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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Sep. 30, 2011	Nov. 14, 2011
Document Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-K
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785
Entity Public Float	$ 0

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2011	Sep. 30, 2010
Current assets:
Cash and cash equivalents	$ 7,267	$ 4,318
Restricted cash	4,308	4,698
Accounts receivable (less allowances for doubtful accounts of $6,368 and $7,072, respectively)	58,736	64,844
Accounts receivable - related parties	7,048	6,313
Accrued utility revenues	14,807	13,988
Inventories	104,263	118,858
Deferred income taxes	42,528	19,431
Income taxes recoverable	9,430	11,814
Regulatory assets	8,608	26,100
Derivative financial instruments	68	486
Prepaid expenses & other current assets	15,481	9,303
Total current assets	272,544	280,153
Property, plant and equipment	2,201,021	2,129,324
Less accumulated depreciation and amortization	(782,665)	(747,354)
Net property, plant and equipment	1,418,356	1,381,970
Goodwill	182,145	180,145
Regulatory assets	291,847	293,217
Other assets	4,456	4,091
Total assets	2,169,348	2,139,576
Current liabilities:
Current maturities of long-term debt	40,000	0
Bank loans	0	17,000
Accounts payable - trade	53,556	61,297
Accounts payable - related parties	10,108	8,144
Employee compensation and benefits accrued	12,770	12,268
Interest accrued	12,319	11,051
Customer deposits and refunds	54,127	57,465
Derivative financial instruments	11,928	10,564
Deferred fuel refunds	6,578	8,295
Pension and postretirement benefit obligations	28,228	20,303
Other current liabilities	33,405	32,848
Total current liabilities	263,019	239,235
Long-term debt	600,000	640,000
Deferred income taxes	361,468	281,101
Deferred investment tax credits	4,958	5,311
Pension and postretirement benefit obligations	142,248	161,338
Other noncurrent liabilities	78,810	78,137
Total liabilities	1,450,503	1,405,122
Commitments and contingencies (note 13)
Common stockholder's equity:
Common Stock, $2.25 par value (authorized - 40,000,000 shares; issued and outstanding - 26,781,785 shares)	60,259	60,259
Additional paid-in capital	468,323	467,631
Retained earnings	212,096	217,960
Accumulated other comprehensive loss	(21,833)	(11,396)
Total common stockholder's equity	718,845	734,454
Total liabilities and stockholder's equity	$ 2,169,348	$ 2,139,576

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2011	Sep. 30, 2010
Current assets:
Allowances for doubtful accounts on accounts receivable	$ 6,368	$ 7,072
Accumulated depreciation and amortization on property, plant and equipment	$ (782,665)	$ (747,354)
Common stockholder's equity:
Common stock, par value	$ 2.25	$ 2.25
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	26,781,785	26,781,785
Common stock, shares outstanding	26,781,785	26,781,785

- Definition

The cumulative amount of depreciation, depletion and amortization (related to property, plant and equipment, but not including land) that has been recognized in the income statement.

+ References + Details

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
Consolidated Statements of Income - USD ($) $ in Thousands	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2009
Revenues	$ 1,137,366	$ 1,169,539	$ 1,381,260
Costs and expenses:
Cost of sales - gas, fuel and purchased power (excluding depreciation shown below)	678,500	730,502	944,793
Operating and administrative expenses	176,922	169,464	191,263
Operating and administrative expenses - related parties	12,125	14,209	14,964
Taxes other than income taxes	16,616	18,638	16,917
Depreciation	49,917	50,747	48,873
Amortization	2,629	2,729	2,239
Other income, net	(10,764)	(6,269)	(7,261)
Total costs and expenses	925,945	980,020	1,211,788
Operating income	211,421	189,519	169,472
Interest expense	42,728	42,336	43,918
Income before income taxes	168,693	147,183	125,554
Income taxes	63,497	56,925	46,832
Net income	$ 105,196	$ 90,258	$ 78,722

Consolidated Comprehensive Income Statement - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2009
Net Income	$ 105,196	$ 90,258	$ 78,722
Net change in fair value of derivative instruments (net of tax of $7,711)	(10,874)	0	0
Reclassifications of net losses on derivative instruments (net of tax of $(483))	681	681	681
Benefit plans, (net of tax of $479, $11,134 and $29,978, respectively)	(674)	(15,699)	(42,270)
Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(304), $(2,414) and $(1,617), respectively) to net income	430	3,406	2,281
Reclassification of pension plans actuarial losses and prior service costs (net of tax of $(59,078)) to regulatory assets	0	83,302	0
Comprehensive income	$ 94,759	$ 161,948	$ 39,414

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

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-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
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- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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+ Details

- Definition

The accumulated change in the value of either the projected benefit obligation or the plan assets resulting from experience different from that assumed or from a change in an actuarial assumption that has not been recognized in net periodic benefit cost, after tax.

+ References

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+ Details

- Definition

Net of tax effect of the reclassification adjustment for accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges included in accumulated comprehensive income that was realized in net income during the period.

+ References

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+ Details

- Definition

The adjustment out of other comprehensive income for actuarial gains or losses recognized as a component of net periodic benefit cost during the period, after tax.

+ References + Details

- Definition

Change in accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges, net of tax effect. The after tax effect change includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

+ References

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+ Details

Condensed Comprehensive Income (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2009
Fair value of derivative instruments, net of tax	$ 7,711	$ 0	$ 0
Reclassifications of net losses (gains) on derivative instruments, net of tax	(483)	(483)	(483)
Benefits plans, net of tax	479	11,134	29,978
Reclassification on benefits plans actuarial, net of tax	(304)	(2,414)	(1,617)
Reclassification of pension plans actuarial, net of tax	$ 0	$ (59,078)	$ 0

- Definition

For each annual statement of income presented, the tax effect of the net gain (loss) recognized in other comprehensive income that is a reclassification adjustment of other comprehensive income as a result of being recognized as a component of net periodic benefit cost for the period.

+ References + Details

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 105,196	$ 90,258	$ 78,722
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	52,546	53,476	51,112
Deferred income taxes, net	50,905	63,654	17,530
Pension expense, net of contributions paid	(6,292)	6,698	7,124
Provision for uncollectible accounts	9,137	10,651	19,193
Other, net	(4,608)	10,257	13,456
Net change in:
Accounts receivable and accrued utility revenues	(4,583)	2,847	(15,133)
Inventories	14,596	77,740	(12,742)
Deferred fuel costs, net of changes in unsettled derivatives	12,842	(18,500)	10,272
Accounts payable	9,229	7,424	(19,437)
Storage agreement security deposits	0	3,500	19,000
Other current assets	(3,817)	(15,511)	(1,072)
Other current liabilities	(14,401)	(889)	8,389
Net cash provided by operating activities	220,750	291,605	176,414
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(98,856)	(81,595)	(79,084)
Net costs of property, plant and equipment disposals	(3,537)	(3,980)	(5,114)
Acquisitions of businesses, net of cash acquired	0	0	(292,551)
Proceeds from sale of CPP	0	0	32,269
Decrease (increase) in restricted cash	390	(4,698)	34,037
Net cash used by investing activities	(102,003)	(90,273)	(310,443)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(99,490)	(74,008)	(61,211)
(Decrease) increase in bank loans	(17,000)	(137,000)	97,000
Issuances of long-term debt	0	0	108,000
Excess tax benefits from equity-based payment arrangements	692	471	280
Net cash (used) provided by financing activities	(115,798)	(210,537)	144,069
Cash and cash equivalents increase (decrease)	2,949	(9,205)	10,040
CASH AND CASH EQUIVALENTS:
End of period	7,267	4,318	13,523
Beginning of period	4,318	13,523	3,483
Increase (decrease)	2,949	(9,205)	10,040
Cash paid for:
Interest	39,151	39,917	40,452
Income taxes	$ 13,856	$ 6,217	$ 26,919

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Retained Earnings [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance, beginning of year at Sep. 30, 2008		$ 60,259	$ 184,201	$ 466,888	$ (43,778)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	$ 78,722		78,722
Cash dividends — Common Stock			(61,221)
Dividends of net assets			0
Stockholders' Equity, Other			8	272
Net change in fair value of derivative instruments	0				0
Reclassifications of net losses on derivative instruments	681				681
Benefit plans, principally actuarial losses	(42,270)				(42,270)
Reclassifications of benefit plans actuarial losses and prior service costs	2,281				2,281
Reclassification of pension plans actuarial losses and prior service costs to regulatory asset	0				0
Balance, end of year at Sep. 30, 2009	646,043	60,259	201,710	467,160	(83,086)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	90,258		90,258
Cash dividends — Common Stock			(74,008)
Dividends of net assets			0
Stockholders' Equity, Other			0	471
Net change in fair value of derivative instruments	0				0
Reclassifications of net losses on derivative instruments	681				681
Benefit plans, principally actuarial losses	(15,699)				(15,699)
Reclassifications of benefit plans actuarial losses and prior service costs	3,406				3,406
Reclassification of pension plans actuarial losses and prior service costs to regulatory asset	83,302				83,302
Balance, end of year at Sep. 30, 2010	734,454	60,259	217,960	467,631	(11,396)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	105,196		105,196
Cash dividends — Common Stock			(99,490)
Dividends of net assets			(11,570)
Stockholders' Equity, Other			0	692
Net change in fair value of derivative instruments	(10,874)				(10,874)
Reclassifications of net losses on derivative instruments	681				681
Benefit plans, principally actuarial losses	(674)				(674)
Reclassifications of benefit plans actuarial losses and prior service costs	430				430
Reclassification of pension plans actuarial losses and prior service costs to regulatory asset	0				0
Balance, end of year at Sep. 30, 2011	$ 718,845	$ 60,259	$ 212,096	$ 468,323	$ (21,833)

Nature of Operations	12 Months Ended
Nature of Operations	Sep. 30, 2011
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	NATURE OF OPERATIONS Nature of Operations UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“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.” PNG also has a heating, ventilation and air-conditioning service business ("UGI Penn HVAC Services, Inc.") which operates principally in the PNG Gas service territory. The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

Significant Accounting Policies

12 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Significant Accounting Policies

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

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.

Certain prior-year amounts have been reclassified to conform to the current-year presentation. At September 30, 2011, removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the Consolidated Balance Sheet. Corresponding prior-year amounts have been reclassified (See Note 5).

Principles of Consolidation

Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate all significant intercompany accounts when we consolidate.

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.

For additional information regarding the effects of rate regulation, see Note 5.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:


•	Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded electricity contract.

•

Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts not qualifying for Level 1.


•	Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2011 or 2010.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 14 for additional information on fair value measurements.

Derivative Instruments

We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Substantially all of the gains and losses on derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets and liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Certain of our derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities.

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 15.

Revenue Recognition

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.

Income Taxes

We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.

We are amortizing deferred investment tax credits related to Utilities’ plant additions over the service lives of the related property. Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is generally consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.

Comprehensive Income

The components of AOCI at September 30, 2011 and 2010 follow:



	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2011	$	(8,377	)	$	(13,456	)	$	(21,833	)
September 30, 2010	$	(8,133	)	$	(3,263	)	$	(11,396	)

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive (loss) income of $(10,473), $71,690 and $(39,308) for Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively, principally reflects gains and losses on derivative instruments accounted for as cash flow hedges and changes in actuarial gains and losses on postretirement benefit plans. Other comprehensive income in Fiscal 2010 also includes the reclassification of $83,302 of accumulated other comprehensive losses associated with UGI Utilities’ pension plan, principally actuarial losses, to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of the pension plan’s funded status (see Note 5). Other comprehensive income (loss) for all periods presented also includes reclassifications of net losses on previously settled interest rate protection agreements (“IRPAs”).

Cash and Cash Equivalents

All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.

Restricted Cash

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

UGI Utilities enters into financial transactions to hedge its cost of gas sold to customers. These transactions are conducted pursuant to an approved risk management plan through an account held at MF Global Inc. (“MF Global”). On October 31, 2011, MF Global filed for Chapter 11 bankruptcy and, in conjunction with the automatic stay, the Chicago Mercantile Exchange froze all MF Global-related accounts. As a result of an emergency order entered by the bankruptcy court, the Company's customer segregated margin account and a portion of its cash was transferred to a new broker. The amount of cash currently frozen at MF Global is not material. At this time, the Company is unable to predict the ultimate impact of the bankruptcy, including any regulatory recovery related to any potential losses we may incur.

Inventories

Our inventories are stated at the lower of cost or market. Substantially all of our inventory is determined on an average cost method.

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2011, 2.5% in Fiscal 2010 and 2.4% in Fiscal 2009. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2011, 2.6% in Fiscal 2010, and 2.9% in Fiscal 2009. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

No depreciation expense is included in cost of sales in the Consolidated Statements of Income.

Goodwill

Our goodwill is the result of business acquisitions. Goodwill is subject to tests for impairment at least annually. We perform goodwill impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill might be impaired. When performing our impairment tests, we use discounted estimates of future cash flows. No provisions for goodwill impairments were recorded during Fiscal 2011, Fiscal 2010 or Fiscal 2009.

Impairment of Long-Lived Assets

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2011, Fiscal 2010 or Fiscal 2009.

Employee Retirement Plans

We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 10).

Equity-Based Compensation

All of our equity-based compensation principally comprising UGI stock options and grants of UGI stock-based equity instruments (“Units”) is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period.

For additional information on our equity-based compensation plans and related disclosures, see Note 12.

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. 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 CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 13.

Accounting Changes	12 Months Ended
Accounting Changes	Sep. 30, 2011
Accounting Changes [Abstract]
Accounting Changes	ACCOUNTING CHANGES Adoption of New Accounting Standards Presentation of Comprehensive Income. In June 2011, the FASB issued Accounting Standards Update ("ASU") 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. Additionally, reclassification adjustments between net income and comprehensive income must be shown on the face of the financial statements. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassification adjustments on the face of the income statement. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 with full retrospective application required. Early adoption is permitted. We applied the provisions of the new guidance effective September 30, 2011 (except for the presentation of reclassification adjustments on the face of the statement of net income,) and report the components of comprehensive income in two separate but consecutive statements as permitted by the new guidance. Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets are recognized in operations (rather than as decreases in goodwill). The new guidance did not have an impact on our financial statements. New Accounting Standards Not Yet Adopted Goodwill Impairment. In September 2011, the 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. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. 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 requirement 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. Early adoption is permitted. We will adopt the new guidance in Fiscal 2012. Fair Value Measurements. In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 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 is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.

- Definition

The entire disclosure for reporting accounting changes and error corrections. It includes the conveyance of information necessary for a user of the Company's financial information to understand all aspects and required disclosure information concerning all changes and error corrections reported in the Company's financial statements for the period.

+ References + Details

Acquisitions of PPL Gas Utilities Corporation

12 Months Ended

Sep. 30, 2011

Acquisition of PPL Gas Utilities Corporation [Abstract]

Acquisition of PPL Gas Utilities Corporation

ACQUISITION OF PPL GAS UTILITIES CORPORATION

On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”), for cash consideration of $267,600 plus estimated working capital of $35,370 (the “CPG Acquisition”). Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary, Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas Propane, L.P. (“AmeriGas OLP”), an affiliate of UGI, for cash consideration of $32,000 plus estimated working capital of $1,621. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108,000 principal amount of 6.375% Senior Notes due 2013 and approximately $75,000 of credit agreement borrowings. UGI Utilities used the $33,621 of cash proceeds from the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.

The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase price allocation are included in our Consolidated Balance Sheets at September 30, 2011 and 2010. Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated working capital of $35,370 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9,738 in cash, including interest. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities reimbursed AmeriGas OLP $1,352.

The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2,300, has been allocated to the assets acquired and liabilities assumed as follows:



Current assets less current liabilities	$	22,065
Property, plant and equipment	227,301
Goodwill	18,419
Utility regulatory assets	22,466
Other assets	7,412
Noncurrent liabilities	(34,383		)
Total	$	263,280

The primary item that results in goodwill is the synergies between CPG Gas and our existing utility businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period. The operating results of CPG are included in our consolidated results beginning October 1, 2008.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 88-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51, 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Appendix F
-Paragraph F4
-Subparagraph e

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 67-73
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e6927-128479

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1486-128463

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1383-128463

+ Details

Regulatory Assets and Liabilities and Regulatory Matters

12 Months Ended

Sep. 30, 2011

Regulated Operations [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:



	2011		2010
Regulatory assets:
Income taxes recoverable	$	97,947	$	82,525
Underfunded pension and postretirement plans	150,669		159,154
Environmental costs	19,547		22,587
Deferred fuel and power costs	12,163		36,597
Removal costs, net	12,313		12,615
Other	7,816		5,839
Total regulatory assets	$	300,455	$	319,317
Regulatory liabilities:
Postretirement benefits	$	11,476	$	10,472
Environmental overcollections	4,758		7,211
Deferred fuel and power refunds	6,578		8,298
State tax benefits — distribution system repairs	6,282		6,685
Other	736		—
Total regulatory liabilities	$	29,830	$	32,666

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.

Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.

Environmental costs. Environmental costs represents amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 13). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2011, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs (as further described below under “Electric Utility DS Rates”), 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 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 overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm-residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2011 and 2010 were $3,081 and $1,359, 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 under GAAP 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 GAAP relating to rate-regulated entities. At September 30, 2011 and 2010, the fair values of Electric Utility's electricity supply contracts were losses of $8,655 and $19,702, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the 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 commencing January 1, 2010, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 2011 and 2010, such gains or losses were not material.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2011, UGI Utilities expects to recover these costs over periods of 1 to 5 years.

Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above.

Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.

State income tax benefits — distribution system repairs. As described in Note 9 below, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repair and maintenance expenses which expenses are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2011, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in “Other noncurrent liabilities” on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.

Other Regulatory Matters

PNG and CPG Base Rate Filings. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16,500 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8,000 as well as $900 in revenues per year for use in CPG's Energy and Efficiency Conservation Program. The increase became effective August 30, 2011 and did not have a material effect on Fiscal 2011 results.

On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38,100 annually for PNG and $19,600 annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19,800 increase in annual base operating revenue for PNG Gas and a $10,000 increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.

Electric Utility DS Rates. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010.

Transfers of Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG's application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. ("Energy Services"), a second-tier wholly-owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG's agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10,949 which amount, net of related deferred taxes of $308, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder's Equity. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9.0 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the "Auburn Line") to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1,109 which amount, net of related deferred taxes of $180, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder's Equity.

Inventories

12 Months Ended

Sep. 30, 2011

Inventory Disclosure [Abstract]

Inventories

INVENTORIES

Inventories comprise the following at September 30:



	2011		2010
Gas Utility natural gas	$	95,590	$	111,531
Materials, supplies and other	8,673		7,327
Total inventories	$	104,263	$	118,858

At September 30, 2011, 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 terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represent 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 value of gas storage inventories released under the SCAAs at September 30, 2011 and 2010 comprising 11.5 billion cubic feet (“bcf”) and 12.1 bcf of natural gas was $54,658 and $62,653, respectively.

Property Plant and Equipment

12 Months Ended

Sep. 30, 2011

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprise the following categories at September 30:



	2011		2010
Distribution	$	1,951,889	$	1,865,980
Transmission	83,419		78,190
General and other, including construction in process	165,713		185,154
Total property, plant and equipment	$	2,201,021	$	2,129,324

- Definition

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

+ References + Details

Debt

12 Months Ended

Sep. 30, 2011

Debt [Abstract]

Debt

DEBT

Long-term debt comprises the following at September 30:



	2011			2010
Senior Notes:
6.375%, due September 2013	$	108,000		$	108,000
5.75%, due September 2016	175,000			175,000
6.21%, due September 2036	100,000			100,000
Medium-Term Notes:
5.53%, due September 2012	40,000			40,000
5.37%, due August 2013	25,000			25,000
5.16%, due May 2015	20,000			20,000
7.37%, due October 2015	22,000			22,000
5.64%, due December 2015	50,000			50,000
6.17%, due June 2017	20,000			20,000
7.25%, due November 2017	20,000			20,000
5.67%, due January 2018	20,000			20,000
6.50%, due August 2033	20,000			20,000
6.13%, due October 2034	20,000			20,000
Total long-term debt	640,000			640,000
Less: current maturities	(40,000		)	—
Total long-term debt due after one year	$	600,000		$	640,000

Principal payments on long-term debt during the next five fiscal years is as follows: $40,000 is due in Fiscal 2012; $133,000 is due in Fiscal 2013; $0 is due in Fiscal 2014; $20,000 is due in Fiscal 2015; and $247,000 is due in Fiscal 2016.

On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in May 2012 but may be extended to October 2015 if the Company satisfies certain requirements relating to approval by the PUC. Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350,000 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks' prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under its credit agreements, which we classify as bank loans, totaling $17,000 at September 30, 2010. There were no amounts outstanding under its credit agreement at September 30, 2011. The weighted-average interest rates on UGI Utilities' revolving credit agreements borrowings at September 30, 2010 was 3.25%. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities 2011 Credit Agreement, totaled $2,000 at September 30, 2011.

The UGI Utilities 2011 Revolving Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Income Taxes

12 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Income Taxes

The provisions for income taxes consist of the following:



	2011			2010			2009
Current expense:
Federal	$	10,447		$	(8,577	)	$	19,302
State	2,227			1,848			10,000
Total current expense (benefit)	12,674			(6,729		)	29,302
Deferred expense	51,174			64,022			17,898
Investment tax credit amortization	(351		)	(368		)	(368		)
Total income tax expense	$	63,497		$	56,925		$	46,832

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:



	2011		2010		2009
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	1.6		4.3		3.6
Other, net	1.0		(0.6	)	(1.3	)
Effective tax rate	37.6	%	38.7	%	37.3	%

Deferred tax liabilities (assets) comprise the following at September 30:



	2011			2010
Excess book basis over tax basis of property, plant and equipment	$	293,457		$	248,153
Goodwill	22,446			17,962
Regulatory assets	124,669			127,262
Other	487			1,856
Gross deferred tax liabilities	441,059			395,233
Pension plan liabilities	(62,818		)	(76,103		)
Allowance for doubtful accounts	(2,642		)	(2,934		)
Deferred investment tax credits	(2,057		)	(2,203		)
Employee-related expenses	(8,032		)	(8,771		)
Regulatory liabilities	(12,378		)	(13,336		)
Environmental liabilities	(7,749		)	(7,040		)
Derivative financial instruments	(11,931		)	(5,195		)
Other	(14,512		)	(17,981		)
Gross deferred tax assets	(122,119		)	(133,563		)
Net deferred tax liabilities	$	318,940		$	261,670

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2008. UGI’s federal income tax return for Fiscal 2009 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of UGI’s pending federal tax audit, we anticipate that the Internal Revenue Service’s (“IRS’s”) audit of UGI’s Fiscal 2009 U.S. federal income tax return will likely be completed during Fiscal 2012.

We file separate company income tax returns in a number of states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns.

During Fiscal 2011 and 2010, interest income of $219 and $25, respectively, was recognized in income taxes in the Consolidated Statements of Income. As of September 30, 2011, we have unrecognized income tax benefits totaling $5,163 including related accrued interest of $265. If these unrecognized tax benefits were subsequently recognized, $211 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 2011 are $4,837 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $3,391.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:



Balance at September 30, 2008	$	945
Additions for tax positions of the current year	63
Additions for tax positions of prior years	197
Settlements with tax authorities	(571		)
Balance at September 30, 2009	634
Additions for tax positions of the current year	3,907
Additions for tax positions of prior years	9
Settlements with tax authorities	(331		)
Decreases for tax positions related to prior years	(25		)
Balance at September 30, 2010	4,194
Additions for tax positions of the current year	920
Settlements with tax authorities	(216		)
September 30, 2011	$	4,898

The Company received IRS consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30,200 which was used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also produced a $43,393 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. As of September 30, 2011, a state net operating loss carryforward of $29,256 remains. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2011 and Fiscal 2010 the Company has added $1,195 and $3,907, respectively, to its liability for unrecognized tax benefits including interest related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount. For further information regarding the regulatory impact of this change, see Note 5.

In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities' Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Employee Retirement Plans

12 Months Ended

Sep. 30, 2011

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Retirement Plans

EMPLOYEE RETIREMENT PLANS

Defined Benefit Pension and Other Postretirement Plans

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”). In addition, we provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all active and retired employees.

Effective December 31, 2010, we merged our then-existing two defined benefit pension plans ("Pension Plan Merger"). As a result of the Pension Plan Merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan's assets and benefit obligations as of December 31, 2010, which decreased pension and postretirement obligations by $46,672; decreased associated regulatory assets by $43,150; and increased pre-tax other comprehensive income by $3,522. The Company's pension plans prior to the Pension Plan Merger, and the Pension Plan after the Pension Plan Merger, are hereafter referred to as the "Company Pension Plans.”

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Company Pension Plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets and the funded status of the Company Pension Plans and other postretirement plans as of September 30, 2011 and 2010. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.



	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
Change in benefit obligations:
Benefit obligations — beginning of year	$	464,977		$	422,041		$	15,140		$	14,610
Service cost	8,151			8,122			217			186
Interest cost	23,815			23,161			701			772
Actuarial (gain) loss	(20,772		)	29,667			(1,516		)	720
Plan amendments	—			—			(126		)	—
Benefits paid	(19,457		)	(18,014		)	(1,083		)	(1,148		)
Benefit obligations — end of year	$	456,714		$	464,977		$	13,333		$	15,140
Change in plan assets:
Fair value of plan assets — beginning of year	$	287,902		$	276,438		$	10,007		$	9,714
Actual gain on assets	2,601			26,125			149			723
Employer contributions	18,718			3,353			732			718
Benefits paid	(19,457		)	(18,014		)	(1,083		)	(1,148		)
Fair value of plan assets — end of year	$	289,764		$	287,902		$	9,805		$	10,007
Funded status of the plans — end of year	$	(166,950	)	$	(177,075	)	$	(3,528	)	$	(5,133	)
(Liabilities) recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(27,600	)	$	(20,303	)	$	(628	)	$	—
Unfunded liabilities — included in other noncurrent liabilities	(139,350		)	(156,772		)	(2,898		)	(5,133		)
Net amount recognized	$	(166,950	)	$	(177,075	)	$	(3,526	)	$	(5,133	)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	174		$	24		$	(91	)	$	55
Net actuarial loss (gain)	14,452			13,640			(168		)	192
Total	$	14,626		$	13,664		$	(259	)	$	247
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1,775		$	271		$	(3,188	)	$	(3,420	)
Net actuarial loss	146,899			155,585			6,294			5,915
Total	$	148,674		$	155,856		$	3,106		$	2,495

In Fiscal 2012, we estimate that we will amortize approximately $8,900 of net actuarial losses and $200 of prior service credits from stockholder’s equity and regulatory assets.

Actuarial assumptions are described below. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the Company postretirement plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the benefit payments. The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets as further described below.



	Pension Plans								Other Postretirement Benefits
Weighted-average assumptions:	2011 (a)		2010		2009		2008		2011		2010		2009		2008
Discount rate	5.3	%	5.0	%	5.5	%	6.8	%	5.3	%	5.0	%	5.5	%	6.8	%
Expected return on plan assets	8.0	%	8.5	%	8.5	%	8.5	%	5.5	%	5.5	%	5.5	%	5.5	%
Rate of increase in salary levels	3.5	%	3.8	%	3.8	%	3.8	%	3.5	%	3.8	%	3.8	%	3.8	%

(a) The discount rate used during Fiscal 2011 to calculate pension expense was a rate of 5.0% through December 31, 2010 (the date of the Utilities Plan Merger) and a rate of 5.5% thereafter.

The ABOs for the Company Pension Plans were $414,985 and $413,814 as of September 30, 2011 and 2010, respectively. Included in the end of year PBOs above are $40,908 at September 30, 2011 and $43,550 at September 30, 2010 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $675 at September 30, 2011 and $666 at September 30, 2010 relating to employees of UGI and certain of its other subsidiaries.

Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components:



	Pension Benefits									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009
Service cost	$	7,176		$	6,980		$	5,975		$	202		$	175		$	131
Interest cost	22,047			21,137			21,326			678			752			820
Expected return on assets	(23,937		)	(23,433		)	(23,794		)	(523		)	(508		)	(523		)
Curtailment gain	—			—			—			(3,245		)	—			—
Amortization of:
Prior service cost (benefit)	302			36			29			(694		)	(406		)	(410		)
Actuarial loss	6,838			5,331			3,588			427			231			88
Net benefit cost (income)	12,426			10,051			7,124			(3,155		)	244			106
Change in associated regulatory liabilities	—			—			—			3,138			3,137			3,271
Benefit cost (income) after change in regulatory liabilities	$	12,426		$	10,051		$	7,124		$	(17	)	$	3,381		$	3,377

Company Pension Plans' assets are held in trust. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2011 and 2010, we made contributions to the Company Pension Plans of $18,718 and $3,353, respectively. We did not make any contributions to the Company Pension Plans in Fiscal 2009. We believe that in Fiscal 2012 we will be required to make contributions to the Company Pension Plans of approximately $27,600.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under GAAP. 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. The required contribution to the VEBA during Fiscal 2012 is not expected to be material.

Expected payments for pension benefits and other postretirement welfare benefits are as follows:



	Pension Benefits		Other Postretirement Benefits
Fiscal 2012	$	20,551	$	1,591
Fiscal 2013	21,653		1,538
Fiscal 2014	22,823		1,556
Fiscal 2015	24,061		1,551
Fiscal 2016	25,300		1,541
Fiscal 2017 - 2021	145,472		7,801

The assumed health care cost trend rates are 7.5% for Fiscal 2012, decreasing to 5.0% in Fiscal 2017. A one percentage point change in the assumed health care cost trend rate would not have had a material impact on Fiscal 2011 other postretirement benefit cost or the September 30, 2011 other postretirement benefit ABO.

We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2011 and 2010, the projected benefit obligations of this plan were $2,232 and $3,074, respectively. We recorded expense for this plan of $583 in Fiscal 2011, $249 in Fiscal 2010 and $635 in Fiscal 2009.

Company Pension Plans and VEBA Assets. The assets of the Company Pension Plans and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Company Pension Plans and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock.

The targets, target ranges and actual allocations for the Company Pension Plans’ and VEBA trust assets at September 30 are as follows:



					Target
	Actual				Asset		Permitted
Pension Plans:	2011		2010		Allocation		Range
Equity investments:
Domestic	49.4	%	56.1	%	52.5	%	40.0% - 65.0%
International	10.7	%	12.2	%	12.5	%	7.5% - 17.5%
Total	60.1	%	68.3	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	39.9	%	31.7	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%



					Target
	Actual				Asset		Permitted
VEBA:	2011		2010		Allocation		Range
Domestic equity investments	62.2	%	64.9	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	37.8	%	35.1	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.6% and 8.3% of Company Pension Plans assets at September 30, 2011 and 2010, respectively. At September 30, 2011, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.

GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of Company Pension Plans and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee.

The fair values of the Company Pension Plans' assets at September 30, 2011 and 2010 by asset class are as follows:



	Company Pension Plans
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2011:
Equity investments:
Domestic	$	143,119	$	—	$	—	$	143,119
International	31,030		—		—		31,030
Fixed income	113,592		—		—		113,592
Cash equivalents	—		2,022		—		2,022
Total	$	287,741	$	2,022	$	—	$	289,763
September 30, 2010:
Equity investments:
Domestic	$	161,485	$	—	$	—	$	161,485
International	35,232		—		—		35,232
Fixed income	88,924		—		—		88,924
Cash equivalents	—		2,261		—		2,261
Total	$	285,641	$	2,261	$	—	$	287,902

The fair values of the VEBA trust assets at September 30, 2011 and 2010 by asset class are as follows:



	VEBA
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2011:
Domestic equities	$	6,098	$	—	$	—	$	6,098
Fixed income	3,320		—		—		3,320
Cash equivalents	—		388		—		388
Total	$	9,418	$	388	$	—	$	9,806
September 30, 2010:
Domestic equities	$	6,498	$	—	$	—	$	6,498
Fixed income	2,964		—		—		2,964
Cash equivalents	—		545		—		545
Total	$	9,462	$	545	$	—	$	10,007

The expected long-term rates of return on Company Pension Plans and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.

Defined Contribution Plan

We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008 who are not eligible to participate in the Company Pension Plans receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $1,820 in Fiscal 2011, $1,663 in Fiscal 2010 and $1,758 in Fiscal 2009.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Number 30
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
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-Number FAS88
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+ Details

Series Preferred Stock	12 Months Ended
Series Preferred Stock	Sep. 30, 2011
Series Preferred Stock [Abstract]
Series Preferred Stock	SERIES PREFERRED STOCK We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2011 or 2010.

Equity-Based Compensation

12 Months Ended

Sep. 30, 2011

Equity Based Compensation [Abstract]

Equity-Based Compensation

EQUITY-BASED COMPENSATION

Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “UGI OECP”), certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” or “Performance Units”) and other equity-based amounts. Under the UGI OECP, the exercise price for options may not be less than the fair market value on the grant date. Awards under the UGI OECP may vest immediately or ratably over a period of years (generally three-year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the UGI OECP provides that the awards of UGI Units may also provide for the crediting of UGI Common Stock dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.

UGI Stock and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to UGI market performance conditions. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance and service conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of Performance Units ultimately paid at the end of the performance period (generally three years) may range from 0% to 200% of the target award based upon UGI’s Total Shareholder Return percentile rank relative to companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and the Russell Midcap Utility Index (excluding telecommunications companies) for grants on or after January 1, 2011.

We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,110 ($650 after-tax) during Fiscal 2011; $853 ($499 after-tax) during Fiscal 2010; and $1,142 ($668 after-tax) during Fiscal 2009.

As of September 30, 2011, there was $546 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 2.2 years. As of September 30, 2011, there was a total of $805 of unrecognized compensation expense associated with 59,799 UGI Unit awards that is expected to be recognized over a weighted average period of 2.0 years. At September 30, 2011 and 2010, total liabilities of $327 and $550, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2011:



	Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2010	57,400		$	26.70	21,534		$	28.02	35,866		$	25.92
Granted	22,800		$	35.25	—		$	—	22,800		$	35.25
Vested	—		$	—	14,221		$	29.59	(14,221	)	$	29.59
Forfeited	(2,801	)	$	24.47	—		$	—	(2,801	)	$	24.47
Unit awards paid	(17,600	)	$	30.00	(17,600	)	$	30.00	—		$	—
September 30, 2011	59,799		$	29.10	18,155		$	27.33	41,644		$	29.87

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
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-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

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+ Details

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Sep. 30, 2011
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Commitments We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $5,221 in Fiscal 2011, $5,737 in Fiscal 2010 and $5,894 in Fiscal 2009. Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2012— $4,847; 2013 — $4,275; 2014 — $3,127; 2015 — $2,340; 2016 — $2,106; after September 30, 2016 — $2,246. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation, natural gas storage and peaking service which Gas Utility may terminate at various dates through 2022. Gas Utility’s costs associated with transportation and storage service agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2011 for fiscal years ending September 30 are as follows: 2012 — $241,859; 2013 — $117,037; 2014 — $86,440; 2015 — $57,986; 2016 — $35,212; after 2016 — $135,315. Contingencies 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 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 $1,800 and $1,100, 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 September 30, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17,917 and $21,385, respectively. In accordance with GAAP related to rate-regulated entities, 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 manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. 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. The Company 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 September 30, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities. 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. UGI Utilities is currently litigating three claims against it relating to out-of-state sites. 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 asserts that the plant operated from 1855 to 1954 and alleges 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 asserts that it has spent approximately $22,000 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. Trial took place in March 2009 and the court's decision is pending. 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. Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 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 $10,000. KeySpan believes that the cost could be as high as $20,000. There have been no recent developments or facts indicating that this will have a material impact to our results of operations or financial condition. 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, CT (“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. The District Court's decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000. Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) 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 located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of UGI Utilities' predecessor is identified as an owner and operator of the site. The City and MUD has requested that UGI Utilities participate in the clean up of this site. 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 is reviewing the EPA's request and will cooperate with its investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. Other Matters Allentown, Pennsylvania Natural Gas Explosion. Allentown, Pennsylvania Natural Gas Explosion. On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and UGI Utilities is cooperating with that investigation. Based on a visual inspection, UGI Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined. UGI Utilities has received more than one hundred property claims and a handful of personal injury and wrongful death claims as a result of the explosion, although no lawsuits have yet been filed. Many of the claims, including two wrongful death claims and more than fifty percent of the property claims received to date, have been settled. UGI Utilities maintains liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of a $500 deductible, will be recovered through UGI Utilities' insurance. We continue to believe that claims and expenses associated with the explosion will not have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows. We cannot predict with certainty the final results of any of the environmental 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. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.

- Definition

The entire disclosure for commitments and contingencies.

+ References

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-Subparagraph (SX 210.5-02.25)
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Fair Value Measurements

12 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 September 30, 2011 and 2010:



	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2011
Assets:
Derivative financial instruments
Commodity contracts	$	27	$	41	$	—	$	68
Liabilities:
Derivative financial instruments
Commodity contracts	$	4,102	$	7,634	$	—	$	11,736
Interest rate contracts	$	—	$	18,585	$	—	$	18,585

September 30, 2010
Assets:
Derivative financial instruments
Commodity contracts	$	61	$	425	$	—	$	486
Liabilities:
Derivative financial instruments
Commodity contracts	$	3,263	$	17,798	$	—	$	21,061

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators.

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at September 30, 2011 were $640,000 and $737,223, respectively. The carrying amount and estimated fair value of our long-term debt at September 30, 2010 were $640,000 and $749,227, 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 types of debt.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

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+ Details

Disclosures About Derivative Instruments and Hedging Activities

12 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

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 and (2) interest 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 commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.

Commodity Price Risk

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. 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 September 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 15.1 million dekatherms and 19.5 million dekatherms, respectively. At September 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 13 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 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 5).

Beginning January 1, 2010, Electric Utility's DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. 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 under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2011 and 2010 the fair values of Electric Utility's forward purchase power agreements comprising losses of $8,655 and $19,702, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying 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 September 30, 2011 and 2010, the volumes of Electric Utility's forward electricity purchase contracts was 788.6 million kilowatt hours and 990.7 million kilowatt hours, respectively. At September 30, 2011, the maximum period over which these contracts extend is 32 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. 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 commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its DS filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 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 5). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 208.6 million kilowatt hours and 546.8 million kilowatt hours, respectively.

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. The volumes of gasoline under these contracts were not material for all periods presented.

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of September 30, 2011, the total notional amounts of our unsettled IRPA contracts was $173,000. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2011 and 2010, Gas Utility’s restricted cash in brokerage accounts totaled $4,308 and $4,698, respectively.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2011 and 2010:



	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2011		2010		Location	2011		2010
Derivatives Designated as Hedging Instruments:
						Derivative financial instruments and Other noncurrent liabilities	$	18,585	$	—

Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	$	41	$	425	Derivative financial instruments and Other noncurrent liabilities	11,736		21,061
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	27		61
Total Derivatives		$	68	$	486		$	30,321	$	21,061

During the years ended September 30, 2011 and 2010, the amount of IRPA net losses included in AOCI that were reclassified into net income for both periods totaled $1,164, respectively. During the years ended September 30, 2011 and 2010, the impact of changes in the fair value of FTRs and gasoline futures and swap contracts on our net income was not material.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
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+ Details

Segment Information

12 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other.”

The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States.

Financial information by business segment follows:



	Total		Gas Utility		Electric Utility		Other
2011
Revenue	$	1,137,366	$	1,026,397	$	109,145	$	1,824
Cost of sales	678,500		610,635		67,865		—
Depreciation and amortization	52,546		48,350		4,196		—
Operating income	211,421		199,643		11,384		394
Interest expense	42,728		40,374		2,354		—
Income before income taxes	168,693		159,269		9,030		394
Total assets	2,169,348		2,028,705		140,643		—
Goodwill	182,145		182,145		—		—
Capital expenditures	98,856		91,328		7,528		—
2010
Revenue	$	1,169,539	$	1,047,521	$	120,246	$	1,772
Cost of sales	730,502		653,439		77,063		—
Depreciation and amortization	53,476		49,474		4,002		—
Operating income	189,519		175,272		13,676		571
Interest expense	42,336		40,515		1,821		—
Income before income taxes	147,183		134,757		11,855		571
Total assets	2,139,576		1,996,281		143,295		—
Goodwill	180,145		180,145		—		—
Capital expenditures	81,595		73,503		8,092		—
2009
Revenue	$	1,381,260	$	1,240,981	$	138,495	$	1,784
Cost of sales	944,793		853,163		91,630		—
Depreciation and amortization	51,112		47,228		3,884		—
Operating income	169,472		153,457		15,376		639
Interest expense	43,918		42,192		1,726		—
Income before income taxes	125,554		111,265		13,650		639
Total assets	2,030,237		1,917,036		113,201		—
Goodwill	180,145		180,145		—		—
Capital expenditures	79,084		73,825		5,259		—

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Other Income, Net

12 Months Ended

Sep. 30, 2011

Other Income [Abstract]

Other Income, Net

OTHER INCOME, NET

Other income, net, comprises the following:



	2011		2010		2009
Non-tariff service income	$	6,422	$	2,437	$	3,221
Interest income	467		867		288
Postretirement benefit plan curtailment gain	3,245		—		—
Other	630		2,965		3,752
Total other income, net	$	10,764	$	6,269	$	7,261

Related Party Transactions	12 Months Ended
Related Party Transactions	Sep. 30, 2011
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities' relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses - related parties in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI's subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material. From time to time, UGI Utilities is a party to SCAAs with Energy Services. At September 30, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives 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. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $35,231, $21,826 and $55,760 in Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which amounts are included in other current liabilities on the Consolidated Balance Sheets, were $15,000 and $7,500 at September 30, 2011 and 2010, respectively. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2011, comprising approximately 7.5 bcf feet of natural gas, was $35,686. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749. UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2011, Fiscal 2010 and Fiscal 2009 totaled $30,093, $25,941 and $24,444, respectively. From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, revenues associated with sales to Energy Services totaled $85,655, $62,074 and $30,911, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above) and beginning April 1, 2011, purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under a one-year agreement. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, such purchases totaled $53,617, $31,157 and $17,268, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows. On October 1, 2008, in conjunction with the CPG Acquisition, CPG’s wholly owned subsidiary CPP sold its assets to AmeriGas OLP, an affiliate of UGI. See Note 4 for additional information regarding this transaction.

- Definition

The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph k

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 04
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Quarterly Data (unaudited)

12 Months Ended

Sep. 30, 2011

Quarterly Data [Abstract]

Quarterly Data (unaudited)

QUARTERLY DATA (unaudited)

The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.



	December 31,				March 31,				June 30,				September 30,
	2010		2009		2011		2010		2011		2010		2011			2010
Revenues	$	350,516	$	362,203	$	484,465	$	477,273	$	172,714	$	175,021	$	129,671		$	155,042
Operating income	$	78,880	$	69,273	$	104,109	$	94,337	$	19,486	$	16,379	$	8,946		$	9,530
Net income (loss)	$	41,074	$	35,163	$	60,163	$	50,612	$	5,478	$	3,604	$	(1,519	)	$	879

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Valuation and Qualifying Accounts

12 Months Ended

Sep. 30, 2011

II — Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)



	Balance at beginning of year		Charged to costs and expenses			Other				Balance at end of year
September 30, 2011
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	7,072	$	9,137		$	(9,841	)	⁽¹⁾	$	6,368
Other reserves:
Other, principally environmental and property and casualty liability	$	33,465	$	10,173		$	(9,558	)	⁽³⁾	$	34,080	⁽⁵⁾

September 30, 2010
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	11,384	$	10,651		$	(14,963	)	⁽¹⁾	$	7,072

Other reserves:
Other, principally environmental and property and casualty liability	$	38,707	$	(1,547	)	$	(2,940	)	⁽³⁾	$	33,465	⁽⁵⁾
						$	(755	)	⁽⁴⁾

September 30, 2009
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	10,369	$	19,193		$	(22,735	)	⁽¹⁾	$	11,384
						$	4,557		⁽²⁾
Other reserves:
Other, principally environmental and property and casualty liability	$	16,011	$	2,335		$	18,495		⁽²⁾	$	38,707	⁽⁵⁾
						$	(3,678	)	⁽³⁾
						$	5,544		⁽⁴⁾


(1)	Uncollectible accounts written off, net of recoveries


(2)	Acquisition adjustments


(3)	Payments, net


(4)	Other adjustments


(5)	At September 30, 2011, 2010 and 2009 UGI Utilities had insurance indemnification receivables associated with its property and casualty liabilities totaling $8,163, $882 and $750, respectively.