10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)

Pennsylvania	23-1174060
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

UGI UTILITIES, INC.

2525 N. 12th Street, Suite 360

Reading, PA

(Address of principal executive offices)

19612

(Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

At July 31, 2012, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	PAGES
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of June 30, 2012, September 30, 2011 and June 30, 2011	1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2012 and 2011	2
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2012 and 2011	3
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2012 and 2011	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. Controls and Procedures	26
Part II Other Information
Item 1. Legal Proceedings	27
Item 1A. Risk Factors	27
Item 6. Exhibits	28
Signatures	29
Exhibit 10.1
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

- i -

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30, 2012			September 30, 2011			June 30, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	75,969		$	7,267		$	108,914
Restricted cash	1,604			4,308			4,055
Accounts receivable (less allowances for doubtful accounts of $7,457, $6,368 and $12,927, respectively)	61,072			58,736			87,858
Accounts receivable — related parties	4,311			7,048			4,277
Accrued utility revenues	14,970			14,807			7,417
Inventories	38,413			104,263			58,751
Deferred income taxes	33,595			42,528			32,302
Regulatory assets	2,681			8,608			2,037
Derivative financial instruments	545			68			329
Prepaid expenses & other current assets	17,890			24,911			15,490
Total current assets	251,050			272,544			321,430
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $809,458, $782,665 and $777,773, respectively)	1,458,654			1,418,356			1,393,010
Goodwill	182,145			182,145			180,145
Regulatory assets	288,366			291,847			255,301
Other assets	5,630			4,456			8,678
Total assets	$	2,185,845		$	2,169,348		$	2,158,564
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	40,000		$	40,000		$	—
Accounts payable	30,457			53,556			41,487
Accounts payable — related parties	10,175			10,108			9,260
Deferred fuel refunds	10,325			6,578			22,451
Derivative financial instruments	7,150			11,928			5,334
Other current liabilities	144,492			140,849			142,797
Total current liabilities	242,599			263,019			221,329
Long-term debt	600,000			600,000			640,000
Deferred income taxes	371,388			361,468			327,039
Deferred investment tax credits	4,698			4,958			5,046
Pension and postretirement benefit obligations	126,007			142,248			113,235
Other noncurrent liabilities	92,409			78,810			69,898
Total liabilities	1,437,101			1,450,503			1,376,547
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	468,630			468,323			468,323
Retained earnings	246,286			212,096			259,307
Accumulated other comprehensive loss	(26,431		)	(21,833		)	(5,872		)
Total common stockholder’s equity	748,744			718,845			782,017
Total liabilities and stockholder’s equity	$	2,185,845		$	2,169,348		$	2,158,564

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Revenues	$	143,644		$	172,714		$	770,087		$	1,007,695
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	62,701			93,383			412,377			615,645
Operating and administrative expenses	37,689			42,910			124,380			134,103
Operating and administrative expenses — related parties	2,107			1,747			7,013			10,595
Taxes other than income taxes	3,919			3,523			12,903			13,350
Depreciation	12,425			12,058			37,132			37,347
Amortization	826			631			2,292			1,896
Other income, net	(1,323		)	(1,024		)	(4,362		)	(7,716		)
	118,344			153,228			591,735			805,220
Operating income	25,300			19,486			178,352			202,475
Interest expense	10,575			10,518			31,859			31,960
Income before income taxes	14,725			8,968			146,493			170,515
Income taxes	6,265			3,490			57,494			63,800
Net income	$	8,460		$	5,478		$	88,999		$	106,715

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2012			2011			2012			2011
Net income	$	8,460		$	5,478		$	88,999		$	106,715
Net (losses) gains in fair value of derivative instruments (net of tax of $4,801, $913, $4,209 and $(2,094), respectively)	(6,772		)	(1,866		)	(5,938		)	2,953
Reclassifications of net losses on derivative instruments (net of tax of $(201), $(120), $(725) and $(362), respectively)	283			171			1,023			511
Benefit plans (net of tax of $(80), $0, $(242) and $(1,461), respectively)	101			(1		)	317			2,060
Comprehensive income	$	2,072		$	3,782		$	84,401		$	112,239

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Nine Months Ended
	June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	88,999		$	106,715
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	39,424			39,243
Deferred income taxes, net	21,269			18,700
Provision for uncollectible accounts	5,592			9,495
Other, net	(12,809		)	8,712
Net change in:
Accounts receivable and accrued utility revenues	(5,354		)	(23,902		)
Inventories	65,850			60,107
Deferred fuel and power costs	8,133			32,951
Accounts payable	(23,032		)	(3,688		)
Other current assets	7,059			5,340
Other current liabilities	7,467			(17,988		)
Net cash provided by operating activities	202,598			235,685
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(79,698		)	(59,590		)
Net costs of property, plant and equipment disposals	(2,400		)	(1,414		)
Decrease in restricted cash	2,704			643
Net cash used by investing activities	(79,394		)	(60,361		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(54,809		)	(54,419		)
Decrease in bank loans	—			(17,000		)
Other	307			691
Net cash used by financing activities	(54,502		)	(70,728		)
Cash and cash equivalents increase	$	68,702		$	104,596
CASH AND CASH EQUIVALENTS:
End of period	$	75,969		$	108,914
Beginning of period	7,267			4,318
Increase	$	68,702		$	104,596

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

1. 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.

2. 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 that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2011 condensed consolidated balance sheet data was derived from audited financial statements but 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 that 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 nine months ended June 30, 2012.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Reclassifications. Removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the June 30, 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.

3. 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 became effective for our interim period ending March 31, 2012 and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.

New Accounting Standards Not Yet Adopted

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

4. 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

Three Months Ended June 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	172,714	$	148,104	$	24,022	$	588
Cost of sales	$	93,383	$	78,811	$	14,572	$	—
Depreciation and amortization	$	12,689	$	11,596	$	1,093	$	—
Operating income (loss)	$	19,486	$	17,171	$	2,432	$	(117	)
Interest expense	$	10,518	$	9,852	$	666	$	—
Income (loss) before income taxes	$	8,968	$	7,319	$	1,766	$	(117	)
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	21,932	$	20,902	$	1,030	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Nine Months EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

Nine Months EndedJune 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	1,007,695	$	921,655	$	84,673	$	1,367
Cost of sales	$	615,645	$	562,251	$	53,394	$	—
Depreciation and amortization	$	39,243	$	36,126	$	3,117	$	—
Operating income	$	202,475	$	193,206	$	9,025	$	244
Interest expense	$	31,960	$	30,202	$	1,758	$	—
Income before income taxes	$	170,515	$	163,004	$	7,267	$	244
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	59,590	$	54,453	$	5,137	$	—

5. Inventories

Inventories comprise the following:

	June 30, 2012		September 30, 2011		June 30, 2011
Gas Utility natural gas	$	27,761	$	95,590	$	50,082
Materials, supplies and other	10,652		8,673		8,669
Total inventories	$	38,413	$	104,263	$	58,751

At June 30, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013 (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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 June 30, 2012, September 30, 2011 and June 30, 2011 comprising 6.0 billion cubic feet (“bcf”), 11.5 bcf and 6.0 bcf of natural gas, was $15,787, $54,658 and $28,633, respectively. In conjunction with the SCAAs, at June 30, 2012, September 30, 2011 and June 30, 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.

6. 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:

	June 30, 2012		September 30, 2011		June 30, 2011
Regulatory assets:
Income taxes recoverable	$	99,891	$	97,947	$	92,695
Underfunded pension and postretirement plans	144,613		150,669		116,003
Environmental costs	16,562		19,547		20,712
Deferred fuel and power costs	9,829		12,163		7,836
Removal costs, net	11,840		12,313		11,240
Other	8,312		7,816		8,852
Total regulatory assets	$	291,047	$	300,455	$	257,338
Regulatory liabilities:
Postretirement benefits	$	12,342	$	11,476	$	11,558
Environmental overcollections	3,726		4,758		6,182
Deferred fuel and power refunds	10,324		6,578		22,451
State tax benefits — distribution system repairs	6,961		6,282		6,166
Other	625		736		—
Total regulatory liabilities	$	33,978	$	29,830	$	46,357

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 gains (losses) on such contracts at June 30, 2012, September 30, 2011 and June 30, 2011 were $280, $(3,081) and $(1,050), 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

mechanism. At June 30, 2012, September 30, 2011 and June 30, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $13,095, $8,655 and $10,082, 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 or losses on FTRs at June 30, 2012, September 30, 2011 and June 30, 2011 were not material.

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 “Incident”). On June 11, 2012, the PUC Bureau of Investigation and Enforcement (“PUC Staff”) issued a formal complaint (“PUC Staff Complaint”) alleging UGI Gas had committed six violations of gas safety regulations and UGI Gas' own operating procedures related to its cast iron main replacement and gas odorant monitoring programs, and its emergency response to the incident. In the PUC Staff Complaint, the PUC Staff recommended that the PUC assess a $386 fine against UGI Gas and require UGI Gas to institute several changes to its gas regulatory compliance program. On July 2, 2012, UGI Gas filed an answer to the PUC Staff Complaint in which UGI Gas expressed its belief that the PUC Staff's allegations were not supported factually and requested that the fines and other relief requested by the PUC Staff be denied. UGI Gas expressed its willingness to continue its cooperation with the Commission and the PUC Staff to implement enhancements to its gas safety programs, and identified several improvements already implemented since the Incident occurred.

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.

7. 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:

- 10 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	1,756		$	1,751		$	43		$	54
Interest cost	5,594			5,564			165			182
Expected return on assets	(5,940		)	(5,972		)	(127		)	(131		)
Amortization of:
Prior service cost (benefit)	62			80			(105		)	(174		)
Actuarial loss	1,963			1,570			99			122
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
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	5,269		$	5,426		$	129		$	161
Interest cost	16,782			16,483			497			547
Expected return on assets	(17,822		)	(17,965		)	(380		)	(392		)
Amortization of:
Prior service cost (benefit)	187			222			(317		)	(522		)
Actuarial loss	5,890			5,268			296			364
Net benefit cost	10,306			9,434			225			158
Change in associated regulatory liabilities	—			—			2,353			2,356
Net expense	$	10,306		$	9,434		$	2,578		$	2,514

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 $23,700 to the Pension Plan during the next twelve months. During the nine months endedJune 30, 2012 and 2011, the Company made contributions to the Pension Plan of $25,442 and $16,682, 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 nine months endedJune 30, 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.

8. 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 June 30, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $15,820 and $20,121, 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 June 30, 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.

Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserted that the plant operated from 1855 to 1954 and alleged that, through control of a subsidiary that owned the plant, UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserted that it has spent approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating to the site and estimated that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. On April 11, 2012, the District Court entered a judgment in favor of UGI Utilities. The appeal period has expired and the District Court's decision is final.

Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court's decision to the United States Court of Appeals for the First Circuit. On May 8, 2012, Frontier's appeal was voluntarily dismissed.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 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, Connecticut (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s 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. UGI Utilities responded to the EPA's information request on January 17, 2012 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 “Incident”).

UGI Utilities has received more than one hundred property claims and a handful of personal injury and wrongful death claims in connection with the Incident. Many of the claims, including three wrongful death claims, several personal injury claims and more than 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. A second lawsuit, in which the property insurer for the Cruz residence and two other properties seeks compensation for the property damaged or destroyed in the Incident, has been filed in the Court of Common Pleas for Lehigh County. UGI Utilities maintains liability insurance for personal injury, wrongful death, property and casualty damages and believes that third-party claims

- 13 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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.

9. 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 June 30, 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 $8,396 and $13,726 during the three and nine months ended June 30, 2012, respectively, and $16,566 and $19,156 during the three and nine months ended June 30, 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 June 30, 2012, September 30, 2011 and June 30, 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 June 30, 2012, comprising approximately 4.1 bcf of natural gas, was $10,512. 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 June 30, 2011, comprising approximately 4.0 bcf of natural gas, was $19,035.

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

- 14 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the nine months ended June 30, 2012 totaled $30,752. During the nine months ended June 30, 2011, such transactions totaled $30,093. There were no such transactions during the three months ended June 30, 2012 or 2011.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2012, revenues associated with such sales to Energy Services totaled $12,067 and $52,744, respectively. During the three and nine months ended June 30, 2011, such revenues totaled $13,529 and $74,589, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity 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 nine months ended June 30, 2012, the aggregate amount of such purchases totaled $13,158 and $36,477, respectively. During the three and nine months ended June 30, 2011, such purchases totaled $9,351 and $44,849, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

10. Fair Value Measurements

Derivative Financial Instruments

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

- 15 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)
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	)
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	128		$	201		$	—	$	329
Interest rate contracts	—			5,047			—		$	5,047
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,330	)	$	(8,802	)	$	—	$	(11,132	)

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 June 30, 2012 were $640,000 and $742,165, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2011 were $640,000 and $715,954, 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).

- 16 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

11. 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 June 30, 2012 and 2011, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 13.2 million dekatherms and 18.6 million dekatherms, respectively. At June 30, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB's guidance in 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 June 30, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13,095 and $10,082, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2012 and 2011, the volumes of Electric Utility's forward electricity purchase contracts was 654.7 million kilowatt hours and 874.4 million kilowatt hours, respectively. At June 30, 2012, the maximum period over which these contracts extend is 23 months.

In order to reduce volatility associated with a substantial portion of its 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 June 30, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 261.0 million kilowatt hours and 287.3 million kilowatt hours, respectively. At June 30, 2012, the maximum period over which we are hedging electricity congestion with FTRs is 11 months.

- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 June 30, 2012 and 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 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements Income. The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness was not material for all periods presented.

At June 30, 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 $899.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At June 30, 2012 and 2011, restricted cash in brokerage accounts totaled $1,604 and $4,055, respectively.

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

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	June 30, 2012		June 30, 2011		Location	June 30, 2012			June 30, 2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	—	$	5,047	Other noncurrent liabilities	$	(28,917	)	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	545		201		Derivative financial instruments and Other noncurrent liabilities	(13,539		)	(11,132		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	—		128		Derivative financial instruments	(17		)	—
Total Derivatives		$	545	$	5,376		$	(42,473	)	$	(11,132	)

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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

Three Months EndedJune 30,:

	Gain (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	$	(11,573	)	$	(2,779	)	$	(484	)	$	(291	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(127	)	$	(3	)							Operating expenses

Nine Months EndedJune 30,:

	Gain (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	$	(10,147	)	$	(5,047	)	$	(1,748	)	$	(873	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	78		$	348								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 that 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2012 (“2012 three-month period”) with the three months ended June 30, 2011 (“2011 three-month period”) and the nine months ended June 30, 2012 ("2012 nine-month period") with the nine months ended June 30, 2011 ("2011 nine-month period"). Our analyses of results of operations should be read in conjunction with the segment information included in Note 4 to the condensed consolidated financial statements.

2012 three-month period compared with 2011 three-month period

							Increase
Three Months Ended June 30,	2012			2011			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	122.3		$	148.1		$	(25.8	)	(17.4	)%
Total margin (a)	$	70.9		$	69.3		$	1.6		2.3	%
Operating income	$	22.5		$	17.2		$	5.3		30.8	%
Income before income taxes	$	12.6		$	7.3		$	5.3		72.6	%
System throughput - bcf
Core market	8.3			8.5			(0.2		)	(2.4	)%
Total	36.2			33.4			2.8			8.4	%
Heating degree days — % (warmer) colder than normal (b)	(19.0		)%	(17.3		)%	—			—
Electric Utility:
Revenues	$	20.8		$	24.0		$	(3.2	)	(13.3	)%
Total margin (a)	$	8.4		$	8.1		$	0.3		3.7	%
Operating income	$	2.6		$	2.4		$	0.2		8.3	%
Income before income taxes	$	1.9		$	1.8		$	0.1		5.6	%
Distribution sales — gwh	221.4			224.7			(3.3		)	(1.5	)%

bcf — billions of cubic feet. gwh — millions of kilowatt-hours.

(a) Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.1 million and $1.4 million during the three-month periods ended June 30, 2012 and 2011, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.

(b) Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in the Gas Utility service territory in the 2012 three-month period based upon heating degree days were 19.0% warmer than normal and modestly warmer than the prior-year period. Total distribution system throughput was above the prior-year, notwithstanding the warmer weather, principally reflecting greater throughput to certain non-weather-sensitive low-margin interruptible delivery service customers. Gas Utility system throughput to core market customers was slightly below last year principally reflecting the effects of the warmer weather and the effects of an early end to the 2012 heating season as temperatures in March 2012 averaged 38% warmer than normal. Gas Utility's core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues decreased $25.8 million during the 2012 three-month period principally reflecting lower revenues from off-system sales ($16.0 million) and a decline in revenues from retail core market customers ($12.6 million). The decrease in retail core market revenues principally reflects the effects on gas cost recovery revenues of lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($7.9 million) and, to a lesser extent, lower retail core-market volumes ($4.1 million). Under Gas Utility's PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred

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UGI UTILITIES, INC. AND SUBSIDIARIES

on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility's cost of gas was $51.4 million in the 2012 three-month period compared with $78.8 million in the prior-year period principally reflecting the lower off-system sales ($16.0 million), lower average PGC rates ($7.9 million) and the slightly lower retail core market volumes.

Gas Utility total margin increased $1.6 million in the 2012 three-month period. The increase principally reflects higher core market margin ($1.2 million) and higher delivery service total margin ($0.5 million). Gas Utility total margin in the current-year period includes incremental margin from the August 2011 base rate increase at CPG Gas.

The increases in Gas Utility operating income and income before income taxes during the 2012 three-month period principally reflects the increase in total margin ($1.6 million) and lower operating and administrative expenses including lower customer accounts and employee benefits expenses and lower required injuries and damages accruals.

Electric Utility. Electric Utility’s kilowatt-hour sales in the 2012 three-month period were 1.5% lower than the prior-year three-month period while Electric Utility revenues declined 13.3%. The decline in revenues is principally the result of lower average Default Service (“DS”) rates reflecting the pass through of lower electricity costs. Electric Utility cost of sales declined to $11.3 million in the 2012 three-month period compared to $14.6 million in the 2011 three-month period principally reflecting the effects of the lower average DS rates.

Electric Utility total margin increased $0.3 million in the 2012 three-month period, notwithstanding the slightly lower sales, reflecting lower revenue-related gross receipts taxes resulting from the lower revenue.

Electric Utility 2012 three-month period operating income and income before income taxes increased principally reflecting the greater total margin ($0.3 million).

Interest Expense and Income Taxes. Our consolidated interest expense in the 2012three-month period was about equal to such amount for the prior-year period. Our effective income tax rate for the three months ended March 31, 2012 was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

2012nine-month period compared with 2011nine-month period

							Increase
Nine Months Ended June 30,	2012			2011			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	696.8		$	921.7		$	(224.9	)	(24.4	)%
Total margin (a)	$	326.2		$	359.4		$	(33.2	)	(9.2	)%
Operating income	$	168.7		$	193.2		$	(24.5	)	(12.7	)%
Income before income taxes	$	138.6		$	163.0		$	(24.4	)	(15.0	)%
System throughput - bcf
Core market	54.7			65.5			(10.8		)	(16.5	)%
Total	146.0			143.5			2.5			1.7	%
Heating degree days — % (warmer) colder than normal (b)	(16.6		)%	4.2		%	—			—
Electric Utility:
Revenues	$	71.9		$	84.7		$	(12.8	)	(15.1	)%
Total margin (a)	$	26.1		$	26.5		$	(0.4	)	(1.5	)%
Operating income	$	9.1		$	9.0		$	0.1		1.1	%
Income before income taxes	$	7.4		$	7.3		$	0.1		1.4	%
Distribution sales — gwh	724.0			754.2			(30.2		)	(4.0	)%

bcf — billions of cubic feet. gwh — millions of kilowatt-hours.

(a) Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total

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UGI UTILITIES, INC. AND SUBSIDIARIES

revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $4.0 million and $4.8 million during the nine-month periods ended June 30, 2012 and 2011, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.

(b) Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in the Gas Utility service territory in the 2012 nine-month period based upon heating degree days were 16.6% warmer than normal and approximately 19.6% warmer than the prior-year period. Total distribution system throughput was about equal to last year, notwithstanding the significantly warmer weather, principally reflecting greater throughput to certain non-weather-sensitive low-margin interruptible delivery service customers. Excluding total volumes to interruptible delivery service customers, Gas Utility system throughput declined 14.3 bcf in the 2012 nine-month period principally reflecting the effects of the significantly warmer weather on throughput to core market customers (10.8 bcf) and lower firm delivery service volumes.

Gas Utility revenues decreased $224.9 million during the 2012 nine-month period principally reflecting a decline in revenues from retail core market customers ($154.3 million) and lower revenues from off-system sales ($63.3 million). The decrease in retail core market revenues principally reflects the effects on gas cost recovery revenues of the lower retail core market volumes ($86.2 million) and lower average PGC rates resulting from lower natural gas prices ($38.1 million). Gas Utility's cost of gas was $370.6 million in the 2012 nine-month period compared with $562.3 million in the prior-year period reflecting the previously mentioned lower retail core-market sales ($86.2 million), the lower average PGC rates ($38.1 million) and the lower off-system sales.

Gas Utility total margin decreased $33.2 million in the 2012 nine-month period. The decrease principally reflects a decrease in core market margin ($25.9 million) and lower firm delivery service total margin ($5.8 million). Gas Utility total margin in the current-year period includes incremental margin from the August 2011 base rate increase at CPG Gas.

The decreases in Gas Utility operating income and income before income taxes during the 2012 nine-month period principally reflects the previously mentioned decrease in total margin ($33.2 million) partially offset by lower operating and administrative expenses.

Electric Utility. Electric Utility's kilowatt-hour sales in the 2012 nine-month period were 4.0% lower than in the prior-year nine-month period on heating degree day weather that was 19.4% warmer. The warmer weather reduced sales to Electric Utility heating customers. Electric Utility revenues were $12.8 million less than the prior year principally as a result of lower average DS rates and, to a lesser extent, the lower sales volumes. Electric Utility cost of sales declined to $41.8 million in the 2012 nine-month period compared to $53.4 million in the 2011 nine-month period principally reflecting the effects of the lower average DS rates in the current-year period and, to a lesser extent, the effects of the lower sales.

Electric Utility total margin declined $0.4 million in the 2012 nine-month period principally the result of the lower sales partially offset by lower revenue-related gross receipts taxes. Electric Utility 2012 nine-month period operating income and income before income taxes were slightly greater than the prior year as the lower total margin was more than offset by lower operating and administrative expenses.

Interest Expense and Income Taxes. Our consolidated interest expense was about equal to such amounts for the prior-year period. Our effective income tax rate for the nine months ended June 30, 2012 was slightly higher than in the prior-year period as the prior-year period reflected the regulatory effects of greater state tax depreciation.

Regulatory Matters

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 incremental operating margin. 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2012 and September 30, 2011 was $640 million. UGI Utilities' total debt outstanding at June 30, 2012 comprises $383 million of Senior Notes and $257 million of Medium-Term Notes. There were no amounts outstanding under UGI Utilities 2011 Credit Agreement at June 30, 2012 or September 30, 2011.

UGI Utilities may borrow up to a total of $300 million under the UGI Utilities 2011 Credit Agreement. The UGI Utilities 2011 Credit Agreement expires in October 2015. During the 2012 and 2011 nine-month periods, average daily bank loan borrowings were $21.3 million and $23.5 million, respectively, and peak bank loan borrowings totaled $70.6 million and $90 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the UGI Utilities 2011 Credit Agreement, UGI Utilities' management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2012.

Cash Flows

Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from our operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas and electricity consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under the UGI Utilities 2011 Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $202.6 million in the 2012 nine-month period compared to cash provided by operating activities of $235.7 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital was $142.5 million in the 2012 nine-month period compared to $182.9 million recorded in the prior-year nine-month period principally reflecting the lower 2012 nine-month period operating results. Changes in operating working capital provided $60.1 million of operating cash flow during the 2012 nine-month period compared to $52.8 million provided during the prior-year nine-month period. The increase in cash provided by changes in operating working capital in the 2012 nine-month period reflects, among other things, lower cash required to fund changes in accounts receivable, principally resulting from the lower sales and lower natural gas costs, and the timing of payments for income taxes. These increases were partially offset by greater cash used to fund changes in accounts payable and lower cash from deferred fuel recoveries.

Investing activities. Cash used by investing activities was $79.4 million in the 2012 nine-month period compared to $60.4 million in the 2011 nine-month period. Total capital expenditures were $79.7 million in the 2012 nine-month period compared with $59.6 million recorded in the prior-year period. The 2012 nine-month period principally reflects higher UGI Gas capital expenditures.

Financing activities. Cash used by financing activities was $54.5 million in the 2012 nine-month period compared with cash used by financing activities of $70.7 million in the 2011 nine-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our revolving credit agreements, cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI totaling $54.8 million and $54.4 million during the 2012 and 2011 nine-month periods, respectively. During the 2012 nine-month period there were no net bank loan borrowings compared with net bank loan repayments of $17.0 million during the prior-year nine-month period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At June 30,

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UGI UTILITIES, INC. AND SUBSIDIARIES

2012 and 2011, Gas Utility had $1.6 million and $4.1 million, respectively, of restricted cash associated with natural gas futures and option accounts with brokers. At June 30, 2012 and 2011, the fair values of our natural gas futures and option contracts were gains (losses) of $0.3 million and $(1.1) million, respectively.

Electric Utility’s DS tariffs contain clauses that permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. FTRs are 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 electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At June 30, 2012 and 2011, the fair values of FTRs were not material.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair values of unsettled IRPAs held at June 30, 2012 and 2011 were a (loss) gain of $(28.9) million and $5.0 million, respectively. A hypothetical 10% adverse change in the three-month LIBOR would result in a decrease in fair value of $3.6 million at June 30, 2012.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at June 30, 2012 and 2011 were not material.

Our unsettled derivative instruments at June 30, 2012 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward purchase contracts, which are included in Electric Utility’s DS recovery mechanism; (3) IRPAs; and (4) exchange-traded gasoline futures and swap contracts.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

(b) Change in Internal Control over Financial Reporting

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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UGI UTILITIES, INC. AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

ITEM 1A. Risk Factors

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows:

Exhibit No.	Exhibit
10.1	Service Agreement For Use Under Seller's GSS Rate Schedule dated July 9, 2012 between Transcontinental Gas Pipe Line Company, LLC and UGI Penn Natural Gas, Inc.
12.1	Computation of ratio of earnings to fixed charges
31.1	Certification by the Chief Executive Officer relating to the Registrant's Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL.Instance
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Labels Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

*XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.

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UGI UTILITIES, INC. AND SUBSIDIARIES

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		UGI Utilities, Inc. (Registrant)
Date:	August 8, 2012	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President — Finance and Chief Financial Officer   (Principal Financial Officer)
Date:	August 8, 2012	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller  (Principal Accounting Officer)

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	Service Agreement For Use Under Seller's GSS Rate Schedule dated July 9, 2012 between Transcontinental Gas Pipe Line Company, LLC and UGI Penn Natural Gas, Inc.
12.1	Computation of ratio of earnings to fixed charges
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2012, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL.Instance
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Labels Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

*XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.

- 30 -

EX-10.EX-10.1

Exhibit 10.1

FORM OF SERVICE AGREEMENT

(For Use Under Seller's GSS Rate Schedule)

THIS AGREEMENT entered into this 9 day of July, 2012, by and between TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC, a Delaware limited liability company, hereinafter referred to as “Seller”, first party, and UGI PENN NATURAL GAS, INC., hereinafter referred to as “Buyer”, second party,

WITNESSETH:

WHEREAS, Seller and Buyer (as successor to PG Energy, Inc.) are parties to that certain service agreement dated July 1, 1996, under Seller's Rate Schedule GSS, pursuant to which Seller provides natural gas storage service for Buyer ("Service Agreement"); and

WHEREAS, the primary term of the Service Agreement expires on March 31, 2013; and

WHEREAS, Seller's firm storage service under Rate Schedule GSS is supported, in part, by a contract storage service purchased from Dominion Transmission, Inc. ("DTI") pursuant to an agreement dated August 23, 1993 under DTI's Rate Schedule GSS ("DTI Storage Service Agreement"); and

WHEREAS, DTI and Seller have negotiated for an extension of the DTI Storage Service Agreement through March 31, 2023; and

WHEREAS, Seller and Buyer desire to continue the natural gas storage service under Rate Schedule GSS for a ten year term ending March 31, 2023 under the terms this agreement, which will supersede the Service Agreement effective April 1, 2013.

NOW, THEREFORE, Seller and Buyer agree as follows:

ARTICLE I

SERVICE TO BE RENDERED

Subject to the terms and provisions of this agreement and of Seller's Rate Schedule GSS, Seller agrees to receive from Buyer for storage, inject into storage for Buyer's account, store, withdraw from storage (or cause to be injected into storage for Buyer's account, stored, and withdrawn from storage) and deliver to Buyer, quantities of natural gas as follows:

To withdraw from storage or cause to be withdrawn from storage, the gas stored for Buyer's account up to a maximum quantity in any day of 56,532 dt, which quantity shall be Buyer's Storage Demand.

To receive and store or cause to be stored up to a total quantity at any one time of 2,746,576 dt, which quantity shall be Buyer's Storage Capacity Quantity.

ARTICLE II

POINT OF DELIVERY

The Point or Points of Delivery for all natural gas delivered by Seller to Buyer under this agreement shall be at or near:

(1) Dallas Meter Station, located at the intersection of State Route #115 and Leidy Line on south side of road adjacent to Natona

Mills, western edge of Dallas, Luzerne County, Pennsylvania.

(2) Saylor Meter Station, located at junction of Saylor Avenue and Transco Pipeline, Plains Township, Luzerne County, Pennsylvania.

(3) Wyoming Monument Meter Station, located on Seller's Leidy Line near Wyoming, Luzerne County, Pennsylvania.

(4) Muncy Meter Station, located at a point of connection of Seller's Leidy Line and Buyer's facilities near Muncy, Lycoming County, Pennsylvania.

(5) Old Lycoming Meter Station, located at a point of connection of Seller's Leidy Line and Buyer's facilities near the intersection of Legislative Route No. 41033 and Route 410 in Lycoming County, Pennsylvania.

(6) Shickshinny Meter Station, located at a point of connection on Seller's Leidy Line and Buyer's facilities near Salem Township, Luzerne County, Pennsylvania.

ARTICLE Ill

DELIVERY PRESSURE

Seller shall deliver natural gas to Buyer at the Point(s) of Delivery at a pressure(s) of: not less than fifty (5O) pounds per square inch gauge, or at such other pressures as may be agreed upon in the day-to­ day operations of Buyer and Seller.

ARTICLE IV

TERM OF AGREEMENT

This agreement shall be effective April 1, 2013 and shall remain in force and effect for a period ending March 31, 2023.

ARTICLE V

RATE SCHEDULE AND PRICE

Buyer shall pay Seller for natural gas service rendered hereunder in accordance with Seller's Rate Schedule GSS and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be amended or superseded from time to time at the initiative of either party. Such rate schedule and General Terms and Conditions are by this reference made a part hereof.

ARTICLE VI MISCELLANEOUS

1. The subject headings of the Articles of this agreement are inserted for the purpose of convenient reference and are not intended to be a part of this agreement nor to be considered in any interpretation of the same.

2. This agreement supersedes and cancels as of the effective date hereof the following contracts: Service agreement dated July 1, 1996.

3. No waiver by either party of anyone or more defaults by the other in the performance of any provisions of this

agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.

4. This agreement shall be interpreted, performed and enforced in accordance with the laws of the State of Texas.

5. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.

6. Notices to either party may be in writing or by telecopy or telephone and shall be considered as duly delivered to the other party at the following address:

(a) If to Seller:

Transcontinental Gas Pipe Line Company, LLC

P. 0. Box 1396

Houston, Texas 77251

Attention: Director, Customer Services

(b) If to Buyer:

UGI PENN NATURAL GAS, INC.

2525 N. 12th Street, Suite 360

Reading, PA 19605

Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party.

IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Seller)

By /s/ Paul F. Egner III_______________

Print Name Paul F. Egner Ill

Title Director, Customer Services

UGI PENN NATURAL GAS, INC.

(Buyer)

By /s/ Robert F. Beard_______________

Print Name Robert F. Beard

Title President and CEO

EX-12.EX 12.1

UGI UTILITIES INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Nine Months Ended June 30,
			Year Ended September 30,
	2012		2011		2010		2009		2008		2007
Earnings:
Earnings before income taxes	$	146,493	$	168,693	$	147,183	$	125,554	$	123,977	$	122,766
Interest expense	31,859		42,728		42,336		43,918		39,065		42,327
Amortization of debt discount and
expense	595		1,060		627		625		467		462
Estimated interest component of
rental expense	1,507		1,740		1,912		1,965		1,619		1,506
	$	180,454	$	214,221	$	192,058	$	172,062	$	165,128	$	167,061
Fixed Charges:
Interest expense	$	31,859	$	42,728	$	42,336	$	43,918	$	39,065	$	42,327
Amortization of debt discount and
expense	595		1,060		627		625		467		462
Allowance for funds used during
construction (capitalized interest)	7		90		74		160		139		179
Estimated interest component of
rental expense	1,507		1,740		1,912		1,965		1,619		1,506
	$	33,968	$	45,618	$	44,949	$	46,668	$	41,290	$	44,474
Ratio of earnings to fixed charges	5.31		4.70		4.27		3.69		4.00		3.76

EX-31.EX 31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert F. Beard, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2012

/s/ Robert F. Beard

Robert F. Beard

President and Chief Executive Officer

EX-31.EX 31.2

EXHIBIT 31.2

CERTIFICATION

I, Donald E. Brown, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2012

/s/ Donald E. Brown

Donald E. Brown

Vice President - Finance and Chief Financial Officer

EX-32.EX 32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

I, Robert F. Beard, Chief Executive Officer, and I, Donald E. Brown, Chief Financial Officer, of UGI Utilities, Inc., a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:

(1) The Company’s periodic report on Form 10-Q for the period ended June 30, 2012 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ Robert F. Beard		/s/ Donald E. Brown
Robert F. Beard		Donald E. Brown
Date:	August 8, 2012	Date:	August 8, 2012

XML

Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Jun. 30, 2011
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 545	$ 5,376
Total Derivatives Liability	(42,473)	(11,132)
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Other assets [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	0	5,047
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Other noncurrent liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(28,917)	0
Commodity contracts [Member] | Derivatives Accounted for Under ACS 980 [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	545	201
Commodity contracts [Member] | Derivatives Accounted for Under ACS 980 [Member] | Derivative financial instruments and other noncurrent liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(13,539)	(11,132)
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	0	128
Total Derivatives Liability	$ (17)	$ 0

XML

Defined Benefit Pension and Other Postretirement Plans Textual (Details) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to pensions plans in next twelve months	$ 23,700
Contribution made to Pension Plan	$ 25,442	$ 16,682

XML

Disclosures About Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Balance sheet location and fair value of derivative assets and liabilities

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

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	June 30, 2012		June 30, 2011		Location	June 30, 2012			June 30, 2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	—	$	5,047	Other noncurrent liabilities	$	(28,917	)	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	545		201		Derivative financial instruments and Other noncurrent liabilities	(13,539		)	(11,132		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	—		128		Derivative financial instruments	(17		)	—
Total Derivatives		$	545	$	5,376		$	(42,473	)	$	(11,132	)

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

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

Three Months EndedJune 30,:

	Gain (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	$	(11,573	)	$	(2,779	)	$	(484	)	$	(291	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(127	)	$	(3	)							Operating expenses

Nine Months EndedJune 30,:

	Gain (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	$	(10,147	)	$	(5,047	)	$	(1,748	)	$	(873	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	78		$	348								Operating expenses/ other income, net

XML

Fair Value Measurements Textual (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Jun. 30, 2011
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 640,000	$ 640,000
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 742,165	$ 715,954

XML

Significant Accounting Policies

9 Months Ended

Jun. 30, 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 that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2011 condensed consolidated balance sheet data was derived from audited financial statements but 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 that 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 nine months ended June 30, 2012.

Reclassifications. Removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the June 30, 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.

XML

Inventories Textual (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012 ft3	Sep. 30, 2011 ft3	Jun. 30, 2011 ft3
Inventory, Net [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	6,000,000,000	11,500,000,000	6,000,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 15,787	$ 54,658	$ 28,633
SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	3
SCAAs [Member] | Other current liabilities [Member]
Inventory, Net [Abstract]
Security Deposit Liability	$ 22,500	$ 22,500	$ 22,500
Expires in October 2012 [Member] | SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	2
Expires in October 2013 [Member] | SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	1

XML

Inventories (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Inventory, Net [Abstract]
Total inventories	$ 38,413	$ 104,263	$ 58,751
Gas Utility Natural Gas [Member]
Inventory, Net [Abstract]
Total inventories	27,761	95,590	50,082
Materials, Supplies and Other [Member]
Inventory, Net [Abstract]
Total inventories	$ 10,652	$ 8,673	$ 8,669

XML

Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 291,047	$ 300,455	$ 257,338
Regulatory Liabilities	33,978	29,830	46,357
Postretirement benefits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	12,342	11,476	11,558
Environmental overcollections [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	3,726	4,758	6,182
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	10,324	6,578	22,451
State tax benefits -- distribution system repairs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	6,961	6,282	6,166
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	625	736	0
Income taxes recoverable [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	99,891	97,947	92,695
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	144,613	150,669	116,003
Environmental costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	16,562	19,547	20,712
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	9,829	12,163	7,836
Removal costs, net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	11,840	12,313	11,240
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 8,312	$ 7,816	$ 8,852

XML

Regulatory Assets and Liabilities and Regulatory Matters Textual (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended		9 Months Ended		12 Months Ended
	Jun. 30, 2012 Y Utility	Jun. 30, 2011	Jun. 30, 2012 Deferral Fuel and Power [Member]	Jun. 30, 2011 Deferral Fuel and Power [Member]	Sep. 30, 2011 Deferral Fuel and Power [Member]	Jun. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Sep. 30, 2011 Electric Utility Electric Supply Contracts [Member]	Jun. 30, 2011 Electric Utility Electric Supply Contracts [Member]	Jun. 11, 2011 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Violation	Feb. 09, 2011 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Persons
Regulatory Assets [Line Items]
Unrealized gains (losses) on derivative financial instrument contracts			$ 280	$ (1,050)	$ (3,081)
Fair value of electric utility electricity supply contracts	42,473	11,132				13,095	8,655	10,082
Deaths from natural gas explosion (in persons)										5
Number of alleged committed violations of gas safety regulations and own operating procedures (in violations)									6
Estimate of possible loss									$ 386
Maximum Percentage of Incremental Operating Margin Traditional Ratemaking (as a percent)	5.00%
Number of years to be eligible for a distribution system improvement charge a utility must have filed a general rate filing (in years)	5
Number of regulated utilities on which there is potential effect of legislation (in years)	4

XML

Nature of Operations

9 Months Ended

Jun. 30, 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.

XML

Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 1,756	$ 1,751	$ 5,269	$ 5,426
Interest cost	5,594	5,564	16,782	16,483
Expected return on assets	(5,940)	(5,972)	(17,822)	(17,965)
Amortization of:
Prior service cost (benefit)	62	80	187	222
Actuarial loss	1,963	1,570	5,890	5,268
Net benefit cost	3,435	2,993	10,306	9,434
Change in associated regulatory liabilities	0	0	0	0
Net expense	3,435	2,993	10,306	9,434
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	43	54	129	161
Interest cost	165	182	497	547
Expected return on assets	(127)	(131)	(380)	(392)
Amortization of:
Prior service cost (benefit)	(105)	(174)	(317)	(522)
Actuarial loss	99	122	296	364
Net benefit cost	75	53	225	158
Change in associated regulatory liabilities	784	785	2,353	2,356
Net expense	$ 859	$ 838	$ 2,578	$ 2,514

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Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Interest rate contracts [Member] | Interest expense/other income, net [Member] | Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain or (loss) recognized in AOCI	$ (11,573)	$ (2,779)	$ (10,147)	$ (5,047)
Gain (loss) reclassified from AOCI into income	(484)	(291)	(1,748)	(873)
Derivatives Not Designated as Hedging Instruments [Member] | Commodity contracts [Member] | Operating expenses [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (Loss) recognized in income	(127)	(3)
Derivatives Not Designated as Hedging Instruments [Member] | Commodity contracts [Member] | Operating expenses/other income, net [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (Loss) recognized in income			$ 78	$ 348

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Current assets:
Cash and cash equivalents	$ 75,969	$ 7,267	$ 108,914
Restricted cash	1,604	4,308	4,055
Accounts receivable (less allowances for doubtful accounts of $7,457, $6,368 and $12,927, respectively)	61,072	58,736	87,858
Accounts receivable — related parties	4,311	7,048	4,277
Accrued utility revenues	14,970	14,807	7,417
Inventories	38,413	104,263	58,751
Deferred income taxes	33,595	42,528	32,302
Regulatory assets	2,681	8,608	2,037
Derivative financial instruments	545	68	329
Prepaid expenses & other current assets	17,890	24,911	15,490
Total current assets	251,050	272,544	321,430
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $809,458, $782,665 and $777,773, respectively)	1,458,654	1,418,356	1,393,010
Goodwill	182,145	182,145	180,145
Regulatory assets	288,366	291,847	255,301
Other assets	5,630	4,456	8,678
Total assets	2,185,845	2,169,348	2,158,564
Current liabilities:
Current maturities of long-term debt	40,000	40,000	0
Accounts payable	30,457	53,556	41,487
Accounts payable — related parties	10,175	10,108	9,260
Deferred fuel refunds	10,325	6,578	22,451
Derivative financial instruments	7,150	11,928	5,334
Other current liabilities	144,492	140,849	142,797
Total current liabilities	242,599	263,019	221,329
Long-term debt	600,000	600,000	640,000
Deferred income taxes	371,388	361,468	327,039
Deferred investment tax credits	4,698	4,958	5,046
Pension and postretirement benefit obligations	126,007	142,248	113,235
Other noncurrent liabilities	92,409	78,810	69,898
Total liabilities	1,437,101	1,450,503	1,376,547
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	468,630	468,323	468,323
Retained earnings	246,286	212,096	259,307
Accumulated other comprehensive loss	(26,431)	(21,833)	(5,872)
Total common stockholder’s equity	748,744	718,845	782,017
Total liabilities and stockholder’s equity	$ 2,185,845	$ 2,169,348	$ 2,158,564

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Tax on (loss) gain on derivative instruments	$ 4,801	$ 913	$ 4,209	$ (2,094)
Tax on reclassifications of net losses (gains) on derivative instruments	(201)	(120)	(725)	(362)
Tax on benefit plans	$ (80)	$ 0	$ (242)	$ (1,461)

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended					3 Months Ended		9 Months Ended					9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Energy Services [Member]	Jun. 30, 2011 Energy Services [Member]	Jun. 30, 2012 Energy Services [Member]	Jun. 30, 2011 Energy Services [Member]	Jun. 30, 2012 Inventories [Member] Energy Services [Member] ft3	Sep. 30, 2011 Inventories [Member] Energy Services [Member] ft3	Jun. 30, 2011 Inventories [Member] Energy Services [Member] ft3	Jun. 30, 2012 SCAAs [Member] Energy Services [Member]	Jun. 30, 2011 SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 SCAAs [Member] Energy Services [Member]	Jun. 30, 2011 SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Sep. 30, 2011 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Jun. 30, 2011 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Jun. 30, 2012 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Jun. 30, 2011 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]
Related Party Transaction [Line Items]
Related party costs incurred	$ 2,107	$ 1,747	$ 7,013	$ 10,595								$ 8,396	$ 16,566	$ 13,726	$ 19,156				$ 30,752	$ 30,093
Related party security deposits																15,000	15,000	15,000
Volume of gas storage inventory (in bcf of natural gas)									4,100,000,000	7,500,000,000	4,000,000,000
Natural gas storage inventory, related parties, current									10,512	35,686	19,035
Revenue from related parties					12,067	13,529	52,744	74,589
Purchases from related party					$ 13,158	$ 9,351	$ 36,477	$ 44,849

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

9 Months Ended

Jun. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory assets and liabilities associated with Gas Utility and Electric Utility

The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30, 2012		September 30, 2011		June 30, 2011
Regulatory assets:
Income taxes recoverable	$	99,891	$	97,947	$	92,695
Underfunded pension and postretirement plans	144,613		150,669		116,003
Environmental costs	16,562		19,547		20,712
Deferred fuel and power costs	9,829		12,163		7,836
Removal costs, net	11,840		12,313		11,240
Other	8,312		7,816		8,852
Total regulatory assets	$	291,047	$	300,455	$	257,338
Regulatory liabilities:
Postretirement benefits	$	12,342	$	11,476	$	11,558
Environmental overcollections	3,726		4,758		6,182
Deferred fuel and power refunds	10,324		6,578		22,451
State tax benefits — distribution system repairs	6,961		6,282		6,166
Other	625		736		—
Total regulatory liabilities	$	33,978	$	29,830	$	46,357

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Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 545	$ 68	$ 329
Derivative financial instruments, liabilities	(13,556)	(11,736)	(11,132)
Commodity contracts [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	545	27	128
Derivative financial instruments, liabilities	(1,457)	(4,102)	(2,330)
Commodity contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	41	201
Derivative financial instruments, liabilities	(12,099)	(7,634)	(8,802)
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			5,047
Derivative financial instruments, liabilities	(28,917)	(18,585)
Interest rate contracts [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			0
Derivative financial instruments, liabilities	0	0
Interest rate contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			5,047
Derivative financial instruments, liabilities	$ (28,917)	$ (18,585)

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Fair Value Measurements (Tables)

9 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

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

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

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)
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	)
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	128		$	201		$	—	$	329
Interest rate contracts	—			5,047			—		$	5,047
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,330	)	$	(8,802	)	$	—	$	(11,132	)

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 88,999	$ 106,715
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	39,424	39,243
Deferred income taxes, net	21,269	18,700
Provision for uncollectible accounts	5,592	9,495
Other, net	(12,809)	8,712
Net change in:
Accounts receivable and accrued utility revenues	(5,354)	(23,902)
Inventories	65,850	60,107
Deferred fuel and power costs	8,133	32,951
Accounts payable	(23,032)	(3,688)
Other current assets	7,059	5,340
Other current liabilities	7,467	(17,988)
Net cash provided by operating activities	202,598	235,685
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(79,698)	(59,590)
Net costs of property, plant and equipment disposals	(2,400)	(1,414)
Decrease in restricted cash	2,704	643
Net cash used by investing activities	(79,394)	(60,361)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(54,809)	(54,419)
Decrease in bank loans	0	(17,000)
Other	307	691
Net cash used by financing activities	(54,502)	(70,728)
Cash and cash equivalents increase	68,702	104,596
CASH AND CASH EQUIVALENTS:
End of period	75,969	108,914
Beginning of period	7,267	4,318
Increase	$ 68,702	$ 104,596

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Allowance for doubtful accounts on accounts receivable	$ 7,457	$ 6,368	$ 12,927
Accumulated depreciation and amortization on property, plant and equipment	$ 809,458	$ 782,665	$ 777,773
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

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Fair Value Measurements

9 Months Ended

Jun. 30, 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 June 30, 2012, September 30, 2011 and June 30, 2011:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)
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	)
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	128		$	201		$	—	$	329
Interest rate contracts	—			5,047			—		$	5,047
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,330	)	$	(8,802	)	$	—	$	(11,132	)

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 June 30, 2012 were $640,000 and $742,165, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2011 were $640,000 and $715,954, 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).

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Document and Entity Information	9 Months Ended
	Jun. 30, 2012	Jul. 31, 2012
Entity Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity 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

XML

Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 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 June 30, 2012 and 2011, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 13.2 million dekatherms and 18.6 million dekatherms, respectively. At June 30, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB's guidance in 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 June 30, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13,095 and $10,082, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2012 and 2011, the volumes of Electric Utility's forward electricity purchase contracts was 654.7 million kilowatt hours and 874.4 million kilowatt hours, respectively. At June 30, 2012, the maximum period over which these contracts extend is 23 months.

In order to reduce volatility associated with a substantial portion of its 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 June 30, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 261.0 million kilowatt hours and 287.3 million kilowatt hours, respectively. At June 30, 2012, the maximum period over which we are hedging electricity congestion with FTRs is 11 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 June 30, 2012 and 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 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements Income. The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness was not material for all periods presented.

At June 30, 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 $899.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At June 30, 2012 and 2011, restricted cash in brokerage accounts totaled $1,604 and $4,055, respectively.

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

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	June 30, 2012		June 30, 2011		Location	June 30, 2012			June 30, 2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	—	$	5,047	Other noncurrent liabilities	$	(28,917	)	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	545		201		Derivative financial instruments and Other noncurrent liabilities	(13,539		)	(11,132		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	—		128		Derivative financial instruments	(17		)	—
Total Derivatives		$	545	$	5,376		$	(42,473	)	$	(11,132	)

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

Three Months EndedJune 30,:

	Gain (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	$	(11,573	)	$	(2,779	)	$	(484	)	$	(291	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(127	)	$	(3	)							Operating expenses

Nine Months EndedJune 30,:

	Gain (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	$	(10,147	)	$	(5,047	)	$	(1,748	)	$	(873	)	Interest expense/ other income, net
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	78		$	348								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 that 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.

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Condensed Consolidated Statements of Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Revenues	$ 143,644	$ 172,714	$ 770,087	$ 1,007,695
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	62,701	93,383	412,377	615,645
Operating and administrative expenses	37,689	42,910	124,380	134,103
Operating and administrative expenses - related parties	2,107	1,747	7,013	10,595
Taxes other than income taxes	3,919	3,523	12,903	13,350
Depreciation	12,425	12,058	37,132	37,347
Amortization	826	631	2,292	1,896
Other income, net	(1,323)	(1,024)	(4,362)	(7,716)
Total costs and expenses	118,344	153,228	591,735	805,220
Operating income	25,300	19,486	178,352	202,475
Interest expense	10,575	10,518	31,859	31,960
Income before income taxes	14,725	8,968	146,493	170,515
Income taxes	6,265	3,490	57,494	63,800
Net income	$ 8,460	$ 5,478	$ 88,999	$ 106,715

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Inventories

9 Months Ended

Jun. 30, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	June 30, 2012		September 30, 2011		June 30, 2011
Gas Utility natural gas	$	27,761	$	95,590	$	50,082
Materials, supplies and other	10,652		8,673		8,669
Total inventories	$	38,413	$	104,263	$	58,751

At June 30, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013 (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 June 30, 2012, September 30, 2011 and June 30, 2011 comprising 6.0 billion cubic feet (“bcf”), 11.5 bcf and 6.0 bcf of natural gas, was $15,787, $54,658 and $28,633, respectively. In conjunction with the SCAAs, at June 30, 2012, September 30, 2011 and June 30, 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.

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Segment Information

9 Months Ended

Jun. 30, 2012

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 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 EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

Three Months Ended June 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	172,714	$	148,104	$	24,022	$	588
Cost of sales	$	93,383	$	78,811	$	14,572	$	—
Depreciation and amortization	$	12,689	$	11,596	$	1,093	$	—
Operating income (loss)	$	19,486	$	17,171	$	2,432	$	(117	)
Interest expense	$	10,518	$	9,852	$	666	$	—
Income (loss) before income taxes	$	8,968	$	7,319	$	1,766	$	(117	)
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	21,932	$	20,902	$	1,030	$	—

Nine Months EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

Nine Months EndedJune 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	1,007,695	$	921,655	$	84,673	$	1,367
Cost of sales	$	615,645	$	562,251	$	53,394	$	—
Depreciation and amortization	$	39,243	$	36,126	$	3,117	$	—
Operating income	$	202,475	$	193,206	$	9,025	$	244
Interest expense	$	31,960	$	30,202	$	1,758	$	—
Income before income taxes	$	170,515	$	163,004	$	7,267	$	244
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	59,590	$	54,453	$	5,137	$	—

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Defined Benefit Pension and Other Postretirement Plans (Tables)

9 Months Ended

Jun. 30, 2012

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

Component of net periodic pension expense and other postretirement benefit costs

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
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	1,756		$	1,751		$	43		$	54
Interest cost	5,594			5,564			165			182
Expected return on assets	(5,940		)	(5,972		)	(127		)	(131		)
Amortization of:
Prior service cost (benefit)	62			80			(105		)	(174		)
Actuarial loss	1,963			1,570			99			122
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
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	5,269		$	5,426		$	129		$	161
Interest cost	16,782			16,483			497			547
Expected return on assets	(17,822		)	(17,965		)	(380		)	(392		)
Amortization of:
Prior service cost (benefit)	187			222			(317		)	(522		)
Actuarial loss	5,890			5,268			296			364
Net benefit cost	10,306			9,434			225			158
Change in associated regulatory liabilities	—			—			2,353			2,356
Net expense	$	10,306		$	9,434		$	2,578		$	2,514

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Significant Accounting Policies (Policies)

9 Months Ended

Jun. 30, 2012

Accounting Policies [Abstract]

Comprehensive Income

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. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts that 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 Tax

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 nine months ended June 30, 2012.

Reclassifications

Reclassifications. Removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet to conform to the current-period presentation.

Use of Estimates

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

Goodwill Impairment

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

Fair Value Measurements

Fair Value Measurements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments result in common fair value measurement and disclosure requirements in 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 became effective for our interim period ending March 31, 2012 and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.

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Commitments and Contingencies

9 Months Ended

Jun. 30, 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 June 30, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $15,820 and $20,121, 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 June 30, 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.

Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserted that the plant operated from 1855 to 1954 and alleged that, through control of a subsidiary that owned the plant, UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserted that it has spent approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating to the site and estimated that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. On April 11, 2012, the District Court entered a judgment in favor of UGI Utilities. The appeal period has expired and the District Court's decision is final.

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

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 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, Connecticut (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s 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. UGI Utilities responded to the EPA's information request on January 17, 2012 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 “Incident”).

UGI Utilities has received more than one hundred property claims and a handful of personal injury and wrongful death claims in connection with the Incident. Many of the claims, including three wrongful death claims, several personal injury claims and more than 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. A second lawsuit, in which the property insurer for the Cruz residence and two other properties seeks compensation for the property damaged or destroyed in the Incident, has been filed in the Court of Common Pleas for Lehigh County. 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.

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Regulatory Assets and Liabilities and Regulatory Matters

9 Months Ended

Jun. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

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:

	June 30, 2012		September 30, 2011		June 30, 2011
Regulatory assets:
Income taxes recoverable	$	99,891	$	97,947	$	92,695
Underfunded pension and postretirement plans	144,613		150,669		116,003
Environmental costs	16,562		19,547		20,712
Deferred fuel and power costs	9,829		12,163		7,836
Removal costs, net	11,840		12,313		11,240
Other	8,312		7,816		8,852
Total regulatory assets	$	291,047	$	300,455	$	257,338
Regulatory liabilities:
Postretirement benefits	$	12,342	$	11,476	$	11,558
Environmental overcollections	3,726		4,758		6,182
Deferred fuel and power refunds	10,324		6,578		22,451
State tax benefits — distribution system repairs	6,961		6,282		6,166
Other	625		736		—
Total regulatory liabilities	$	33,978	$	29,830	$	46,357

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 gains (losses) on such contracts at June 30, 2012, September 30, 2011 and June 30, 2011 were $280, $(3,081) and $(1,050), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility's DS recovery mechanism. At June 30, 2012, September 30, 2011 and June 30, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $13,095, $8,655 and $10,082, 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 or losses on FTRs at June 30, 2012, September 30, 2011 and June 30, 2011 were not material.

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 “Incident”). On June 11, 2012, the PUC Bureau of Investigation and Enforcement (“PUC Staff”) issued a formal complaint (“PUC Staff Complaint”) alleging UGI Gas had committed six violations of gas safety regulations and UGI Gas' own operating procedures related to its cast iron main replacement and gas odorant monitoring programs, and its emergency response to the incident. In the PUC Staff Complaint, the PUC Staff recommended that the PUC assess a $386 fine against UGI Gas and require UGI Gas to institute several changes to its gas regulatory compliance program. On July 2, 2012, UGI Gas filed an answer to the PUC Staff Complaint in which UGI Gas expressed its belief that the PUC Staff's allegations were not supported factually and requested that the fines and other relief requested by the PUC Staff be denied. UGI Gas expressed its willingness to continue its cooperation with the Commission and the PUC Staff to implement enhancements to its gas safety programs, and identified several improvements already implemented since the Incident occurred.

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.

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Defined Benefit Pension and Other Postretirement Plans

9 Months Ended

Jun. 30, 2012

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

Defined Benefit Pension and Other Postretirement Plans

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
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	1,756		$	1,751		$	43		$	54
Interest cost	5,594			5,564			165			182
Expected return on assets	(5,940		)	(5,972		)	(127		)	(131		)
Amortization of:
Prior service cost (benefit)	62			80			(105		)	(174		)
Actuarial loss	1,963			1,570			99			122
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
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Service cost	$	5,269		$	5,426		$	129		$	161
Interest cost	16,782			16,483			497			547
Expected return on assets	(17,822		)	(17,965		)	(380		)	(392		)
Amortization of:
Prior service cost (benefit)	187			222			(317		)	(522		)
Actuarial loss	5,890			5,268			296			364
Net benefit cost	10,306			9,434			225			158
Change in associated regulatory liabilities	—			—			2,353			2,356
Net expense	$	10,306		$	9,434		$	2,578		$	2,514

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 $23,700 to the Pension Plan during the next twelve months. During the nine months endedJune 30, 2012 and 2011, the Company made contributions to the Pension Plan of $25,442 and $16,682, 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 nine months endedJune 30, 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.

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Related Party Transactions

9 Months Ended

Jun. 30, 2012

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 UGI Energy Services, Inc. ("Energy Services"), a second-tier wholly owned subsidiary of UGI. At June 30, 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 $8,396 and $13,726 during the three and nine months ended June 30, 2012, respectively, and $16,566 and $19,156 during the three and nine months ended June 30, 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 June 30, 2012, September 30, 2011 and June 30, 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 June 30, 2012, comprising approximately 4.1 bcf of natural gas, was $10,512. 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 June 30, 2011, comprising approximately 4.0 bcf of natural gas, was $19,035.

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 nine months ended June 30, 2012 totaled $30,752. During the nine months ended June 30, 2011, such transactions totaled $30,093. There were no such transactions during the three months ended June 30, 2012 or 2011.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2012, revenues associated with such sales to Energy Services totaled $12,067 and $52,744, respectively. During the three and nine months ended June 30, 2011, such revenues totaled $13,529 and $74,589, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity 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 nine months ended June 30, 2012, the aggregate amount of such purchases totaled $13,158 and $36,477, respectively. During the three and nine months ended June 30, 2011, such purchases totaled $9,351 and $44,849, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	3 Months Ended	9 Months Ended		9 Months Ended						9 Months Ended			9 Months Ended
	Jun. 30, 2012 Environmental Issue [Member]	Jun. 30, 2012 Environmental Issue [Member] PNG MGP [Member]	Jun. 30, 2012 Environmental Remediation Expense [Member] CPG MGP [Member]	Mar. 31, 2012 Environmental Remediation Expense [Member] CPG MGP [Member]	Jun. 30, 2012 Environmental Remediation Expense [Member] PNG MGP [Member]	Mar. 31, 2011 Environmental Remediation Expense [Member] PNG MGP [Member]	Jun. 06, 2006 Key Span [Member]	Jun. 24, 2004 Key Span [Member]	May 22, 2009 Yankee Gas Services Company and Connecticut Light and Power Company [Member] MPG Operations [Member] Site	Sep. 11, 2006 Yankee Gas Services Company and Connecticut Light and Power Company [Member] MPG Operations [Member] Site	Jun. 30, 2012 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Claims	Feb. 09, 2011 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Persons	Sep. 22, 2006 Closed Litigation [Member] SCE and G [Member]	Jun. 30, 2012 Pending Litigation [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Decedent Claims	Jun. 30, 2012 Minimum [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Claims
Commitments and Contingencies [Line Items]
Environmental expenditures cap during calendar year			$ 1,800		$ 1,100
Option to termination agreement by either party effective at end of any two-year period beginning with the original effective date in March 2004 (in years)		2 years
Accrual for environmental loss contingencies				15,820		20,121
Base year for determination of investigation and remediation cost (in years)	5 years
Alleged Percentage of Liability (as a percent)								50.00%					25.00%
Approximate remediation cost spent by claimant								2,300					22,000
Approximate third party claim relating to the site													26,000
Environmental exit cost anticipated by claimant								11,000					14,000
Environmental exit cost based on third party estimate							10,000
Additional environment exit cost based on claimant estimate							20,000
Number of sites owned by claimant seeking contributions for past and future remediation costs (in sites)										13
Number of sites claimant withdrew from claims (in sites)									3
Number of sites UGI Utilities acknowledged it operated (in sites)									1
Number of sites dismissed by court (in sites)									9
Deaths from natural gas explosion (in persons)												5
Property claims (in claims)															100
Claims settled and dismissed (in claims)											3
Percentage of property claims settled to date (as a percent)											85.00%
Pending claims (in claims)														1
Pending claims, number of decedents, in which plaintiffs seeking compensatory and damages (in decendents)														2
Liability insurance deductible											$ 500

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Inventories (Tables)

9 Months Ended

Jun. 30, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:

	June 30, 2012		September 30, 2011		June 30, 2011
Gas Utility natural gas	$	27,761	$	95,590	$	50,082
Materials, supplies and other	10,652		8,673		8,669
Total inventories	$	38,413	$	104,263	$	58,751

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Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2012
Accounting Policies [Abstract]
Unrecognized tax benefits which reduced income tax expense and increased net income	$ 204

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Net income	$ 8,460	$ 5,478	$ 88,999	$ 106,715
Net (losses) gains in fair value of derivative instruments (net of tax $4,801, $913, $4,209 and $(2,094), respectively)	(6,772)	(1,866)	(5,938)	2,953
Reclassifications of net losses on derivative instruments (net of tax of $(201), $(120), $(725) and $(362), respectively)	283	171	1,023	511
Benefit plans (net of tax of $(80), $0, $(242) and $(1,461),respectively)	101	(1)	317	2,060
Comprehensive income	$ 2,072	$ 3,782	$ 84,401	$ 112,239

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Accounting Changes

9 Months Ended

Jun. 30, 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 became effective for our interim period ending March 31, 2012 and is required to be applied prospectively. The adoption of this accounting guidance did not have a material impact on our financial statements.

New Accounting Standards Not Yet Adopted

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

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Segment	Jun. 30, 2011	Sep. 30, 2011
Segment Reporting [Abstract]
Number of reportable segments (in segments)			2
Segment Reporting Information [Line Items]
Revenues	$ 143,644	$ 172,714	$ 770,087	$ 1,007,695
Cost of sales	62,701	93,383	412,377	615,645
Depreciation and amortization	13,251	12,689	39,424	39,243
Operating income (loss)	25,300	19,486	178,352	202,475
Interest expense	10,575	10,518	31,859	31,960
Income (loss) before income taxes	14,725	8,968	146,493	170,515
Total assets (at period end)	2,185,845	2,158,564	2,185,845	2,158,564	2,169,348
Goodwill (at period end)	182,145	180,145	182,145	180,145	182,145
Capital expenditures	29,914	21,932	79,698	59,590
Gas Utility [Member]
Segment Reporting Information [Line Items]
Revenues	122,273	148,104	696,814	921,655
Cost of sales	51,401	78,811	370,572	562,251
Depreciation and amortization	12,332	11,596	36,635	36,126
Operating income (loss)	22,535	17,171	168,735	193,206
Interest expense	9,965	9,852	30,148	30,202
Income (loss) before income taxes	12,570	7,319	138,587	163,004
Total assets (at period end)	2,027,023	2,002,033	2,027,023	2,002,033
Goodwill (at period end)	182,145	180,145	182,145	180,145
Capital expenditures	29,004	20,902	76,470	54,453
Electric Utility [Member]
Segment Reporting Information [Line Items]
Revenues	20,779	24,022	71,888	84,673
Cost of sales	11,300	14,572	41,805	53,394
Depreciation and amortization	919	1,093	2,789	3,117
Operating income (loss)	2,554	2,432	9,147	9,025
Interest expense	610	666	1,711	1,758
Income (loss) before income taxes	1,944	1,766	7,436	7,267
Total assets (at period end)	158,822	156,531	158,822	156,531
Goodwill (at period end)	0	0	0	0
Capital expenditures	910	1,030	3,228	5,137
Other [Member]
Segment Reporting Information [Line Items]
Revenues	592	588	1,385	1,367
Cost of sales	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income (loss)	211	(117)	470	244
Interest expense	0	0	0	0
Income (loss) before income taxes	211	(117)	470	244
Total assets (at period end)	0	0	0	0
Goodwill (at period end)	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

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Disclosures About Derivative Instruments and Hedging Activities Textual (Details) (USD $) In Thousands, unless otherwise specified				9 Months Ended							9 Months Ended
	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011	Jun. 30, 2012 Electric Utility electric transmission congestion [Member] States kWh	Jun. 30, 2011 Electric Utility electric transmission congestion [Member] kWh	Jun. 30, 2012 Midstream and Marketing [Member] Electric transmission congestion (excluding Electric Utility) [Member]	Jun. 30, 2012 Gas Utility [Member] DTH	Jun. 30, 2011 Gas Utility [Member] DTH	Jun. 30, 2012 Electric Utility - Forward Contract [Member] kWh	Jun. 30, 2011 Electric Utility - Forward Contract [Member] kWh	Jun. 30, 2012 Interest Rate Protection Agreements [Member]	Jun. 30, 2011 Interest Rate Protection Agreements [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)				261,000,000	287,300,000		13,200,000	18,600,000	654,700,000	874,400,000
Fair values of electric utility's forward purchase power agreements	$ 42,473		$ 11,132						$ 13,095	$ 10,082
Underlying variable rate debt											173,000	173,000
Recorded loss amount included in Other Income, Net											(682)
Maximum length of time hedged in price risk cash flow hedges (in months)						11 months	16 months		23 months
Disclosures About Derivative Instruments Hedging Activities (Additional Textual) [Abstract]
Transmission organization controls movements of wholesale electricity in number of states (in states)				14
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	899
Restricted Cash in brokerage accounts	$ 1,604	$ 4,308	$ 4,055

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Segment Information (Tables)

9 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

Three Months EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

Three Months Ended June 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	172,714	$	148,104	$	24,022	$	588
Cost of sales	$	93,383	$	78,811	$	14,572	$	—
Depreciation and amortization	$	12,689	$	11,596	$	1,093	$	—
Operating income (loss)	$	19,486	$	17,171	$	2,432	$	(117	)
Interest expense	$	10,518	$	9,852	$	666	$	—
Income (loss) before income taxes	$	8,968	$	7,319	$	1,766	$	(117	)
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	21,932	$	20,902	$	1,030	$	—

Nine Months EndedJune 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

Nine Months EndedJune 30, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	1,007,695	$	921,655	$	84,673	$	1,367
Cost of sales	$	615,645	$	562,251	$	53,394	$	—
Depreciation and amortization	$	39,243	$	36,126	$	3,117	$	—
Operating income	$	202,475	$	193,206	$	9,025	$	244
Interest expense	$	31,960	$	30,202	$	1,758	$	—
Income before income taxes	$	170,515	$	163,004	$	7,267	$	244
Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	59,590	$	54,453	$	5,137	$	—