Document and Entity Information

9 Months Ended

Jun. 30, 2012

Jul. 31, 2012

Entity Information [Line Items]

Entity Registrant Name

UGI CORP /PA/

Entity Central Index Key

0000884614

Document Type

10-Q

Document Period End Date

Jun. 30, 2012

Amendment Flag

false

Document Fiscal Year Focus

2012

Document Fiscal Period Focus

Q3

Current Fiscal Year End Date

--09-30

Entity Filer Category

Large Accelerated Filer

Entity Common Stock, Shares Outstanding

112,467,512

Condensed Consolidated Balance Sheets (unaudited) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Current assets:

Cash and cash equivalents

$ 436.5

$ 238.5

$ 317.8

Restricted cash

7.6

17.2

10.2

Accounts receivable (less allowances for doubtful accounts of $45.7, $36.8 and $45.0, respectively)

624.9

546.7

595.7

Accrued utility revenues

15.0

14.8

7.4

Inventories

317.3

363.0

271.6

Deferred income taxes

52.3

44.9

26.8

Utility regulatory assets

2.7

8.6

2.0

Derivative financial instruments

21.6

10.2

10.5

Prepaid expenses and other current assets

59.4

62.2

48.2

Total current assets

1,537.3

1,306.1

1,290.2

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $$2,226.8, $2,080.0 and $2,077.1, respectively)

4,188.9

3,204.5

3,216.8

Goodwill

2,756.0

1,562.2

1,612.0

Intangible assets, net

717.7

147.8

159.5

Other assets

452.3

442.7

395.2

Total assets

9,652.2

6,663.3

6,673.7

Current liabilities:

Current maturities of long-term debt

86.1

47.4

38.5

Bank loans

187.3

138.7

206.1

Accounts payable

346.0

399.6

338.7

Derivative financial instruments

116.5

49.7

21.2

Other current liabilities

577.4

442.5

430.4

Total current liabilities

1,313.3

1,077.9

1,034.9

Long-term debt

3,475.1

2,110.3

2,039.5

Deferred income taxes

832.8

709.2

678.3

Deferred investment tax credits

4.7

5.0

Other noncurrent liabilities

589.5

569.8

535.1

Total liabilities

6,215.4

4,472.2

4,292.8

Commitments and contingencies (note 11)

UGI Corporation stockholders' equity

UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,623,094, 115,507,094 and 115,507,094 shares, respectively)

1,148.8

937.4

934.9

Retained earnings

1,211.2

1,085.8

1,137.3

Accumulated other comprehensive (loss) income

(77.7)

(17.7)

67.6

Treasury stock, at cost

(24.3)

(27.8)

(28.6)

Total UGI Corporation stockholders' equity

2,258.0

1,977.7

2,111.2

Noncontrolling interests, principally in AmeriGas Partners

1,178.8

213.4

269.7

Total equity

3,436.8

2,191.1

2,380.9

Total liabilities and equity

$ 9,652.2

$ 6,663.3

$ 6,673.7

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)

In Millions, except Share data, unless otherwise specified

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Accounts receivable, allowances for doubtful accounts

$ 45.7

$ 36.8

$ 45.0

Property, plant and equipment, accumulated depreciation and amortization

$ 2,226.8

$ 2,080.0

$ 2,077.1

UGI Common Stock, without par value (in dollars per share)

UGI Common Stock, without par value, shares authorized (in shares)

300,000,000

UGI Common Stock, without par value, shares issued (in shares)

115,623,094

115,507,094

Condensed Consolidated Statements of Income (unaudited) (USD $)

In Millions, except Share data in Thousands, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Revenues

$ 1,277.2

$ 1,105.4

$ 5,393.5

$ 5,052.0

Costs and expenses:

Cost of sales (excluding depreciation shown below)

810.2

731.0

3,438.6

3,317.5

Operating and administrative expenses

405.8

304.3

1,191.5

966.4

Utility taxes other than income taxes

3.9

3.6

12.9

13.4

Depreciation

69.5

50.8

191.0

149.0

Amortization

15.1

7.0

36.7

19.6

Other income, net

(8.1)

(8.5)

(27.1)

(40.4)

Total costs and expenses

1,296.4

1,088.2

4,843.6

4,425.5

Operating income (loss)

(19.2)

17.2

549.9

626.5

Loss from equity investees

(0.1)

(0.2)

(0.8)

Gain (loss) on extinguishment of debt

0.1

0

(13.3)

(18.8)

Interest expense

(61.3)

(35.0)

(162.6)

(102.6)

(Loss) income before income taxes

(80.5)

(18.0)

373.8

504.3

Income tax benefit (taxes)

4.0

4.5

(113.2)

(147.2)

Net (loss) income

(76.5)

(13.5)

260.6

357.1

Less: net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners

70.2

6.3

(46.5)

(101.8)

Net (loss) income attributable to UGI Corporation

$ (6.3)

$ (7.2)

$ 214.1

$ 255.3

(Loss) earnings per common share attributable to UGI stockholders:

Basic (in dollars per share)

$ (0.06)

$ 1.90

$ 2.29

Diluted (in dollars per share)

$ (0.06)

$ 1.89

$ 2.26

Average common shares outstanding (thousands):

Basic (in shares)

112,726

112,020

112,484

111,515

Diluted (in shares)

112,726

112,020

113,295

113,046

Dividends declared per common share (in dollars per share)

$ 0.27

$ 0.26

$ 0.79

$ 0.76

Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Net (loss) income

$ (76.5)

$ (13.5)

$ 260.6

$ 357.1

Net (losses) gains on derivative instruments (net of tax of $9.3, $6.2, $48.6 and $(6.9), respectively)

(63.2)

(10.8)

(143.9)

25.6

Reclassifications of net losses on derivative instruments (net of tax of $(9.5) $(1.5), $(31.3) and $(18.5), respectively)

(24.8)

2.9

(69.5)

(11.0)

Foreign currency adjustments (net of tax of $11.2, $(2.8), $9.7 and $(8.8), respectively)

(35.6)

13.2

(33.9)

37.8

Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax

0.1

0

0.3

2.1

Comprehensive income

(150.4)

(14.0)

152.6

433.6

Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners

107.3

10.8

(0.4)

(100.6)

Comprehensive income attributable to UGI Corporation

$ (43.1)

$ (3.2)

$ 152.2

$ 333.0

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Tax on (loss) gain on derivative instruments

$ 9.3

$ 6.2

$ 48.6

$ (6.9)

Tax on reclassifications on derivative instruments

(9.5)

(1.5)

(31.3)

(18.5)

Tax on foreign currency adjustments

11.2

(2.8)

9.7

(8.8)

Tax on benefit plans

$ 0.1

$ 0

$ (0.2)

$ (1.4)

Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)

In Millions, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$ 260.6

$ 357.1

Reconcile to net cash from operating activities:

Depreciation and amortization

227.7

168.6

Deferred income taxes, net

9.9

24.8

Provision for uncollectible accounts

21.3

19.8

Net change in realized gains and losses deferred as cash flow hedges

(11.7)

13.8

Loss on extinguishments of debt, net

13.3

18.8

Other, net

2.6

18.4

Net change in:

Accounts receivable and accrued utility revenues

71.2

(93.1)

Inventories

128.1

56.7

Utility deferred fuel costs

8.1

33.0

Accounts payable

(132.2)

(51.3)

Other current assets

22.8

(6.8)

Other current liabilities

(55.5)

(92.6)

Net cash provided by operating activities

566.2

467.2

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(236.0)

(245.3)

Acquisitions of businesses, net of cash acquired

(1,573.7)

(49.6)

Decrease in restricted cash

9.6

24.6

Other

0.1

(1.7)

Net cash used by investing activities

(1,800.0)

(272.0)

CASH FLOWS FROM FINANCING ACTIVITIES

Dividends on UGI Common Stock

(88.7)

(84.7)

Distributions on AmeriGas Partners Common Units

(126.5)

(69.7)

Issuances of debt

1,550.4

981.5

Repayments of debt

(240.1)

(987.3)

Increase in bank loans

31.0

5.4

Receivables Facility net borrowings (repayments)

18.9

(12.1)

Issuances of UGI Common Stock

12.7

24.9

Issuance of AmeriGas Partners Common Units

276.6

Other

0.5

3.4

Net cash provided (used) by financing activities

1,434.8

(138.6)

EFFECT OF EXCHANGE RATE CHANGES ON CASH

(3.0)

0.5

Cash and cash equivalents increase

198.0

57.1

Cash and cash equivalents:

End of period

436.5

317.8

Beginning of period

238.5

260.7

Increase

198.0

57.1

AmeriGas Partners [Member]

CASH FLOWS FROM FINANCING ACTIVITIES

Issuance of AmeriGas Partners Common Units

$ 0

Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) an energy marketing, midstream infrastructure, storage and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”), and beginning January 12, 2012, also through AmeriGas OLP’s principal operating subsidiaries Heritage Operating, L.P. (“HOLP”) and Titan Propane LLC (“Titan LLC”). AmeriGas OLP, HOLP and Titan LLC are collectively referred to herein as the “Operating Partnerships.” On January 12, 2012, AmeriGas Partners completed the acquisition of the subsidiaries of Energy Transfer Partners, L.P., a Delaware limited partnership (“ETP”), that operated ETP’s propane distribution business (“Heritage Propane”) (see Note 4, “Partnership Acquisition of Heritage Propane”). AmeriGas Partners, AmeriGas OLP and HOLP are Delaware limited partnerships, and Titan LLC is a Delaware limited liability company. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the "Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At June 30, 2012, the General Partner held a 1% general partner interest and 25.4% limited partner interest in AmeriGas Partners and an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.6% interest in AmeriGas Partners comprises 39,460,280 publicly held Common Units and 29,567,362 Common Units held by ETP as a result of the acquisition of Heritage Propane. On August 1, 2012, Titan LLC merged with and into AmeriGas OLP.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries (1) conducts LPG distribution businesses in France and, subsequent to the Shell Acquisition described below, in Belgium, the Netherlands and Luxembourg (collectively “Antargaz”); (2) conducts LPG distribution businesses in 11 central and eastern European countries including, subsequent to the Shell Acquisition, Norway, Sweden and Finland (collectively referred to as “Flaga”); (3) conducts an LPG distribution business in the United Kingdom subsequent to the Shell Acquisition; and (4) conducts an LPG distribution business in the Nantong region of China. On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €133.6 ($179.0) in cash (the “Shell Acquisition”). We refer to our foreign LPG operations collectively as “International Propane.” Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage and energy services business primarily in the Mid-Atlantic region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries (“HVAC/R”).

Our natural gas and electric distribution utility businesses are 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;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” 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, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

Significant Accounting Policies

Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s and ETP’s limited partner interests in the Partnership and the outside ownership interests in certain subsidiaries of Antargaz and Flaga as noncontrolling interests. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method.

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, 2011 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 our Annual Report on Form 10-K for the year ended September 30, 2011 (“Company’s 2011 Annual Financial Statements and Notes”). 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.

Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts that are restricted from withdrawal.

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

Shares used in computing basic and diluted earnings per share are as follows:



	Three Months Ended June 30,		Nine Months Ended June 30,
	2012	2011	2012	2011
Denominator (thousands of shares):
Average common shares outstanding for basic computation	112,726	112,020	112,484	111,515
Incremental shares issuable for stock options and awards	—	—	811	1,531
Average common shares outstanding for diluted computation	112,726	112,020	113,295	113,046

Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.

Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.

Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we now believe it is more likely than not that a portion of our foreign tax credits will be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $4.7 for the nine months ended June 30, 2012.

As a result of the completion of the audit of the Company’s 2009 federal income tax return, during the nine months ended June 30, 2012, the Company adjusted its unrecognized tax benefits, which amount was not material.

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.

Accounting Changes

Adoption of New Accounting Standards

Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.

Fair Value Measurements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance became effective for our interim period ending March 31, 2012 and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.

New Accounting Standards Not Yet Adopted

Indefinite-Lived Intangible Asset Impairment. In July 2012, the FASB issued guidance on testing indefinite-lived intangible assets, other than goodwill, for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount. If the entity determines on the basis of qualitative factors that the fair value of the indefinite-lived intangible asset is not more likely than not impaired, the entity would not need to calculate the value of the asset. The new guidance does not revise the requirement to test indefinite-lived intangible assets annually for impairment. In addition, the new guidance does not amend the requirement to test these assets for impairment between annual tests if there is a change in events or circumstances. The new guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 with early adoption permitted. We plan on adopting the new guidance in the fourth quarter of Fiscal 2012.

Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in ASU 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods. We are currently evaluating the impact of the new guidance on our future disclosures.

Partnership Acquisition of Heritage Propane

On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,598.2 comprising $1,465.6 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,132.6 (the “Heritage Acquisition”). The Acquisition Date cash consideration for the Heritage Acquisition was subject to purchase price adjustments based on working capital, cash and the amount of indebtedness of Heritage Propane (“Working Capital Adjustment”) and certain excess sales proceeds resulting from ETP's sale of HOLP's former cylinder exchange business (“HPX”). In April 2012, AmeriGas Partners paid $25.5 of additional cash consideration as a result of the Working Capital Adjustment and in June 2012, AmeriGas Partners received $18.9 in cash representing the excess cash proceeds from the sale of HPX. The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), and Heritage ETC, L.P. (the “Contributor”). The acquired business conducts its propane operations in 41 states through HOLP and Titan LLC. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The Heritage Acquisition is consistent with our growth strategies, one of which is to grow our core business through acquisitions.

Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and the sole member of Titan LLC; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. As a result of the Heritage Acquisition, the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, contributed 934,327 Common Units to the Partnership having a fair value of $41.7. These Common Units were subsequently cancelled.

The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes”). For further information on the 6.75% Notes and the 7.00% Notes, see Note 10.

The Condensed Consolidated Balance Sheet at June 30, 2012 reflects a preliminary allocation of the purchase price to the assets acquired and liabilities assumed. The purchase price paid comprises AmeriGas Partners Common Units issued having a fair value of $1,132.6, and total net cash consideration of $1,472.2 including cash acquired of $60.7. The Partnership is in the process of obtaining information required to determine the fair values of certain assets and liabilities acquired, principally long-term intangible and tangible assets. The Partnership expects to finalize these amounts by the end of fiscal 2012. The preliminary purchase price allocation is as follows:



Assets acquired:
Current assets	$	280.3
Property, plant & equipment	890.5
Customer relationships (estimated useful life of 15 years)	418.9
Trademarks and tradenames	144.2
Goodwill	1,167.5
Other assets	10.4
Total assets acquired	$	2,911.8

Liabilities assumed:
Current liabilities	$	(223.5	)
Long-term debt	(61.6		)
Other noncurrent liabilities	(21.9		)
Total liabilities assumed	$	(307.0	)
Total	$	2,604.8

Goodwill associated with the Heritage Acquisition principally results from synergies expected from combining the operations and from assembled workforce. The tax effects of such goodwill will be realized over a fifteen-year period.

Transaction expenses associated with the Heritage Acquisition, which are included in operating and administrative expenses on the Condensed Consolidated Statements of Income, totaled $0.5 and $5.3 for the three and nine months ended June 30, 2012, respectively. The results of operations of Heritage Propane are included in the Condensed Consolidated Statements of Income since the Acquisition Date. As a result of achieving planned strategic operating and marketing milestones, it is impracticable to determine the impact of the Heritage Propane operations on the revenues and earnings of the Company.

The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2010:



	Three Months Ended June 30,						Nine Months Ended June 30,
	2012 (As Reported)			2011			2012		2011
Revenues	$	1,277.2		$	1,335.6		$	5,885.2	$	6,257.8
Net (loss) income attributable to UGI Corporation	$	(6.3	)	$	(14.0	)	$	211.4	$	253.9
(Loss) earnings per common share attributable to UGI Corporation stockholders:
Basic	$	(0.06	)	$	(0.12	)	$	1.88	$	2.28
Diluted	$	(0.06	)	$	(0.12	)	$	1.87	$	2.25

The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.

In accordance with the Contribution Agreement, ETP and the Partnership entered into a transition services agreement and ETP, HPX and the Partnership also entered into a transition services agreement, (collectively, the “TSA”) whereby each party may be a provider and receiver of certain services to the other. The principal services include general business continuity, information technology, accounting, tax and administrative services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed by the parties. Amounts associated with such services were not material.

Goodwill and Intangible Assets

The Company’s intangible assets comprise the following:



	June 30, 2012			September 30, 2011			June 30, 2011
Goodwill (not subject to amortization)	$	2,756.0		$	1,562.2		$	1,612.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	689.3		$	232.1		$	240.6
Trademarks and tradenames (not subject to amortization)	189.6			47.9			51.9
Gross carrying amount	878.9			280.0			292.5
Accumulated amortization	(161.2		)	(132.2		)	(133.0		)
Intangible assets, net	$	717.7		$	147.8		$	159.5

The increases in goodwill and intangible assets during the nine months ended June 30, 2012 principally reflect the effects of the Heritage Acquisition and, to a much lesser extent, the Shell Acquisition. Amortization expense of intangible assets was $12.4 and $31.2 for the three and nine months ended June 30, 2012, respectively, and $5.4 and $15.1 for the three and nine months ended June 30, 2011, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of June 30, 2012, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2012 and for the next four fiscal years is as follows: remainder of Fiscal 2012 — $12.8; Fiscal 2013 — $51.1; Fiscal 2014 — $49.8; Fiscal 2015 — $47.6; Fiscal 2016 — $45.4.

Segment Information

We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) or regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga, our propane distribution business in the United Kingdom and our propane distribution business in China (“Flaga & Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. We refer to both international segments collectively as “International Propane.”

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2011 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership 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 EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Midstream & Marketing segments principally based upon their income before income taxes.

Three Months Ended June 30, 2012:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,277.2		$	(32.2	)	(d)	$	571.9		$	122.3		$	20.8		$	166.7		$	211.8		$	193.4		$	22.5
Cost of sales	$	810.2		$	(30.9	)	(d)	$	334.0		$	51.4		$	11.3		$	145.2		$	133.6		$	153.0		$	12.6
Segment profit:
Operating (loss) income	$	(19.2	)	$	—			$	(48.4	)	$	22.5		$	2.6		$	4.9		$	(1.2	)	$	2.4		$	(2.0	)
Loss from equity investees	(0.1		)	—				—			—			—			—			(0.1		)	—			—
Gain on extinguishments of debt	0.1			—				0.1			—			—			—			—			—			—
Interest expense	(61.3		)	—				(41.8		)	(9.9		)	(0.6		)	(1.2		)	(6.3		)	(1.2		)	(0.3		)
(Loss) income before income taxes	$	(80.5	)	$	—			$	(90.1	)	$	12.6		$	2.0		$	3.7		$	(7.6	)	$	1.2		$	(2.3	)
Partnership EBITDA (a)								$	1.8
Noncontrolling interests’ net loss	$	(70.2	)	$	—			$	(70.0	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	84.6		$	—			$	49.5		$	12.3		$	0.9		$	3.2		$	13.5		$	4.7		$	0.5
Capital expenditures	$	83.7		$	—			$	25.2		$	29.0		$	0.9		$	13.6		$	12.0		$	2.8		$	0.2
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	158.8		$	616.3		$	1,664.7		$	513.2		$	180.1
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	—		$	95.0		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	—		$	2.8		$	605.0		$	92.4		$	7.0

Three Months Ended June 30, 2011:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,105.4		$	(40.0	)	(d)	$	470.8		$	148.1		$	24.1		$	217.1		$	161.0		$	102.3		$	22.0
Cost of sales	$	731.0		$	(39.1	)	(d)	$	300.8		$	78.8		$	14.6		$	193.1		$	95.3		$	74.6		$	12.9
Segment profit:
Operating income (loss)	$	17.2		$	—			$	6.7		$	17.2		$	2.4		$	8.4		$	(11.4	)	$	(3.6	)	$	(2.5	)
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	—			—				—			—			—			—			—			—			—
Interest expense	(35.0		)	—				(15.7		)	(9.9		)	(0.7		)	(0.6		)	(7.1		)	(0.8		)	(0.2		)
(Loss) income before income taxes	$	(18.0	)	$	—			$	(9.0	)	$	7.3		$	1.7		$	7.8		$	(18.7	)	$	(4.4	)	$	(2.7	)
Partnership EBITDA (a)								$	31.1
Noncontrolling interests’ net loss	$	(6.3	)	$	—			$	(6.1	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	57.8		$	—			$	24.5		$	11.6		$	1.1		$	1.8		$	13.5		$	4.7		$	0.6
Capital expenditures	$	78.5		$	—			$	18.6		$	20.9		$	1.0		$	18.7		$	12.0		$	6.6		$	0.7
Total assets (at period end)	$	6,673.7		$	(81.0	)		$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—			$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—			$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9


(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income (loss):



Three Months Ended June 30,	2012			2011
Partnership EBITDA (ii)	$	1.8		$	31.1
Depreciation and amortization	(49.5		)	(24.5		)
Gain on extinguishments of debt	(0.1		)	—
Noncontrolling interests (i)	(0.6		)	0.1
Operating (loss) income	$	(48.4	)	$	6.7


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


(ii)	Includes $0.1 gain associated with extinguishments of Partnership debt in 2012.


(b)	International Propane—Flaga & Other principally comprises Flaga’s retail distribution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

(c)

Corporate & Other results principally comprise HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.


(d)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2012:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	5,393.5		$	(129.1	)	(d)	$	2,411.3		$	696.8		$	71.9		$	674.5		$	958.7		$	646.5		$	62.9
Cost of sales	$	3,438.6		$	(125.6	)	(d)	$	1,447.8		$	370.6		$	41.8		$	565.6		$	597.9		$	506.3		$	34.2
Segment profit:
Operating income (loss)	$	549.9		$	—			$	206.7		$	168.7		$	9.2		$	59.4		$	96.3		$	16.8		$	(7.2	)
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	(13.3		)	—				(13.3		)	—			—			—			—			—			—
Interest expense	(162.6		)	—				(103.4		)	(30.1		)	(1.7		)	(3.6		)	(19.7		)	(3.4		)	(0.7		)
Income (loss) before income taxes	$	373.8		$	—			$	90.0		$	138.6		$	7.5		$	55.8		$	76.4		$	13.4		$	(7.9	)
Partnership EBITDA (a)								$	310.0
Noncontrolling interests’ net income	$	46.5		$	—			$	46.2		$	—		$	—		$	—		$	0.3		$	—		$	—
Depreciation and amortization	$	227.7		$	—			$	118.5		$	36.6		$	2.8		$	9.0		$	42.6		$	16.6		$	1.6
Capital expenditures	$	237.7		$	—			$	70.3		$	76.5		$	3.2		$	47.6		$	28.0		$	11.5		$	0.6
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	158.8		$	616.3		$	1,664.7		$	513.2		$	180.1
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	—		$	95.0		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	—		$	2.8		$	605.0		$	92.4		$	7.0

Nine Months Ended June 30, 2011:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	5,052.0		$	(172.9	)	(d)	$	2,077.8		$	921.7		$	84.7		$	857.0		$	889.7		$	332.4		$	61.6
Cost of sales	$	3,317.5		$	(170.3	)	(d)	$	1,300.9		$	562.3		$	53.4		$	738.6		$	554.0		$	243.8		$	34.8
Segment profit:
Operating income (loss)	$	626.5		$	0.2			$	252.9		$	193.2		$	9.0		$	76.7		$	101.0		$	(0.2	)	$	(6.3	)
Loss from equity investees	(0.8		)	—				—			—			—			—			(0.8		)	—			—
Loss on extinguishments of debt	(18.8		)	—				(18.8		)	—			—			—			—			—			—
Interest expense	(102.6		)	—				(47.4		)	(30.2		)	(1.8		)	(2.0		)	(18.5		)	(2.1		)	(0.6		)
Income (loss) before income taxes	$	504.3		$	0.2			$	186.7		$	163.0		$	7.2		$	74.7		$	81.7		$	(2.3	)	$	(6.9	)
Partnership EBITDA (a)								$	301.9
Noncontrolling interests’ net income	$	101.8		$	—			$	101.2		$	—		$	—		$	—		$	0.6		$	—		$	—
Depreciation and amortization	$	168.6		$	—			$	70.4		$	36.1		$	3.1		$	5.4		$	38.4		$	13.7		$	1.5
Capital expenditures	$	246.1		$	—			$	59.2		$	54.5		$	5.1		$	81.5		$	31.8		$	12.6		$	1.4
Total assets (at period end)	$	6,673.7		$	(81.0	)		$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—			$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—			$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9


(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:



Nine Months Ended June 30,	2012			2011
Partnership EBITDA (ii)	$	310.0		$	301.9
Depreciation and amortization	(118.5		)	(70.4		)
Loss on extinguishment of debt	13.3			18.8
Noncontrolling interests (i)	1.9			2.6
Operating income	$	206.7		$	252.9


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


(ii)	Includes $13.3 loss and $18.8 loss, respectively, associated with extinguishments of Partnership debt.


(b)	International Propane—Flaga & Other principally comprises Flaga’s retail distribution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

(c)

Corporate & Other results principally comprise HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.


(d)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Energy Services Accounts Receivable Securitization Facility

Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2013, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility back-up purchasers.

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 commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. Trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet; the Company reflects a liability equal to the amount advanced by the commercial paper conduit; and the Company records interest expense on amounts sold to the commercial paper conduit.

During the nine months ended June 30, 2012 and 2011, Energy Services transferred trade receivables to ESFC totaling $674.4 and $923.5, respectively. During the nine months ended June 30, 2012 and 2011, ESFC sold an aggregate $266.5 and $68.0, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2012, the balance of ESFC receivables was $41.0 and there was $10.0 sold to the commercial paper conduit. At June 30, 2011, the outstanding balance of ESFC receivables was $50.9 and there were no amounts sold to the commercial paper conduit.

Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2011 Annual Financial Statements and Notes. UGI Utilities 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:



	June 30, 2012		September 30, 2011		June 30, 2011
Regulatory assets:
Income taxes recoverable	$	99.9	$	97.9	$	92.7
Underfunded pension and postretirement plans	144.6		150.7		116.0
Environmental costs	16.6		19.5		20.7
Deferred fuel and power costs	9.8		12.2		7.8
Removal costs, net	11.8		12.3		11.2
Other	8.3		7.8		8.9
Total regulatory assets	$	291.0	$	300.4	$	257.3
Regulatory liabilities:
Postretirement benefits	$	12.3	$	11.5	$	11.6
Environmental overcollections	3.7		4.7		6.2
Deferred fuel and power refunds	10.3		6.6		22.4
State tax benefits—distribution system repairs	7.0		6.3		6.2
Other	0.7		0.7		—
Total regulatory liabilities	$	34.0	$	29.8	$	46.4

Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s tariffs contain clauses which 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”) rates 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 overcollected costs are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized gains (losses) on such contracts at June 30, 2012, September 30, 2011 and June 30, 2011 were $0.3, $(3.1) and $(1.1), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility’s DS recovery mechanism. At June 30, 2012, September 30, 2011 and June 30, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $13.1, $8.7 and $10.1, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

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 financial 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 refunds. Unrealized gains on FTRs at June 30, 2012, September 30, 2011 and June 30, 2011 were not material.

Distribution System Improvement Charge. On April 14, 2012, legislation enabling gas and electric utilities in Pennsylvania to seek surcharge recovery of eligible capital investment in distribution system infrastructure improvement projects became effective. The surcharge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC surcharge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures, for up to five percent of distribution rates. 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. We are currently evaluating the potential effect of this legislation on our four regulated utilities. Filings to implement a DSIC surcharge may be filed no earlier than January 2, 2013.

Defined Benefit Pension and Other Postretirement Plans

In the U.S., we currently sponsor one 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 (“Pension Plan”). We also provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz 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 June 30,						Three Months Ended June 30,
	2012			2011			2012			2011
Service cost	$	2.1		$	2.1		$	0.1		$	0.1
Interest cost	6.1			6.1			0.2			0.3
Expected return on assets	(6.4		)	(6.4		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.2		)
Actuarial loss	2.1			1.7			0.1			0.1
Net benefit cost	4.0			3.6			0.2			0.2
Change in associated regulatory liabilities	—			—			0.8			0.8
Net expense	$	4.0		$	3.6		$	1.0		$	1.0
							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	6.4		$	6.6		$	0.3		$	0.4
Interest cost	18.3			18.1			0.8			0.8
Expected return on assets	(19.2		)	(19.4		)	(0.4		)	(0.4		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.3		)	(0.5		)
Actuarial loss	6.3			5.7			0.3			0.3
Net benefit cost	12.0			11.2			0.7			0.6
Change in associated regulatory liabilities	—			—			2.3			2.4
Net expense	$	12.0		$	11.2		$	3.0		$	3.0

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $24 to the Pension Plan during the next twelve months. During the nine months ended June 30, 2012 and 2011, the Company made contributions to the Pension Plan of $25.4 and $16.7, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the nine months ended June 30, 2012 and 2011, nor are they expected to be material for all of Fiscal 2012.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $2.1 and $2.2 for the nine months ended June 30, 2012 and 2011, respectively.

Debt

In December 2011, Flaga entered into a €19.1 euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525%. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at June 30, 2012 was 3.85%.

In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, AmeriGas Finance Corp. and AmeriGas Finance LLC (the “Issuers”) issued $550 principal amount of 6.75% Notes due May 2020 and $1,000 principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the 6.75% Notes, in whole or in part, at any time on or after May 20, 2016 and to redeem the 7.00% Notes, in whole or in part, at any time on or after May 20, 2017, subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. On or prior to May 20, 2015, the Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of each of the 6.75% Notes and the 7.00% Notes with the proceeds of an AmeriGas Partners registered public equity offering. The Notes and guarantees rank equal in right of payment with all of AmeriGas Partners’ existing senior notes.

On March 28, 2012, AmeriGas Partners announced that holders of approximately $383.5 in aggregate principal amount of outstanding 6.50% Senior Notes due May 2021 (the “6.50% Notes”), representing approximately 82% of the total $470 principal amount outstanding, had validly tendered their notes in connection with the Partnership’s March 14, 2012 offer to purchase for cash up to $200 of the 6.50% Notes. Tendered 6.50% Notes in the amount of $200 were redeemed on March 28, 2012 at an effective price of 105% using an approximate proration factor of 52.3% of total notes tendered. The Partnership recorded a loss on extinguishment of debt of $13.4 associated with this transaction.

During June 2012, AmeriGas Partners repurchased approximately $19.2 aggregate principal amount of outstanding 7.00% Notes. The Partnership recorded a net gain on extinguishment of debt associated with this transaction, which amount was not material.

Commitments and Contingencies

Environmental Matters

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“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, 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 terminates at the end of 2013. 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 June 30, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $15.8 and $20.1, respectively. We have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process 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. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, 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 does not expect its 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 Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing 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.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserted that the plant operated from 1855 to 1954 and alleged that, through control of a subsidiary that owned the plant, UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserted that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimated that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. On April 11, 2012, the District Court entered a judgment in favor of UGI Utilities. The appeal period has expired and the District Court's decision is final.

Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit. On May 8, 2012, Frontier's appeal was voluntarily dismissed.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan has indicated that the cost could be as high as $20. There have been no recent developments in this case.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, Connecticut (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s decision in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. On March 30, 2012, the District Court ruled that a portion of the contamination at Waterbury North was related to UGI Utilities’ period of operation. The appeal period has expired and the District Court’s decision is final. Based upon information currently available, we believe that UGI Utilities’ liability at Waterbury North will not have a material adverse effect on our financial condition.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities’ predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012 and is cooperating with its investigation.

AmeriGas Propane

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009 and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

AmeriGas San Bernardino. In July 2001, HOLP acquired a company that had previously received a request for information from the EPA regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred prior to the construction of the facility acquired by HOLP, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). No follow-up correspondence has been received from the EPA on the matter since HOLP’s acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

Claremont, Chestertown and Bennington. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan LLC is purportedly the beneficial holder of title with respect to three former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites.

Claremont, New Hampshire and Chestertown, Maryland. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Bennington, Vermont. In 1996, a predecessor company of Titan LLC performed an environmental assessment of its property in Bennington, Vermont and discovered that the site was a former MGP. At that time, Titan LLC’s predecessor informed the company that previously owned and operated the MGP of potential liability under CERCLA. Titan LLC has not received any requests to remediate or provide costs associated with the site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters

AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego (the “District Attorneys”) have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena sought information and documents regarding AmeriGas OLP’s cylinder exchange program and alleges potential violations of California’s Unfair Competition Law. We reviewed and responded to the subpoena and will continue to cooperate with the District Attorneys.

Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership that relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.

Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action lawsuit in the Circuit Court of Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In this lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Court has not certified the class and, in October 2008, stayed the lawsuit pending resolution of a separate, but related, class action lawsuit filed against AmeriGas OLP in Monongalia County, which was settled in Fiscal 2011. We believe we have good defenses to the claims in this action.

BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas OLP in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not have a material impact on our results of operations and financial condition.

We cannot predict the final results of any of the environmental or other pending claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Equity

The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the nine months ended June 30, 2012 and 2011:



				UGI Shareholders
	Non- controlling Interests			Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Equity
Nine Months Ended June 30, 2012:
Balance September 30, 2011	$	213.4		$	937.4	$	1,085.8		$	(17.7	)	$	(27.8	)	$	2,191.1
Net income	46.5					214.1									260.6
Net losses on derivative instruments	(69.8		)						(74.1		)				(143.9		)
Reclassifications of net losses on derivative instruments	23.7								45.8						69.5
Benefit plans									0.3						0.3
Foreign currency translation and transaction adjustments									(33.9		)				(33.9		)
Dividends and distributions	(126.8		)			(88.7		)							(215.5		)
AmeriGas Partners Common Unit public offering	276.6														276.6
AmeriGas Common Units issued in connection with Heritage Acquisition	1,132.6														1,132.6
Adjustments to reflect change in ownership of AmeriGas Partners	(321.4		)	194.4					1.9						(125.1		)
Equity transactions—other	4.7			17.0								3.5			25.2
Other	(0.7		)												(0.7		)
Balance June 30, 2012	$	1,178.8		$	1,148.8	$	1,211.2		$	(77.7	)	$	(24.3	)	$	3,436.8
Nine Months Ended June 30, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income	101.8					255.3									357.1
Net gains on derivative instruments	14.8								10.8						25.6
Reclassifications of net (gains) losses on derivative instruments	(16.0		)						27.0						11.0
Benefit plans									2.1						2.1
Foreign currency translation adjustments									37.8						37.8
Dividends and distributions	(69.7		)			(84.7		)							(154.4		)
Equity transactions	0.5			28.8								9.6			38.9
Other	1.2														1.2
Balance June 30, 2011	$	269.7		$	934.9	$	1,137.3		$	67.6		$	(28.6	)	$	2,380.9

As a result of the January 2012 issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the Heritage Acquisition and related General Partner Common Unit transactions (see Note 4), and the March 2012 issuance of 7,000,000 AmeriGas Partners Common Units pursuant to AmeriGas Partners’ public offering (see Note 16), the Company recorded an increase in UGI Corporation stockholders’ equity (which amount is net of deferred income taxes) and an associated pre-tax decrease in noncontrolling interests equity. The adjustments are included in the table above under the caption “Adjustments to reflect changes in ownership of AmeriGas Partners.”

Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2012, September 30, 2011 and June 30, 2011:



	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5.1		$	12.3		$	—	$	17.4
Foreign currency contracts	$	—		$	7.1		$	—	$	7.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(18.0	)	$	(102.0	)	$	—	$	(120.0	)
Interest rate contracts	$	—		$	(67.0	)	$	—	$	(67.0	)
September 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	3.5		$	3.3		$	—	$	6.8
Foreign currency contracts	$	—		$	5.3		$	—	$	5.3
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(28.1	)	$	(16.1	)	$	—	$	(44.2	)
Foreign currency contracts	$	—		$	(3.3	)	$	—	$	(3.3	)
Interest rate contracts	$	—		$	(44.4	)	$	—	$	(44.4	)
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.6		$	10.1		$	—	$	10.7
Foreign currency contracts	$	—		$	—		$	—	$	—
Interest rate contracts	$	—		$	5.0		$	—	$	5.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(12.2	)	$	(11.6	)	$	—	$	(23.8	)
Foreign currency contracts	$	—		$	(6.1	)	$	—	$	(6.1	)
Interest rate contracts	$	—		$	(3.6	)	$	—	$	(3.6	)

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 financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts 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 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. 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 (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. At June 30, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,561.2 and $3,730.7, respectively. At June 30, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,078.0 and $2,170.4, 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 financial 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 from trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 14.

Disclosures About 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. Because most of our derivative instruments generally qualify for hedge accounting or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane 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. In addition, the Partnership from time to time enters into price swap and option agreements to reduce short-term commodity price volatility and to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes.

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 June 30, 2012 and 2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.2 million dekatherms and 18.6 million dekatherms, respectively. At June 30, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 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 in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

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. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception. Because these contracts no longer qualify for the normal purchases and normal sales exception, the fair values of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13.1 and $10.1, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2012 and 2011, the volumes of Electric Utility’s forward electricity purchase contracts was 654.7 million kilowatt hours and 874.4 million kilowatt hours, respectively. At June 30, 2012, the maximum period over which these contracts extend is 23 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains Financial Transmission Rights ("FTRs") through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 8). At June 30, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 261.0 million kilowatt hours and 287.3 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2012 and 2011, the volumes associated with Midstream & Marketing’s FTRs totaled 1,285.5 million kilowatt hours and 1,955.2 million kilowatt hours, respectively.

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 and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. At June 30, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.1 million dekatherms and 2.2 million gallons, respectively. Midstream & Marketing has entered into and may continue to enter into fixed-price propane sales agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales agreements, Midstream & Marketing enters into price swap and option contracts.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.

At June 30, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:



	Volumes
	June 30,
Commodity	2012	2011
LPG (millions of gallons)	231.9	145.0
Natural gas (millions of dekatherms)	21.2	21.2
Electricity calls (millions of kilowatt-hours)	1,688.4	1,318.0
Electricity puts (millions of kilowatt-hours)	131.8	117.2

At June 30, 2012, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 29 months with a weighted average of 7 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 41 months with a weighted average of 11 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 33 months for electricity call contracts, with a weighted average of 9 months, and 18 months for electricity put contracts, with a weighted average of 10 months. At June 30, 2012, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 11 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At June 30, 2012, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $99.1.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2012 and 2011, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €441.9 and €398.8, 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”). At June 30, 2012 and 2011, the total notional amount of unsettled IRPAs was $173. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt anticipated to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements of Income.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At June 30, 2012, 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 $0.9.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG forecasted to occur during the heating-season months of October through March. At June 30, 2012 and 2011, we were hedging a total of $75.0 and $141.4 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2012, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 29 months with a weighted average of 13 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At both June 30, 2012 and 2011, we were hedging a total of €14.5 of our euro-denominated net investments. As of June 30, 2012, such foreign currency contracts extend through September 2012.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At June 30, 2012, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $3.2. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

In conjunction with the Shell Acquisition, in September 2011 we entered into foreign currency exchange transactions to economically hedge the U.S. dollar amount of a substantial portion of the associated euro-denominated purchase price. Through the date of their final expiration in October 2011, these contracts were recorded at fair value with gains or losses recorded in other income, net, which amounts for the 2012 nine-month period were not material.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial 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 form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and options contracts generally require cash deposits in margin accounts. At June 30, 2012 and 2011, restricted cash in brokerage accounts totaled $7.6 and $10.2, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 2012. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2012, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2012 and 2011:



	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,				Balance Sheet	Fair Value June 30,
	Location	2012		2011		Location	2012			2011
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	4.2	$	6.0	Derivative financial instruments and Other noncurrent liabilities	$	(95.5	)	$	(12.6	)
Foreign currency contracts	Derivative financial instruments and Other assets	7.1		—		Derivative financial instruments and Other noncurrent liabilities	—			(6.1		)
Interest rate contracts	Other assets	—		5.0		Derivative financial instruments and Other noncurrent liabilities	(67.0		)	(3.6		)
Total Derivatives Designated as Hedging Instruments		$	11.3	$	11.0		$	(162.5	)	$	(22.3	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.6	$	0.2	Derivative financial instruments and Other noncurrent liabilities	$	(13.4	)	$	(11.2	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	12.6	$	4.5	Derivative financial instruments	(11.1		)	—
Total Derivatives		$	24.5	$	15.7		$	(187.0	)	$	(33.5	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended June 30, 2012 and 2011:

Three Months Ended June 30,:



	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2012			2011			2012			2011			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(59.3	)	$	(1.4	)	$	(31.0	)	$	3.9		Cost of sales
Foreign currency contracts	3.1			(1.9		)	—			—			Cost of sales
Interest rate contracts	(16.6		)	(13.2		)	(3.3		)	(2.4		)	Interest expense / other income, net
Total	$	(72.8	)	$	(16.5	)	$	(34.3	)	$	1.5
Net Investment Hedges:
Foreign currency contracts	$	0.9		$	(0.5	)

	Gain (Loss)												Location of Gain (Loss)
	Recognized in Income												Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2012			2011
Commodity contracts	$	(15.9	)	$	0.2								Cost of sales
Commodity contracts	(0.1		)	—									Operating expenses / other income, net
Total	$	(16.0	)	$	0.2

Nine Months Ended June 30,:



	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2012			2011			2012			2011			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(166.2	)	$	25.4		$	(94.4	)	$	(19.1	)	Cost of sales
Foreign currency contracts	2.8			(3.4		)	2.0			(0.7		)	Cost of sales
Interest rate contracts	(29.0		)	11.6			(8.4		)	(9.6		)	Interest expense / other income, net
Total	$	(192.4	)	$	33.6		$	(100.8	)	$	(29.4	)
Net Investment Hedges:
Foreign currency contracts	$	0.9		$	(1.1	)



	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2012			2011
Commodity contracts	$	(12.6	)	$	(0.4	)	Cost of sales
Commodity contracts	0.1			0.3			Operating expenses / other income, net
Foreign currency contracts	0.5			—			Other income, net
Total	$	(12.0	)	$	(0.1	)

The amounts of derivative gains or losses representing ineffectiveness were not material for the nine months ended June 30, 2012 and 2011. During the three months ended June 30, 2012, the Partnership entered into propane swap and put option contracts to reduce short-term volatility in propane prices associated with a portion of its forecasted propane purchases during the months of April 2012 to August 2012. These contracts did not qualify for hedge accounting treatment and the change in fair value was recorded through cost of sales in the Condensed Consolidated Statements of Income. Net realized and unrealized losses recognized in income totaling $14.9 related to these contracts are included in the tables above under the caption "Derivatives Not Designated as Hedging Instruments." The remaining volumes of propane under these contracts totaled approximately 29 million gallons at June 30, 2012.

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 and contracts that provide for the purchase and delivery, or sale, of natural gas, LPG and electricity to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting because they provide for the delivery of products 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.

Inventories

Inventories comprise the following:



	June 30, 2012		September 30, 2011		June 30, 2011
Non-utility LPG and natural gas	$	220.1	$	222.2	$	170.5
Gas Utility natural gas	27.8		95.6		50.1
Materials, supplies and other	69.4		45.2		51.0
Total inventories	$	317.3	$	363.0	$	271.6

At June 30, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor 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 term 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), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at June 30, 2012, September 30, 2011 and June 30, 2011 comprising 1.9 billion cubic feet (“bcf”), 3.9 bcf and 2.0 bcf of natural gas was $5.3, $19.0 and $9.6, respectively.

Partnership Issuance of Common Units

On March 21, 2012, AmeriGas Partners sold 7 million Common Units in an underwritten public offering at a public offering price of $41.25 per unit. The net proceeds of this offering and related capital contributions from the General Partner totaling $279.4 were used to redeem $200 of AmeriGas Partners 6.50% Senior Notes pursuant to a tender offer (see Note 10), to reduce Partnership bank loan borrowings and for general corporate purposes.

Significant Accounting Policies (Policies)

Restricted Cash

Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts that are restricted from withdrawal.

Earnings Per Common Share

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

Shares used in computing basic and diluted earnings per share are as follows:



	Three Months Ended June 30,		Nine Months Ended June 30,
	2012	2011	2012	2011
Denominator (thousands of shares):
Average common shares outstanding for basic computation	112,726	112,020	112,484	111,515
Incremental shares issuable for stock options and awards	—	—	811	1,531
Average common shares outstanding for diluted computation	112,726	112,020	113,295	113,046

Comprehensive Income

Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.

Reclassifications

Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.

Income Taxes

Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we now believe it is more likely than not that a portion of our foreign tax credits will be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $4.7 for the nine months ended June 30, 2012.

As a result of the completion of the audit of the Company’s 2009 federal income tax return, during the nine months ended June 30, 2012, the Company adjusted its unrecognized tax benefits, which amount was not material.

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.

Goodwill Impairment

Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.

Fair Value Measurements

Fair Value Measurements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance became effective for our interim period ending March 31, 2012 and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.

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 June 30,		Nine Months Ended June 30,
	2012	2011	2012	2011
Denominator (thousands of shares):
Average common shares outstanding for basic computation	112,726	112,020	112,484	111,515
Incremental shares issuable for stock options and awards	—	—	811	1,531
Average common shares outstanding for diluted computation	112,726	112,020	113,295	113,046

Partnership Acquisition of Heritage Propane (Tables)

Assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition

The preliminary purchase price allocation is as follows:



Assets acquired:
Current assets	$	280.3
Property, plant & equipment	890.5
Customer relationships (estimated useful life of 15 years)	418.9
Trademarks and tradenames	144.2
Goodwill	1,167.5
Other assets	10.4
Total assets acquired	$	2,911.8

Liabilities assumed:
Current liabilities	$	(223.5	)
Long-term debt	(61.6		)
Other noncurrent liabilities	(21.9		)
Total liabilities assumed	$	(307.0	)
Total	$	2,604.8

Partnership's unaudited consolidated results of operations

The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2010:



	Three Months Ended June 30,						Nine Months Ended June 30,
	2012 (As Reported)			2011			2012		2011
Revenues	$	1,277.2		$	1,335.6		$	5,885.2	$	6,257.8
Net (loss) income attributable to UGI Corporation	$	(6.3	)	$	(14.0	)	$	211.4	$	253.9
(Loss) earnings per common share attributable to UGI Corporation stockholders:
Basic	$	(0.06	)	$	(0.12	)	$	1.88	$	2.28
Diluted	$	(0.06	)	$	(0.12	)	$	1.87	$	2.25

Goodwill and Intangible Assets (Tables)

Component of company's intangible assets

The Company’s intangible assets comprise the following:



	June 30, 2012			September 30, 2011			June 30, 2011
Goodwill (not subject to amortization)	$	2,756.0		$	1,562.2		$	1,612.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	689.3		$	232.1		$	240.6
Trademarks and tradenames (not subject to amortization)	189.6			47.9			51.9
Gross carrying amount	878.9			280.0			292.5
Accumulated amortization	(161.2		)	(132.2		)	(133.0		)
Intangible assets, net	$	717.7		$	147.8		$	159.5

Segment Information (Tables)

Segment Information

Three Months Ended June 30, 2012:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,277.2		$	(32.2	)	(d)	$	571.9		$	122.3		$	20.8		$	166.7		$	211.8		$	193.4		$	22.5
Cost of sales	$	810.2		$	(30.9	)	(d)	$	334.0		$	51.4		$	11.3		$	145.2		$	133.6		$	153.0		$	12.6
Segment profit:
Operating (loss) income	$	(19.2	)	$	—			$	(48.4	)	$	22.5		$	2.6		$	4.9		$	(1.2	)	$	2.4		$	(2.0	)
Loss from equity investees	(0.1		)	—				—			—			—			—			(0.1		)	—			—
Gain on extinguishments of debt	0.1			—				0.1			—			—			—			—			—			—
Interest expense	(61.3		)	—				(41.8		)	(9.9		)	(0.6		)	(1.2		)	(6.3		)	(1.2		)	(0.3		)
(Loss) income before income taxes	$	(80.5	)	$	—			$	(90.1	)	$	12.6		$	2.0		$	3.7		$	(7.6	)	$	1.2		$	(2.3	)
Partnership EBITDA (a)								$	1.8
Noncontrolling interests’ net loss	$	(70.2	)	$	—			$	(70.0	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	84.6		$	—			$	49.5		$	12.3		$	0.9		$	3.2		$	13.5		$	4.7		$	0.5
Capital expenditures	$	83.7		$	—			$	25.2		$	29.0		$	0.9		$	13.6		$	12.0		$	2.8		$	0.2
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	158.8		$	616.3		$	1,664.7		$	513.2		$	180.1
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	—		$	95.0		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	—		$	2.8		$	605.0		$	92.4		$	7.0

Three Months Ended June 30, 2011:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,105.4		$	(40.0	)	(d)	$	470.8		$	148.1		$	24.1		$	217.1		$	161.0		$	102.3		$	22.0
Cost of sales	$	731.0		$	(39.1	)	(d)	$	300.8		$	78.8		$	14.6		$	193.1		$	95.3		$	74.6		$	12.9
Segment profit:
Operating income (loss)	$	17.2		$	—			$	6.7		$	17.2		$	2.4		$	8.4		$	(11.4	)	$	(3.6	)	$	(2.5	)
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	—			—				—			—			—			—			—			—			—
Interest expense	(35.0		)	—				(15.7		)	(9.9		)	(0.7		)	(0.6		)	(7.1		)	(0.8		)	(0.2		)
(Loss) income before income taxes	$	(18.0	)	$	—			$	(9.0	)	$	7.3		$	1.7		$	7.8		$	(18.7	)	$	(4.4	)	$	(2.7	)
Partnership EBITDA (a)								$	31.1
Noncontrolling interests’ net loss	$	(6.3	)	$	—			$	(6.1	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	57.8		$	—			$	24.5		$	11.6		$	1.1		$	1.8		$	13.5		$	4.7		$	0.6
Capital expenditures	$	78.5		$	—			$	18.6		$	20.9		$	1.0		$	18.7		$	12.0		$	6.6		$	0.7
Total assets (at period end)	$	6,673.7		$	(81.0	)		$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—			$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—			$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9


(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income (loss):



Three Months Ended June 30,	2012			2011
Partnership EBITDA (ii)	$	1.8		$	31.1
Depreciation and amortization	(49.5		)	(24.5		)
Gain on extinguishments of debt	(0.1		)	—
Noncontrolling interests (i)	(0.6		)	0.1
Operating (loss) income	$	(48.4	)	$	6.7


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


(ii)	Includes $0.1 gain associated with extinguishments of Partnership debt in 2012.


(b)	International Propane—Flaga & Other principally comprises Flaga’s retail distribution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

(c)

Corporate & Other results principally comprise HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.


(d)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2012:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	5,393.5		$	(129.1	)	(d)	$	2,411.3		$	696.8		$	71.9		$	674.5		$	958.7		$	646.5		$	62.9
Cost of sales	$	3,438.6		$	(125.6	)	(d)	$	1,447.8		$	370.6		$	41.8		$	565.6		$	597.9		$	506.3		$	34.2
Segment profit:
Operating income (loss)	$	549.9		$	—			$	206.7		$	168.7		$	9.2		$	59.4		$	96.3		$	16.8		$	(7.2	)
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	(13.3		)	—				(13.3		)	—			—			—			—			—			—
Interest expense	(162.6		)	—				(103.4		)	(30.1		)	(1.7		)	(3.6		)	(19.7		)	(3.4		)	(0.7		)
Income (loss) before income taxes	$	373.8		$	—			$	90.0		$	138.6		$	7.5		$	55.8		$	76.4		$	13.4		$	(7.9	)
Partnership EBITDA (a)								$	310.0
Noncontrolling interests’ net income	$	46.5		$	—			$	46.2		$	—		$	—		$	—		$	0.3		$	—		$	—
Depreciation and amortization	$	227.7		$	—			$	118.5		$	36.6		$	2.8		$	9.0		$	42.6		$	16.6		$	1.6
Capital expenditures	$	237.7		$	—			$	70.3		$	76.5		$	3.2		$	47.6		$	28.0		$	11.5		$	0.6
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	158.8		$	616.3		$	1,664.7		$	513.2		$	180.1
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	—		$	95.0		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	—		$	2.8		$	605.0		$	92.4		$	7.0

Nine Months Ended June 30, 2011:



								Reportable Segments
																				International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	5,052.0		$	(172.9	)	(d)	$	2,077.8		$	921.7		$	84.7		$	857.0		$	889.7		$	332.4		$	61.6
Cost of sales	$	3,317.5		$	(170.3	)	(d)	$	1,300.9		$	562.3		$	53.4		$	738.6		$	554.0		$	243.8		$	34.8
Segment profit:
Operating income (loss)	$	626.5		$	0.2			$	252.9		$	193.2		$	9.0		$	76.7		$	101.0		$	(0.2	)	$	(6.3	)
Loss from equity investees	(0.8		)	—				—			—			—			—			(0.8		)	—			—
Loss on extinguishments of debt	(18.8		)	—				(18.8		)	—			—			—			—			—			—
Interest expense	(102.6		)	—				(47.4		)	(30.2		)	(1.8		)	(2.0		)	(18.5		)	(2.1		)	(0.6		)
Income (loss) before income taxes	$	504.3		$	0.2			$	186.7		$	163.0		$	7.2		$	74.7		$	81.7		$	(2.3	)	$	(6.9	)
Partnership EBITDA (a)								$	301.9
Noncontrolling interests’ net income	$	101.8		$	—			$	101.2		$	—		$	—		$	—		$	0.6		$	—		$	—
Depreciation and amortization	$	168.6		$	—			$	70.4		$	36.1		$	3.1		$	5.4		$	38.4		$	13.7		$	1.5
Capital expenditures	$	246.1		$	—			$	59.2		$	54.5		$	5.1		$	81.5		$	31.8		$	12.6		$	1.4
Total assets (at period end)	$	6,673.7		$	(81.0	)		$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—			$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—			$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9


(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:



Nine Months Ended June 30,	2012			2011
Partnership EBITDA (ii)	$	310.0		$	301.9
Depreciation and amortization	(118.5		)	(70.4		)
Loss on extinguishment of debt	13.3			18.8
Noncontrolling interests (i)	1.9			2.6
Operating income	$	206.7		$	252.9


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


(ii)	Includes $13.3 loss and $18.8 loss, respectively, associated with extinguishments of Partnership debt.


(b)	International Propane—Flaga & Other principally comprises Flaga’s retail distribution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

(c)

Corporate & Other results principally comprise HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.


(d)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

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:



	June 30, 2012		September 30, 2011		June 30, 2011
Regulatory assets:
Income taxes recoverable	$	99.9	$	97.9	$	92.7
Underfunded pension and postretirement plans	144.6		150.7		116.0
Environmental costs	16.6		19.5		20.7
Deferred fuel and power costs	9.8		12.2		7.8
Removal costs, net	11.8		12.3		11.2
Other	8.3		7.8		8.9
Total regulatory assets	$	291.0	$	300.4	$	257.3
Regulatory liabilities:
Postretirement benefits	$	12.3	$	11.5	$	11.6
Environmental overcollections	3.7		4.7		6.2
Deferred fuel and power refunds	10.3		6.6		22.4
State tax benefits—distribution system repairs	7.0		6.3		6.2
Other	0.7		0.7		—
Total regulatory liabilities	$	34.0	$	29.8	$	46.4

Defined Benefit Pension and Other Postretirement Plans (Tables)

Component 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 June 30,						Three Months Ended June 30,
	2012			2011			2012			2011
Service cost	$	2.1		$	2.1		$	0.1		$	0.1
Interest cost	6.1			6.1			0.2			0.3
Expected return on assets	(6.4		)	(6.4		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.2		)
Actuarial loss	2.1			1.7			0.1			0.1
Net benefit cost	4.0			3.6			0.2			0.2
Change in associated regulatory liabilities	—			—			0.8			0.8
Net expense	$	4.0		$	3.6		$	1.0		$	1.0
							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	6.4		$	6.6		$	0.3		$	0.4
Interest cost	18.3			18.1			0.8			0.8
Expected return on assets	(19.2		)	(19.4		)	(0.4		)	(0.4		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.3		)	(0.5		)
Actuarial loss	6.3			5.7			0.3			0.3
Net benefit cost	12.0			11.2			0.7			0.6
Change in associated regulatory liabilities	—			—			2.3			2.4
Net expense	$	12.0		$	11.2		$	3.0		$	3.0

Equity (Tables)

Changes in UGI's equity and the equity of the noncontrolling interests

The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the nine months ended June 30, 2012 and 2011:



				UGI Shareholders
	Non- controlling Interests			Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Equity
Nine Months Ended June 30, 2012:
Balance September 30, 2011	$	213.4		$	937.4	$	1,085.8		$	(17.7	)	$	(27.8	)	$	2,191.1
Net income	46.5					214.1									260.6
Net losses on derivative instruments	(69.8		)						(74.1		)				(143.9		)
Reclassifications of net losses on derivative instruments	23.7								45.8						69.5
Benefit plans									0.3						0.3
Foreign currency translation and transaction adjustments									(33.9		)				(33.9		)
Dividends and distributions	(126.8		)			(88.7		)							(215.5		)
AmeriGas Partners Common Unit public offering	276.6														276.6
AmeriGas Common Units issued in connection with Heritage Acquisition	1,132.6														1,132.6
Adjustments to reflect change in ownership of AmeriGas Partners	(321.4		)	194.4					1.9						(125.1		)
Equity transactions—other	4.7			17.0								3.5			25.2
Other	(0.7		)												(0.7		)
Balance June 30, 2012	$	1,178.8		$	1,148.8	$	1,211.2		$	(77.7	)	$	(24.3	)	$	3,436.8
Nine Months Ended June 30, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income	101.8					255.3									357.1
Net gains on derivative instruments	14.8								10.8						25.6
Reclassifications of net (gains) losses on derivative instruments	(16.0		)						27.0						11.0
Benefit plans									2.1						2.1
Foreign currency translation adjustments									37.8						37.8
Dividends and distributions	(69.7		)			(84.7		)							(154.4		)
Equity transactions	0.5			28.8								9.6			38.9
Other	1.2														1.2
Balance June 30, 2011	$	269.7		$	934.9	$	1,137.3		$	67.6		$	(28.6	)	$	2,380.9

Fair Value Measurement (Tables)

Financial assets and financial liabilities that are measured at fair value on a recurring basis

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2012, September 30, 2011 and June 30, 2011:



	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5.1		$	12.3		$	—	$	17.4
Foreign currency contracts	$	—		$	7.1		$	—	$	7.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(18.0	)	$	(102.0	)	$	—	$	(120.0	)
Interest rate contracts	$	—		$	(67.0	)	$	—	$	(67.0	)
September 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	3.5		$	3.3		$	—	$	6.8
Foreign currency contracts	$	—		$	5.3		$	—	$	5.3
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(28.1	)	$	(16.1	)	$	—	$	(44.2	)
Foreign currency contracts	$	—		$	(3.3	)	$	—	$	(3.3	)
Interest rate contracts	$	—		$	(44.4	)	$	—	$	(44.4	)
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.6		$	10.1		$	—	$	10.7
Foreign currency contracts	$	—		$	—		$	—	$	—
Interest rate contracts	$	—		$	5.0		$	—	$	5.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(12.2	)	$	(11.6	)	$	—	$	(23.8	)
Foreign currency contracts	$	—		$	(6.1	)	$	—	$	(6.1	)
Interest rate contracts	$	—		$	(3.6	)	$	—	$	(3.6	)

Disclosures About Derivative Instruments and Hedging Activities (Tables)

Outstanding derivative commodity instruments volumes

At June 30, 2012 and 2011, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:



	Volumes
	June 30,
Commodity	2012	2011
LPG (millions of gallons)	231.9	145.0
Natural gas (millions of dekatherms)	21.2	21.2
Electricity calls (millions of kilowatt-hours)	1,688.4	1,318.0
Electricity puts (millions of kilowatt-hours)	131.8	117.2

Balance sheet location and fair value of derivative assets and liabilities

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2012 and 2011:



	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,				Balance Sheet	Fair Value June 30,
	Location	2012		2011		Location	2012			2011
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	4.2	$	6.0	Derivative financial instruments and Other noncurrent liabilities	$	(95.5	)	$	(12.6	)
Foreign currency contracts	Derivative financial instruments and Other assets	7.1		—		Derivative financial instruments and Other noncurrent liabilities	—			(6.1		)
Interest rate contracts	Other assets	—		5.0		Derivative financial instruments and Other noncurrent liabilities	(67.0		)	(3.6		)
Total Derivatives Designated as Hedging Instruments		$	11.3	$	11.0		$	(162.5	)	$	(22.3	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.6	$	0.2	Derivative financial instruments and Other noncurrent liabilities	$	(13.4	)	$	(11.2	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	12.6	$	4.5	Derivative financial instruments	(11.1		)	—
Total Derivatives		$	24.5	$	15.7		$	(187.0	)	$	(33.5	)

Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended June 30, 2012 and 2011:

Three Months Ended June 30,:



	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2012			2011			2012			2011			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(59.3	)	$	(1.4	)	$	(31.0	)	$	3.9		Cost of sales
Foreign currency contracts	3.1			(1.9		)	—			—			Cost of sales
Interest rate contracts	(16.6		)	(13.2		)	(3.3		)	(2.4		)	Interest expense / other income, net
Total	$	(72.8	)	$	(16.5	)	$	(34.3	)	$	1.5
Net Investment Hedges:
Foreign currency contracts	$	0.9		$	(0.5	)

	Gain (Loss)												Location of Gain (Loss)
	Recognized in Income												Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2012			2011
Commodity contracts	$	(15.9	)	$	0.2								Cost of sales
Commodity contracts	(0.1		)	—									Operating expenses / other income, net
Total	$	(16.0	)	$	0.2

Nine Months Ended June 30,:



	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2012			2011			2012			2011			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(166.2	)	$	25.4		$	(94.4	)	$	(19.1	)	Cost of sales
Foreign currency contracts	2.8			(3.4		)	2.0			(0.7		)	Cost of sales
Interest rate contracts	(29.0		)	11.6			(8.4		)	(9.6		)	Interest expense / other income, net
Total	$	(192.4	)	$	33.6		$	(100.8	)	$	(29.4	)
Net Investment Hedges:
Foreign currency contracts	$	0.9		$	(1.1	)



	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2012			2011
Commodity contracts	$	(12.6	)	$	(0.4	)	Cost of sales
Commodity contracts	0.1			0.3			Operating expenses / other income, net
Foreign currency contracts	0.5			—			Other income, net
Total	$	(12.0	)	$	(0.1	)

Inventories (Tables)

Inventories

Inventories comprise the following:



	June 30, 2012		September 30, 2011		June 30, 2011
Non-utility LPG and natural gas	$	220.1	$	222.2	$	170.5
Gas Utility natural gas	27.8		95.6		50.1
Materials, supplies and other	69.4		45.2		51.0
Total inventories	$	317.3	$	363.0	$	271.6

Nature of Operations (Details)

In Millions, except Share data, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Country

Oct. 14, 2011

Shell Acquisition [Member]

USD ($)

Oct. 14, 2011

Shell Acquisition [Member]

EUR (€)

Nature of Operations (Textual) [Abstract]

Business acquired by parent through subsidiaries for cash (in dollars/euros)

$ 179.0

€ 133.6

Nature of Operations (Additional Textual) [Abstract]

General Partner held a general partner interest in AmeriGas Partners

1.00%

Percentage of limited partnership interest in AmeriGas Partners

25.40%

Effective ownership interest in AmeriGas OLP

27.10%

Limited Partnership Common Units held in AmeriGas Partners (in units)

23,756,882

General public as limited partner interests in AmeriGas Partners

73.60%

Common Units Owned by Public (in units)

39,460,280

Common Units Owned by ETP (in units)

29,567,362

Number of countries (countries)

11

Significant Accounting Policies (Details)

In Thousands, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Denominator (thousands of shares):

Average common shares outstanding for basic computation (in shares)

112,726

112,020

112,484

111,515

Incremental shares issuable for stock options and awards (in shares)

0

811

1,531

Average common shares outstanding for diluted computation (in shares)

112,726

112,020

113,295

113,046

Significant Accounting Policies (Details Textual) (USD $)

In Millions, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Significant Accounting Policies (Textual) [Abstract]

Decrease in income tax expense

$ 4.7

Partnership Acquisition of Heritage Propane (Details) (USD $)

In Millions, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Liabilities assumed:

Total

$ 2,604.8

Heritage Propane [Member]

Assets acquired:

Current assets

280.3

Property, plant & equipment

890.5

Customer relationships (estimated useful life of 15 years)

418.9

Trademarks and tradenames

144.2

Goodwill

1,167.5

Other assets

10.4

Total assets acquired

2,911.8

Liabilities assumed:

Current liabilities

(223.5)

Long-term debt

(61.6)

Other noncurrent liabilities

(21.9)

Total liabilities assumed

$ (307.0)

Customer Relationships [Member] |
Heritage Propane [Member]

Finite Lived Intangible Asset Useful Life

Estimated useful life (in years)

15 years

Partnership Acquisition of Heritage Propane (Details 1) (Heritage Propane [Member], USD $)

In Millions, except Per Share data, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Heritage Propane [Member]

Partnership unaudited consolidated results of operations

Revenues

$ 1,277.2

$ 1,335.6

$ 5,885.2

$ 6,257.8

Net income attributable to UGI Corporation

$ (6.3)

$ (14.0)

$ 211.4

$ 253.9

Earnings per common share attributable to UGI Corporation stockholders:

Basic (in dollars per share)

$ (0.06)

$ (0.12)

$ 1.88

$ 2.28

Diluted (in dollars per share)

$ (0.06)

$ (0.12)

$ 1.87

$ 2.25

Partnership Acquisition of Heritage Propane (Details Textual) (USD $)

In Millions, except Share data, unless otherwise specified

3 Months Ended

9 Months Ended

0 Months Ended

12 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

AmeriGas Partners Senior Notes Due 2020 [Member]

Jun. 30, 2012

AmeriGas Partners Senior Notes Due 2022 [Member]

Jun. 30, 2012

Heritage [Member]

Jun. 30, 2012

Heritage [Member]

Jan. 12, 2012

Heritage [Member]

Jan. 12, 2012

Titan [Member]

Jan. 12, 2012

Energy Transfer Partners, L.P. [Member]

States

Jan. 12, 2012

Heritage Propane [Member]

Dec. 31, 2011

Heritage Propane [Member]

Customer

gal

Jan. 12, 2012

Heritage Propane [Member]

AmeriGas Partners Senior Notes Due 2020 [Member]

Jan. 12, 2012

Heritage Propane [Member]

AmeriGas Partners Senior Notes Due 2022 [Member]

Acquisition (Textual) [Abstract]

Purchase price of the acquisition

$ 2,598.2

Business acquired by parent through subsidiaries for cash

1,472.2

1,465.6

Common units issued by AmeriGas Partners (in units)

29,567,362

Consideration in AmeriGas Partners Common Units

1,132.6

Working capital adjustment, additional cash paid

25.5

Number of states in which business operates (in states)

41

Annual delivery of propane by subsidiary (in gallons)

500,000,000

Number of retail customer (in customers)

1,000,000

Percentage of Limited partner interest (as a percent)

99.999%

99.99%

Percentage of membership interest (as a percent)

100.00%

Percentage of general partner interest (as a percent)

0.01%

0.001%

Number of common units contributed by Entity (in units)

934,327

Fair value of common stock

41.7

Percentage senior notes due (as a percent)

6.75%

7.00%

6.75%

7.00%

Proceeds from issuance of Senior notes

3,561.2

2,078.0

550.0

1,000.0

Maturity dates of Notes issued (in year of maturity)

2020

2022

Operating and administrative costs

0.5

5.3

Working capital adjustment and cash acquired

$ 60.7

Partnership Acquisition of Heritage Propane Heritage Acquisition (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

Jun. 30, 2012

Business Acquisition [Line Items]

Purchase price adjustment cash received

$ 18.9

Goodwill and Intangible Assets (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Component of Company's Intangible Assets [Abstract]

Goodwill (not subject to amortization)

$ 2,756.0

$ 1,562.2

$ 1,612.0

Intangible assets:

Customer relationships, noncompete agreements and other

689.3

232.1

240.6

Trademarks and tradenames (not subject to amortization)

189.6

47.9

51.9

Gross carrying amount

878.9

280.0

292.5

Accumulated amortization

(161.2)

(132.2)

(133.0)

Net carrying amount

$ 717.7

$ 147.8

$ 159.5

Goodwill and Intangible Assets (Details Textual) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Component of Company's Intangible Assets (Textual) [Abstract]

Amortization expense of intangible assets

$ 12.4

$ 5.4

$ 31.2

$ 15.1

Expected aggregate amortization expense of intangible assets for the next five fiscal years:

Remainder of fiscal 2012

12.8

Fiscal 2013

51.1

Fiscal 2014

49.8

Fiscal 2015

47.6

Fiscal 2016

$ 45.4

Segment Information (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Sep. 30, 2011

Segment information

Revenues

$ 1,277.2

$ 1,105.4

$ 5,393.5

$ 5,052.0

Cost of sales

810.2

731.0

3,438.6

3,317.5

Segment profit:

Operating income (loss)

(19.2)

17.2

549.9

626.5

Loss from equity investees

(0.1)

(0.2)

(0.8)

Gain (loss) on extinguishment of debt

0.1

0

(13.3)

(18.8)

Interest expense

(61.3)

(35.0)

(162.6)

(102.6)

Income (loss) before income taxes

(80.5)

(18.0)

373.8

504.3

Noncontrolling interests' net income (loss)

(70.2)

(6.3)

46.5

101.8

Depreciation and amortization

84.6

57.8

227.7

168.6

Capital expenditures

83.7

78.5

237.7

246.1

Total assets (at period end)

9,652.2

6,673.7

9,652.2

6,673.7

6,663.3

Bank loans (at period end)

187.3

206.1

187.3

206.1

138.7

Goodwill (at period end)

2,756.0

1,612.0

2,756.0

1,612.0

1,562.2

Eliminations [Member]

Segment information

Revenues

(32.2)¹

(40.0)¹

(129.1)¹

(172.9)¹

Cost of sales

(30.9)¹

(39.1)¹

(125.6)¹

(170.3)¹

Segment profit:

Operating income (loss)

0

0.2

Income (loss) before income taxes

0

0.2

Total assets (at period end)

(87.4)

(81.0)

(87.4)

(81.0)

AmeriGas Propane [Member]

Segment information

Revenues

571.9

470.8

2,411.3

2,077.8

Cost of sales

334.0

300.8

1,447.8

1,300.9

Segment profit:

Operating income (loss)

(48.4)

6.7

206.7

252.9

Loss from equity investees

0

Gain (loss) on extinguishment of debt

0.1

0

(13.3)

(18.8)

Interest expense

(41.8)

(15.7)

(103.4)

(47.4)

Income (loss) before income taxes

(90.1)

(9.0)

90.0

186.7

Partnership EBITDA

1.8 ² ³

31.1 ² ³

310.0 ⁴ ⁵

301.9 ⁴ ⁵

Noncontrolling interests' net income (loss)

(70.0)

(6.1)

46.2

101.2

Depreciation and amortization

49.5

24.5

118.5

70.4

Capital expenditures

25.2

18.6

70.3

59.2

Total assets (at period end)

4,579.5

1,772.1

4,579.5

1,772.1

Bank loans (at period end)

68.8

176.0

68.8

176.0

Goodwill (at period end)

1,866.7

695.8

1,866.7

695.8

Gas Utility [Member]

Segment information

Revenues

122.3

148.1

696.8

921.7

Cost of sales

51.4

78.8

370.6

562.3

Segment profit:

Operating income (loss)

22.5

17.2

168.7

193.2

Loss from equity investees

0

Interest expense

(9.9)

(30.1)

(30.2)

Income (loss) before income taxes

12.6

7.3

138.6

163.0

Depreciation and amortization

12.3

11.6

36.6

36.1

Capital expenditures

29.0

20.9

76.5

54.5

Total assets (at period end)

2,027.0

2,002.0

2,027.0

2,002.0

Goodwill (at period end)

182.1

180.1

182.1

180.1

Electric Utility [Member]

Segment information

Revenues

20.8

24.1

71.9

84.7

Cost of sales

11.3

14.6

41.8

53.4

Segment profit:

Operating income (loss)

2.6

2.4

9.2

9.0

Loss from equity investees

0

Interest expense

(0.6)

(0.7)

(1.7)

(1.8)

Income (loss) before income taxes

2.0

1.7

7.5

7.2

Depreciation and amortization

0.9

1.1

2.8

3.1

Capital expenditures

0.9

1.0

3.2

5.1

Total assets (at period end)

158.8

156.5

158.8

156.5

Midstream & Marketing [Member]

Segment information

Revenues

166.7

217.1

674.5

857.0

Cost of sales

145.2

193.1

565.6

738.6

Segment profit:

Operating income (loss)

4.9

8.4

59.4

76.7

Loss from equity investees

0

Interest expense

(1.2)

(0.6)

(3.6)

(2.0)

Income (loss) before income taxes

3.7

7.8

55.8

74.7

Depreciation and amortization

3.2

1.8

9.0

5.4

Capital expenditures

13.6

18.7

47.6

81.5

Total assets (at period end)

616.3

572.2

616.3

572.2

Bank loans (at period end)

95.0

Goodwill (at period end)

2.8

International Propane, Antargaz [Member]

Segment information

Revenues

211.8

161.0

958.7

889.7

Cost of sales

133.6

95.3

597.9

554.0

Segment profit:

Operating income (loss)

(1.2)

(11.4)

96.3

101.0

Loss from equity investees

(0.1)

(0.2)

(0.8)

Interest expense

(6.3)

(7.1)

(19.7)

(18.5)

Income (loss) before income taxes

(7.6)

(18.7)

76.4

81.7

Noncontrolling interests' net income (loss)

(0.2)

0.3

0.6

Depreciation and amortization

13.5

42.6

38.4

Capital expenditures

12.0

28.0

31.8

Total assets (at period end)

1,664.7

1,678.2

1,664.7

1,678.2

Goodwill (at period end)

605.0

641.1

605.0

641.1

International Propane, Flaga & Other [Member]

Segment information

Revenues

193.4 ⁶

102.3 ⁶

646.5 ⁶

332.4 ⁶

Cost of sales

153.0 ⁶

74.6 ⁶

506.3 ⁶

243.8 ⁶

Segment profit:

Operating income (loss)

2.4 ⁶

(3.6)⁶

16.8 ⁶

(0.2)⁶

Loss from equity investees

0

Interest expense

(1.2)⁶

(0.8)⁶

(3.4)⁶

(2.1)⁶

Income (loss) before income taxes

1.2 ⁶

(4.4)⁶

13.4 ⁶

(2.3)⁶

Depreciation and amortization

4.7 ⁶

16.6 ⁶

13.7 ⁶

Capital expenditures

2.8 ⁶

6.6 ⁶

11.5 ⁶

12.6 ⁶

Total assets (at period end)

513.2 ⁶

407.3 ⁶

513.2 ⁶

407.3 ⁶

Bank loans (at period end)

23.5 ⁶

30.1 ⁶

23.5 ⁶

30.1 ⁶

Goodwill (at period end)

92.4 ⁶

85.3 ⁶

92.4 ⁶

85.3 ⁶

Corporate & Other [Member]

Segment information

Revenues

22.5 ⁶

22.0 ⁶

62.9 ⁷

61.6 ⁷

Cost of sales

12.6 ⁶

12.9 ⁶

34.2 ⁷

34.8 ⁷

Segment profit:

Operating income (loss)

(2.0)⁶

(2.5)⁶

(7.2)⁷

(6.3)⁷

Loss from equity investees

0

Interest expense

(0.3)⁶

(0.2)⁶

(0.7)⁷

(0.6)⁷

Income (loss) before income taxes

(2.3)⁶

(2.7)⁶

(7.9)⁷

(6.9)⁷

Depreciation and amortization

0.5 ⁶

0.6 ⁶

1.6 ⁷

1.5 ⁷

Capital expenditures

0.2 ⁶

0.7 ⁶

0.6 ⁷

1.4 ⁷

Total assets (at period end)

180.1 ⁶ ⁷

166.4 ⁶ ⁷

180.1 ⁶ ⁷

166.4 ⁶ ⁷

Goodwill (at period end)

$ 7.0 ⁶ ⁷

$ 6.9 ⁶ ⁷

$ 7.0 ⁶ ⁷

$ 6.9 ⁶ ⁷

[1] Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

[2] Includes $0.1 gain associated with extinguishments of Partnership debt in 2012.

[3] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income (loss):Three Months Ended June 30, 2012 2011Partnership EBITDA (ii) $1.8 $31.1Depreciation and amortization (49.5) (24.5)Gain on extinguishments of debt (0.1) —Noncontrolling interests (i) (0.6) 0.1Operating (loss) income $(48.4) $6.7

[4] Includes $13.3 loss and $18.8 loss, respectively, associated with extinguishments of Partnership debt.

[5] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Nine Months Ended June 30, 2012 2011Partnership EBITDA (ii) $310.0 $301.9Depreciation and amortization (118.5) (70.4)Loss on extinguishment of debt 13.3 18.8Noncontrolling interests (i) 1.9 2.6Operating income $206.7 $252.9

[6] International Propane—Flaga & Other principally comprises Flaga’s retail distribution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

[7] Corporate & Other results principally comprise HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

Segment Information (Details 1) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Reconciliation of partnership EBITDA

Depreciation and amortization

$ (84.6)

$ (57.8)

$ (227.7)

$ (168.6)

Loss on extinguishment of debt

(0.1)

0

13.3

18.8

Operating income (loss)

(19.2)

17.2

549.9

626.5

AmeriGas Propane [Member]

Reconciliation of partnership EBITDA

Partnership EBITDA

1.8 ¹ ²

31.1 ¹ ²

310.0 ³ ⁴

301.9 ³ ⁴

Depreciation and amortization

(49.5)

(24.5)

(118.5)

(70.4)

Loss on extinguishment of debt

(0.1)

0

13.3

18.8

Noncontrolling interests

(0.6)⁵

0.1 ⁵

1.9 ⁵

2.6 ⁵

Operating income (loss)

$ (48.4)

$ 6.7

$ 206.7

$ 252.9

[1] Includes $0.1 gain associated with extinguishments of Partnership debt in 2012.

[2] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income (loss):Three Months Ended June 30, 2012 2011Partnership EBITDA (ii) $1.8 $31.1Depreciation and amortization (49.5) (24.5)Gain on extinguishments of debt (0.1) —Noncontrolling interests (i) (0.6) 0.1Operating (loss) income $(48.4) $6.7

[3] Includes $13.3 loss and $18.8 loss, respectively, associated with extinguishments of Partnership debt.

[4] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Nine Months Ended June 30, 2012 2011Partnership EBITDA (ii) $310.0 $301.9Depreciation and amortization (118.5) (70.4)Loss on extinguishment of debt 13.3 18.8Noncontrolling interests (i) 1.9 2.6Operating income $206.7 $252.9

[5] Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Segment Information (Details Textual) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Reportable_Segments

Jun. 30, 2011

Segment Reporting Information [Line Items]

Number of reportable segments (in reportable segments)

6

Loss on extinguishment of debt

$ 0.1

$ 0

$ (13.3)

$ (18.8)

Segment Information (Textual) [Abstract]

General Partner's interest in AmeriGas OLP (as a percent)

1.01%

AmeriGas Propane [Member]

Segment Reporting Information [Line Items]

Loss on extinguishment of debt

$ 0.1

$ 0

$ (13.3)

$ (18.8)

Energy Services Accounts Receivable Securitization Facility (Details) (USD $)

In Millions, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Energy services accounts receivable securitization facility (Additional Textual) [Abstract]

Receivables facility

$ 200

Energy Services Funding Corporation [Member]

Energy services accounts receivable securitization facility (Textual) [Abstract]

Sale of undivided interests in its trade receivables to the commercial paper conduit

266.5

68.0

Outstanding balance of trade receivables

41.0

50.9

Outstanding balance of trade receivables sold

10.0

Energy Services [Member]

Energy services accounts receivable securitization facility (Textual) [Abstract]

Sale of trade receivables

$ 674.4

$ 923.5

Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

$ 291.0

$ 300.4

$ 257.3

Regulatory Liabilities

34.0

29.8

46.4

Postretirement benefits [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Liabilities

12.3

11.5

11.6

Environmental overcollections [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Liabilities

3.7

4.7

6.2

Deferred fuel and power refunds [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Liabilities

10.3

6.6

22.4

State tax benefits - distribution system repairs [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Liabilities

7.0

6.3

6.2

Other [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Liabilities

0.7

0

Income taxes recoverable [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

99.9

97.9

92.7

Underfunded pension and postretirement plans [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

144.6

150.7

116.0

Environmental costs [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

16.6

19.5

20.7

Deferred fuel and power costs [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

9.8

12.2

7.8

Removal costs, net [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

11.8

12.3

11.2

Other [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

$ 8.3

$ 7.8

$ 8.9

Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textual) (USD $)

In Millions, unless otherwise specified

9 Months Ended

Jun. 30, 2012

Sep. 30, 2011

Jun. 30, 2011

Regulatory Assets [Line Items]

Fair value of electric utility electricity supply contracts

$ 187.0

$ 33.5

Maximum Percentage of Incremental Operating Margin Traditional Ratemaking (as a percent)

5.00%

Number of years to be eligible for a distribution system improvement charge a utility must have filed a general rate filing (in years)

5

Number of regulated utilities on which there is potential effect of legislation (in regulated utilities)

4

Deferral Fuel and Power [Member]

Regulatory Assets [Line Items]

Unrealized gains (losses) on derivative financial instrument contracts

0.3

(3.1)

(1.1)

Electric Utility Electric Supply Contracts [Member]

Regulatory Assets [Line Items]

Fair value of electric utility electricity supply contracts

$ 13.1

$ 8.7

$ 10.1

Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Pension Benefits [Member]

Components of net periodic pension expense and other postretirement benefit costs [Abstract]

Service cost

$ 2.1

$ 6.4

$ 6.6

Interest cost

6.1

18.3

18.1

Expected return on assets

(6.4)

(19.2)

(19.4)

Amortization of:

Prior service cost (benefit)

0.1

0.2

Actuarial loss

2.1

1.7

6.3

5.7

Net benefit cost

4.0

3.6

12.0

11.2

Change in associated regulatory liabilities

0

Net expense

4.0

3.6

12.0

11.2