View Filing Data

Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Mar. 31, 2012	Apr. 30, 2012
Document Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
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

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2012	Sep. 30, 2011	Mar. 31, 2011
Current assets:
Cash and cash equivalents	$ 46,593	$ 7,267	$ 75,472
Restricted cash	4,260	4,308	3,996
Accounts receivable (less allowances for doubtful accounts of $8,900, $6,368 and $13,558, respectively)	105,330	58,736	154,398
Accounts receivable — related parties	6,353	7,048	13,181
Accrued utility revenues	25,474	14,807	43,163
Inventories	23,640	104,263	16,674
Deferred income taxes	33,907	42,528	33,201
Regulatory assets	3,593	8,608	1,762
Derivative financial instruments	185	68	1,920
Prepaid expenses & other current assets	24,000	24,911	19,794
Total current assets	273,335	272,544	363,561
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $800,423, $782,665 and $770,842, respectively)	1,441,612	1,418,356	1,394,053
Goodwill	182,145	182,145	180,145
Regulatory assets	292,096	291,847	254,632
Other assets	4,718	4,456	11,060
Total assets	2,193,906	2,169,348	2,203,451
Current liabilities:
Current maturities of long-term debt	40,000	40,000	0
Accounts payable	27,180	53,556	49,203
Accounts payable — related parties	7,488	10,108	10,742
Deferred fuel refunds	12,022	6,578	33,955
Derivative financial instruments	11,404	11,928	4,291
Other current liabilities	149,357	140,849	163,355
Total current liabilities	247,451	263,019	261,546
Long-term debt	600,000	600,000	640,000
Deferred income taxes	367,088	361,468	305,371
Deferred investment tax credits	4,784	4,958	5,134
Pension and postretirement benefit obligations	130,731	142,248	115,628
Other noncurrent liabilities	81,441	78,810	71,531
Total liabilities	1,431,495	1,450,503	1,399,210
Commitments and contingencies (note 8)
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	60,259
Additional paid-in capital	468,564	468,323	468,302
Retained earnings	253,631	212,096	279,856
Accumulated other comprehensive loss	(20,043)	(21,833)	(4,176)
Total common stockholder’s equity	762,411	718,845	804,241
Total liabilities and stockholder’s equity	$ 2,193,906	$ 2,169,348	$ 2,203,451

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2012	Sep. 30, 2011	Mar. 31, 2011
Current assets:
Allowances for doubtful accounts on accounts receivable	$ 8,900	$ 6,368	$ 13,558
Accumulated depreciation and amortization on property, plant and equipment	$ 800,423	$ 782,665	$ 770,842
Common stockholder's equity:
Common stock, par value	$ 2.25	$ 2.25	$ 2.25
Common stock, shares authorized	40,000,000	40,000,000	40,000,000
Common stock, shares issued	0	0	0
Common stock, shares outstanding	26,781,785	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

Condensed Consolidated Statements of Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Revenues	$ 345,802	$ 484,465	$ 626,443	$ 834,981
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	192,770	308,778	349,676	522,262
Operating and administrative expenses	45,749	51,299	86,691	91,193
Operating and administrative expenses - related parties	2,781	5,923	4,906	8,848
Taxes other than income taxes	4,857	5,469	8,984	9,827
Depreciation	12,328	12,683	24,707	25,289
Amortization	782	633	1,466	1,265
Other income, net	(1,912)	(4,429)	(3,039)	(6,692)
Total costs and expenses	257,355	380,356	473,391	651,992
Operating income	88,447	104,109	153,052	182,989
Interest expense	10,677	10,809	21,284	21,442
Income before income taxes	77,770	93,300	131,768	161,547
Income taxes	29,899	33,137	51,229	60,310
Net income	$ 47,871	$ 60,163	$ 80,539	$ 101,237

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Net income	$ 47,871	$ 60,163	$ 80,539	$ 101,237
Net gains in fair value of derivative instruments (net of tax $(1,869), $0, $(592) and ($3,007))	2,635	578	834	4,819
Reclassifications of net losses on derivative instruments (net of tax of ($403), ($121), $(524) and $(242))	570	170	740	340
Benefit plans, (net of tax of ($81), $78, $(162) and ($1,461), respectively)	77	(110)	216	2,061
Comprehensive income	$ 51,153	$ 60,801	$ 82,329	$ 108,457

- 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

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 Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Tax on (loss) gain on derivative instruments	$ (1,869)	$ 0	$ (592)	$ (3,007)
Tax on reclassifications of net losses (gains) on derivative instruments	(403)	(121)	(524)	(242)
Tax on benefit plans	$ (81)	$ 78	$ (162)	$ (1,461)

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 80,539	$ 101,237
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	26,173	26,554
Deferred income taxes, net	12,229	(1,627)
Provision for uncollectible accounts	5,819	8,626
Other, net	(10,663)	3,524
Net change in:
Accounts receivable and accrued utility revenues	(62,385)	(137,223)
Inventories	80,623	102,184
Deferred fuel and power costs	14,039	43,281
Accounts payable	(28,996)	5,510
Other current assets	786	3,277
Other current liabilities	11,202	9,665
Net cash provided by operating activities	129,366	165,008
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(49,784)	(37,658)
Net costs of property, plant and equipment disposals	(1,541)	(1,220)
Decrease in restricted cash	48	702
Net cash used by investing activities	(51,277)	(38,176)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(39,004)	(39,348)
Decrease in bank loans	0	(17,000)
Other	241	670
Net cash used by financing activities	(38,763)	(55,678)
Cash and cash equivalents increase	39,326	71,154
CASH AND CASH EQUIVALENTS:
End of period	46,593	75,472
Beginning of period	7,267	4,318
Increase	$ 39,326	$ 71,154

Nature of Operations	6 Months Ended
Nature of Operations	Mar. 31, 2012
Nature of Operations [Abstract]
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 ("HVAC Business"). 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	6 Months Ended
Significant Accounting Policies	Mar. 31, 2012
Accounting Policies [Abstract]
Significant Accounting Policies	Significant Accounting Policies Basis of Presentation. Our condensed 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. The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2011 condensed consolidated balance sheet data was derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2011 (“Company’s 2011 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and includes actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income. 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 were 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. Income Taxes. As a result of the completion of the audit of the UGI 2009 federal income tax return, the Company adjusted its unrecognized tax benefits which reduced income tax expense and increased net income by $204 for the three and six months ended March 31, 2012. Reclassifications. Removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the March 31, 2011 Condensed Consolidated Balance Sheet to conform to the current-period presentation. Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Accounting Changes	6 Months Ended
Accounting Changes	Mar. 31, 2012
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Accounting Changes Adoption of New Accounting Standards Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012. Fair Value Measurements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments result in common fair value measurement and disclosure requirements in U.S. 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. The adoption of this accounting guidance did not have a material impact on our financial statements. New Accounting Standards Not Yet Adopted Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in ASU 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods. We are currently evaluating the impact of the provisions of the new guidance on our future disclosures.

- 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

Segment Information

6 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

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 of the Company’s 2011 Annual Financial Statements and Notes. 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:

Three Months Ended March 31, 2012:



			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	345,802	$	319,511	$	25,940	$	351
Cost of sales	$	192,770	$	177,492	$	15,278	$	—
Depreciation and amortization	$	13,110	$	12,159	$	951	$	—
Operating income	$	88,447	$	84,969	$	3,363	$	115
Interest expense	$	10,677	$	10,085	$	592	$	—
Income before income taxes	$	77,770	$	74,884	$	2,771	$	115

Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	26,926	$	25,654	$	1,272	$	—

Three Months Ended March 31, 2011:



			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	484,465	$	452,437	$	31,711	$	317
Cost of sales	$	308,778	$	288,527	$	20,251	$	—
Depreciation and amortization	$	13,316	$	12,305	$	1,011	$	—
Operating income	$	104,109	$	100,968	$	2,990	$	151
Interest expense	$	10,809	$	10,242	$	567	$	—
Income before income taxes	$	93,300	$	90,726	$	2,423	$	151

Total assets (at period end)	$	2,203,451	$	2,045,178	$	158,273	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	20,071	$	17,465	$	2,606	$	—

Six Months Ended March 31, 2012:



			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	626,443	$	574,541	$	51,109	$	793
Cost of sales	$	349,676	$	319,171	$	30,505	$	—
Depreciation and amortization	$	26,173	$	24,304	$	1,869	$	—
Operating income	$	153,052	$	146,200	$	6,593	$	259
Interest expense	$	21,284	$	20,183	$	1,101	$	—
Income before income taxes	$	131,768	$	126,017	$	5,492	$	259

Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	49,784	$	47,466	$	2,318	$	—

Six Months Ended March 31, 2011:



			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	834,981	$	773,551	$	60,651	$	779
Cost of sales	$	522,262	$	483,440	$	38,822	$	—
Depreciation and amortization	$	26,554	$	24,530	$	2,024	$	—
Operating income	$	182,989	$	176,035	$	6,593	$	361
Interest expense	$	21,442	$	20,350	$	1,092	$	—
Income before income taxes	$	161,547	$	155,685	$	5,501	$	361

Total assets (at period end)	$	2,203,451	$	2,045,178	$	158,273	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	37,658	$	33,551	$	4,107	$	—

- 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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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+ Details

Inventories

6 Months Ended

Mar. 31, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:



	March 31, 2012		September 30, 2011		March 31, 2011
Gas Utility natural gas	$	12,761	$	95,590	$	7,927
Materials, supplies and other	10,879		8,673		8,747
Total inventories	$	23,640	$	104,263	$	16,674

At March 31, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013 (see Note 9). 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 represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

The carrying value of gas storage inventories released under the SCAAs at March 31, 2012, September 30, 2011 and March 31, 2011 comprising 1.8 billion cubic feet (“bcf”), 11.5 bcf and 1.1 bcf of natural gas, was $7,661, $54,658 and $5,089, respectively. In conjunction with the SCAAs, at March 31, 2012, September 30, 2011 and March 31, 2011, UGI Utilities held a total of $22,500 of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Regulatory Assets and Liabilities and Regulatory Matters

6 Months Ended

Mar. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 5 to the Company’s 2011 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:



	March 31, 2012		September 30, 2011		March 31, 2011
Regulatory assets:
Income taxes recoverable	$	99,226	$	97,947	$	89,875
Underfunded pension and postretirement plans	146,631		150,669		116,003
Environmental costs	18,247		19,547		22,014
Deferred fuel and power costs	11,012		12,163		8,153
Removal costs, net	11,915		12,313		11,740
Other	8,658		7,816		8,609
Total regulatory assets	$	295,689	$	300,455	$	256,394
Regulatory liabilities:
Postretirement benefits	$	12,053	$	11,476	$	11,196
Environmental overcollections	3,843		4,758		6,811
Deferred fuel and power refunds	12,021		6,578		33,955
State tax benefits — distribution system repairs	6,735		6,282		6,339
Other	748		736		—
Total regulatory liabilities	$	35,400	$	29,830	$	58,301

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized (losses) gains on such contracts at March 31, 2012, September 30, 2011 and March 31, 2011 were $(3,113), $(3,081) and $1,503, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility's DS recovery mechanism. At March 31, 2012, September 30, 2011 and March 31, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $14,747, $8,655 and $10,682, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains on FTRs at March 31, 2012, September 30, 2011 and March 31, 2011 were not material.

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

Defined Benefit Pension and Other Postretirement Plans

6 Months Ended

Mar. 31, 2012

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

Defined Benefit Pension and Other Postretirement Plans

We currently sponsor one defined benefit pension plan (“Pension Plan”) for employees hired prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI and certain of UGI’s other wholly owned domestic subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all active and retired employees.

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



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
Service cost	$	1,756		$	1,750		$	43		$	54
Interest cost	5,594			5,564			166			183
Expected return on assets	(5,940		)	(5,971		)	(127		)	(131		)
Amortization of:
Prior service cost (benefit)	62			80			(106		)	(174		)
Actuarial loss	1,963			1,570			99			121
Net benefit cost	3,435			2,993			75			53
Change in associated regulatory liabilities	—			—			784			785
Net expense	$	3,435		$	2,993		$	859		$	838



	Pension Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
Service cost	$	3,512		$	3,675		$	86		$	107
Interest cost	11,188			10,919			332			365
Expected return on assets	(11,880		)	(11,993		)	(254		)	(261		)
Amortization of:
Prior service cost (benefit)	124			142			(212		)	(348		)
Actuarial loss	3,926			3,698			198			243
Net benefit cost	6,870			6,441			150			106
Change in associated regulatory liabilities	—			—			1,568			1,570
Net expense	$	6,870		$	6,441		$	1,718		$	1,676

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $22,900 to the Pension Plan during the next twelve months. During the six months ended March 31, 2012 and 2011, the Company made contributions to the Pension Plan of $19,712 and $12,576, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months ended March 31, 2012 and 2011, nor are they expected to be material for all of Fiscal 2012.

We also participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.

- 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
-Paragraph 5
-Subparagraph a
-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)
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-Paragraph 5
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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)
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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
-Publisher FASB
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-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 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 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.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-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 10: http://www.xbrl.org/2003/role/presentationRef
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-Name FASB Staff Position (FSP)
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 158
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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 12: http://www.xbrl.org/2003/role/presentationRef
-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.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-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 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Commitments and Contingencies

6 Months Ended

Mar. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies


	Commitments and 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 manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 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 March 31, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $16,789 and $20,864, 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 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 March 31, 2012, 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 two 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 $26,000 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. On April 11, 2012, the District Court entered a judgment in favor of UGI Utilities. SCE&G has thirty days from the date of the District Court's judgment to appeal this decision.

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 has indicated that the cost could be as high as $20,000. There have been no recent developments in this case.

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

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

Other Matters

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 continues to investigate 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. Results of forensic testing by an expert independent laboratory have been provided to the PUC investigatory team.

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. Many of the claims, including three wrongful death claims, several personal injury claims and approximately eighty-five percent of the property claims received to date, have been settled. One wrongful death lawsuit has been filed in the Court of Common Pleas for Northampton County, Pennsylvania, by the executor of the estates of two of the decedents, Katherine Cruz and Ofelia Ben, in which plaintiffs seek compensatory and punitive damages related to the incident and against which the Company has filed preliminary objections. UGI Utilities maintains liability insurance for personal injury, wrongful death, 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 and that there is no basis for a punitive damage award in this matter. 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-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 5
-Paragraph 9, 10, 11, 12
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-Name Accounting Standards Codification
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-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
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-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Related Party Transactions

6 Months Ended

Mar. 31, 2012

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 UGI Energy Services, Inc. ("Energy Services"), a second-tier wholly owned subsidiary of UGI. At March 31, 2012, 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 $408 and $5,330 during the three and six months ended March 31, 2012, respectively, and $297 and $2,590 during the three and six months ended March 31, 2011. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, were $15,000 as of March 31, 2012, September 30, 2011 and March 31, 2011.

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 March 31, 2012, comprising approximately 1.2 bcf of natural gas, was $4,725. The carrying value of these gas storage inventories at September 30, 2011, comprising approximately 7.5 bcf of natural gas, was $35,686. The carrying value of these gas storage inventories at March 31, 2011, comprising approximately 0.7 bcf of natural gas, was $3,452.

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 the three and six months ended March 31, 2012 totaled $8,386 and $30,752, respectively. During the three and six months ended March 31, 2011, such transactions totaled $11,338 and $30,093, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2012, revenues associated with such sales to Energy Services totaled $23,574 and $40,656, respectively. During the three and six months ended March 31, 2011, such revenues totaled $38,497 and $61,059, 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 purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and six months ended March 31, 2012, the aggregate amount of such purchases totaled $13,267 and $23,319, respectively. During the three and six months ended March 31, 2011, such purchases totaled $22,002 and $35,498, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

- 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
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 04
-Paragraph b

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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-Name Accounting Standards Codification
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-Subparagraph (SX 210.4-08.(k))
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+ Details

Fair Value Measurements

6 Months Ended

Mar. 31, 2012

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 March 31, 2012, September 30, 2011 and March 31, 2011:



	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
March 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	185		$	—		$	—	$	185
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,674	)	$	(13,228	)	$	—	$	(17,902	)
Interest rate contracts	$	—		$	(17,345	)	$	—	$	(17,345	)
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	)
March 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	1,806		$	114		$	—	$	1,920
Interest rate contracts	—			7,827			—		$	7,827
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,371	)	$	(9,311	)	$	—	$	(10,682	)

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. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at March 31, 2012 were $640,000 and $725,990, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2011 were $640,000 and $707,512, 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 (Level 2).

- 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-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 107
-Paragraph 15C, 15D
-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 107
-Paragraph 15A
-Subparagraph a-d
-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 Statement of Financial Accounting Standard (FAS)
-Number 107
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Disclosures About Derivative Instruments and Hedging Activities

6 Months Ended

Mar. 31, 2012

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, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2012 and 2011, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 11.6 million dekatherms and 21.5 million dekatherms, respectively. At March 31, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 19 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB's guidance in Accounting Standards Codification ("ASC") 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 6).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception. Because these contracts no longer qualify for the normal purchases and normal sales exception, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At March 31, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $14,747 and $10,682, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At March 31, 2012 and 2011, the volumes of Electric Utility's forward electricity purchase contracts was 707.4 million kilowatt hours and 835.5 million kilowatt hours, respectively. At March 31, 2012, the maximum period over which these contracts extend is 26 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, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 6). At March 31, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 52.2 million kilowatt hours and 138.2 million kilowatt hours, respectively. At March 31, 2012, the maximum period over which we are hedging electricity congestion with FTRs is 2 months.

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 and the fair values of 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 accumulated other comprehensive income (“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 March 31, 2012 and 2011, the total notional amounts of our unsettled IRPA contracts was $173,000 and $106,500, respectively. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the three and six months ended March 31, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements Income.

At March 31, 2012, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $988.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At March 31, 2012 and 2011, restricted cash in brokerage accounts totaled $4,260 and $3,996, respectively.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2012 and 2011:



	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	March 31, 2012		March 31, 2011		Location	March 31, 2012			March 31, 2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	—	$	7,827	Other noncurrent liabilities	$	(17,345	)	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	1		1,617		Derivative financial instruments and Other noncurrent liabilities	(17,902		)	(10,682		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	184		303		Derivative financial instruments	—			—
Total Derivatives		$	185	$	9,747		$	(35,247	)	$	(10,682	)

The following table provides information on the effects of derivative instruments on the Consolidated Statement of Income and changes in AOCI for three and six months ended March 31, 2012 and 2011:

Three Months Ended March 31,:



	Gain or (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2012		2011		2012			2011			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	4,504	$	578	$	(973	)	$	(291	)	Interest expense/ other income, net

Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012		2011
Commodity contracts	$	257	$	190							Operating expenses

Six Months Ended March 31,:



	Gain or (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or (Loss)
	2012		2011		2012			2011			Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	1,427	$	7,827	$	(1,264	)	$	(582	)	Interest expense/ other income, net

Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012		2011
Commodity contracts	$	205	$	351							Operating expenses/ other income, net

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 and contracts which provide for the purchase and delivery of natural gas 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 because they provide for the delivery of products in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

- 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.

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