 2018. On January 25, 2018, UGI’s Board of Directors authorized an extension of the share repurchase program for up to 8 million shares of UGI Corporation Common Stock for an additional four-year period expiring in January 2022.
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities. Cash flow provided by operating activities was $926.8 million in the 2018 nine-month period compared to $846.0 million in the 2017 nine-month period. Cash flow from operating activities before changes in operating working capital was $1,043.8 million in the 2018 nine-month period compared to $976.7 million in the prior-year period. The higher cash flow from operating activities before changes in operating working capital principally reflects the improved operating results in the current-year period. Cash used to fund changes in operating working capital totaled $117.0 million in the 2018 nine-month period compared to $130.7 million in the prior-year period. Higher cash required to fund changes in accounts receivable was partially offset by higher cash from changes in other current liabilities including accrued income taxes, and higher overcollections of deferred fuel costs at UGI Utilities. The higher cash needed to fund changes in accounts receivable reflects, in large part, the impact of higher volumes sold and higher LPG and natural gas costs.
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Investing Activities. Cash flow used by investing activities was $572.9 million in the 2018 nine-month period compared with $531.7 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses and assets; changes in restricted cash balances; investments in investees; and proceeds from sales of assets and businesses. Cash payments for property, plant and equipment were $394.2 million in the 2018 nine-month period compared to $471.9 million in the prior-year period. Cash payments in the prior-year include capital expenditures associated with the Sunbury Pipeline project at Midstream & Marketing. Cash used for acquisitions of businesses and assets in the 2018 nine-month period principally reflects UGI International’s acquisition of UniverGas, Midstream & Marketing’s acquisition of the Texas Creek natural gas gathering assets, and a small acquisition by AmeriGas Propane.
Financing Activities. Cash flow used by financing activities was $402.3 million in the 2018 nine-month period compared with $217.1 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 AmeriGas Partners Common Units; and, from time to time, issuances of UGI and AmeriGas Partners equity instruments. In October 2017, UGI Utilities issued $125 million of unsecured notes and used the proceeds principally to reduce short-term borrowings and for general corporate purposes. Repayments of debt during the 2018 nine-month principally include, among others, UGI Utilities’ repayments of $40 million of maturing Medium-Term Notes and UGI International’s repayments of approximately $82 million of term-loan debt at UGI France SAS and Flaga.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the 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 (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20-day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one-for-one basis.
IMPACT OF TAX REFORM
U.S. Tax Reform
On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, 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. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities and applies a broader application of compensation limitations.
As a result, in December 2017, we reduced our net deferred income tax liabilities due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of enactment. We adjusted these original provisional amounts during the three months ended March 31, 2018 and June 30, 2018. Because part of the reduction relates to our regulated utility plant assets, most of the reduction to UGI Utilities’ deferred income taxes is not being recognized immediately in income tax expense and UGI Utilities has recorded a regulatory liability associated with these excess deferred income taxes which is being amortized over the remaining lives of the assets that gave rise to such excess deferred income taxes. The amount of the reduction in our net deferred income tax liabilities resulting from the TCJA that reduced income tax expense totaled $0.8 million and $172.1 million for the three and nine months ended June 30, 2018, respectively.
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In addition to the adjustments to our net deferred income tax liabilities that reduced our income tax expense as noted above, our income tax expense for the three and nine months ended June 30, 2018, was further reduced by approximately $6.1 million and $60.6 million, respectively, principally as a result of our lower Fiscal 2018 blended income tax rate of 24.5%.
On May 17, 2018, the PUC issued an Order requiring Pennsylvania utilities, including UGI Gas, CPG and PNG, 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 as a result of the TCJA. During the nine months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $24.1 million, and recorded a regulatory liability in an equal amount, to reflect (1) $17.1 million of tax benefits accrued during the period January 1, 2018 to June 30, 2018, plus (2) $7.0 million of tax benefits expected to be generated by the future amortization of the regulatory liability.
For a more detailed description of the impacts of the TCJA including the impacts on our regulated utility operations, see Note 5 and Note 7 to condensed consolidated financial statements.
Changes in French Corporate Income Tax Rates
In December 2017, the French Parliament approved the December 2017 French Finance Bills. One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4%. 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 as of the date of enactment. We adjusted these provisional amounts during the three month periods ended March 31, 2018 and June 30, 2018. The amount of the reduction in our net deferred income tax liabilities resulting from the December 2017 French Finance Bills (increased) decreased income tax expense by $(0.1) million and $13.5 million during the three and nine months ended June 30, 2018, respectively.
In addition to the adjustments to deferred income taxes resulting from the December 2017 French Finance Bills, net income attributable to UGI for the three and nine months ended June 30, 2018, also reflects the impact on income taxes of the higher single-year Fiscal 2018 income tax rate in France. The higher Fiscal 2018 income tax rate in France (decreased) increased income tax expense by approximately $(0.2) million and $4.7 million during the three and nine months ended June 30, 2018, respectively.
For a more detailed description of the impacts of the December 2017 French Finance Bills, see Note 5 to condensed consolidated financial statements.
UTILITY REGULATORY MATTERS
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9.2 million, which was later reduced by the Company to $7.7 million to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March 27, 2018. The PUC entered an Order dated March 1, 2018, suspending the effective date for the rate increase to allow for investigation and public hearings in a review process that is expected to last up to nine months from the date of filing. The matter is currently pending before two PUC administrative law judges who are expected to issue a recommended decision that will be the subject of a final decision by the PUC. Although the Company expects to receive a final decision from the PUC in October 2018, the Company cannot predict the timing or the ultimate outcome of the rate case review process.
On August 31, 2017, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 million annual base distribution rate increase for PNG. The increase became effective on October 20, 2017.
On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.
Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more-timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and
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CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing. PNG’s DSIC has been reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate case.
In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018, for the amount of DSIC-eligible plant placed into service as it exceeded the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case during the third quarter of Fiscal 2018.
Utilities Merger Request. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PUC and MD PSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. There are no expected changes to annual base distribution rates for the combined utilities or to existing regulatory assets and liabilities as a result of the proposed merger. On July 20, 2018, UGI Utilities filed a Joint Petition for Settlement among the parties to the proceeding for approval by two administrative law judges by recommended decision that will be the subject of a final decision by the PUC. On July 25, 2018 the MD PSC issued an order approving UGI Utilities’ merger request. UGI Utilities cannot predict the timing or the ultimate outcome of the PUC review of the merger request. On August 3, 2018, FERC approved requests made by CPG, PNG, and UGI Utilities in May 2018 relating to the transfer of certain FERC authorizations from PNG and CPG to UGI Utilities, to ensure continuity of certain interstate gas transportation services currently conducted by CPG and PNG after the effective date of the proposed merger. With the receipt of these FERC approvals, the approval of an application to transfer CPG’s service territory designation to UGI Utilities remains the only FERC approval yet to be received in connection with the proposed merger.
IMPAIRMENT OF PARTNERSHIP TRADENAMES AND TRADEMARKS
In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over a period of approximately three years. As a result, during the three months ended June 30, 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and, in accordance with GAAP associated with intangible assets, adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9 million. During the three months ended June 30, 2018, the Partnership recorded a non-cash impairment charge of $75.0 million. The impairment charge reduced net income attributable to UGI Corporation for the three and nine months ended June 30, 2018, by $14.5 million ($0.08 per diluted share). For further information, see Notes 6 and 12 to condensed consolidated financial statements.
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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 and option 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 of the prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the NYMEX, to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism. At June 30, 2018, the fair values of Gas Utility’s natural gas futures and option contracts were not material.
Electric Utility's DS tariffs contain clauses which 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 FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At June 30, 2018, all of Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. At June 30, 2018, Electric Utility did not have any FTR contracts.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income. At June 30, 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 sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX, ICE and over-the-counter natural gas and electricity futures 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 futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane.
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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 of unsettled commodity price risk sensitive derivative instruments held at June 30, 2018 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a gain of $92.4 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges would result in a decrease in fair value of approximately $79.6 million at June 30, 2018.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt at June 30, 2018, includes short-term borrowings and UGI France SAS’s, Flaga’s and UGI Utilities’ variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France SAS and Flaga, through the use of pay-fixed, receive-variable interest rate swaps, have fixed the underlying euribor interest rates on their euro-denominated term loans through all, or a substantial portion of, the periods such debt is outstanding. In addition, Flaga’s U.S. dollar-denominated loan has been swapped from a floating-rate U.S. dollar-denominated interest rate to a fixed-rate euro-denominated interest rate through a cross-currency swap, removing interest rate risk (and foreign currency exchange risk as further described below under Foreign Currency Exchange Rate Risk) associated with the underlying interest payments. At June 30, 2018, combined borrowings outstanding under variable-rate debt agreements, excluding UGI France SAS’s and Flaga’s effectively fixed-rate debt, totaled $421.0 million.
As previously mentioned, in October 2017, UGI Utilities entered into a $125 million variable-rate Term Loan. Under the UGI Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on UGI Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed rate debt, from time to time we enter into IRPAs.
The fair value of unsettled interest rate risk sensitive derivative instruments held at June 30, 2018 (including pay-fixed, receive-variable interest rate swaps) was a loss of $1.5 million. A 50 basis point adverse change in the three-month euribor rate and three-month LIBOR would result in a decrease in fair value of approximately $1.2 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. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at June 30, 2018, by approximately $140.0 million, which amount would be reflected in other comprehensive income. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are sold or liquidated. At June 30, 2018, there were no unsettled net investment hedges outstanding.
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. Beginning October 1, 2016, in order
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to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts.
As previously mentioned, Flaga has a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. This cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance.
The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at June 30, 2018, including the fair value of Flaga’s cross-currency swap, was a gain of $1.2 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 $54.3 million.
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. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2018, restricted cash in brokerage accounts totaled $7.7 million. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 2018. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2018, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
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 change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is 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 Annual Report on Form 10-K for the fiscal year ended September 30, 2017, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K 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 June 30, 2018.

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)
April 1, 2018 to April 30, 2018 |  | — |  | — |  | — |  | 8.00 million
May 1, 2018 to May 31, 2018 |  | — |  | — |  | — |  | 8.00 million
June 1, 2018 to June 30, 2018 |  | 600,000 |  | $49.13 |  | 600,000 |  | 7.40 million
Total |  | 600,000 |  |  |  | 600,000 |  |

(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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
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
10.1 |  | Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between UGI Corporation and Ted J. Jastrzebski. |  |  |  |  |  |
31.1 |  | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 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 June 30, 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 June 30, 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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
EXHIBIT INDEX

10.1 |  | Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between UGI Corporation and Ted J. Jastrzebski.
31.1 |  | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 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 June 30, 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 June 30, 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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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: | August 7, 2018 | By: | /s/ Ted J. Jastrzebski
|  |  | Ted J. Jastrzebski
|  |  | Chief Financial Officer
Date: | August 7, 2018 | By: | /s/ Ann P. Kelly
|  |  | Ann P. Kelly
|  |  | Vice President, Chief Accounting Officer
|  |  | and Corporate Controller

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