UGI CORP /PA/, 10-Q filed on 5/6/2016
Quarterly Report
Document and Entity Information
6 Months Ended
Mar. 31, 2016
Apr. 30, 2016
Document and Entity Information [Abstract]
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
Entity Central Index Key
0000884614 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2016 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q2 
 
Current Fiscal Year End Date
--09-30 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
172,680,789 
Condensed Consolidated Balance Sheets (unaudited) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Current assets:
 
 
 
Cash and cash equivalents
$ 466.2 
$ 369.7 
$ 445.5 
Restricted cash
40.0 
69.3 
56.7 
Accounts receivable (less allowances for doubtful accounts of $34.1, $29.7 and $42.7, respectively)
858.4 
619.7 
1,046.0 
Accrued utility revenues
24.1 
12.1 
42.1 
Inventories
176.5 
239.9 
201.5 
Deferred income taxes
0 
7.8 
49.6 
Utility regulatory assets
3.2 
4.1 
0.6 
Derivative instruments
21.0 
23.3 
33.1 
Prepaid expenses and other current assets
117.6 
113.9 
83.9 
Total current assets
1,707.0 
1,459.8 
1,959.0 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,987.1, $2,835.0 and $2,691.0, respectively)
5,083.1 
4,994.1 
4,486.3 
Goodwill
2,998.6 
2,953.4 
2,731.2 1
Intangible assets, net
598.2 
610.1 
537.5 
Utility regulatory assets
345.0 
300.1 
252.0 
Derivative instruments
1.2 
16.3 
20.9 
Deferred income taxes
7.2 
0 
4.0 
Other assets
215.1 
212.8 
191.8 
Total assets
10,955.4 
10,546.6 
10,182.7 1
Current liabilities:
 
 
 
Current maturities of long-term debt
8.5 
258.0 
470.5 
Short-term borrowings
227.1 
189.9 
89.9 1
Accounts payable
379.8 
392.9 
440.8 
Derivative instruments
70.2 
121.8 
129.0 
Other current liabilities
781.1 
716.3 
719.5 
Total current liabilities
1,466.7 
1,678.9 
1,849.7 
Long-term debt
3,630.5 
3,441.8 
2,958.2 
Deferred income taxes
1,186.7 
1,134.0 
942.0 
Deferred investment tax credits
3.4 
3.6 
3.8 
Derivative instruments
20.4 
31.2 
34.3 
Other noncurrent liabilities
722.7 
684.7 
511.0 
Total liabilities
7,030.4 
6,974.2 
6,299.0 
Commitments and contingencies
   
   
   
UGI Corporation stockholders’ equity:
 
 
 
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,842,891, 173,806,991 and 173,788,741 shares, respectively)
1,205.8 
1,214.6 
1,215.0 
Retained earnings
1,906.2 
1,636.9 
1,715.0 
Accumulated other comprehensive loss
(129.9)
(114.6)
(85.4)
Treasury stock, at cost
(41.9)
(44.9)
(41.6)
Total UGI Corporation stockholders’ equity
2,940.2 
2,692.0 
2,803.0 
Noncontrolling interests, principally in AmeriGas Partners
984.8 
880.4 
1,080.7 
Total equity
3,925.0 
3,572.4 
3,883.7 
Total liabilities and equity
$ 10,955.4 
$ 10,546.6 
$ 10,182.7 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Statement of Financial Position [Abstract]
 
 
 
Accounts receivable, allowances for doubtful accounts
$ 34.1 
$ 29.7 
$ 42.7 
Property, plant and equipment, accumulated depreciation and amortization
$ 2,987.1 
$ 2,835.0 
$ 2,691.0 
UGI Common Stock, without par value, shares authorized
450,000,000 
450,000,000 
450,000,000 
UGI Common Stock, without par value, shares issued
173,842,891 
173,806,991 
173,788,741 
Condensed Consolidated Statements of Income (unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Income Statement [Abstract]
 
 
 
 
Revenues
$ 1,972.1 
$ 2,455.6 1
$ 3,578.7 
$ 4,460.2 1
Costs and expenses:
 
 
 
 
Cost of sales (excluding depreciation shown below)
776.9 
1,205.4 1
1,510.9 
2,610.0 1
Operating and administrative expenses
481.0 
466.6 
945.1 
902.3 
Utility taxes other than income taxes
4.4 
4.8 
8.2 
8.9 
Depreciation
83.4 
73.8 
169.1 
149.6 
Amortization
17.3 
14.2 
32.2 
29.4 
Other operating income, net
(6.3)
(11.3)
(7.7)
(25.4)
Total costs and expenses
1,356.7 
1,753.5 
2,657.8 
3,674.8 
Operating income
615.4 
702.1 1
920.9 
785.4 1
Loss from equity investees
0 
(0.1)1
(0.1)
(1.1)1
Interest expense
(57.3)
(58.2)1
(115.2)
(117.2)1
Income before income taxes
558.1 
643.8 1
805.6 
667.1 1
Income tax expense
(150.1)
(161.6)
(229.7)
(184.7)
Net income including noncontrolling interests
408.0 
482.2 
575.9 
482.4 
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners
(174.8)
(235.7)1
(228.1)
(201.8)1
Net income attributable to UGI Corporation
$ 233.2 
$ 246.5 
$ 347.8 
$ 280.6 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic (in dollars per share)
$ 1.35 
$ 1.42 
$ 2.01 
$ 1.62 
Diluted (in dollars per share)
$ 1.33 
$ 1.40 
$ 1.99 
$ 1.60 
Weighted-average common shares outstanding (thousands):
 
 
 
 
Basic (in shares)
172,619 
173,154 
172,733 
173,055 
Diluted (in shares)
174,845 
175,628 
174,953 
175,715 
Dividends declared per common share (in dollars per share)
$ 0.2275 
$ 0.2175 
$ 0.455 
$ 0.435 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income including noncontrolling interests
$ 408.0 
$ 482.2 
$ 575.9 
$ 482.4 
Other comprehensive income (loss):
 
 
 
 
Net (losses) gains on derivative instruments (net of tax of $18.5, $(10.4), $14.3 and $(14.3), respectively)
(29.7)
20.2 
(22.9)
27.9 
Reclassifications of net (gains) losses on derivative instruments (net of tax of $2.7, $1.1, $5.9 and $(0.4), respectively)
(4.3)
(1.9)
(9.6)
0.2 
Foreign currency adjustments (net of tax of $0, $35.0, $0 and $50.6, respectively)
46.7 
(64.5)
16.5 
(95.0)
Benefit plans (net of tax of $(0.1), $(0.2), $(0.4) and $(0.6), respectively)
0.3 
0.4 
0.7 
1.0 
Other comprehensive income (loss)
13.0 
(45.8)
(15.3)
(65.9)
Comprehensive income including noncontrolling interests
421.0 
436.4 
560.6 
416.5 
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners
(174.8)
(235.1)
(228.1)
(200.1)
Comprehensive income attributable to UGI Corporation
$ 246.2 
$ 201.3 
$ 332.5 
$ 216.4 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
 
Tax on (loss) gain on derivative instruments
$ 18.5 
$ (10.4)
$ 14.3 
$ (14.3)
Tax on reclassification on derivative instruments
2.7 
1.1 
5.9 
(0.4)
Tax on foreign currency adjustments
0 
35.0 
0 
50.6 
Tax on benefit plans
$ (0.1)
$ (0.2)
$ (0.4)
$ (0.6)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income including noncontrolling interests
$ 575.9 
$ 482.4 
Adjustments to reconcile net income to net cash from operating activities:
 
 
Depreciation and amortization
201.3 
179.0 1
Deferred income tax expense (benefit)
49.5 
(33.7)
Provision for uncollectible accounts
14.8 
20.7 
Unrealized (gains) losses on derivative instruments
(65.1)
125.2 
Other, net
0.9 
7.0 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(268.8)
(469.7)
Inventories
63.6 
208.0 
Utility deferred fuel and power costs, net of changes in unsettled derivatives
(7.8)
55.8 
Accounts payable
(5.9)
31.8 
Other current assets
(12.6)
(8.3)
Other current liabilities
72.5 
59.6 
Net cash provided by operating activities
618.3 
657.8 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(254.6)
(233.5)
Acquisitions of businesses, net of cash acquired
(49.4)
(7.3)
Decrease (increase) in restricted cash
29.3 
(40.1)
Other, net
6.5 
15.1 
Net cash used by investing activities
(268.2)
(265.8)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends on UGI Common Stock
(78.5)
(75.0)
Distributions on AmeriGas Partners publicly held Common Units
(127.2)
(121.7)
Repayments of debt
(78.4)
(6.9)
Increase (decrease) in short-term borrowings
52.6 
(112.2)
Receivables Facility net repayments
(15.5)
(7.5)
Issuances of UGI Common Stock
5.2 
5.0 
Repurchases of UGI Common Stock
(24.7)
(17.3)
Other
6.9 
(2.3)
Net cash used by financing activities
(259.6)
(337.9)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
6.0 
(28.1)
Cash and cash equivalents increase
96.5 
26.0 
CASH AND CASH EQUIVALENTS
 
 
End of period
466.2 
445.5 
Beginning of period
$ 369.7 
$ 419.5 
Condensed Consolidated Statements of Changes in Equity (unaudited) (USD $)
In Millions, unless otherwise specified
Total
Parent
Common stock, without par value
Retained earnings
Accumulated other comprehensive income (loss)
Treasury stock
Noncontrolling interests
Balance, beginning of period at Sep. 30, 2014
 
 
$ 1,215.6 
$ 1,509.4 
$ (21.2)
$ (44.7)
$ 1,004.1 
Increase (Decrease) in Stockholders' Equity
 
 
 
 
 
 
 
Common Stock issued in connection with employee and director plans (including (losses) on treasury stock transactions), net of tax withheld
 
 
(15.1)
 
 
 
 
Excess tax benefits realized on equity-based compensation
 
 
5.0 
 
 
 
 
Equity-based compensation expense
 
 
9.5 
 
 
 
 
Net income including noncontrolling interests
482.4 
 
 
280.6 
 
 
201.8 
Cash dividends on Common Stock
 
 
 
(75.0)
 
 
 
Net (losses) gains on derivative instruments, net of tax
27.9 
 
 
 
27.9 
 
 
Reclassification of net (gains) losses on derivative instruments, net of tax
0.2 
 
 
 
1.9 
 
(1.7)
Benefit plans, net of tax
1.0 
 
 
 
1.0 
 
 
Foreign currency, net of tax
(95.0)
 
 
 
(95.0)
 
 
Common stock issued in connection with employee and director plans, net of tax withheld
 
 
 
 
 
24.7 
 
Repurchases of Common Stock
 
 
 
 
 
(17.3)
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(4.3)
 
Dividends and distributions
 
 
 
 
 
 
(122.2)
Other
 
 
 
 
 
 
(1.3)
Balance, end of period at Mar. 31, 2015
3,883.7 
2,803.0 
1,215.0 
1,715.0 
(85.4)
(41.6)
1,080.7 
Balance, beginning of period at Sep. 30, 2015
3,572.4 
 
1,214.6 
1,636.9 
(114.6)
(44.9)
880.4 
Increase (Decrease) in Stockholders' Equity
 
 
 
 
 
 
 
Common Stock issued in connection with employee and director plans (including (losses) on treasury stock transactions), net of tax withheld
 
 
(22.4)
 
 
 
 
Excess tax benefits realized on equity-based compensation
 
 
6.9 
 
 
 
 
Equity-based compensation expense
 
 
6.7 
 
 
 
 
Net income including noncontrolling interests
575.9 
 
 
347.8 
 
 
228.1 
Cash dividends on Common Stock
 
 
 
(78.5)
 
 
 
Net (losses) gains on derivative instruments, net of tax
(22.9)
 
 
 
(22.9)
 
 
Reclassification of net (gains) losses on derivative instruments, net of tax
(9.6)
 
 
 
(9.6)
 
0 
Benefit plans, net of tax
0.7 
 
 
 
0.7 
 
 
Foreign currency, net of tax
16.5 
 
 
 
16.5 
 
 
Common stock issued in connection with employee and director plans, net of tax withheld
 
 
 
 
 
42.1 
 
Repurchases of Common Stock
 
 
 
 
 
(24.7)
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(14.4)
 
Dividends and distributions
 
 
 
 
 
 
(127.2)
Other
 
 
 
 
 
 
3.5 
Balance, end of period at Mar. 31, 2016
$ 3,925.0 
$ 2,940.2 
$ 1,205.8 
$ 1,906.2 
$ (129.9)
$ (41.9)
$ 984.8 
Nature of Operations
Nature of Operations
Note 1 — Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe. 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”), which is referred to herein as the “Operating Partnership.” 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 March 31, 2016, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 15 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2015 (the “Company’s 2015 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2016 and 2015 were $17.3 and $13.1, respectively.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“UGI France”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); and (3) an LPG distribution business in the United Kingdom (“AvantiGas”). On May 29, 2015, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding), an indirect wholly owned subsidiary of UGI, purchased all of the outstanding shares of Totalgaz SAS (the “Totalgaz Acquisition”), a retail distributor of LPG in France. The retail LPG distribution business of Totalgaz SAS and its subsidiaries is referred to herein as “Finagaz” and is included in our UGI France reportable segment (see Notes 14 and 15). The retail LPG distribution business of UGI France prior to the Totalgaz Acquisition is also referred to herein as “Antargaz.” In March 2016, we sold our LPG distribution business located in the Nantong region of China. The sale did not have a material impact on our financial statements for the three and six months ended March 31, 2016. We refer to our foreign LPG operations collectively as “UGI International.”

Enterprises, through UGI Energy Services, LLC and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC is referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries (“HVAC”).

Our natural gas distribution utility business (“Gas Utility”) is conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its 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, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission. Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
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 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, 2015, 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 2015 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 stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
 
Shares used in computing basic and diluted earnings per share are as follows: 
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2016
 
2015
 
2016
 
2015
Denominator (thousands of shares):
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding - basic
 
172,619

 
173,154

 
172,733

 
173,055

Incremental shares issuable for stock options and awards
 
2,226

 
2,474

 
2,220

 
2,660

Weighted-average common shares outstanding - diluted
 
174,845

 
175,628

 
174,953

 
175,715



Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by Gas Utility and Electric Utility (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.

Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, on the Condensed Consolidated Statements of Income.

Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities.

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 12.

Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation.

Consolidated Effective Income Tax Rate. UGI’s consolidated effective income tax rate, defined as total income tax (expense) or benefit 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.

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

Correction of Prior Period Error in Other Comprehensive Income
During the three months ended June 30, 2015, the Company recorded an adjustment to decrease other comprehensive income related to prior periods by reducing the amount of net deferred tax assets that had been previously recognized for (1) foreign currency adjustments related to foreign subsidiaries whose undistributed earnings are considered indefinitely reinvested, and (2) foreign currency adjustments related to intercompany loans between a U.S. domiciled entity and its foreign branch that is considered disregarded for tax purposes and for which income taxes will not be payable. Accounting Standards Codification (“ASC”) No. 740, “Income Taxes,” provides an exception to recording deferred tax attributes associated with these components of comprehensive income. Previously, the Company had incorrectly recorded deferred taxes on these currency adjustments. During the three months ended June 30, 2015, the Company evaluated the effects of the errors, both qualitatively and quantitatively, and concluded that they did not have a material impact on any prior period financial statement and recorded the cumulative effect of the error as of April 1, 2015. If the Company had corrected the error in all of the periods prior to April 1, 2015, other comprehensive loss for the three and six months ended March 31, 2015, would have increased by $32.7 and $47.1, respectively.
Accounting Changes
Accounting Changes
Note 3 — Accounting Changes

Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as a result, the September 30, 2015 and March 31, 2015 Condensed Consolidated Balance Sheets included herein have not been adjusted.
Accounting Standards Not Yet Adopted

Share-Based Payments. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2016 (Fiscal 2018). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.
Debt Issuance Costs. In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard 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. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.
Inventories
Inventories
Note 4 — Inventories

Inventories comprise the following: 
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Non-utility LPG and natural gas
 
$
106.7

 
$
140.7

 
$
135.8

Gas Utility natural gas
 
3.8

 
37.5

 
6.3

Materials, supplies and other
 
66.0

 
61.7

 
59.4

Total inventories
 
$
176.5

 
$
239.9

 
$
201.5



At March 31, 2016, UGI Utilities was a party to two principal storage contract administrative agreements (“SCAAs”) having terms of three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

As of March 31, 2016, UGI Utilities had SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at March 31, 2016, September 30, 2015 and March 31, 2015, comprising 0.2 billion cubic feet (“bcf”), 4.0 bcf and 0.2 bcf of natural gas, was $0.5, $9.8 and $0.7, respectively.
Goodwill and Intangible Assets
Goodwill and Intangible Assets
Note 5 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following: 
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Goodwill (not subject to amortization)
 
$
2,998.6

 
$
2,953.4

 
$
2,731.2

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
778.3

 
$
761.1

 
$
670.2

Accumulated amortization
 
(312.3
)
 
(282.4
)
 
(254.1
)
Intangible assets, net (definite-lived)
 
466.0

 
478.7

 
416.1

Trademarks and tradenames (indefinite-lived)
 
132.2

 
131.4

 
121.4

Total intangible assets, net
 
$
598.2

 
$
610.1

 
$
537.5


The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $15.2 and $28.0 for the three and six months ended March 31, 2016, respectively. Amortization expense of intangible assets was $12.0 and $25.0 for the three and six months ended March 31, 2015, respectively. Amortization expense included in cost of sales on the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2016 and for the next four fiscal years is as follows: remainder of Fiscal 2016 — $24.4; Fiscal 2017 — $46.6; Fiscal 2018 — $45.1; Fiscal 2019 — $43.4; Fiscal 2020 — $42.1.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 6 — Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 9 in the Company’s 2015 Annual Report. UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Regulatory assets:
 
 
 
 
 
 
Income taxes recoverable
 
$
118.2

 
$
115.9

 
$
111.5

Underfunded pension and postretirement plans
 
135.8

 
140.8

 
105.5

Environmental costs (a)
 
60.5

 
20.0

 
14.1

Removal costs, net
 
25.0

 
21.2

 
18.4

Other
 
8.7

 
6.3

 
3.1

Total regulatory assets
 
$
348.2

 
$
304.2

 
$
252.6

Regulatory liabilities (b):
 
 
 
 
 
 
Postretirement benefits
 
$
19.3

 
$
20.0

 
$
19.3

Deferred fuel and power refunds
 
30.8

 
36.6

 
40.6

State tax benefits—distribution system repairs
 
14.2

 
13.3

 
10.6

Other
 
2.5

 
1.1

 
2.1

Total regulatory liabilities
 
$
66.8

 
$
71.0

 
$
72.6



(a)
Environmental costs at March 31, 2016, include amounts probable of recovery recorded in conjunction with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 9).
(b)
Regulatory liabilities are recorded in other current and other noncurrent liabilities on the Condensed Consolidated Balance Sheets.

Deferred fuel and power—costs and 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 (losses) on such contracts at March 31, 2016, September 30, 2015 and March 31, 2015 were $(1.9), $(3.3) and $(3.4), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not elect the NPNS exception under GAAP for these contracts. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At March 31, 2016, September 30, 2015, and March 31, 2015, the fair values of Electric Utility’s electricity supply contracts were (losses) of $(0.2), $(0.5) and $(1.2), respectively. These amounts are reflected in current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (see Note 12).

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at March 31, 2016, September 30, 2015, and March 31, 2015, were not material.

Preliminary Stage Information Technology Costs. During the three months ended March 31, 2016, it was determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the three months ended March 31, 2016, we capitalized $5.8 of such project costs ($5.7 of which had been expensed in prior periods) and recorded associated increases to utility property, plant and equipment ($2.7) and regulatory assets ($3.1).

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58.6 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities requested that the new gas rates become effective March 19, 2016. The PUC entered an Order dated February 11, 2016, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last approximately nine months from the date of filing; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. Also in March 2016, UGI Gas sought PUC approval to initiate a DSIC effective November 2017 after rates from the pending rate case become effective, along with a petition, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on any of these petitions. The Company cannot predict the timing or outcome of these petitions. The impact of the DSIC charge at PNG and CPG did not have a material effect on Gas Utility results of operations.
Energy Services Accounts Receivable Securitization Facility
Energy Services Accounts Receivable Securitization Facility
Note 7 — Energy Services Accounts Receivable Securitization Facility

Energy Services has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2016. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November through April and up to $75 of eligible receivables during the period May through October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, 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. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable.

During the six months ended March 31, 2016 and 2015, Energy Services transferred trade receivables to ESFC totaling $468.0 and $692.0, respectively. During the six months ended March 31, 2016 and 2015, ESFC sold an aggregate $167.5 and $216.5, respectively, of undivided interests in its trade receivables to the bank. At March 31, 2016, the outstanding balance of ESFC receivables was $55.3, of which $4.0 was sold to the bank. At March 31, 2015, the outstanding balance of ESFC receivables was $96.9 and there were no amounts sold to the bank. Losses on sales of receivables to the bank during the three and six months ended March 31, 2016 and 2015, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.
Debt
Debt
Note 8 — Debt
In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 variable-rate term loan facility. Borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan facility were used to refinance its €19.1 term loan due October 2016 and its €26.7 term loan due August 2016. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility.
The Flaga Credit Facility Agreement revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the actual amount borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. The Flaga Credit Facility Agreement is scheduled to expire in October 2020.
The €45.8 term loan matures in October 2020. The €45.8 term bears interest at three-month euribor rates, plus a margin. The margin on such borrowings ranges from 0.40% to 1.80% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying euribor rate on the term loan borrowings at 2.18% through September 2016 and 0.23% from October 2016 through October 2020.
Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Condensed Consolidated Statement of Cash Flows.

In February 2016, Energy Services entered into a Second Amended and Restated Credit Agreement (the "Energy Services Credit Agreement"), as borrower, with a group of lenders providing for borrowings up to $240, including a $50 sublimit for letters of credit. Borrowings under the Energy Services Credit Agreement bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus a margin. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, and (c) the Adjusted LIBOR plus 1%. The margin on such borrowings is currently 2.25%. The Energy Services Credit Agreement requires that Energy Services not exceed ratios of total indebtedness to EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00. The Energy Services Credit Agreement is scheduled to expire in March 2021.

In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) which provides for the private placement of (1) $100 aggregate principal amount of 2.95% Senior Notes due June 30, 2026; (2) $200 aggregate principal amount of 4.12% Senior Notes due September 30, 2046; and (3) $100 aggregate principal amount of 4.12% Senior Notes due October 31, 2046. These Senior Notes are expected to be issued in June 2016, September 2016 and October 2016, respectively. These Senior Notes, when issued, will be unsecured and will rank equally with UGI Utilities’ existing outstanding senior debt. UGI Utilities expects to use the net proceeds from the issuance of the Senior Notes to refinance existing debt and for general corporate purposes. Because UGI Utilities intends to use a portion of the net proceeds from the issuance of $200 Senior Notes in September 2016 to repay UGI Utilities’ currently outstanding $175 principal amount of 5.75% Senior Notes due September 30, 2016, the 5.75% Senior Notes have been classified as long-term on the March 31, 2016, Condensed Consolidated Balance Sheet.
Commitments and Contingencies
Commitments and Contingencies
Note 9 — Commitments and Contingencies

Environmental Matters

UGI Utilities

From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of 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 has also acquired two subsidiaries (CPG and PNG) which have similar histories of owning, and in some cases operating, MGPs in Pennsylvania.
UGI Utilities and its subsidiaries have entered into agreements with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, required environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At March 31, 2016 and 2015, our estimated accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.8 and $9.6, respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6).

UGI Utilities’ UGI Gas division has negotiated a Consent Order and Agreement (“UGI Gas-COA”) with the DEP and is awaiting execution thereof. The UGI Gas-COA would be effective October 1, 2016, and would be scheduled to terminate in September 2031. The UGI Gas-COA would require UGI Gas to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties would be capped at $2.5 in any calendar year. At March 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the UGI Gas-COA totaled $43.8. UGI Gas has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and (2) CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. UGI Gas has proposed a similar environmental cost tracking mechanism that will address the costs incurred under the UGI Gas-COA.

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 its former subsidiaries. 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 former subsidiaries 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 March 31, 2016, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas MGP sites outside of Pennsylvania was material.

Other Matters

Purported Class Action Lawsuits.  Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers.  The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws.  The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.  On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri.  In July 2015, the Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers.  The direct customers filed an appeal with the United States Court of Appeals for the Eighth Circuit, which is still pending. The indirect customers filed an amended complaint claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In January 2016, the District Court dismissed the remaining injunctive relief claims for the indirect purchasers. As a result, the only claims remaining with respect to indirect purchasers involve alleged violations of Wisconsin, Maine and Vermont state antitrust laws. 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 position, results of operations or cash flows.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
Note 10 — 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 active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, UGI France employees 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 March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
2.5

 
$
2.5

 
$
0.2

 
$
0.1

Interest cost
 
6.6

 
6.3

 
0.3

 
0.2

Expected return on assets
 
(8.0
)
 
(8.0
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1

 
0.1

 
(0.2
)
 
(0.1
)
Actuarial loss
 
2.7

 
2.5

 
—

 
—

Net benefit cost
 
3.9

 
3.4

 
0.2

 
0.1

Change in associated regulatory liabilities
 
—

 
—

 
0.8

 
1.0

Net expense
 
$
3.9

 
$
3.4

 
$
1.0

 
$
1.1

 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
5.0

 
$
4.9

 
$
0.4

 
$
0.3

Interest cost
 
13.2

 
12.6

 
0.5

 
0.4

Expected return on assets
 
(16.0
)
 
(15.9
)
 
(0.3
)
 
(0.3
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.2

 
0.2

 
(0.3
)
 
(0.2
)
Actuarial loss
 
5.4

 
5.0

 
—

 
—

Net benefit cost
 
7.8

 
6.8

 
0.3

 
0.2

Change in associated regulatory liabilities
 
—

 
—

 
1.7

 
1.9

Net expense
 
$
7.8

 
$
6.8

 
$
2.0

 
$
2.1



The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and 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 six months ended March 31, 2016 and 2015, the Company made cash contributions to the U.S. Pension Plan of $4.9 and $5.6, respectively. The Company expects to make additional discretionary cash contributions of approximately $5.0 to the U.S. Pension Plan during the remainder of Fiscal 2016.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the six months ended March 31, 2016 and 2015.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three and six months ended March 31, 2016 and 2015 were not material.
Fair Value Measurements
Fair Value Measurements
Note 11 — 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 March 31, 2016, September 30, 2015 and March 31, 2015:  
 
 
Asset (Liability)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2016:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
20.3

 
$
16.7

 
$
—

 
$
37.0

Foreign currency contracts
 
$
—

 
$
11.6

 
$
—

 
$
11.6

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(59.0
)
 
$
(48.4
)
 
$
—

 
$
(107.4
)
Foreign currency contracts
 
$
—

 
$
(5.0
)
 
$
—

 
$
(5.0
)
Interest rate contracts
 
$
—

 
$
(3.4
)
 
$
—

 
$
(3.4
)
Cross-currency swaps
 
$
—

 
$
(1.3
)
 
$
—

 
$
(1.3
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8

September 30, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
17.4

 
$
11.6

 
$
—

 
$
29.0

Foreign currency contracts
 
$
—

 
$
29.1

 
$
—

 
$
29.1

Cross-currency swaps
 
$
—

 
$
0.4

 
$
—

 
$
0.4

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(70.0
)
 
$
(99.0
)
 
$
—

 
$
(169.0
)
Foreign currency contracts
 
$
—

 
$
(0.1
)
 
$
—

 
$
(0.1
)
Interest rate contracts
 
$
—

 
$
(10.8
)
 
$
—

 
$
(10.8
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
30.3

 
$
—

 
$
—

 
$
30.3

March 31, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
13.9

 
$
8.3

 
$
—

 
$
22.2

Foreign currency contracts
 
$
—

 
$
35.8

 
$
—

 
$
35.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
9.7

 
$
—

 
$
9.7

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(64.0
)
 
$
(104.3
)
 
$
—

 
$
(168.3
)
Interest rate contracts
 
$
—

 
$
(12.5
)
 
$
—

 
$
(12.5
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8



(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 designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At March 31, 2016, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,639.0 and $3,775.3, respectively. At March 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,428.7 and $3,664.2, respectively. 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).

Financial instruments other than derivative instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our 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 12. 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.
Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
Note 12 — 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.
 
Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units 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. At March 31, 2016 and 2015, total volumes associated with LPG commodity derivative instruments totaled 370.2 million gallons and 362.5 million gallons, respectively. At March 31, 2016, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 42 months.

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. At March 31, 2016 and 2015, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10.0 million dekatherms and 9.7 million dekatherms, respectively. At March 31, 2016, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 11 months. Gains and losses on natural gas futures contracts and any gains on 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 6).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument liabilities on the Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At March 31, 2016 and 2015, the volumes associated with Electric Utility’s forward electricity purchase contracts for which NPNS has not been elected were 23.6 million kilowatt hours and 384.4 million kilowatt hours, respectively. At March 31, 2016, the maximum period over which these contracts extend is 8 months.

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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At March 31, 2016 and 2015, the total volumes associated with FTRs and NYISO capacity contracts totaled 89.7 million kilowatt hours and 124.6 million kilowatt hours, respectively. At March 31, 2016, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 2 months.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and 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. 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 or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.

At March 31, 2016 and 2015, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 84.7 million dekatherms and 118.3 million dekatherms, respectively. At March 31, 2016 and 2015, total volumes associated with Midstream & Marketing’s natural gas basis swap contracts totaled 90.1 million dekatherms and 47.3 million dekatherms, respectively. At March 31, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 56 months. At March 31, 2016 and 2015, total volumes associated with Midstream & Marketing’s electricity long forward and futures contracts and electricity short forward and futures contracts totaled 591.1 million kilowatt hours and 431.6 million kilowatt hours, and 356.0 million kilowatt hours and 315.4 million kilowatt hours, respectively. At March 31, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 34 months for electricity call contracts and 27 months for electricity put contracts. At March 31, 2016, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 1.7 million dekatherms and there were no propane storage NYMEX contracts. At March 31, 2015, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.6 million dekatherms and there were no propane storage NYMEX contracts.
 
At March 31, 2016, there were no amounts remaining in AOCI related to commodity derivative hedges.
Interest Rate Risk

France SAS’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates of interest on their variable-rate term loans through April 2019 in the case of France SAS’s swap agreements and, through the respective scheduled maturity dates in the case of Flaga’s long-term debt agreements. The France SAS swaps were originally executed in Fiscal 2015 at which time such swaps were designated in a cash flow hedging relationship associated with €600 notional amount of term loan debt issued in conjunction with the Totalgaz Acquisition. In March 2016, France SAS amended the terms of its pay-fixed, receive-variable interest rate swap agreements associated with the €600 term loan debt to purchase a 0% floor that is identical to the 0% floor embedded in France SAS’s term loan debt. In conjunction with the amendments, in March 2016 France SAS paid its interest rate swap counterparties €7.7, which amount substantially equaled the interest rate swaps’ fair value. Concurrent with the amendments to the interest rate swaps, the swaps were simultaneously de-designated and re-designated as cash flow hedges of future anticipated interest payments associated with the €600 term loan debt. The amended swaps fix the underlying euribor rate on the €600 term loan at 0.18%. As of March 31, 2016 and 2015, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €645.8 and €401.1, respectively.

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”). On March 31, 2016, concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities agreed to settle all of its then-existing IRPA contracts associated with such debt at a loss of $36.0 (which amount was paid in early April 2016 and is included in other current liabilities on the March 31, 2016, Condensed Consolidated Balance Sheet). Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 8 for additional information on the 2016 Note Purchase Agreement. At March 31, 2016 and 2015, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At March 31, 2016, 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 $3.1.

Foreign Currency Exchange Rate Risk

In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, we hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At March 31, 2016 and 2015, we were hedging a total of $262.5 and $223.5 of our foreign operations’ anticipated U.S. dollar-denominated LPG purchases, respectively. At March 31, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 36 months. 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 International Propane euro-denominated net investments. At March 31, 2016 and 2015, we had no euro-denominated net investment hedges.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At March 31, 2016, the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $7.8.

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 fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At March 31, 2016 and 2015, cross-currency swaps were hedging foreign currency risk associated with interest and principal payments on $59.1 and $52.0 of Flaga U.S. dollar-denominated debt, respectively.

At March 31, 2016, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings during the next twelve months is not material.
 
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 March 31, 2016 and 2015, restricted cash in brokerage accounts totaled $40.0 and $56.7, respectively. 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 March 31, 2016. 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 March 31, 2016, 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. 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.

Fair Value of Derivative Instruments
 
The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2016 and 2015:
 
 
March 31,
2016
 
March 31,
2015
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Foreign currency contracts
 
$
11.6

 
$
35.8

Cross-currency contracts
 
—

 
9.7

Interest rate contracts
 
—

 
0.1

 
 
11.6

 
45.6

Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
1.2

 
—

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
35.8

 
22.2

Total derivative assets - gross
 
48.6

 
67.8

Gross amounts offset in the balance sheet
 
(26.4
)
 
(13.8
)
Total derivative assets - net
 
$
22.2

 
$
54.0

Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Foreign currency contracts
 
$
(5.0
)
 
$
—

Cross-currency contracts
 
(1.3
)
 
—

Interest rate contracts
 
(3.4
)
 
(12.5
)
 
 
(9.7
)
 
(12.5
)
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
(3.5
)
 
(5.2
)
Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
(103.9
)
 
(163.1
)
Total derivative liabilities - gross
 
(117.1
)
 
(180.8
)
Gross amounts offset in the balance sheet
 
26.4

 
13.8

Cash collateral pledged
 
0.1

 
3.7

Total derivative liabilities - net
 
$
(90.6
)
 
$
(163.3
)


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 and noncontrolling interests for the three and six months ended March 31, 2016 and 2015:
 
 
Gain (Loss)
Recognized in
AOCI
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Three Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
—

 
$
—

 
$
0.1

 
Cost of sales
Foreign currency contracts
 
(10.7
)
 
23.7

 
8.1

 
6.5

 
Cost of sales
Cross-currency contracts
 
(0.3
)
 
5.4

 
0.2

 
(0.1
)
 
Interest expense/other operating income, net
Interest rate contracts
 
(37.2
)
 
1.6

 
(1.3
)
 
(3.5
)
 
Interest expense
Total
 
$
(48.2
)
 
$
30.7

 
$
7.0

 
$
3.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 

Three Months Ended March 31,
 
2016
 
2015
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(6.0
)
 
$
(12.3
)
 
Cost of sales
 

Commodity contracts
 
0.2

 
(4.6
)
 
Revenues
 
 
Total
 
$
(5.8
)
 
$
(16.9
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in
AOCI
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
—

 
$
—

 
$
(2.3
)
 
Cost of sales
Foreign currency contracts
 
(5.3
)
 
32.4

 
17.2

 
9.2

 
Cost of sales
Cross-currency contracts
 
(0.3
)
 
7.5

 
0.2

 
(0.1
)
 
Interest expense/other operating income, net
Interest rate contracts
 
(31.6
)
 
2.4

 
(1.9
)
 
(7.4
)
 
Interest expense
Total
 
$
(37.2
)
 
$
42.3

 
$
15.5

 
$
(0.6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 
 
Six Months Ended March 31,
 
2016
 
2015
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(52.2
)
 
$
(304.8
)
 
Cost of sales
 
 
Commodity contracts
 
1.8

 
(0.8
)
 
Revenues
 
 
Commodity contracts
 
(0.1
)
 
(0.5
)
 
Operating expenses/other
operating income, net
 
 
Total
 
$
(50.5
)
 
$
(306.1
)
 
 
 
 
 
 

For the three and six months ended March 31, 2016, the amounts of derivative gains or losses representing ineffectiveness were losses of $2.1 and $5.5, respectively, which are recorded in other operating income, net, on the Condensed Consolidated Statements of Income and are related to interest rate contracts at UGI France. For the three and six months ended March 31, 2016, the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material. For the three and six months ended March 31, 2015, the amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material.

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 many of these contracts have the requisite elements of a derivative instrument, certain of these contracts qualify for NPNS exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income
Note 13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three and six months ended March 31, 2016 and 2015:

Three Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2015
 
$
(20.0
)
 
$
12.7

 
$
(135.6
)
 
$
(142.9
)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
 
—

 
(29.7
)
 
46.7

 
17.0

Amounts reclassified from AOCI:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.4

 
(7.0
)
 
—

 
(6.6
)
Reclassification adjustments tax expense
 
(0.1
)
 
2.7

 
—

 
2.6

Reclassification adjustments (after-tax)
 
0.3

 
(4.3
)
 
—

 
(4.0
)
Other comprehensive income (loss) attributable to UGI
 
0.3

 
(34.0
)
 
46.7

 
13.0

AOCI - March 31, 2016
 
$
(19.7
)
 
$
(21.3
)
 
$
(88.9
)
 
$
(129.9
)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency (a)
 
Total
AOCI - December 31, 2014
 
$
(20.0
)
 
$
1.7

 
$
(21.8
)
 
$
(40.1
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
20.2

 
(64.5
)
 
(44.3
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(3.0
)
 
—

 
(2.4
)
Reclassification adjustments tax benefit
 
(0.2
)
 
1.1

 
—

 
0.9

Reclassification adjustments (after-tax)
 
0.4

 
(1.9
)
 
—

 
(1.5
)
Other comprehensive income (loss)
 
0.4

 
18.3

 
(64.5
)
 
(45.8
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
0.5

 
—

 
0.5

Other comprehensive income (loss) attributable to UGI
 
0.4

 
18.8

 
(64.5
)
 
(45.3
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)


Six Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2015
 
$
(20.4
)
 
$
11.2

 
$
(105.4
)
 
$
(114.6
)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
 
—

 
(22.9
)
 
16.5

 
(6.4
)
Amounts reclassified from AOCI:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.1

 
(15.5
)
 
—

 
(14.4
)
Reclassification adjustments tax expense
 
(0.4
)
 
5.9

 
—

 
5.5

Reclassification adjustments (after-tax)
 
0.7

 
(9.6
)
 
—

 
(8.9
)
Other comprehensive income (loss) attributable to UGI
 
0.7

 
(32.5
)
 
16.5

 
(15.3
)
AOCI - March 31, 2016
 
$
(19.7
)
 
$
(21.3
)
 
$
(88.9
)
 
$
(129.9
)
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency (a)
 
Total
AOCI - September 30, 2014
 
$
(20.6
)
 
$
(9.3
)
 
$
8.7

 
$
(21.2
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
27.9

 
(95.0
)
 
(67.1
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.6

 
0.6

 
—

 
2.2

Reclassification adjustments tax benefit
 
(0.6
)
 
(0.4
)
 
—

 
(1.0
)
Reclassification adjustments (after-tax)
 
1.0

 
0.2

 
—

 
1.2

Other comprehensive income (loss)
 
1.0

 
28.1

 
(95.0
)
 
(65.9
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
1.7

 
—

 
1.7

Other comprehensive income (loss) attributable to UGI
 
1.0

 
29.8

 
(95.0
)
 
(64.2
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)


(a)
See Note 2 relating to correction of prior period error in other comprehensive income.
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12.
Segment Information
Segment Information
Note 14 — Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. As more fully described below, effective October 1, 2015, the composition of our UGI Utilities (formerly Gas Utility) and Energy Services reportable segments changed to include certain operating segments previously included in Corporate & Other. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising UGI France; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) UGI Utilities; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”

As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”) associated with our regulated utility operations, effective October 1, 2015, we began including our Electric Utility operating segment with our Gas Utility reportable segment now referred to as “UGI Utilities.” Also, as a result of changes in segment management and reporting for HVAC, effective October 1, 2015, we began including HVAC operating segment within our Energy Services reportable segment. Previously, these two business units, neither of which met the quantitative threshold for presentation as a reportable segment under GAAP, were included within “Corporate & Other” in our segment information. In accordance with GAAP, prior-period amounts for these reportable segments have been restated to reflect these changes.

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 2015 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 net gains and losses on commodity derivative instruments not associated with current-period transactions (“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. We evaluate the performance of our other reportable segments principally based upon their income before income taxes as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s CODM does not consider such items when evaluating the financial performance of our reportable segments.
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Three Months Ended
March 31, 2016
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy Services
 
Electric Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
1,972.1

 
$
(59.2
)
(c)
$
827.5

 
$
322.0

 
$
285.7

 
$
15.8

 
$
446.7

 
$
132.0

 
$
1.6

Cost of sales
 
$
776.9

 
$
(58.5
)
(c)
$
298.2

 
$
137.5

 
$
186.1

 
$
6.3

 
$
197.2

 
$
73.8

 
$
(63.7
)
Segment profit:
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Operating income
 
$
615.4

 
$
—

 
$
250.4

 
$
114.5

 
$
76.1

 
$
1.7

 
$
94.6

 
$
16.9

 
$
61.2

Interest expense
 
(57.3
)
 
—

 
(40.8
)
 
(9.3
)
 
(0.5
)
 
—

 
(5.6
)
 
(0.9
)
 
(0.2
)
Income before income taxes
 
$
558.1

 
$
—

 
$
209.6

 
$
105.2

 
$
75.6

 
$
1.7

 
$
89.0

 
$
16.0

 
$
61.0

Partnership Adjusted EBITDA (a)
 

 
 
 
$
295.4

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
174.8

 
$
—

 
$
146.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
28.7

Depreciation and amortization
 
$
100.7

 
$
(0.1
)
 
$
47.4

 
$
17.0

 
$
4.3

 
$
3.4

 
$
23.3

 
$
5.0

 
$
0.4

Capital expenditures (including the effects of accruals)
 
$
114.5

 
$
—

 
$
27.8

 
$
48.1

 
$
15.2

 
$
1.1

 
$
17.3

 
$
5.0

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Three Months Ended
March 31, 2015 (d)
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
2,455.6

 
$
(114.7
)
(c)
$
1,100.3

 
$
500.6

 
$
424.1

 
$
24.8

 
$
347.2

 
$
172.9

 
$
0.4

Cost of sales
 
$
1,205.4

 
$
(114.0
)
(c)
$
505.2

 
$
278.3

 
$
305.5

 
$
9.4

 
$
200.3

 
$
123.3

 
$
(102.6
)
Segment profit:
 
 
 
 
 
 
 
 
 

 

 
 
 
 
 
 
Operating income
 
$
702.1

 
$
0.1

 
$
296.9

 
$
142.7

 
$
91.1

 
$
8.0

 
$
53.2

 
$
11.5

 
$
98.6

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(58.2
)
 
—

 
(41.1
)
 
(10.7
)
 
(0.5
)
 
—

 
(4.9
)
 
(0.9
)
 
(0.1
)
Income before income taxes
 
$
643.8

 
$
0.1

 
$
255.8

 
$
132.0

 
$
90.6

 
$
8.0

 
$
48.2

 
$
10.6

 
$
98.5

Partnership Adjusted EBITDA (a)
 

 
 
 
$
342.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (e)
 
$
235.7

 
$
—

 
$
180.9

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
54.5

Depreciation and amortization
 
$
88.0

 
$
(0.1
)
 
$
48.1

 
$
15.7

 
$
3.9

 
$
3.3

 
$
11.8

 
$
5.2

 
$
0.1

Capital expenditures (including the effects of accruals)
 
$
91.4

 
$
—

 
$
26.8

 
$
41.3

 
$
6.0

 
$
2.3

 
$
9.6

 
$
5.4

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Six Months Ended
March 31, 2016
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
3,578.7

 
$
(104.6
)
(c)
$
1,471.6

 
$
520.0

 
$
500.5

 
$
30.6

 
$
855.4

 
$
301.5

 
$
3.7

Cost of sales
 
$
1,510.9

 
$
(103.0
)
(c)
$
541.4

 
$
212.9

 
$
337.3

 
$
12.3

 
$
389.8

 
$
184.0

 
$
(63.8
)
Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
 
$
920.9

 
$
0.1

 
$
380.0

 
$
162.8

 
$
117.4

 
$
3.3

 
$
163.3

 
$
33.3

 
$
60.7

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(115.2
)
 
—

 
(81.8
)
 
(18.8
)
 
(1.3
)
 
—

 
(11.2
)
 
(1.8
)
 
(0.3
)
Income before income taxes
 
$
805.6

 
$
0.1

 
$
298.2

 
$
144.0

 
$
116.1

 
$
3.3

 
$
152.0

 
$
31.5

 
$
60.4

Partnership Adjusted EBITDA (a)
 

 
 
 
$
473.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
228.1

 
$
—

 
$
203.3

 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
24.6

Depreciation and amortization
 
$
201.3

 
$
(0.1
)
 
$
96.6

 
$
33.7

 
$
8.4

 
$
6.7

 
$
44.9

 
$
10.6

 
$
0.5

Capital expenditures (including the effects of accruals)
 
$
247.4

 
$
—

 
$
55.8

 
$
109.6

 
$
37.1

 
$
1.6

 
$
33.6

 
$
9.7

 
$
—

As of March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,955.4

 
$
(87.5
)
 
$
4,201.1

 
$
2,641.6

 
$
723.0

 
$
277.2

 
$
2,522.4

 
$
551.7

 
$
125.9

Short-term borrowings
 
$
227.1

 
$
—

 
$
65.3

 
$
155.0

 
$
4.0

 
$
—

 
$
1.6

 
$
1.2

 
$
—

Goodwill
 
$
2,998.6

 
$
—

 
$
1,971.3

 
$
182.1

 
$
11.5

 
$
—

 
$
734.5

 
$
99.2

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Six Months Ended
March 31, 2015 (d)
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
4,460.2

 
$
(182.4
)
(c)
$
1,989.1

 
$
787.9

 
$
738.2

 
$
41.3

 
$
685.1

 
$
397.5

 
$
3.5

Cost of sales
 
$
2,610.0

 
$
(181.0
)
(c)
$
967.6

 
$
421.4

 
$
550.1

 
$
17.4

 
$
409.6

 
$
295.9

 
$
129.0

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
785.4

 
$
0.1

 
$
436.6

 
$
218.3

 
$
137.4

 
$
7.3

 
$
91.6

 
$
26.6

 
$
(132.5
)
Loss from equity investees
 
(1.1
)
 
—

 
—

 
—

 
—

 
—

 
(1.1
)
 
—

 
—

Interest expense
 
(117.2
)
 
—

 
(82.1
)
 
(21.3
)
 
(1.1
)
 
—

 
(10.5
)
 
(1.9
)
 
(0.3
)
Income (loss) before income taxes
 
$
667.1

 
$
0.1

 
$
354.5

 
$
197.0

 
$
136.3

 
$
7.3

 
$
80.0

 
$
24.7

 
$
(132.8
)
Partnership EBITDA (a)
 
 
 
 
 
$
530.6

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (e)
 
$
201.8

 
$
—

 
$
247.7

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

 
$
(46.3
)
Depreciation and amortization
 
$
179.0

 
$
—

 
$
97.5

 
$
31.1

 
$
7.7

 
$
6.0

 
$
25.1

 
$
11.3

 
$
0.3

Capital expenditures (including the effects of accruals)
 
$
214.9

 
$
—

 
$
57.2

 
$
96.3

 
$
18.9

 
$
8.9

 
$
21.7

 
$
11.8

 
$
0.1

As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,182.7

 
$
(109.5
)
 
$
4,423.8

 
$
2,506.0

 
$
719.6

 
$
281.2

 
$
1,569.2

 
$
539.7

 
$
252.7

Short-term borrowings
 
$
89.9

 
$
—

 
$
55.0

 
$
30.5

 
$
—

 
$
—

 
$
0.1

 
$
4.3

 
$
—

Goodwill
 
$
2,731.2

 
$
—

 
$
1,949.7

 
$
182.1

 
$
11.8

 
$
—

 
$
510.9

 
$
76.7

 
$
—


(a)
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2016
 
2015
 
2016
 
2015
Partnership Adjusted EBITDA
 
$
295.4

 
$
342.1

 
$
473.1

 
$
530.6

Depreciation and amortization
 
(47.4
)
 
(48.1
)
 
(96.6
)
 
(97.5
)
Noncontrolling interests (i)
 
2.4

 
2.9

 
3.5

 
3.5

Operating income
 
$
250.4

 
$
296.9

 
$
380.0

 
$
436.6

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

(b)
Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company, and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $64.0 and $102.2 during the three months ended March 31, 2016 and 2015, respectively, and $65.1 and $(127.5) during the six months ended March 31, 2016 and 2015, respectively. Corporate & Other assets principally comprise cash and short-term investments of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(d)
Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.
(e)
Amounts for AmeriGas Propane and Corporate & Other have been corrected to properly reflect gains and (losses) on commodity derivative instruments not associated with current period transactions.
Acquisition of Totalgaz
Acquisition of Totalgaz
Note 15 — Acquisition of Totalgaz

On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, France SAS, acquired all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France. In November 2015, France SAS received €1.1 ($1.2) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition nearly doubles our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions.

The Company has accounted for the Totalgaz Acquisition using the acquisition method. At March 31, 2016, the allocation of the purchase price is substantially complete except for the valuation of certain liabilities associated with cylinder deposits and amounts related to deferred income tax assets and liabilities. These amounts are preliminary pending the obtaining of additional information. The Company expects to obtain additional information during the measurement period under GAAP of up to one year from the Acquisition Date as necessary to determine the final allocation of the purchase price. Accordingly, the fair value estimates presented below relating to these items are subject to change.

The components of the Totalgaz purchase price allocation are as follows:

Assets acquired:
 
Cash
$
86.8

Accounts receivable (a)
170.3

Prepaid expenses and other current assets
11.0

Property, plant and equipment
375.6

Intangible assets (b)
91.3

Other assets
21.4

Total assets acquired
$
756.4

 
 
Liabilities assumed:
 
Accounts payable
109.2

Other current liabilities
103.5

Deferred income taxes
115.8

Other noncurrent liabilities
117.5

Total liabilities assumed
$
446.0

Goodwill
186.2

Net consideration transferred (including working capital adjustments)
$
496.6


(a)
Approximates the gross contractual amounts of receivables acquired.
(b)
Comprises $79.3 of customer relationships and $12.0 of tradenames.

The excess of the purchase price for the Totalgaz Acquisition over the preliminary fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI France reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes.
The Company recognized $7.2 and $11.0 of direct transaction-related costs associated with the Totalgaz Acquisition during the three and six months ended March 31, 2015, respectively, which are reflected primarily in operating and administrative expenses on the Condensed Consolidated Statements of Income.

The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for the three and six months ended March 31, 2015 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014.
 
Three Months Ended
March 31, 2015
 
Six Months Ended
March 31, 2015
 
As Reported
 
Pro Forma Adjusted
 
As Reported
 
Pro Forma Adjusted
Revenues
$
2,455.6

 
$
2,601.8

 
$
4,460.2

 
$
4,786.3

Net income attributable to UGI Corporation
$
246.5

 
$
287.3

 
$
280.6

 
$
333.9

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
 
 
 
Basic
$
1.42

 
$
1.66

 
$
1.62

 
$
1.93

Diluted
$
1.40

 
$
1.64

 
$
1.60

 
$
1.90


The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
In connection with the Totalgaz Acquisition, the Company agreed with the French Competition Authority (the “FCA”) to divest certain assets and investments of Totalgaz SAS and certain assets of Antargaz located in France no later than August 15, 2016. Following the closing of the Totalgaz Acquisition, two competitors in the French LPG distribution market challenged the decision of the FCA. The competitors’ request for interim measures suspending the effectiveness of the agreed remedies was denied by the supreme administrative court (conseil d’etat). Proceedings on the merits are continuing. While UGI cannot predict the final outcome of these proceedings at this time, we believe the FCA and the Company have strong defenses to the claims and intend to vigorously defend against them.
For additional information regarding the Totalgaz Acquisition, see Note 4 to the Company’s 2015 Annual Report.
Summary of Significant Accounting Policies (Policies)
Earnings Per Common Share 
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Derivative Instruments 
Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by Gas Utility and Electric Utility (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.

Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, on the Condensed Consolidated Statements of Income.

Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities.

Use of Estimates 
Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Adoption of New Accounting Standard and Accounting Standards Not Yet Adopted 
Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as a result, the September 30, 2015 and March 31, 2015 Condensed Consolidated Balance Sheets included herein have not been adjusted.
Accounting Standards Not Yet Adopted

Share-Based Payments. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2016 (Fiscal 2018). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.
Debt Issuance Costs. In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard 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. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.
Summary of Significant Accounting Policies (Tables)
Shares Used in Computing Basic and Diluted Earnings Per Share
Shares used in computing basic and diluted earnings per share are as follows: 
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2016
 
2015
 
2016
 
2015
Denominator (thousands of shares):
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding - basic
 
172,619

 
173,154

 
172,733

 
173,055

Incremental shares issuable for stock options and awards
 
2,226

 
2,474

 
2,220

 
2,660

Weighted-average common shares outstanding - diluted
 
174,845

 
175,628

 
174,953

 
175,715

Inventories (Tables)
Components of Inventories
Inventories comprise the following: 
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Non-utility LPG and natural gas
 
$
106.7

 
$
140.7

 
$
135.8

Gas Utility natural gas
 
3.8

 
37.5

 
6.3

Materials, supplies and other
 
66.0

 
61.7

 
59.4

Total inventories
 
$
176.5

 
$
239.9

 
$
201.5

Goodwill and Intangible Assets (Tables)
Components of Company's Goodwill and Intangible Assets
Goodwill and intangible assets comprise the following: 
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Goodwill (not subject to amortization)
 
$
2,998.6

 
$
2,953.4

 
$
2,731.2

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
778.3

 
$
761.1

 
$
670.2

Accumulated amortization
 
(312.3
)
 
(282.4
)
 
(254.1
)
Intangible assets, net (definite-lived)
 
466.0

 
478.7

 
416.1

Trademarks and tradenames (indefinite-lived)
 
132.2

 
131.4

 
121.4

Total intangible assets, net
 
$
598.2

 
$
610.1

 
$
537.5

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)
Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility
The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
Regulatory assets:
 
 
 
 
 
 
Income taxes recoverable
 
$
118.2

 
$
115.9

 
$
111.5

Underfunded pension and postretirement plans
 
135.8

 
140.8

 
105.5

Environmental costs (a)
 
60.5

 
20.0

 
14.1

Removal costs, net
 
25.0

 
21.2

 
18.4

Other
 
8.7

 
6.3

 
3.1

Total regulatory assets
 
$
348.2

 
$
304.2

 
$
252.6

Regulatory liabilities (b):
 
 
 
 
 
 
Postretirement benefits
 
$
19.3

 
$
20.0

 
$
19.3

Deferred fuel and power refunds
 
30.8

 
36.6

 
40.6

State tax benefits—distribution system repairs
 
14.2

 
13.3

 
10.6

Other
 
2.5

 
1.1

 
2.1

Total regulatory liabilities
 
$
66.8

 
$
71.0

 
$
72.6



(a)
Environmental costs at March 31, 2016, include amounts probable of recovery recorded in conjunction with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 9).
(b)
Regulatory liabilities are recorded in other current and other noncurrent liabilities on the Condensed Consolidated Balance Sheets.
Defined Benefit Pension and Other Postretirement Plans (Tables)
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs
Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
2.5

 
$
2.5

 
$
0.2

 
$
0.1

Interest cost
 
6.6

 
6.3

 
0.3

 
0.2

Expected return on assets
 
(8.0
)
 
(8.0
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1

 
0.1

 
(0.2
)
 
(0.1
)
Actuarial loss
 
2.7

 
2.5

 
—

 
—

Net benefit cost
 
3.9

 
3.4

 
0.2

 
0.1

Change in associated regulatory liabilities
 
—

 
—

 
0.8

 
1.0

Net expense
 
$
3.9

 
$
3.4

 
$
1.0

 
$
1.1

 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
5.0

 
$
4.9

 
$
0.4

 
$
0.3

Interest cost
 
13.2

 
12.6

 
0.5

 
0.4

Expected return on assets
 
(16.0
)
 
(15.9
)
 
(0.3
)
 
(0.3
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.2

 
0.2

 
(0.3
)
 
(0.2
)
Actuarial loss
 
5.4

 
5.0

 
—

 
—

Net benefit cost
 
7.8

 
6.8

 
0.3

 
0.2

Change in associated regulatory liabilities
 
—

 
—

 
1.7

 
1.9

Net expense
 
$
7.8

 
$
6.8

 
$
2.0

 
$
2.1

Fair Value Measurement (Tables)
Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis
The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2016, September 30, 2015 and March 31, 2015:  
 
 
Asset (Liability)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2016:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
20.3

 
$
16.7

 
$
—

 
$
37.0

Foreign currency contracts
 
$
—

 
$
11.6

 
$
—

 
$
11.6

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(59.0
)
 
$
(48.4
)
 
$
—

 
$
(107.4
)
Foreign currency contracts
 
$
—

 
$
(5.0
)
 
$
—

 
$
(5.0
)
Interest rate contracts
 
$
—

 
$
(3.4
)
 
$
—

 
$
(3.4
)
Cross-currency swaps
 
$
—

 
$
(1.3
)
 
$
—

 
$
(1.3
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8

September 30, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
17.4

 
$
11.6

 
$
—

 
$
29.0

Foreign currency contracts
 
$
—

 
$
29.1

 
$
—

 
$
29.1

Cross-currency swaps
 
$
—

 
$
0.4

 
$
—

 
$
0.4

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(70.0
)
 
$
(99.0
)
 
$
—

 
$
(169.0
)
Foreign currency contracts
 
$
—

 
$
(0.1
)
 
$
—

 
$
(0.1
)
Interest rate contracts
 
$
—

 
$
(10.8
)
 
$
—

 
$
(10.8
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
30.3

 
$
—

 
$
—

 
$
30.3

March 31, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
13.9

 
$
8.3

 
$
—

 
$
22.2

Foreign currency contracts
 
$
—

 
$
35.8

 
$
—

 
$
35.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
9.7

 
$
—

 
$
9.7

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(64.0
)
 
$
(104.3
)
 
$
—

 
$
(168.3
)
Interest rate contracts
 
$
—

 
$
(12.5
)
 
$
—

 
$
(12.5
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8



(a)
Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
Derivative Instruments and Hedging Activities (Tables)
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities 
The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2016 and 2015:
 
 
March 31,
2016
 
March 31,
2015
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Foreign currency contracts
 
$
11.6

 
$
35.8

Cross-currency contracts
 
—

 
9.7

Interest rate contracts
 
—

 
0.1

 
 
11.6

 
45.6

Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
1.2

 
—

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
35.8

 
22.2

Total derivative assets - gross
 
48.6

 
67.8

Gross amounts offset in the balance sheet
 
(26.4
)
 
(13.8
)
Total derivative assets - net
 
$
22.2

 
$
54.0

Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Foreign currency contracts
 
$
(5.0
)
 
$
—

Cross-currency contracts
 
(1.3
)
 
—

Interest rate contracts
 
(3.4
)
 
(12.5
)
 
 
(9.7
)
 
(12.5
)
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
(3.5
)
 
(5.2
)
Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
(103.9
)
 
(163.1
)
Total derivative liabilities - gross
 
(117.1
)
 
(180.8
)
Gross amounts offset in the balance sheet
 
26.4

 
13.8

Cash collateral pledged
 
0.1

 
3.7

Total derivative liabilities - net
 
$
(90.6
)
 
$
(163.3
)
Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest 
The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and six months ended March 31, 2016 and 2015:
 
 
Gain (Loss)
Recognized in
AOCI
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Three Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
—

 
$
—

 
$
0.1

 
Cost of sales
Foreign currency contracts
 
(10.7
)
 
23.7

 
8.1

 
6.5

 
Cost of sales
Cross-currency contracts
 
(0.3
)
 
5.4

 
0.2

 
(0.1
)
 
Interest expense/other operating income, net
Interest rate contracts
 
(37.2
)
 
1.6

 
(1.3
)
 
(3.5
)
 
Interest expense
Total
 
$
(48.2
)
 
$
30.7

 
$
7.0

 
$
3.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 

Three Months Ended March 31,
 
2016
 
2015
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(6.0
)
 
$
(12.3
)
 
Cost of sales
 

Commodity contracts
 
0.2

 
(4.6
)
 
Revenues
 
 
Total
 
$
(5.8
)
 
$
(16.9
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in
AOCI
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
—

 
$
—

 
$
(2.3
)
 
Cost of sales
Foreign currency contracts
 
(5.3
)
 
32.4

 
17.2

 
9.2

 
Cost of sales
Cross-currency contracts
 
(0.3
)
 
7.5

 
0.2

 
(0.1
)
 
Interest expense/other operating income, net
Interest rate contracts
 
(31.6
)
 
2.4

 
(1.9
)
 
(7.4
)
 
Interest expense
Total
 
$
(37.2
)
 
$
42.3

 
$
15.5

 
$
(0.6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 
 
Six Months Ended March 31,
 
2016
 
2015
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(52.2
)
 
$
(304.8
)
 
Cost of sales
 
 
Commodity contracts
 
1.8

 
(0.8
)
 
Revenues
 
 
Commodity contracts
 
(0.1
)
 
(0.5
)
 
Operating expenses/other
operating income, net
 
 
Total
 
$
(50.5
)
 
$
(306.1
)
 
 
 
 
 
 

Accumulated Other Comprehensive Income (Tables)
Schedule of Accumulated Other Comprehensive Income
The tables below present changes in AOCI during the three and six months ended March 31, 2016 and 2015:

Three Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2015
 
$
(20.0
)
 
$
12.7

 
$
(135.6
)
 
$
(142.9
)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
 
—

 
(29.7
)
 
46.7

 
17.0

Amounts reclassified from AOCI:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.4

 
(7.0
)
 
—

 
(6.6
)
Reclassification adjustments tax expense
 
(0.1
)
 
2.7

 
—

 
2.6

Reclassification adjustments (after-tax)
 
0.3

 
(4.3
)
 
—

 
(4.0
)
Other comprehensive income (loss) attributable to UGI
 
0.3

 
(34.0
)
 
46.7

 
13.0

AOCI - March 31, 2016
 
$
(19.7
)
 
$
(21.3
)
 
$
(88.9
)
 
$
(129.9
)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency (a)
 
Total
AOCI - December 31, 2014
 
$
(20.0
)
 
$
1.7

 
$
(21.8
)
 
$
(40.1
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
20.2

 
(64.5
)
 
(44.3
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(3.0
)
 
—

 
(2.4
)
Reclassification adjustments tax benefit
 
(0.2
)
 
1.1

 
—

 
0.9

Reclassification adjustments (after-tax)
 
0.4

 
(1.9
)
 
—

 
(1.5
)
Other comprehensive income (loss)
 
0.4

 
18.3

 
(64.5
)
 
(45.8
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
0.5

 
—

 
0.5

Other comprehensive income (loss) attributable to UGI
 
0.4

 
18.8

 
(64.5
)
 
(45.3
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)


Six Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2015
 
$
(20.4
)
 
$
11.2

 
$
(105.4
)
 
$
(114.6
)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
 
—

 
(22.9
)
 
16.5

 
(6.4
)
Amounts reclassified from AOCI:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.1

 
(15.5
)
 
—

 
(14.4
)
Reclassification adjustments tax expense
 
(0.4
)
 
5.9

 
—

 
5.5

Reclassification adjustments (after-tax)
 
0.7

 
(9.6
)
 
—

 
(8.9
)
Other comprehensive income (loss) attributable to UGI
 
0.7

 
(32.5
)
 
16.5

 
(15.3
)
AOCI - March 31, 2016
 
$
(19.7
)
 
$
(21.3
)
 
$
(88.9
)
 
$
(129.9
)
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency (a)
 
Total
AOCI - September 30, 2014
 
$
(20.6
)
 
$
(9.3
)
 
$
8.7

 
$
(21.2
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
27.9

 
(95.0
)
 
(67.1
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.6

 
0.6

 
—

 
2.2

Reclassification adjustments tax benefit
 
(0.6
)
 
(0.4
)
 
—

 
(1.0
)
Reclassification adjustments (after-tax)
 
1.0

 
0.2

 
—

 
1.2

Other comprehensive income (loss)
 
1.0

 
28.1

 
(95.0
)
 
(65.9
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
1.7

 
—

 
1.7

Other comprehensive income (loss) attributable to UGI
 
1.0

 
29.8

 
(95.0
)
 
(64.2
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)


(a)
See Note 2 relating to correction of prior period error in other comprehensive income.
Segment Information (Tables)
Schedule of Segment Reporting Information
Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s CODM does not consider such items when evaluating the financial performance of our reportable segments.
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Three Months Ended
March 31, 2016
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy Services
 
Electric Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
1,972.1

 
$
(59.2
)
(c)
$
827.5

 
$
322.0

 
$
285.7

 
$
15.8

 
$
446.7

 
$
132.0

 
$
1.6

Cost of sales
 
$
776.9

 
$
(58.5
)
(c)
$
298.2

 
$
137.5

 
$
186.1

 
$
6.3

 
$
197.2

 
$
73.8

 
$
(63.7
)
Segment profit:
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Operating income
 
$
615.4

 
$
—

 
$
250.4

 
$
114.5

 
$
76.1

 
$
1.7

 
$
94.6

 
$
16.9

 
$
61.2

Interest expense
 
(57.3
)
 
—

 
(40.8
)
 
(9.3
)
 
(0.5
)
 
—

 
(5.6
)
 
(0.9
)
 
(0.2
)
Income before income taxes
 
$
558.1

 
$
—

 
$
209.6

 
$
105.2

 
$
75.6

 
$
1.7

 
$
89.0

 
$
16.0

 
$
61.0

Partnership Adjusted EBITDA (a)
 

 
 
 
$
295.4

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
174.8

 
$
—

 
$
146.0

 
$
—

 
$
—

 
$
—

 
$
0.1

 
$
—

 
$
28.7

Depreciation and amortization
 
$
100.7

 
$
(0.1
)
 
$
47.4

 
$
17.0

 
$
4.3

 
$
3.4

 
$
23.3

 
$
5.0

 
$
0.4

Capital expenditures (including the effects of accruals)
 
$
114.5

 
$
—

 
$
27.8

 
$
48.1

 
$
15.2

 
$
1.1

 
$
17.3

 
$
5.0

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Three Months Ended
March 31, 2015 (d)
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
2,455.6

 
$
(114.7
)
(c)
$
1,100.3

 
$
500.6

 
$
424.1

 
$
24.8

 
$
347.2

 
$
172.9

 
$
0.4

Cost of sales
 
$
1,205.4

 
$
(114.0
)
(c)
$
505.2

 
$
278.3

 
$
305.5

 
$
9.4

 
$
200.3

 
$
123.3

 
$
(102.6
)
Segment profit:
 
 
 
 
 
 
 
 
 

 

 
 
 
 
 
 
Operating income
 
$
702.1

 
$
0.1

 
$
296.9

 
$
142.7

 
$
91.1

 
$
8.0

 
$
53.2

 
$
11.5

 
$
98.6

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(58.2
)
 
—

 
(41.1
)
 
(10.7
)
 
(0.5
)
 
—

 
(4.9
)
 
(0.9
)
 
(0.1
)
Income before income taxes
 
$
643.8

 
$
0.1

 
$
255.8

 
$
132.0

 
$
90.6

 
$
8.0

 
$
48.2

 
$
10.6

 
$
98.5

Partnership Adjusted EBITDA (a)
 

 
 
 
$
342.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (e)
 
$
235.7

 
$
—

 
$
180.9

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
54.5

Depreciation and amortization
 
$
88.0

 
$
(0.1
)
 
$
48.1

 
$
15.7

 
$
3.9

 
$
3.3

 
$
11.8

 
$
5.2

 
$
0.1

Capital expenditures (including the effects of accruals)
 
$
91.4

 
$
—

 
$
26.8

 
$
41.3

 
$
6.0

 
$
2.3

 
$
9.6

 
$
5.4

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Six Months Ended
March 31, 2016
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
3,578.7

 
$
(104.6
)
(c)
$
1,471.6

 
$
520.0

 
$
500.5

 
$
30.6

 
$
855.4

 
$
301.5

 
$
3.7

Cost of sales
 
$
1,510.9

 
$
(103.0
)
(c)
$
541.4

 
$
212.9

 
$
337.3

 
$
12.3

 
$
389.8

 
$
184.0

 
$
(63.8
)
Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
 
$
920.9

 
$
0.1

 
$
380.0

 
$
162.8

 
$
117.4

 
$
3.3

 
$
163.3

 
$
33.3

 
$
60.7

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(115.2
)
 
—

 
(81.8
)
 
(18.8
)
 
(1.3
)
 
—

 
(11.2
)
 
(1.8
)
 
(0.3
)
Income before income taxes
 
$
805.6

 
$
0.1

 
$
298.2

 
$
144.0

 
$
116.1

 
$
3.3

 
$
152.0

 
$
31.5

 
$
60.4

Partnership Adjusted EBITDA (a)
 

 
 
 
$
473.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
228.1

 
$
—

 
$
203.3

 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
24.6

Depreciation and amortization
 
$
201.3

 
$
(0.1
)
 
$
96.6

 
$
33.7

 
$
8.4

 
$
6.7

 
$
44.9

 
$
10.6

 
$
0.5

Capital expenditures (including the effects of accruals)
 
$
247.4

 
$
—

 
$
55.8

 
$
109.6

 
$
37.1

 
$
1.6

 
$
33.6

 
$
9.7

 
$
—

As of March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,955.4

 
$
(87.5
)
 
$
4,201.1

 
$
2,641.6

 
$
723.0

 
$
277.2

 
$
2,522.4

 
$
551.7

 
$
125.9

Short-term borrowings
 
$
227.1

 
$
—

 
$
65.3

 
$
155.0

 
$
4.0

 
$
—

 
$
1.6

 
$
1.2

 
$
—

Goodwill
 
$
2,998.6

 
$
—

 
$
1,971.3

 
$
182.1

 
$
11.5

 
$
—

 
$
734.5

 
$
99.2

 
$
—

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
Six Months Ended
March 31, 2015 (d)
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Revenues
 
$
4,460.2

 
$
(182.4
)
(c)
$
1,989.1

 
$
787.9

 
$
738.2

 
$
41.3

 
$
685.1

 
$
397.5

 
$
3.5

Cost of sales
 
$
2,610.0

 
$
(181.0
)
(c)
$
967.6

 
$
421.4

 
$
550.1

 
$
17.4

 
$
409.6

 
$
295.9

 
$
129.0

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
785.4

 
$
0.1

 
$
436.6

 
$
218.3

 
$
137.4

 
$
7.3

 
$
91.6

 
$
26.6

 
$
(132.5
)
Loss from equity investees
 
(1.1
)
 
—

 
—

 
—

 
—

 
—

 
(1.1
)
 
—

 
—

Interest expense
 
(117.2
)
 
—

 
(82.1
)
 
(21.3
)
 
(1.1
)
 
—

 
(10.5
)
 
(1.9
)
 
(0.3
)
Income (loss) before income taxes
 
$
667.1

 
$
0.1

 
$
354.5

 
$
197.0

 
$
136.3

 
$
7.3

 
$
80.0

 
$
24.7

 
$
(132.8
)
Partnership EBITDA (a)
 
 
 
 
 
$
530.6

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (e)
 
$
201.8

 
$
—

 
$
247.7

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

 
$
(46.3
)
Depreciation and amortization
 
$
179.0

 
$
—

 
$
97.5

 
$
31.1

 
$
7.7

 
$
6.0

 
$
25.1

 
$
11.3

 
$
0.3

Capital expenditures (including the effects of accruals)
 
$
214.9

 
$
—

 
$
57.2

 
$
96.3

 
$
18.9

 
$
8.9

 
$
21.7

 
$
11.8

 
$
0.1

As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,182.7

 
$
(109.5
)
 
$
4,423.8

 
$
2,506.0

 
$
719.6

 
$
281.2

 
$
1,569.2

 
$
539.7

 
$
252.7

Short-term borrowings
 
$
89.9

 
$
—

 
$
55.0

 
$
30.5

 
$
—

 
$
—

 
$
0.1

 
$
4.3

 
$
—

Goodwill
 
$
2,731.2

 
$
—

 
$
1,949.7

 
$
182.1

 
$
11.8

 
$
—

 
$
510.9

 
$
76.7

 
$
—


(a)
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2016
 
2015
 
2016
 
2015
Partnership Adjusted EBITDA
 
$
295.4

 
$
342.1

 
$
473.1

 
$
530.6

Depreciation and amortization
 
(47.4
)
 
(48.1
)
 
(96.6
)
 
(97.5
)
Noncontrolling interests (i)
 
2.4

 
2.9

 
3.5

 
3.5

Operating income
 
$
250.4

 
$
296.9

 
$
380.0

 
$
436.6

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

(b)
Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company, and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $64.0 and $102.2 during the three months ended March 31, 2016 and 2015, respectively, and $65.1 and $(127.5) during the six months ended March 31, 2016 and 2015, respectively. Corporate & Other assets principally comprise cash and short-term investments of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
(d)
Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.
(e)
Amounts for AmeriGas Propane and Corporate & Other have been corrected to properly reflect gains and (losses) on commodity derivative instruments not associated with current period transactions.
Acquisition of Totalgaz (Tables)
Schedule of Preliminary Purchase Price Allocation 
The components of the Totalgaz purchase price allocation are as follows:

Assets acquired:
 
Cash
$
86.8

Accounts receivable (a)
170.3

Prepaid expenses and other current assets
11.0

Property, plant and equipment
375.6

Intangible assets (b)
91.3

Other assets
21.4

Total assets acquired
$
756.4

 
 
Liabilities assumed:
 
Accounts payable
109.2

Other current liabilities
103.5

Deferred income taxes
115.8

Other noncurrent liabilities
117.5

Total liabilities assumed
$
446.0

Goodwill
186.2

Net consideration transferred (including working capital adjustments)
$
496.6


(a)
Approximates the gross contractual amounts of receivables acquired.
(b)
Comprises $79.3 of customer relationships and $12.0 of tradenames.
Schedule of Pro Forma Information 
The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for the three and six months ended March 31, 2015 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014.
 
Three Months Ended
March 31, 2015
 
Six Months Ended
March 31, 2015
 
As Reported
 
Pro Forma Adjusted
 
As Reported
 
Pro Forma Adjusted
Revenues
$
2,455.6

 
$
2,601.8

 
$
4,460.2

 
$
4,786.3

Net income attributable to UGI Corporation
$
246.5

 
$
287.3

 
$
280.6

 
$
333.9

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
 
 
 
Basic
$
1.42

 
$
1.66

 
$
1.62

 
$
1.93

Diluted
$
1.40

 
$
1.64

 
$
1.60

 
$
1.90

Nature of Operations (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2016
county
Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
 
General Partner held a general partner interest in AmeriGas Partners
1.00% 
 
Percentage of limited partnership interest in AmeriGas Partners
25.30% 
 
Effective ownership interest in AmeriGas OLP
27.10% 
 
General public as limited partner interests in AmeriGas Partners
73.70% 
 
General Partner incentive distribution
$ 17.3 
$ 13.1 
Number of counties of operation
1 
 
Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Denominator (thousands of shares):
 
 
 
 
Weighted-average common shares outstanding - basic
172,619 
173,154 
172,733 
173,055 
Incremental shares issuable for stock options and awards
2,226 
2,474 
2,220 
2,660 
Weighted-average common shares outstanding - diluted
174,845 
175,628 
174,953 
175,715 
Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2016
Accounting Policies [Abstract]
 
 
Increase in other comprehensive (loss) income
$ 32.7 
$ 47.1 
Inventories - Components of Inventories (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Inventory
 
 
 
Inventory, net
$ 176.5 
$ 239.9 
$ 201.5 
Non-utility LPG and natural gas
 
 
 
Inventory
 
 
 
Inventory, net
106.7 
140.7 
135.8 
Gas Utility natural gas
 
 
 
Inventory
 
 
 
Inventory, net
3.8 
37.5 
6.3 
Materials, supplies and other
 
 
 
Inventory
 
 
 
Inventory, net
$ 66.0 
$ 61.7 
$ 59.4 
Inventories (Details) (UGI Utilities, USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2016
Mar. 31, 2016
Storage Contract Administrative Agreements
Bcf
storage_agreement
Sep. 30, 2015
Storage Contract Administrative Agreements
Bcf
Mar. 31, 2015
Storage Contract Administrative Agreements
Bcf
Inventory
 
 
 
 
Number of storage agreements
 
2 
 
 
SCAA contract term (in years)
3 years 
 
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)
 
0.2 
4.0 
0.2 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
 
$ 0.5 
$ 9.8 
$ 0.7 
Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
Goodwill (not subject to amortization)
$ 2,998.6 
$ 2,953.4 
$ 2,731.2 1
Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
778.3 
761.1 
670.2 
Accumulated amortization
(312.3)
(282.4)
(254.1)
Intangible assets, net (definite-lived)
466.0 
478.7 
416.1 
Trademarks and tradenames (indefinite-lived)
132.2 
131.4 
121.4 
Total intangible assets, net
$ 598.2 
$ 610.1 
$ 537.5 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
 
Amortization expense of intangible assets
$ 15.2 
$ 12.0 
$ 28.0 
$ 25.0 
Remainder of Fiscal 2016
24.4 
 
24.4 
 
Fiscal 2017
46.6 
 
46.6 
 
Fiscal 2018
45.1 
 
45.1 
 
Fiscal 2019
43.4 
 
43.4 
 
Fiscal 2020
$ 42.1 
 
$ 42.1 
 
Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
$ 348.2 
$ 304.2 
$ 252.6 
Regulatory liabilities
66.8 1
71.0 1
72.6 1
Postretirement benefits
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
19.3 1
20.0 1
19.3 1
Deferred fuel and power refunds
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
30.8 1
36.6 1
40.6 1
State tax benefits—distribution system repairs
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
14.2 1
13.3 1
10.6 1
Other
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
2.5 1
1.1 1
2.1 1
Income taxes recoverable
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
118.2 
115.9 
111.5 
Underfunded pension and postretirement plans
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
135.8 
140.8 
105.5 
Environmental costs
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
60.5 2
20.0 2
14.1 2
Removal costs, net
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
25.0 
21.2 
18.4 
Other
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
$ 8.7 
$ 6.3 
$ 3.1 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended 0 Months Ended 6 Months Ended 12 Months Ended 1 Months Ended 6 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 6 Months Ended
Mar. 31, 2016
UGI Utilities
Jan. 19, 2016
UGI Utilities
Pennsylvania Public Utility Commission
Mar. 31, 2016
UGI Utilities
Pennsylvania Public Utility Commission
Sep. 30, 2014
UGI Utilities
Pennsylvania Public Utility Commission
Mar. 31, 2016
UGI Utilities
Pennsylvania Public Utility Commission
Maximum
Mar. 31, 2016
UGI Utilities
Pennsylvania Public Utility Commission
Maximum
Apr. 1, 2015
UGI Utilities
Pennsylvania Public Utility Commission
PNG
Mar. 31, 2016
UGI Utilities
Pennsylvania Public Utility Commission
PNG
Maximum
Mar. 31, 2016
UGI Utilities
Pennsylvania Public Utility Commission
CPG
Maximum
Apr. 1, 2016
UGI Utilities
Pennsylvania Public Utility Commission
Subsequent Event
CPG
Mar. 31, 2016
Gas Utility
Sep. 30, 2015
Gas Utility
Mar. 31, 2015
Gas Utility
Mar. 31, 2016
Electric Utility Electric Supply Contracts
Sep. 30, 2015
Electric Utility Electric Supply Contracts
Mar. 31, 2015
Electric Utility Electric Supply Contracts
Mar. 31, 2016
Deferred Project Costs
UGI Utilities
Mar. 31, 2016
Information Technology
UGI Utilities
Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of unrealized gains (losses)
 
 
 
 
 
 
 
 
 
 
$ (1.9)
$ (3.3)
$ (3.4)
$ (0.2)
$ (0.5)
$ (1.2)
 
 
Capitalized project costs
5.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1 
2.7 
Project costs expensed in prior periods
5.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Requested operating revenue increase
 
$ 58.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated time period for regulatory approval (in months)
 
9 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum period since petition to file a general rate filing
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DSIC, percent of amount billed to customers
 
 
 
0.00% 
5.00% 
5.00% 
0.00% 
10.00% 
10.00% 
0.00% 
 
 
 
 
 
 
 
 
Energy Services Accounts Receivable Securitization Facility (Details) (USD $)
6 Months Ended
Mar. 31, 2016
Energy Services
Mar. 31, 2015
Energy Services
Mar. 31, 2016
Energy Services Funding Corporation
Mar. 31, 2015
Energy Services Funding Corporation
Oct. 31, 2016
Forecast
Maximum
Apr. 30, 2016
Forecast
Maximum
Accounts, Notes, Loans and Financing Receivable
 
 
 
 
 
 
Receivables facility
 
 
 
 
$ 75,000,000 
$ 150,000,000 
Sale of trade receivables
468,000,000 
692,000,000 
 
 
 
 
Sale of undivided interests in its trade receivables to the commercial paper conduit
 
 
167,500,000 
216,500,000 
 
 
Outstanding balance of trade receivables
 
 
55,300,000 
96,900,000 
 
 
Outstanding balance of trade receivables sold
 
 
$ 4,000,000 
$ 0 
 
 
Debt (Details)
1 Months Ended 1 Months Ended
Mar. 31, 2016
USD ($)
Mar. 31, 2015
USD ($)
Feb. 29, 2016
Energy Services
Energy Services Credit Agreement
Oct. 31, 2015
Line of Credit
Flaga
Flaga Credit Facility Agreement
EUR (€)
Mar. 31, 2016
Line of Credit
Flaga
Flaga Multi-Currency Working Capital Facility
EUR (€)
Oct. 31, 2015
Line of Credit
Flaga
Revolving Credit Facility
Flaga Credit Facility Agreement
EUR (€)
Oct. 31, 2015
Line of Credit
Flaga
Revolving Credit Facility
Flaga Credit Facility Agreement
EURIBOR
Minimum
Oct. 31, 2015
Line of Credit
Flaga
Revolving Credit Facility
Flaga Credit Facility Agreement
EURIBOR
Maximum
Feb. 29, 2016
Line of Credit
Energy Services
Energy Services Credit Agreement
USD ($)
Feb. 29, 2016
Line of Credit
Energy Services
Energy Services Credit Agreement
Federal Funds Rate
Feb. 29, 2016
Line of Credit
Energy Services
Energy Services Credit Agreement
London Interbank Offered Rate (LIBOR)
Feb. 29, 2016
Line of Credit
Energy Services
Letter of Credit [Member]
Energy Services Credit Agreement
USD ($)
Oct. 31, 2015
Overdraft Facility
Flaga
Flaga Credit Facility Agreement
EUR (€)
Oct. 31, 2015
Guarantee Facility
Flaga
Flaga Credit Facility Agreement
EUR (€)
Oct. 31, 2015
Term Loan
Flaga
Flaga Credit Facility Agreement
EUR (€)
Oct. 31, 2015
Term Loan
Flaga
Flaga Credit Facility Agreement
Three-Month EURIBOR
Interest Rate Swap
Through September 2016
Oct. 31, 2015
Term Loan
Flaga
Flaga Credit Facility Agreement
Three-Month EURIBOR
Interest Rate Swap
October 2016 Through October 2020
Oct. 31, 2015
Term Loan
Flaga
Flaga Credit Facility Agreement
Three-Month EURIBOR
Minimum
Oct. 31, 2015
Term Loan
Flaga
Flaga Credit Facility Agreement
Three-Month EURIBOR
Maximum
Mar. 31, 2016
Term Loan
Flaga
Flaga Term Loan Due October 2016
EUR (€)
Mar. 31, 2016
Term Loan
Flaga
Flaga Term Loan Due August 2016
EUR (€)
Apr. 30, 2016
Senior Notes
UGI Utilities
Senior Notes due June 2026
Subsequent Event
USD ($)
Apr. 30, 2016
Senior Notes
UGI Utilities
Senior Notes due September 2046
Subsequent Event
USD ($)
Apr. 30, 2016
Senior Notes
UGI Utilities
Senior Notes due October 2046
Subsequent Event
USD ($)
Mar. 31, 2016
Senior Notes
UGI Utilities
Senior Notes Due September 2016
USD ($)
Line of Credit Facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity
 
 
 
€ 100,800,000.0 
€ 46,000,000 
€ 25,000,000 
 
 
$ 240,000,000 
 
 
$ 50,000,000 
€ 5,000,000 
€ 25,000,000 
€ 45,800,000.0 
 
 
 
 
 
 
 
 
 
 
Long-term debt
3,639,000,000 
3,428,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
19,100,000 
26,700,000 
 
 
 
 
Basis spread on variable rate
 
 
 
 
 
 
1.45% 
3.65% 
2.25% 
0.50% 
1.00% 
 
 
 
 
 
 
0.40% 
1.80% 
 
 
 
 
 
 
Facility fee on unused balance
 
 
 
 
 
30.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underlying EURIBOR fixed rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.18% 
0.23% 
 
 
 
 
 
 
 
 
Maximum ratio of total indebtedness to EBITDA
 
 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum ratio of EBITDA to interest expense
 
 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate principal amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 100,000,000 
$ 200,000,000 
$ 100,000,000 
$ 175,000,000 
Stated interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.95% 
4.12% 
4.12% 
5.75% 
Commitments and Contingencies (Details) (USD $)
6 Months Ended 6 Months Ended
Mar. 31, 2016
lb
Oct. 31, 2014
lawsuit
Mar. 31, 2016
UGI Utilities
Environmental Matters
Mar. 31, 2016
UGI Utilities
CPG and PNG COAs
Mar. 31, 2015
UGI Utilities
CPG and PNG COAs
Mar. 31, 2016
CPG MGP
Environmental Matters
Mar. 31, 2016
PNG MGP
Mar. 31, 2016
PNG MGP
Environmental Matters
Mar. 31, 2016
UGI Gas MGP Properties
Environmental Matters
Mar. 31, 2016
UGI Gas-COA
UGI Utilities
Mar. 31, 2016
PNG and CPG
UGI Utilities
subsidiary
Commitments and Contingencies
 
 
 
 
 
 
 
 
 
 
 
Number of subsidiaries acquired with similar histories
 
 
 
 
 
 
 
 
 
 
2 
Environmental expenditures cap during calendar year
 
 
 
 
 
$ 1,800,000.0 
 
$ 1,100,000.0 
 
 
 
Loss contingency, settlement agreement, terms
 
 
 
 
 
 
2 years 
 
 
 
 
Accrual for environmental loss contingencies
 
 
 
11,800,000 
9,600,000 
 
 
 
 
43,800,000 
 
Expected environmental expenditures cap during calendar year
 
 
 
 
 
 
 
 
$ 2,500,000 
 
 
Base year for determination of investigation and remediation cost (in years)
 
 
5 years 
 
 
 
 
 
 
 
 
Class action lawsuits (more than 35)
 
35 
 
 
 
 
 
 
 
 
 
Amount of propane in cylinders before reduction (in pounds)
17 
 
 
 
 
 
 
 
 
 
 
Amount of propane in cylinders after reduction (in pounds)
15 
 
 
 
 
 
 
 
 
 
 
Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Pension Benefits
 
 
 
 
Defined Benefit Plan Disclosure
 
 
 
 
Service cost
$ 2.5 
$ 2.5 
$ 5.0 
$ 4.9 
Interest cost
6.6 
6.3 
13.2 
12.6 
Expected return on assets
(8.0)
(8.0)
(16.0)
(15.9)
Amortization of:
 
 
 
 
Prior service cost (benefit)
0.1 
0.1 
0.2 
0.2 
Actuarial loss
2.7 
2.5 
5.4 
5.0 
Net benefit cost
3.9 
3.4 
7.8 
6.8 
Change in associated regulatory liabilities
0 
0 
0 
0 
Net expense
3.9 
3.4 
7.8 
6.8 
Other Postretirement Benefits
 
 
 
 
Defined Benefit Plan Disclosure
 
 
 
 
Service cost
0.2 
0.1 
0.4 
0.3 
Interest cost
0.3 
0.2 
0.5 
0.4 
Expected return on assets
(0.1)
(0.1)
(0.3)
(0.3)
Amortization of:
 
 
 
 
Prior service cost (benefit)
(0.2)
(0.1)
(0.3)
(0.2)
Actuarial loss
0 
0 
0 
0 
Net benefit cost
0.2 
0.1 
0.3 
0.2 
Change in associated regulatory liabilities
0.8 
1.0 
1.7 
1.9 
Net expense
$ 1.0 
$ 1.1 
$ 2.0 
$ 2.1 
Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)
6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
Contribution made to Pension and Post-retirement Plans
$ 4,900,000 
$ 5,600,000 
Expected contribution to pension plan during remainder of fiscal year
5,000,000 
 
Other Postretirement Benefits
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
Contribution made to Pension and Post-retirement Plans
$ 0 
$ 0 
Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
$ 48.6 
 
$ 67.8 
Derivative financial instruments, liabilities
(117.1)
 
(180.8)
Fair Value, Measurements, Recurring
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
31.8 1
30.3 1
31.8 1
Fair Value, Measurements, Recurring |
Commodity contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
37.0 
29.0 
22.2 
Derivative financial instruments, liabilities
(107.4)
(169.0)
(168.3)
Fair Value, Measurements, Recurring |
Foreign currency contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
11.6 
29.1 
35.8 
Derivative financial instruments, liabilities
(5.0)
(0.1)
 
Fair Value, Measurements, Recurring |
Interest rate contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
 
0.1 
Derivative financial instruments, liabilities
(3.4)
(10.8)
(12.5)
Fair Value, Measurements, Recurring |
Cross-currency swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
0.4 
9.7 
Derivative financial instruments, liabilities
(1.3)
 
 
Fair Value, Measurements, Recurring |
Level 1
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
31.8 1
30.3 1
31.8 1
Fair Value, Measurements, Recurring |
Level 1 |
Commodity contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
20.3 
17.4 
13.9 
Derivative financial instruments, liabilities
(59.0)
(70.0)
(64.0)
Fair Value, Measurements, Recurring |
Level 1 |
Foreign currency contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 
Derivative financial instruments, liabilities
0 
0 
 
Fair Value, Measurements, Recurring |
Level 1 |
Interest rate contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
 
0 
Derivative financial instruments, liabilities
0 
0 
0 
Fair Value, Measurements, Recurring |
Level 1 |
Cross-currency swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
0 
0 
Derivative financial instruments, liabilities
0 
 
 
Fair Value, Measurements, Recurring |
Level 2
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
0 1
0 1
0 1
Fair Value, Measurements, Recurring |
Level 2 |
Commodity contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
16.7 
11.6 
8.3 
Derivative financial instruments, liabilities
(48.4)
(99.0)
(104.3)
Fair Value, Measurements, Recurring |
Level 2 |
Foreign currency contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
11.6 
29.1 
35.8 
Derivative financial instruments, liabilities
(5.0)
(0.1)
 
Fair Value, Measurements, Recurring |
Level 2 |
Interest rate contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
 
0.1 
Derivative financial instruments, liabilities
(3.4)
(10.8)
(12.5)
Fair Value, Measurements, Recurring |
Level 2 |
Cross-currency swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
0.4 
9.7 
Derivative financial instruments, liabilities
(1.3)
 
 
Fair Value, Measurements, Recurring |
Level 3
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
0 1
0 1
0 1
Fair Value, Measurements, Recurring |
Level 3 |
Commodity contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 
Derivative financial instruments, liabilities
0 
0 
0 
Fair Value, Measurements, Recurring |
Level 3 |
Foreign currency contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 
Derivative financial instruments, liabilities
0 
0 
 
Fair Value, Measurements, Recurring |
Level 3 |
Interest rate contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
 
0 
Derivative financial instruments, liabilities
0 
0 
0 
Fair Value, Measurements, Recurring |
Level 3 |
Cross-currency swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
 
0 
0 
Derivative financial instruments, liabilities
$ 0 
 
 
Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Mar. 31, 2015
Fair Value Disclosures [Abstract]
 
 
Carrying value of long-term debt
$ 3,639.0 
$ 3,428.7 
Estimated fair value of long-term debt
$ 3,775.3 
$ 3,664.2 
Derivative Instruments and Hedging Activities (Details)
3 Months Ended 6 Months Ended 1 Months Ended 0 Months Ended 6 Months Ended 6 Months Ended
Mar. 31, 2016
USD ($)
Mar. 31, 2016
USD ($)
Sep. 30, 2015
USD ($)
Mar. 31, 2015
USD ($)
Mar. 31, 2016
UGI France
Mar. 31, 2016
Commodity contracts
USD ($)
Mar. 31, 2016
Interest Rate Swap
EUR (€)
Mar. 31, 2015
Interest Rate Swap
EUR (€)
Mar. 31, 2016
Interest Rate Swap
UGI France
USD ($)
Mar. 31, 2016
Interest Rate Swap
UGI France
EURIBOR
Mar. 31, 2016
Interest Rate Swap
UGI France
Term Loan
EUR (€)
Mar. 31, 2016
Interest Rate Protection Agreements
USD ($)
Mar. 31, 2015
Interest Rate Protection Agreements
USD ($)
Mar. 31, 2016
Interest Rate Protection Agreements
UGI Utilities
USD ($)
Mar. 31, 2016
Foreign currency contracts
USD ($)
Mar. 31, 2016
Foreign currency contracts
EUR (€)
Mar. 31, 2015
Foreign currency contracts
USD ($)
Mar. 31, 2015
Foreign currency contracts
EUR (€)
Mar. 31, 2016
Cross-currency contracts
USD ($)
Mar. 31, 2015
Cross-currency contracts
USD ($)
Mar. 31, 2016
Propane
Commodity contracts
gal
Mar. 31, 2015
Propane
Commodity contracts
gal
Mar. 31, 2016
Propane
Natural Gas Storage and Propane Storage NYMEX Contracts
gal
Mar. 31, 2015
Propane
Natural Gas Storage and Propane Storage NYMEX Contracts
gal
Mar. 31, 2016
Natural Gas
Natural Gas Futures, Forward And Pipeline Contracts
MMBTU
Mar. 31, 2015
Natural Gas
Natural Gas Futures, Forward And Pipeline Contracts
MMBTU
Mar. 31, 2016
Natural Gas
Gas Basis Swap Contracts
MMBTU
Mar. 31, 2015
Natural Gas
Gas Basis Swap Contracts
MMBTU
Mar. 31, 2016
Natural Gas
Natural Gas Storage and Propane Storage NYMEX Contracts
MMBTU
Mar. 31, 2015
Natural Gas
Natural Gas Storage and Propane Storage NYMEX Contracts
MMBTU
Mar. 31, 2016
Natural Gas
Gas Utility
Commodity contracts
MMBTU
Mar. 31, 2015
Natural Gas
Gas Utility
Commodity contracts
MMBTU
Mar. 31, 2016
Electricity
Commodity contracts
Long
kWh
Mar. 31, 2015
Electricity
Commodity contracts
Long
kWh
Mar. 31, 2016
Electricity
Commodity contracts
Short
kWh
Mar. 31, 2015
Electricity
Commodity contracts
Short
kWh
Mar. 31, 2016
Electricity
Electric Utility
Commodity contracts
kWh
Mar. 31, 2015
Electricity
Electric Utility
Commodity contracts
kWh
Mar. 31, 2016
Electricity
Electric Utility
Financial Transmission Rights
kWh
Mar. 31, 2016
Electricity
Electric Utility
NYISO Capacity Swap Contracts
Mar. 31, 2015
Electricity
Electric Utility
NYISO Capacity Swap Contracts
kWh
Derivative
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume of LPG commodity derivatives (in gallons)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
370,200,000 
362,500,000 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum length of time hedging exposure to LPG commodity price risk (in months)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (energy measure)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
84,700,000 
118,300,000 
90,100,000 
47,300,000 
1,700,000 
600,000 
10,000,000 
9,700,000 
591,100,000 
356,000,000 
431,600,000 
315,400,000 
23,600,000 
384,400,000 
89,700,000 
 
124,600,000 
Maximum length of time hedged in price risk cash flow hedges (in months)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36 months 
36 months 
 
 
 
 
 
 
 
 
56 months 
 
 
 
 
 
11 months 
 
34 months 
 
27 months 
 
8 months 
 
2 months 
2 months 
 
Amounts remaining in AOCI related to commodity derivative hedges
 
 
 
 
 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount (in currency)
 
 
 
 
 
 
645,800,000 
401,100,000 
 
 
600,000,000 
0 
0 
 
262,500,000 
0 
223,500,000 
0 
59,100,000 
52,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative interest rate floor
 
 
 
 
0.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payment to interest rate swap counterparties
 
 
 
 
 
 
 
 
7,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underlying EURIBOR fixed rate
 
 
 
 
 
 
 
 
 
0.18% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on settlement of IRPAs
 
 
 
 
 
 
 
 
 
 
 
 
 
36,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months
(3,100,000)
(3,100,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months
7,800,000 
7,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted cash
40,000,000 
40,000,000 
69,300,000 
56,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (loss) on ineffectiveness and excluded derivatives recognized in income
$ (2,100,000)
$ (5,500,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Mar. 31, 2015
Derivative assets:
 
 
Derivative asset, gross
$ 48.6 
$ 67.8 
Gross amounts offset in the balance sheet
(26.4)
(13.8)
Total derivative assets - net
22.2 
54.0 
Derivative liabilities:
 
 
Derivative liability, gross
(117.1)
(180.8)
Gross amounts offset in the balance sheet
26.4 
13.8 
Cash collateral pledged
0.1 
3.7 
Total derivative liabilities - net
(90.6)
(163.3)
Designated as Hedging Instrument
 
 
Derivative assets:
 
 
Derivative asset, gross
11.6 
45.6 
Derivative liabilities:
 
 
Derivative liability, gross
(9.7)
(12.5)
Designated as Hedging Instrument |
Foreign currency contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
11.6 
35.8 
Derivative liabilities:
 
 
Derivative liability, gross
(5.0)
0 
Designated as Hedging Instrument |
Cross-currency contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
0 
9.7 
Derivative liabilities:
 
 
Derivative liability, gross
(1.3)
0 
Designated as Hedging Instrument |
Interest rate contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
0 
0.1 
Derivative liabilities:
 
 
Derivative liability, gross
(3.4)
(12.5)
Derivatives Subject To PGC and DS Mechanisms |
Commodity contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
1.2 
0 
Derivative liabilities:
 
 
Derivative liability, gross
(3.5)
(5.2)
Derivatives Not Designated as Hedging Instruments |
Commodity contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
35.8 
22.2 
Derivative liabilities:
 
 
Derivative liability, gross
$ (103.9)
$ (163.1)
Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Derivatives Not Designated as Hedging Instruments
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in Income
$ (5.8)
$ (16.9)
$ (50.5)
$ (306.1)
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in AOCI
(48.2)
30.7 
(37.2)
42.3 
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
7.0 
3.0 
15.5 
(0.6)
Commodity contracts |
Derivatives Not Designated as Hedging Instruments |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in Income
(6.0)
(12.3)
(52.2)
(304.8)
Commodity contracts |
Derivatives Not Designated as Hedging Instruments |
Revenues
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in Income
0.2 
(4.6)
1.8 
(0.8)
Commodity contracts |
Derivatives Not Designated as Hedging Instruments |
Operating Expenses / Other Operating Income, Net
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in Income
 
 
(0.1)
(0.5)
Commodity contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in AOCI
0 
0 
0 
0 
Commodity contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
0 
0.1 
0 
(2.3)
Foreign currency contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in AOCI
(10.7)
23.7 
(5.3)
32.4 
Foreign currency contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
8.1 
6.5 
17.2 
9.2 
Cross-currency contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in AOCI
(0.3)
5.4 
(0.3)
7.5 
Cross-currency contracts |
Cash Flow Hedges |
Interest Expense / Other Operating Income, Net
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
0.2 
(0.1)
0.2 
(0.1)
Interest rate contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Recognized in AOCI
(37.2)
1.6 
(31.6)
2.4 
Interest rate contracts |
Cash Flow Hedges |
Interest Expense
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
$ (1.3)
$ (3.5)
$ (1.9)
$ (7.4)
Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
AOCI Attributable to Parent, Net of Tax
 
 
 
 
Balance, beginning of period
 
 
$ 3,572.4 
 
Amounts reclassified from AOCI:
 
 
 
 
Other comprehensive income (loss)
13.0 
(45.8)
(15.3)
(65.9)
Balance, end of period
3,925.0 
3,883.7 
3,925.0 
3,883.7 
Postretirement Benefit Plans
 
 
 
 
AOCI Attributable to Parent, Net of Tax
 
 
 
 
Balance, beginning of period
(20.0)
(20.0)
(20.4)
(20.6)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
0 
0 
0 
0 
Amounts reclassified from AOCI:
 
 
 
 
Reclassification adjustments (pre-tax)
0.4 
0.6 
1.1 
1.6 
Reclassification adjustments tax benefit (expense)
(0.1)
(0.2)
(0.4)
(0.6)
Reclassification adjustments (after-tax)
0.3 
0.4 
0.7 
1.0 
Other comprehensive income (loss)
 
0.4 
 
1.0 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
0 
 
0 
Other comprehensive income (loss) attributable to UGI
0.3 
0.4 
0.7 
1.0 
Balance, end of period
(19.7)
(19.6)
(19.7)
(19.6)
Derivative Instruments
 
 
 
 
AOCI Attributable to Parent, Net of Tax
 
 
 
 
Balance, beginning of period
12.7 
1.7 
11.2 
(9.3)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
(29.7)
20.2 
(22.9)
27.9 
Amounts reclassified from AOCI:
 
 
 
 
Reclassification adjustments (pre-tax)
(7.0)
(3.0)
(15.5)
0.6 
Reclassification adjustments tax benefit (expense)
2.7 
1.1 
5.9 
(0.4)
Reclassification adjustments (after-tax)
(4.3)
(1.9)
(9.6)
0.2 
Other comprehensive income (loss)
 
18.3 
 
28.1 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
0.5 
 
1.7 
Other comprehensive income (loss) attributable to UGI
(34.0)
18.8 
(32.5)
29.8 
Balance, end of period
(21.3)
20.5 
(21.3)
20.5 
Foreign Currency
 
 
 
 
AOCI Attributable to Parent, Net of Tax
 
 
 
 
Balance, beginning of period
(135.6)
(21.8)1
(105.4)
8.7 1
Other comprehensive (loss) income before reclassification adjustments (after-tax)
46.7 
(64.5)1
16.5 
(95.0)1
Amounts reclassified from AOCI:
 
 
 
 
Reclassification adjustments (pre-tax)
0 
0 1
0 
0 1
Reclassification adjustments tax benefit (expense)
0 
0 1
0 
0 1
Reclassification adjustments (after-tax)
0 
0 1
0 
0 1
Other comprehensive income (loss)
 
(64.5)1
 
(95.0)1
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
0 1
 
0 1
Other comprehensive income (loss) attributable to UGI
46.7 
(64.5)1
16.5 
(95.0)1
Balance, end of period
(88.9)
(86.3)1
(88.9)
(86.3)1
AOCI Attributable to Parent
 
 
 
 
AOCI Attributable to Parent, Net of Tax
 
 
 
 
Balance, beginning of period
(142.9)
(40.1)
(114.6)
(21.2)
Other comprehensive (loss) income before reclassification adjustments (after-tax)
17.0 
(44.3)
(6.4)
(67.1)
Amounts reclassified from AOCI:
 
 
 
 
Reclassification adjustments (pre-tax)
(6.6)
(2.4)
(14.4)
2.2 
Reclassification adjustments tax benefit (expense)
2.6 
0.9 
5.5 
(1.0)
Reclassification adjustments (after-tax)
(4.0)
(1.5)
(8.9)
1.2 
Other comprehensive income (loss)
 
(45.8)
 
(65.9)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
0.5 
 
1.7 
Other comprehensive income (loss) attributable to UGI
13.0 
(45.3)
(15.3)
(64.2)
Balance, end of period
$ (129.9)
$ (85.4)
$ (129.9)
$ (85.4)
Segment Information (Details)
6 Months Ended
Mar. 31, 2016
segment
Segment Reporting [Abstract]
 
Number of reportable segments (in reportable segments)
6 
Segment Information - Schedule of Segment Reporting Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Sep. 30, 2015
Segment Reporting Information
 
 
 
 
 
Revenues
$ 1,972.1 
$ 2,455.6 1
$ 3,578.7 
$ 4,460.2 1
 
Cost of sales
776.9 
1,205.4 1
1,510.9 
2,610.0 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
615.4 
702.1 1
920.9 
785.4 1
 
Loss from equity investees
0 
(0.1)1
(0.1)
(1.1)1
 
Interest expense
(57.3)
(58.2)1
(115.2)
(117.2)1
 
Income before income taxes
558.1 
643.8 1
805.6 
667.1 1
 
Noncontrolling interests’ net income
174.8 
235.7 1
228.1 
201.8 1
 
Depreciation and amortization
100.7 
88.0 1
201.3 
179.0 1
 
Capital expenditures (including the effects of accruals)
114.5 
91.4 1
247.4 
214.9 1
 
Total assets
10,955.4 
10,182.7 1
10,955.4 
10,182.7 1
10,546.6 
Short-term borrowings
227.1 
89.9 1
227.1 
89.9 1
189.9 
Goodwill
2,998.6 
2,731.2 1
2,998.6 
2,731.2 1
2,953.4 
AmeriGas Propane
 
 
 
 
 
Segment profit:
 
 
 
 
 
Operating income (loss)
250.4 
296.9 
380.0 
436.6 
 
Partnership Adjusted EBITDA
295.4 
342.1 
473.1 
530.6 
 
Depreciation and amortization
47.4 
48.1 
96.6 
97.5 
 
Eliminations
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
(59.2)2
(114.7)1 2
(104.6)2
(182.4)1 2
 
Cost of sales
(58.5)2
(114.0)1 2
(103.0)2
(181.0)1 2
 
Segment profit:
 
 
 
 
 
Operating income (loss)
0 
0.1 1
0.1 
0.1 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
0 
0 1
0 
0 1
 
Income before income taxes
0 
0.1 1
0.1 
0.1 1
 
Noncontrolling interests’ net income
0 
0 1
0 
0 1
 
Depreciation and amortization
(0.1)
(0.1)1
(0.1)
0 1
 
Capital expenditures (including the effects of accruals)
0 
0 1
0 
0 1
 
Total assets
(87.5)
(109.5)1
(87.5)
(109.5)1
 
Short-term borrowings
0 
0 1
0 
0 1
 
Goodwill
0 
0 1
0 
0 1
 
Operating Segments |
AmeriGas Propane
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
827.5 
1,100.3 1
1,471.6 
1,989.1 1
 
Cost of sales
298.2 
505.2 1
541.4 
967.6 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
250.4 
296.9 1
380.0 
436.6 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
(40.8)
(41.1)1
(81.8)
(82.1)1
 
Income before income taxes
209.6 
255.8 1
298.2 
354.5 1
 
Partnership Adjusted EBITDA
295.4 3
342.1 1 3
473.1 3
530.6 1 3
 
Noncontrolling interests’ net income
146.0 
180.9 1 4
203.3 
247.7 1 4
 
Depreciation and amortization
47.4 
48.1 1
96.6 
97.5 1
 
Capital expenditures (including the effects of accruals)
27.8 
26.8 1
55.8 
57.2 1
 
Total assets
4,201.1 
4,423.8 1
4,201.1 
4,423.8 1
 
Short-term borrowings
65.3 
55.0 1
65.3 
55.0 1
 
Goodwill
1,971.3 
1,949.7 1
1,971.3 
1,949.7 1
 
Operating Segments |
UGI Utilities
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
322.0 
500.6 1
520.0 
787.9 1
 
Cost of sales
137.5 
278.3 1
212.9 
421.4 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
114.5 
142.7 1
162.8 
218.3 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
(9.3)
(10.7)1
(18.8)
(21.3)1
 
Income before income taxes
105.2 
132.0 1
144.0 
197.0 1
 
Noncontrolling interests’ net income
0 
0 1
0 
0 1
 
Depreciation and amortization
17.0 
15.7 1
33.7 
31.1 1
 
Capital expenditures (including the effects of accruals)
48.1 
41.3 1
109.6 
96.3 1
 
Total assets
2,641.6 
2,506.0 1
2,641.6 
2,506.0 1
 
Short-term borrowings
155.0 
30.5 1
155.0 
30.5 1
 
Goodwill
182.1 
182.1 1
182.1 
182.1 1
 
Operating Segments |
Midstream & Marketing, Energy Services
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
285.7 
424.1 1
500.5 
738.2 1
 
Cost of sales
186.1 
305.5 1
337.3 
550.1 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
76.1 
91.1 1
117.4 
137.4 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
(0.5)
(0.5)1
(1.3)
(1.1)1
 
Income before income taxes
75.6 
90.6 1
116.1 
136.3 1
 
Noncontrolling interests’ net income
0 
0 1
0 
0 1
 
Depreciation and amortization
4.3 
3.9 1
8.4 
7.7 1
 
Capital expenditures (including the effects of accruals)
15.2 
6.0 1
37.1 
18.9 1
 
Total assets
723.0 
719.6 1
723.0 
719.6 1
 
Short-term borrowings
4.0 
0 1
4.0 
0 1
 
Goodwill
11.5 
11.8 1
11.5 
11.8 1
 
Operating Segments |
Midstream & Marketing, Electric Generation
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
15.8 
24.8 1
30.6 
41.3 1
 
Cost of sales
6.3 
9.4 1
12.3 
17.4 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
1.7 
8.0 1
3.3 
7.3 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
0 
0 1
0 
0 1
 
Income before income taxes
1.7 
8.0 1
3.3 
7.3 1
 
Noncontrolling interests’ net income
0 
0 1
0 
0 1
 
Depreciation and amortization
3.4 
3.3 1
6.7 
6.0 1
 
Capital expenditures (including the effects of accruals)
1.1 
2.3 1
1.6 
8.9 1
 
Total assets
277.2 
281.2 1
277.2 
281.2 1
 
Short-term borrowings
0 
0 1
0 
0 1
 
Goodwill
0 
0 1
0 
0 1
 
Operating Segments |
UGI International, UGI France
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
446.7 
347.2 1
855.4 
685.1 1
 
Cost of sales
197.2 
200.3 1
389.8 
409.6 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
94.6 
53.2 1
163.3 
91.6 1
 
Loss from equity investees
 
(0.1)1
(0.1)
(1.1)1
 
Interest expense
(5.6)
(4.9)1
(11.2)
(10.5)1
 
Income before income taxes
89.0 
48.2 1
152.0 
80.0 1
 
Noncontrolling interests’ net income
0.1 
0.3 1
0.2 
0.4 1
 
Depreciation and amortization
23.3 
11.8 1
44.9 
25.1 1
 
Capital expenditures (including the effects of accruals)
17.3 
9.6 1
33.6 
21.7 1
 
Total assets
2,522.4 
1,569.2 1
2,522.4 
1,569.2 1
 
Short-term borrowings
1.6 
0.1 1
1.6 
0.1 1
 
Goodwill
734.5 
510.9 1
734.5 
510.9 1
 
Operating Segments |
UGI International, Flaga & Other
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
132.0 
172.9 1
301.5 
397.5 1
 
Cost of sales
73.8 
123.3 1
184.0 
295.9 1
 
Segment profit:
 
 
 
 
 
Operating income (loss)
16.9 
11.5 1
33.3 
26.6 1
 
Loss from equity investees
 
0 1
0 
0 1
 
Interest expense
(0.9)
(0.9)1
(1.8)
(1.9)1
 
Income before income taxes
16.0 
10.6 1
31.5 
24.7 1
 
Noncontrolling interests’ net income
0 
0 1
0 
0 1
 
Depreciation and amortization
5.0 
5.2 1
10.6 
11.3 1
 
Capital expenditures (including the effects of accruals)
5.0 
5.4 1
9.7 
11.8 1
 
Total assets
551.7 
539.7 1
551.7 
539.7 1
 
Short-term borrowings
1.2 
4.3 1
1.2 
4.3 1
 
Goodwill
99.2 
76.7 1
99.2 
76.7 1
 
Corporate & Other
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
1.6 5
0.4 1 5
3.7 5
3.5 1 5
 
Cost of sales
(63.7)5
(102.6)1 5
(63.8)5
129.0 1 5
 
Segment profit:
 
 
 
 
 
Operating income (loss)
61.2 5
98.6 1 5
60.7 5
(132.5)1 5
 
Loss from equity investees
 
0 1 5
0 5
0 1 5
 
Interest expense
(0.2)5
(0.1)1 5
(0.3)5
(0.3)1 5
 
Income before income taxes
61.0 5
98.5 1 5
60.4 5
(132.8)1 5
 
Noncontrolling interests’ net income
28.7 5
54.5 1 4 5
24.6 5
(46.3)1 4 5
 
Depreciation and amortization
0.4 5
0.1 1 5
0.5 5
0.3 1 5
 
Capital expenditures (including the effects of accruals)
0 5
0 1 5
0 5
0.1 1 5
 
Total assets
125.9 5
252.7 1 5
125.9 5
252.7 1 5
 
Short-term borrowings
0 5
0 1 5
0 5
0 1 5
 
Goodwill
0 5
0 1 5
0 5
0 1 5
 
Gains (losses) on unsettled commodity derivative instruments, net
$ 64.0 
$ 102.2 
$ 65.1 
$ (127.5)
 
Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Segment Reporting Information
 
 
 
 
Depreciation and amortization
$ (100.7)
$ (88.0)1
$ (201.3)
$ (179.0)1
Operating income
615.4 
702.1 1
920.9 
785.4 1
General Partnership interest in AmeriGas OLP (percentage)
1.01% 
1.01% 
1.01% 
1.01% 
Amerigas Propane
 
 
 
 
Segment Reporting Information
 
 
 
 
Partnership Adjusted EBITDA
295.4 
342.1 
473.1 
530.6 
Depreciation and amortization
(47.4)
(48.1)
(96.6)
(97.5)
Noncontrolling interests
2.4 2
2.9 2
3.5 2
3.5 2
Operating income
$ 250.4 
$ 296.9 
$ 380.0 
$ 436.6 
Acquisition of Totalgaz (Details)
6 Months Ended 3 Months Ended 6 Months Ended 1 Months Ended
Mar. 31, 2016
USD ($)
competitor
Mar. 31, 2015
USD ($)
Mar. 31, 2016
Totalgaz SAS
USD ($)
Mar. 31, 2016
Totalgaz SAS
USD ($)
Nov. 30, 2015
Totalgaz SAS
France SAS
USD ($)
Nov. 30, 2015
Totalgaz SAS
France SAS
EUR (€)
Mar. 31, 2016
Totalgaz SAS
France SAS
2015 Senior Facilities Agreement
Term Loan
EUR (€)
Business Acquisition
 
 
 
 
 
 
 
Adjustment to working capital
 
 
 
 
$ 1,200,000 
€ 1,100,000 
 
Recognized direct transaction costs
 
 
7,200,000 
11,000,000 
 
 
 
Long-term debt
$ 3,639,000,000 
$ 3,428,700,000 
 
 
 
 
€ 600,000,000 
Number of competitors challenging agreement
2 
 
 
 
 
 
 
Acquisition of Totalgaz - Schedule of Preliminary Purchase Price Allocation (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Sep. 30, 2015
Mar. 31, 2015
May 29, 2015
Totalgaz SAS
May 29, 2015
Totalgaz SAS
Customer Relationships
Assets acquired:
 
 
 
 
 
Cash
 
 
 
$ 86.8 
 
Accounts receivable
 
 
 
170.3 1
 
Prepaid expenses and other current assets
 
 
 
11.0 
 
Property, plant and equipment
 
 
 
375.6 
 
Intangible assets
 
 
 
91.3 2
 
Other assets
 
 
 
21.4 
 
Total assets acquired
 
 
 
756.4 
 
Liabilities assumed:
 
 
 
 
 
Accounts payable
 
 
 
109.2 
 
Other current liabilities
 
 
 
103.5 
 
Deferred income taxes
 
 
 
115.8 
 
Other noncurrent liabilities
 
 
 
117.5 
 
Total liabilities assumed
 
 
 
446.0 
 
Goodwill
2,998.6 
2,953.4 
2,731.2 3
186.2 
 
Net consideration transferred (including working capital adjustments)
 
 
 
496.6 
 
Finite-lived intangibles assets acquired
 
 
 
 
79.3 2
Indefinite-lived intangible assets acquired
 
 
 
$ 12.0 2
 
Acquisition of Totalgaz - Schedule of Pro Forma Information (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
As Reported
 
 
 
 
Revenues
$ 1,972.1 
$ 2,455.6 1
$ 3,578.7 
$ 4,460.2 1
Net income attributable to UGI Corporation
233.2 
246.5 
347.8 
280.6 
Earnings Per Share [Abstract]
 
 
 
 
Basic (in dollars per share)
$ 1.35 
$ 1.42 
$ 2.01 
$ 1.62 
Diluted (in dollars per share)
$ 1.33 
$ 1.40 
$ 1.99 
$ 1.60 
Totalgaz SAS
 
 
 
 
Pro Forma Adjusted
 
 
 
 
Revenues
 
2,601.8 
 
4,786.3 
Net income attributable to UGI Corporation
 
$ 287.3 
 
$ 333.9 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic (in dollars per share)
 
$ 1.66 
 
$ 1.93 
Diluted (in dollars per share)
 
$ 1.64 
 
$ 1.90