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 December 31, 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 January 31, 2013, 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 December 31, 2012, September 30, 2012 and December 30, 2011	1
Condensed Consolidated Statements of Income for the three months ended December 31, 2012 and 2011	2
Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2012 and 2011	3
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 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	17
Item 3. Quantitative and Qualitative Disclosures About Market Risk	20
Item 4. Controls and Procedures	22
Part II Other Information
Item 1A. Risk Factors	23
Item 6. Exhibits	23
Signatures	24

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	December 31, 2012			September 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	7,924		$	1,259		$	4,228
Restricted cash	2,106			—			3,066
Accounts receivable (less allowances for doubtful accounts of $4,232, $3,588 and $5,824, respectively)	97,821			47,362			102,332
Accounts receivable — related parties	7,230			4,571			8,534
Accrued utility revenues	59,036			16,911			53,811
Inventories	61,861			67,334			97,451
Deferred income taxes	42,803			46,436			37,779
Regulatory assets	3,632			6,473			8,126
Derivative financial instruments	4,760			5,468			18
Prepaid expenses & other current assets	20,948			29,313			15,720
Total current assets	308,121			225,127			331,065
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $826,781, $815,720 and $793,418, respectively)	1,496,606			1,479,949			1,427,332
Goodwill	182,145			182,145			182,145
Regulatory assets	326,996			331,932			293,365
Other assets	5,836			4,026			4,551
Total assets	$	2,319,704		$	2,223,179		$	2,238,458
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	133,000		$	133,000		$	40,000
Bank loans	73,100			9,200			57,700
Accounts payable	48,762			46,754			44,450
Accounts payable — related parties	8,476			10,192			7,024
Deferred fuel refunds	1,916			4,435			5,019
Derivative financial instruments	35,947			36,011			14,697
Other current liabilities	121,726			131,092			163,711
Total current liabilities	422,927			370,684			332,601
Long-term debt	467,000			467,000			600,000
Deferred income taxes	422,190			417,052			355,446
Deferred investment tax credits	4,526			4,612			4,871
Pension and postretirement benefit obligations	177,094			179,056			135,119
Other noncurrent liabilities	57,498			56,262			83,505
Total liabilities	1,551,235			1,494,666			1,511,542
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	468,985			468,692			468,417
Retained earnings	266,191			229,379			221,565
Accumulated other comprehensive loss	(26,966		)	(29,817		)	(23,325		)
Total common stockholder’s equity	768,469			728,513			726,916
Total liabilities and stockholder’s equity	$	2,319,704		$	2,223,179		$	2,238,458

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
	December 31,
	2012			2011
Revenues	$	273,797		$	280,641
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	138,277			156,906
Operating and administrative expenses	44,235			40,942
Operating and administrative expenses — related parties	1,805			2,125
Taxes other than income taxes	4,276			4,127
Depreciation	12,753			12,379
Amortization	818			684
Other income, net	(931		)	(1,127		)
	201,233			216,036
Operating income	72,564			64,605
Interest expense	10,077			10,607
Income before income taxes	62,487			53,998
Income taxes	25,675			21,330
Net income	$	36,812		$	32,668

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 December 31,
	2012		2011
Net income	$	36,812	$	32,668
Other comprehensive income (loss):
Net gains (losses) in fair value of derivative instruments (net of tax of $(1,799) and $1,267, respectively)	2,537		(1,801		)
Reclassifications of net losses on derivative instruments (net of tax of $(84) and $(121), respectively)	119		170
Benefit plans (net of tax of $(139) and $(99), respectively)	195		139
Other comprehensive income (loss)	2,851		(1,492		)
Comprehensive income	$	39,663	$	31,176

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)

	Three Months Ended
	December 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	36,812		$	32,668
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	13,571			13,063
Deferred income taxes, net	6,554			(587		)
Provision for uncollectible accounts	2,106			2,223
Other, net	514			2,505
Net change in:
Accounts receivable and accrued utility revenues	(97,349		)	(86,309		)
Inventories	5,473			6,812
Deferred fuel and power costs	4,845			1,552
Accounts payable	292			(12,190		)
Other current assets	8,936			9,186
Other current liabilities	(7,126		)	15,666
Net cash used by operating activities	(25,372		)	(15,411		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(29,728		)	(22,858		)
Net costs of property, plant and equipment disposals	(322		)	(607		)
(Increase) decrease in restricted cash	(2,106		)	1,242
Net cash used by investing activities	(32,156		)	(22,223		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	—			(23,199		)
Increase in bank loans	63,900			57,700
Other	293			94
Net cash provided by financing activities	64,193			34,595
Cash and cash equivalents increase (decrease)	$	6,665		$	(3,039	)
CASH AND CASH EQUIVALENTS:
End of period	$	7,924		$	4,228
Beginning of period	1,259			7,267
Increase (decrease)	$	6,665		$	(3,039	)

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.” UGI Gas, PNG and CPG 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 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, 2012, 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, 2012 (“Company’s 2012 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 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.

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

New Accounting Standard Not Yet Adopted

Disclosures about Offsetting Assets and Liabilities. In December 2011, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements

- 5 -

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 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 2012 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Financial information by business segment follows:

Three Months EndedDecember 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	273,797	$	248,254	$	25,118	$	425
Cost of sales	$	138,277	$	123,574	$	14,703	$	—
Depreciation and amortization	$	13,571	$	12,605	$	966	$	—
Operating income	$	72,564	$	69,789	$	2,624	$	151
Interest expense	$	10,077	$	9,572	$	505	$	—
Income before income taxes	$	62,487	$	60,217	$	2,119	$	151
Total assets (at period end)	$	2,319,704	$	2,164,368	$	155,336	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,728	$	28,519	$	1,209	$	—

Three Months EndedDecember 31, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	280,641	$	255,030	$	25,169	$	442
Cost of sales	$	156,906	$	141,679	$	15,227	$	—
Depreciation and amortization	$	13,063	$	12,145	$	918	$	—
Operating income	$	64,605	$	61,231	$	3,230	$	144
Interest expense	$	10,607	$	10,098	$	509	$	—
Income before income taxes	$	53,998	$	51,133	$	2,721	$	144
Total assets (at period end)	$	2,238,458	$	2,088,710	$	149,748	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	22,858	$	21,812	$	1,046	$	—

5. Inventories

Inventories comprise the following:

	December 31, 2012		September 30, 2012		December 31, 2011
Gas Utility natural gas	$	51,838	$	57,663	$	87,735
Materials, supplies and other	10,023		9,671		9,716
Total inventories	$	61,861	$	67,334	$	97,451

At December 31, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expires in October 2013 and two of which expire in October 2015 (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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 December 31, 2012, September 30, 2012 and December 31, 2011 comprising 9.1 billion cubic feet (“bcf”), 11.4 bcf and 10.8 bcf of natural gas, was $27,251, $32,627 and $50,912, respectively. In conjunction with the SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at December 31, 2012, and $22,500 at September 30, 2012 and December 31, 2011. 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 4 to the Company’s 2012 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:

	December 31, 2012		September 30, 2012		December 31, 2011
Regulatory assets:
Income taxes recoverable	$	103,665	$	103,172	$	98,741
Underfunded pension and postretirement plans	184,764		188,222		148,650
Environmental costs	17,119		16,812		19,372
Deferred fuel and power costs	7,797		11,602		14,798
Removal costs, net	11,541		12,718		11,946
Other	5,742		5,879		7,984
Total regulatory assets	$	330,628	$	338,405	$	301,491
Regulatory liabilities:
Postretirement benefits	$	13,486	$	13,147	$	11,764
Environmental overcollections	3,077		2,883		4,740
Deferred fuel and power refunds	1,916		4,435		5,019
State tax benefits — distribution system repairs	7,750		7,385		6,509
Other	570		494		377
Total regulatory liabilities	$	26,799	$	28,344	$	28,409

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 December 31, 2012, September 30, 2012, and December 31, 2011, were $(440), $5,303 and $(2,589), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP, the fair

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

values of these contracts are recognized on the balance with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At December 31, 2012, September 30, 2012, and December 31, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $8,182, $9,207 and $13,529, 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 December 31, 2012, September 30, 2012, and December 31, 2011, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012 (“PUC Staff Complaint”), pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Commissioners adopted a Joint Motion on January 24, 2013 (the “Joint Motion”) to adopt the Joint Settlement, with certain modifications. In addition to the commitments made by UGI Utilities in the Joint Settlement, the Joint Motion would require UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $386 to $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program, but would not require UGI Utilities to concede to having violated any regulation or operating procedure. We anticipate that the PUC Staff will issue in the near future a tentative order that incorporates the terms and conditions of the Joint Settlement, as modified. The provisions of the tentative order will become final and effective unless any party to the Joint Settlement objects to any of the terms and conditions included in the tentative order within five business days from the date of the issuance. The Company does not believe that the cost of complying with the requirements of the Joint Motion will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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 postretirement life insurance benefits to nearly all active and retired employees.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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
	December 31,						December 31,
	2012			2011			2012			2011
Service cost	$	2,053		$	1,756		$	51		$	43
Interest cost	5,196			5,594			143			166
Expected return on assets	(6,198		)	(5,940		)	(132		)	(127		)
Amortization of:
Prior service cost (benefit)	—			62			(105		)	(106		)
Actuarial loss	3,428			1,963			91			99
Net benefit cost	4,479			3,435			48			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	863		$	859

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 Plan 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 $10,000 to the Pension Plan during the remainder of Fiscal 2013. During the three months endedDecember 31, 2012 and 2011, the Company made contributions to the Pension Plan of $5,730 and $4,106, 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 three months endedDecember 31, 2012 and 2011, nor are they expected to be material for all of Fiscal 2013.

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 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 December 31, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,965 and $17,751, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 December 31, 2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

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

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 matter.

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 Incident. 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. With the exception of two wrongful death actions, the large majority of claims have been settled. There are several less significant personal injury and property claims that have not yet been settled. 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 material 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.

At December 31, 2012, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, two of which expire October 31, 2015 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 $4,324 and $4,921 during the three months ended December 31, 2012 and 2011, respectively. 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 $16,500 as of December 31, 2012, and $15,000 as of September 30, 2012 and December 31, 2011.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at December 31, 2012, comprising approximately 9.1 bcf of natural gas, was $27,251. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21,217. The carrying value of these gas storage inventories at December 31, 2011, comprising approximately 7.6 bcf of natural gas, was $35,230.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2012, totaled $17,825. During the three months ended December 31, 2011, such transactions totaled $22,365.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2012 and 2011, revenues associated with such sales to Energy Services totaled $19,824 and $17,081, 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 months ended December 31,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2012 and 2011, the aggregate amount of such purchases totaled $19,020 and $10,051, 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 December 31, 2012, September 30, 2012 and December 31, 2011:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
December 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	374		$	160		$	—	$	534
Interest rate contracts	—			4,226			—		$	4,226
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,315	)	$	(7,726	)	$	—	$	(9,041	)
Interest rate contracts	$	—		$	(30,412	)	$	—	$	(30,412	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	—			(30,522		)	—		$	(30,522	)
December 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	—		$	18		$	—	$	18
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,053	)	$	(12,067	)	$	—	$	(16,120	)
Interest rate contracts	$	—		$	(21,662	)	$	—	$	(21,662	)

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 (except for 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 December 31, 2012, were $600,000 and $696,217, respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2011, were $640,000 and $747,461, 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).

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 December 31, 2012 and 2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.0 million dekatherms and 9.1 million dekatherms, respectively. At December 31, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 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 accounting guidance 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. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At December 31, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $8,182 and $13,529, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2012 and 2011, the volumes of Electric Utility’s forward electricity purchase contracts was 482.3 million kilowatt hours and 816.0 million kilowatt hours, respectively. At December 31, 2012, the maximum period over which these contracts extend is 17 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). At December 31, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 118.2 million kilowatt hours and 130.0 million kilowatt hours, respectively. At December 31, 2012, the maximum period over which we are hedging electricity congestion with FTRs is 5 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. Associated volumes, fair values and effects on net income 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 December 31, 2012 and 2011, the total notional amounts of unsettled IRPAs 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.

At December 31, 2012, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $1,043.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At December 31, 2012 and 2011, restricted cash in brokerage accounts totaled $2,106 and $3,066, respectively.

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

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2012		2011		Location	2012			2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,226	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(30,412	)	$	(21,662	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	420		18		Derivative financial instruments and Other noncurrent liabilities	(9,041		)	(16,118		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	114		—		Derivative financial instruments	—			(2		)
Total Derivatives		$	4,760	$	18		$	(39,453	)	$	(37,782	)

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Three Months EndedDecember 31,:

	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	$	4,336		$	(3,077	)	$	(203	)	$	(291	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(2	)	$	(51	)							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, or sale, of natural gas and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

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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 and the impact of regulatory enforcement activity related thereto, ranging from financial penalties, required reporting or operational measures up to suspension of applicable certificates of public convenience; (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, 2012, 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 December 31, 2012 (“2012 three-month period”) with the three months ended December 31, 2011 (“2011 three-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 December 31,	2012			2011			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	248.3		$	255.0		$	(6.7	)	(2.6	)%
Total margin (a)	$	124.7		$	113.3		$	11.4		10.1	%
Operating income	$	69.8		$	61.2		$	8.6		14.1	%
Income before income taxes	$	60.2		$	51.1		$	9.1		17.8	%
System throughput - bcf
Core market	21.8			19.4			2.4			12.4	%
Total	54.0			49.0			5.0			10.2	%
Heating degree days — % (warmer) than normal (b)	(3.6		)%	(12.2		)%	—			—
Electric Utility:
Revenues	$	25.1		$	25.2		$	(0.1	)	(0.4	)%
Total margin (a)	$	9.0		$	8.5		$	0.5		5.9	%
Operating income	$	2.6		$	3.2		$	(0.6	)	(18.8	)%
Income before income taxes	$	2.1		$	2.7		$	(0.6	)	(22.2	)%
Distribution sales — gwh	248.2			244.0			4.2			1.7	%

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 $1.4 million during each of the three-month periods ended December 31, 2012 and 2011. 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 3.6% warmer than normal but 9.6% colder than the prior-year period. Total distribution system throughput increased principally reflecting greater throughput to core market customers and greater volumes associated with lower margin firm and interruptible delivery service customers. 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 system throughput to core market customers was above last year principally reflecting the effects of the colder weather and, to a much lesser extent, customer growth over the last several years, principally conversions from oil, prompted by sustained lower natural gas prices and high oil prices.

Notwithstanding the increase in system throughput, Gas Utility revenues decreased $6.7 million during the 2012 three-month period principally reflecting lower revenues from off-system sales ($6.3 million) and a decline in revenues from retail core market customers ($6.0 million). These decreases were partially offset by higher revenues from firm and interruptible delivery service customers from higher volumes. 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 ($22.2 million) partially offset by the effects on retail core-market revenues of greater retail core-market volumes. 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 on the balance sheet as a regulatory

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UGI UTILITIES, INC. AND SUBSIDIARIES

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 $123.6 million in the 2012 three-month period compared with $141.7 million in the prior-year period principally reflecting lower average PGC rates ($22.2 million) and the lower off-system sales ($6.3 million) partially offset by the effects on cost of sales of the greater retail core-market volumes.

Gas Utility total margin increased $11.4 million in the 2012 three-month period principally reflecting higher core market margin ($8.6 million) and higher firm delivery service total margin. The higher core market total margin reflects the effects of the greater core market volumes.

The increase in Gas Utility operating income during the 2012 three-month period principally reflects the increase in total margin ($11.4 million) partially offset by higher operating and administrative expenses including, among other things, higher distribution system maintenance expenses and greater pension expense.

Electric Utility. Temperatures based upon heating degree days during the 2012 three-month period were approximately 9.7% colder than the prior-year period while revenues were slightly lower. The slight decline in revenues notwithstanding the higher sales 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 $14.7 million in the 2012 three-month period compared to $15.2 million in the 2011 three-month period principally reflecting the effects of the lower average DS rates.

Electric Utility total margin increased $0.5 million in the 2012 three-month period reflecting in large part the slightly higher distribution sales and greater transmission revenue.

Electric Utility 2012 three-month period operating income and income before income taxes decreased as the greater total margin ($0.5 million) was more than offset by greater operating and administrative costs including distribution system repair and maintenance costs associated with Hurricane Sandy.

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 December 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.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at December 31, 2012, was $673.1 million compared to debt outstanding of $609.2 million at September 30, 2012. UGI Utilities’ total debt outstanding at December 31, 2012, comprises $383 million of Senior Notes, $217 million of Medium-Term Notes and $73.1 million of bank loan borrowings.

UGI Utilities may borrow up to a total of $300 million under its credit agreement (“2011 Credit Agreement”). The 2011 Credit Agreement expires in October 2015. During the 2012 and 2011three-month periods, average daily bank loan borrowings were $53.5 million and $29.7 million, respectively, and peak bank loan borrowings totaled $78.6 million and $70.5 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 2011 Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2013.

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 2011 Credit Agreement to manage seasonal cash flow needs.

Cash used by operating activities was $25.4 million in the 2012 three-month period compared to cash used by operating activities of $15.4 million in the prior-year three-month period. Cash flow from operating activities before changes in operating working capital was $59.6 million in the 2012 three-month period compared to $49.9 million recorded in the prior-year three-month period principally reflecting the greater 2012 three-month period operating results and higher noncash charges for deferred income taxes.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Changes in operating working capital used $84.9 million of operating cash flow during the 2012 three-month period compared to $65.3 million used during the prior-year three-month period. The increase in cash used by changes in operating working capital in the 2012 three-month period reflects, among other things, greater cash required to fund changes in accounts receivable, principally resulting from the higher sales during the quarter, and greater cash used to fund interest payments due to the timing of such payments. These increases in cash used by changes in operating working capital were partially offset by the timing and amount of cash used to fund changes in accounts payable.

Investing activities. Cash used by investing activities was $32.2 million in the 2012 three-month period compared to $22.2 million in the 2011 three-month period. Total capital expenditures were $29.7 million in the 2012 three-month period compared with $22.9 million recorded in the prior-year period. The 2012 three-month period principally reflects higher UGI Gas capital expenditures.

Financing activities. Cash provided by financing activities was $64.2 million in the 2012 three-month period compared with cash provided by financing activities of $34.6 million in the 2011 three-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. During the 2012 three-month period there were net bank loan borrowings of $63.9 million compared with net bank loan borrowings of $57.7 million during the prior-year three-month period.

Regulatory Matters

On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012 (“PUC Staff Complaint”), pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Commissioners adopted a Joint Motion on January 24, 2013 (the “Joint Motion”) to adopt the Joint Settlement, with certain modifications. In addition to the commitments made by UGI Utilities in the Joint Settlement, the Joint Motion would require UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 million to $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program, but would not require UGI Utilities to concede to having violated any regulation or operating procedure. We anticipate that the PUC Staff will issue in the near future a tentative order that incorporates the terms and conditions of the Joint Settlement, as modified. The provisions of the tentative order will become final and effective unless any party to the Joint Settlement objects to any of the terms and conditions included in the tentative order within five business days from the date of the issuance. The Company does not believe that the cost of complying with the requirements of the Joint Motion will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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 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 December 31, 2012 and 2011, Gas Utility had $2.1 million and $3.1 million, respectively, of restricted cash associated with natural gas futures and option accounts with brokers. At December 31, 2012 and 2011, the fair values of our natural gas futures and option contracts were losses of $0.4 million and $2.6 million, respectively.

Electric Utility's DS tariffs contain clauses which 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. At December 31, 2012 and 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $8.2 million and $13.5 million, respectively. At December 31, 2012 and 2011, the fair

- 20 -

UGI UTILITIES, INC. AND SUBSIDIARIES

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 December 31, 2012 and 2011, were losses of $26.2 million and $21.7 million, respectively. A hypothetical 10% adverse change in the three-month LIBOR would result in a decrease in fair value of $7.8 million at December 31, 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 December 31, 2012 and 2011, were not material.

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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 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, 2012, 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.

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibit
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 December 31, 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 December 31, 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 December 31, 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.

- 23 -

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:	February 8, 2013	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President — Finance and Chief Financial Officer
Date:	February 8, 2013	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

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 December 31, 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 December 31, 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 December 31, 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.

- 25 -

EX-12.1

UGI UTILITIES, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Three Months Ended December 31,
			Year Ended September 30,
	2012		2012		2011		2010		2009		2008
Earnings:
Earnings before income taxes	$	62,487	$	142,971	$	168,693	$	147,183	$	125,554	$	123,977
Interest expense	10,077		42,412		42,728		42,336		43,918		39,065
Amortization of debt discount and
expense	176		814		1,060		627		625		467
Estimated interest component of
rental expense	500		2,121		1,740		1,912		1,965		1,619
	$	73,240	$	188,318	$	214,221	$	192,058	$	172,062	$	165,128
Fixed Charges:
Interest expense	$	10,077	$	42,412	$	42,728	$	42,336	$	43,918	$	39,065
Amortization of debt discount and
expense	176		814		1,060		627		625		467
Allowance for funds used during
construction (capitalized interest)	80		10		90		74		160		139
Estimated interest component of
rental expense	500		2,121		1,740		1,912		1,965		1,619
	$	10,833	$	45,357	$	45,618	$	44,949	$	46,668	$	41,290
Ratio of earnings to fixed charges	6.76		4.15		4.70		4.27		3.69		4.00

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: February 8, 2013

/s/ Robert F. Beard

Robert F. Beard

President and Chief Executive Officer

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: February 8, 2013

/s/ Donald E. Brown

Donald E. Brown

Vice President - Finance and Chief Financial Officer

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 December 31, 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:	February 8, 2013	Date:	February 8, 2013

XML

Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 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	$ 4,336	$ (3,077)
Gain (loss) reclassified from AOCI into income	(203)	(291)
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	$ (2)	$ (51)

XML

Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								3 Months Ended		3 Months Ended
	Dec. 31, 2012 Environmental Issue [Member]	Dec. 31, 2012 Environmental Issue [Member] PNG MGP [Member]	Dec. 31, 2012 Environmental Remediation Expense [Member] CPG MGP [Member]	Dec. 31, 2012 Environmental Remediation Expense [Member] PNG MGP [Member]	Dec. 31, 2012 CPG and PNG COAs [Member]	Dec. 31, 2011 CPG and PNG COAs [Member]	Jun. 06, 2006 Key Span [Member]	Jun. 24, 2004 Key Span [Member]	Dec. 31, 2012 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member]	Feb. 09, 2011 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Persons	Dec. 31, 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					14,965	17,751
Base year for determination of investigation and remediation cost (in years)	5 years
Alleged Percentage of Liability (as a percent)								50.00%
Approximate remediation cost spent by claimant								2,300
Environmental exit cost anticipated by claimant								11,000
Environmental exit cost based on third party estimate							10,000
Additional environment exit cost based on claimant estimate							20,000
Deaths from natural gas explosion (in persons)										5
Property claims (in claims)											100
Liability insurance deductible									$ 500

XML

Disclosures About Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Dec. 31, 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 December 31, 2012 and 2011:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2012		2011		Location	2012			2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,226	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(30,412	)	$	(21,662	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	420		18		Derivative financial instruments and Other noncurrent liabilities	(9,041		)	(16,118		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	114		—		Derivative financial instruments	—			(2		)
Total Derivatives		$	4,760	$	18		$	(39,453	)	$	(37,782	)

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

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

Three Months EndedDecember 31,:

	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	$	4,336		$	(3,077	)	$	(203	)	$	(291	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(2	)	$	(51	)							Operating expenses/other income, net

XML

Disclosures About Derivative Instruments and Hedging Activities Textual (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Derivative Liabilities	$ 39,453		$ 37,782
Total Derivatives Assets	4,760		18
Disclosures About Derivative Instruments Hedging Activities (Additional Textual) [Abstract]
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	1,043
Restricted Cash in brokerage accounts	2,106	0	3,066
Electric Utility electric transmission congestion [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)	118,200,000		130,000,000
Maximum length of time hedged in price risk cash flow hedges (in months)	5 months
Gas Utility [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)	13,000,000		9,100,000
Maximum length of time hedged in price risk cash flow hedges (in months)	9 months
Electric Utility [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)	482,300,000		816,000,000
Derivative Liabilities	8,182		13,529
Maximum length of time hedged in price risk cash flow hedges (in months)	17 months
Interest Rate Protection Agreements [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Underlying variable rate debt	173,000		173,000
Derivative financial instruments [Member] | Derivatives Designated as Hedging Instruments [Member] | Interest rate contracts [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Total Derivatives Assets	4,226		0
Derivative financial instruments [Member] | Derivatives Accounted for Under ACS 980 [Member] | Commodity contracts [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Total Derivatives Assets	420		18
Derivative financial instruments [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Commodity contracts [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Derivative Liabilities	0		2
Total Derivatives Assets	114		0
Derivative financial instruments and other noncurrent liabilities [Member] | Derivatives Accounted for Under ACS 980 [Member] | Commodity contracts [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Derivative Liabilities	$ 9,041		$ 16,118

XML

Significant Accounting Policies

3 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Significant Accounting Policies

Significant Accounting Policies

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

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments 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, 2012, 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, 2012 (“Company’s 2012 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 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.

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

Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 330,628	$ 338,405	$ 301,491
Regulatory Liabilities	26,799	28,344	28,409
Postretirement benefits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	13,486	13,147	11,764
Environmental overcollections [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	3,077	2,883	4,740
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	1,916	4,435	5,019
State tax benefits -- distribution system repairs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	7,750	7,385	6,509
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	570	494	377
Income taxes recoverable [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	103,665	103,172	98,741
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	184,764	188,222	148,650
Environmental costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	17,119	16,812	19,372
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	7,797	11,602	14,798
Removal costs, net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	11,541	12,718	11,946
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 5,742	$ 5,879	$ 7,984

XML

Inventories Textual (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012 ft3	Sep. 30, 2012 ft3	Dec. 31, 2011 ft3
Inventory, Net [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	9,100,000,000	11,400,000,000	10,800,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 27,251	$ 32,627	$ 50,912
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	$ 16,500	$ 22,500	$ 22,500
Expires in October 2015 [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

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Regulatory Assets and Liabilities and Regulatory Matters Textual (Details) (USD $) In Thousands, unless otherwise specified			3 Months Ended		12 Months Ended				0 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Deferral Fuel and Power [Member]	Dec. 31, 2011 Deferral Fuel and Power [Member]	Sep. 30, 2012 Deferral Fuel and Power [Member]	Dec. 31, 2012 Electric Utility Electric Supply Contracts [Member]	Sep. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Dec. 31, 2011 Electric Utility Electric Supply Contracts [Member]	Oct. 03, 2012 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member]	Feb. 09, 2011 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Persons	Dec. 31, 2012 Allentown Incident [Member]	Dec. 31, 2012 Revised Penalty [Member] Allentown Incident [Member]
Regulatory Assets [Line Items]
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains									14 years
Unrealized gains (losses) on derivative financial instrument contracts			$ (440)	$ (2,589)	$ 5,303
Fair value of electric utility electricity supply contracts	(39,453)	(37,782)				8,182	9,207	13,529
Deaths from natural gas explosion (in persons)										5
Penalty Assessed											$ 386	$ 500
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains									30 years

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Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 2,053	$ 1,756
Interest cost	5,196	5,594
Expected return on assets	(6,198)	(5,940)
Amortization of:
Prior service cost (benefit)	0	62
Actuarial loss	3,428	1,963
Net benefit cost	4,479	3,435
Change in associated regulatory liabilities	0	0
Net expense	4,479	3,435
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	51	43
Interest cost	143	166
Expected return on assets	(132)	(127)
Amortization of:
Prior service cost (benefit)	(105)	(106)
Actuarial loss	91	99
Net benefit cost	48	75
Change in associated regulatory liabilities	815	784
Net expense	$ 863	$ 859

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Nature of Operations

3 Months Ended

Dec. 31, 2012

Nature of Operations [Abstract]

Nature of Operations

Nature of Operations

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG 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 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.

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Defined Benefit Pension and Other Postretirement Plans Textual (Details) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to pensions plans in next twelve months	$ 10,000
Contribution made to Pension Plan	$ 5,730	$ 4,106

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 7,924	$ 1,259	$ 4,228
Restricted cash	2,106	0	3,066
Accounts receivable (less allowances for doubtful accounts of $4,232, $3,588 and $5,824, respectively)	97,821	47,362	102,332
Accounts receivable — related parties	7,230	4,571	8,534
Accrued utility revenues	59,036	16,911	53,811
Inventories	61,861	67,334	97,451
Deferred income taxes	42,803	46,436	37,779
Regulatory assets	3,632	6,473	8,126
Derivative financial instruments	4,760	5,468	18
Prepaid expenses & other current assets	20,948	29,313	15,720
Total current assets	308,121	225,127	331,065
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $826,781, $815,720 and $793,418, respectively)	1,496,606	1,479,949	1,427,332
Goodwill	182,145	182,145	182,145
Regulatory assets	326,996	331,932	293,365
Other assets	5,836	4,026	4,551
Total assets	2,319,704	2,223,179	2,238,458
Current liabilities:
Current maturities of long-term debt	133,000	133,000	40,000
Bank loans	73,100	9,200	57,700
Accounts payable	48,762	46,754	44,450
Accounts payable — related parties	8,476	10,192	7,024
Deferred fuel refunds	1,916	4,435	5,019
Derivative financial instruments	35,947	36,011	14,697
Other current liabilities	121,726	131,092	163,711
Total current liabilities	422,927	370,684	332,601
Long-term debt	467,000	467,000	600,000
Deferred income taxes	422,190	417,052	355,446
Deferred investment tax credits	4,526	4,612	4,871
Pension and postretirement benefit obligations	177,094	179,056	135,119
Other noncurrent liabilities	57,498	56,262	83,505
Total liabilities	1,551,235	1,494,666	1,511,542
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	468,985	468,692	468,417
Retained earnings	266,191	229,379	221,565
Accumulated other comprehensive loss	(26,966)	(29,817)	(23,325)
Total common stockholder’s equity	768,469	728,513	726,916
Total liabilities and stockholder’s equity	$ 2,319,704	$ 2,223,179	$ 2,238,458

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Tax on (loss) gain on derivative instruments	$ 1,799	$ (1,267)
Tax on reclassifications of net losses (gains) on derivative instruments	84	121
Tax on benefit plans	$ 139	$ 99

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Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 534	$ 5,468	$ 18
Derivative financial instruments, liabilities	(9,041)	(9,437)	(16,120)
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	374	5,468	0
Derivative financial instruments, liabilities	(1,315)	(671)	(4,053)
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	160	0	18
Derivative financial instruments, liabilities	(7,726)	(8,766)	(12,067)
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	4,226
Derivative financial instruments, liabilities	(30,412)	(30,522)	(21,662)
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, 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	4,226
Derivative financial instruments, liabilities	$ (30,412)	$ (30,522)	$ (21,662)

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

3 Months Ended

Dec. 31, 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:

	December 31, 2012		September 30, 2012		December 31, 2011
Regulatory assets:
Income taxes recoverable	$	103,665	$	103,172	$	98,741
Underfunded pension and postretirement plans	184,764		188,222		148,650
Environmental costs	17,119		16,812		19,372
Deferred fuel and power costs	7,797		11,602		14,798
Removal costs, net	11,541		12,718		11,946
Other	5,742		5,879		7,984
Total regulatory assets	$	330,628	$	338,405	$	301,491
Regulatory liabilities:
Postretirement benefits	$	13,486	$	13,147	$	11,764
Environmental overcollections	3,077		2,883		4,740
Deferred fuel and power refunds	1,916		4,435		5,019
State tax benefits — distribution system repairs	7,750		7,385		6,509
Other	570		494		377
Total regulatory liabilities	$	26,799	$	28,344	$	28,409

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Fair Value Measurements Textual (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 600,000	$ 640,000
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 696,217	$ 747,461

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Fair Value Measurements (Tables)

3 Months Ended

Dec. 31, 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 December 31, 2012, September 30, 2012 and December 31, 2011:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
December 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	374		$	160		$	—	$	534
Interest rate contracts	—			4,226			—		$	4,226
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,315	)	$	(7,726	)	$	—	$	(9,041	)
Interest rate contracts	$	—		$	(30,412	)	$	—	$	(30,412	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	—			(30,522		)	—		$	(30,522	)
December 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	—		$	18		$	—	$	18
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,053	)	$	(12,067	)	$	—	$	(16,120	)
Interest rate contracts	$	—		$	(21,662	)	$	—	$	(21,662	)

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 36,812	$ 32,668
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	13,571	13,063
Deferred income taxes, net	6,554	(587)
Provision for uncollectible accounts	2,106	2,223
Other, net	514	2,505
Net change in:
Accounts receivable and accrued utility revenues	(97,349)	(86,309)
Inventories	5,473	6,812
Deferred fuel and power costs	4,845	1,552
Accounts payable	292	(12,190)
Other current assets	8,936	9,186
Other current liabilities	(7,126)	15,666
Net cash used by operating activities	(25,372)	(15,411)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(29,728)	(22,858)
Net costs of property, plant and equipment disposals	(322)	(607)
(Increase) decrease in restricted cash	(2,106)	1,242
Net cash used by investing activities	(32,156)	(22,223)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	0	(23,199)
Increase in bank loans	63,900	57,700
Other	293	94
Net cash provided by financing activities	64,193	34,595
Cash and cash equivalents increase (decrease)	6,665	(3,039)
CASH AND CASH EQUIVALENTS:
End of period	7,924	4,228
Beginning of period	1,259	7,267
Increase (decrease)	$ 6,665	$ (3,039)

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Allowance for doubtful accounts on accounts receivable	$ 4,232	$ 3,588	$ 5,824
Accumulated depreciation and amortization on property, plant and equipment	$ 826,781	$ 815,720	$ 793,418
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

3 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2012, September 30, 2012 and December 31, 2011:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
December 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	374		$	160		$	—	$	534
Interest rate contracts	—			4,226			—		$	4,226
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,315	)	$	(7,726	)	$	—	$	(9,041	)
Interest rate contracts	$	—		$	(30,412	)	$	—	$	(30,412	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	—			(30,522		)	—		$	(30,522	)
December 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	—		$	18		$	—	$	18
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,053	)	$	(12,067	)	$	—	$	(16,120	)
Interest rate contracts	$	—		$	(21,662	)	$	—	$	(21,662	)

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 (except for 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 December 31, 2012, were $600,000 and $696,217, respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2011, were $640,000 and $747,461, 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	3 Months Ended
	Dec. 31, 2012	Jan. 31, 2013
Entity Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
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

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Disclosures About Derivative Instruments and Hedging Activities

3 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

. Disclosures About Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2012 and 2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.0 million dekatherms and 9.1 million dekatherms, respectively. At December 31, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 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 accounting guidance 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. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At December 31, 2012 and 2011, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $8,182 and $13,529, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2012 and 2011, the volumes of Electric Utility’s forward electricity purchase contracts was 482.3 million kilowatt hours and 816.0 million kilowatt hours, respectively. At December 31, 2012, the maximum period over which these contracts extend is 17 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. 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 GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). At December 31, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 118.2 million kilowatt hours and 130.0 million kilowatt hours, respectively. At December 31, 2012, the maximum period over which we are hedging electricity congestion with FTRs is 5 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. Associated volumes, fair values and effects on net income 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 December 31, 2012 and 2011, the total notional amounts of unsettled IRPAs 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.

At December 31, 2012, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $1,043.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At December 31, 2012 and 2011, restricted cash in brokerage accounts totaled $2,106 and $3,066, respectively.

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

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2012		2011		Location	2012			2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,226	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(30,412	)	$	(21,662	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	420		18		Derivative financial instruments and Other noncurrent liabilities	(9,041		)	(16,118		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	114		—		Derivative financial instruments	—			(2		)
Total Derivatives		$	4,760	$	18		$	(39,453	)	$	(37,782	)

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

Three Months EndedDecember 31,:

	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	$	4,336		$	(3,077	)	$	(203	)	$	(291	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income
	2012			2011
Commodity contracts	$	(2	)	$	(51	)							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, or sale, of natural gas and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

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Condensed Consolidated Statements of Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Revenues	$ 273,797	$ 280,641
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	138,277	156,906
Operating and administrative expenses	44,235	40,942
Operating and administrative expenses - related parties	1,805	2,125
Taxes other than income taxes	4,276	4,127
Depreciation	12,753	12,379
Amortization	818	684
Other income, net	(931)	(1,127)
Total costs and expenses	201,233	216,036
Operating income	72,564	64,605
Interest expense	10,077	10,607
Income before income taxes	62,487	53,998
Income taxes	25,675	21,330
Net income	$ 36,812	$ 32,668

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Inventories

3 Months Ended

Dec. 31, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	December 31, 2012		September 30, 2012		December 31, 2011
Gas Utility natural gas	$	51,838	$	57,663	$	87,735
Materials, supplies and other	10,023		9,671		9,716
Total inventories	$	61,861	$	67,334	$	97,451

At December 31, 2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expires in October 2013 and two of which expire in October 2015 (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 December 31, 2012, September 30, 2012 and December 31, 2011 comprising 9.1 billion cubic feet (“bcf”), 11.4 bcf and 10.8 bcf of natural gas, was $27,251, $32,627 and $50,912, respectively. In conjunction with the SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at December 31, 2012, and $22,500 at September 30, 2012 and December 31, 2011. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

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Segment Information

3 Months Ended

Dec. 31, 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 2012 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 EndedDecember 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	273,797	$	248,254	$	25,118	$	425
Cost of sales	$	138,277	$	123,574	$	14,703	$	—
Depreciation and amortization	$	13,571	$	12,605	$	966	$	—
Operating income	$	72,564	$	69,789	$	2,624	$	151
Interest expense	$	10,077	$	9,572	$	505	$	—
Income before income taxes	$	62,487	$	60,217	$	2,119	$	151
Total assets (at period end)	$	2,319,704	$	2,164,368	$	155,336	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,728	$	28,519	$	1,209	$	—

Three Months EndedDecember 31, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	280,641	$	255,030	$	25,169	$	442
Cost of sales	$	156,906	$	141,679	$	15,227	$	—
Depreciation and amortization	$	13,063	$	12,145	$	918	$	—
Operating income	$	64,605	$	61,231	$	3,230	$	144
Interest expense	$	10,607	$	10,098	$	509	$	—
Income before income taxes	$	53,998	$	51,133	$	2,721	$	144
Total assets (at period end)	$	2,238,458	$	2,088,710	$	149,748	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	22,858	$	21,812	$	1,046	$	—

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Defined Benefit Pension and Other Postretirement Plans (Tables)

3 Months Ended

Dec. 31, 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
	December 31,						December 31,
	2012			2011			2012			2011
Service cost	$	2,053		$	1,756		$	51		$	43
Interest cost	5,196			5,594			143			166
Expected return on assets	(6,198		)	(5,940		)	(132		)	(127		)
Amortization of:
Prior service cost (benefit)	—			62			(105		)	(106		)
Actuarial loss	3,428			1,963			91			99
Net benefit cost	4,479			3,435			48			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	863		$	859

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Significant Accounting Policies (Policies)

3 Months Ended

Dec. 31, 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 actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Restrict

Restricted Cash

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

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.

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Commitments and Contingencies

3 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,965 and $17,751, 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 December 31, 2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

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

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 matter.

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 Incident. 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. With the exception of two wrongful death actions, the large majority of claims have been settled. There are several less significant personal injury and property claims that have not yet been settled. 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 material effect on our consolidated financial position, results of operations or cash flows.

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Regulatory Assets and Liabilities and Regulatory Matters

3 Months Ended

Dec. 31, 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 4 to the Company’s 2012 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:

	December 31, 2012		September 30, 2012		December 31, 2011
Regulatory assets:
Income taxes recoverable	$	103,665	$	103,172	$	98,741
Underfunded pension and postretirement plans	184,764		188,222		148,650
Environmental costs	17,119		16,812		19,372
Deferred fuel and power costs	7,797		11,602		14,798
Removal costs, net	11,541		12,718		11,946
Other	5,742		5,879		7,984
Total regulatory assets	$	330,628	$	338,405	$	301,491
Regulatory liabilities:
Postretirement benefits	$	13,486	$	13,147	$	11,764
Environmental overcollections	3,077		2,883		4,740
Deferred fuel and power refunds	1,916		4,435		5,019
State tax benefits — distribution system repairs	7,750		7,385		6,509
Other	570		494		377
Total regulatory liabilities	$	26,799	$	28,344	$	28,409

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 December 31, 2012, September 30, 2012, and December 31, 2011, were $(440), $5,303 and $(2,589), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are recognized on the balance with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At December 31, 2012, September 30, 2012, and December 31, 2011, the fair values of Electric Utility’s electricity supply contracts were losses of $8,182, $9,207 and $13,529, 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 December 31, 2012, September 30, 2012, and December 31, 2011, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012 (“PUC Staff Complaint”), pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Commissioners adopted a Joint Motion on January 24, 2013 (the “Joint Motion”) to adopt the Joint Settlement, with certain modifications. In addition to the commitments made by UGI Utilities in the Joint Settlement, the Joint Motion would require UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $386 to $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program, but would not require UGI Utilities to concede to having violated any regulation or operating procedure. We anticipate that the PUC Staff will issue in the near future a tentative order that incorporates the terms and conditions of the Joint Settlement, as modified. The provisions of the tentative order will become final and effective unless any party to the Joint Settlement objects to any of the terms and conditions included in the tentative order within five business days from the date of the issuance. The Company does not believe that the cost of complying with the requirements of the Joint Motion will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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Defined Benefit Pension and Other Postretirement Plans

3 Months Ended

Dec. 31, 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 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
	December 31,						December 31,
	2012			2011			2012			2011
Service cost	$	2,053		$	1,756		$	51		$	43
Interest cost	5,196			5,594			143			166
Expected return on assets	(6,198		)	(5,940		)	(132		)	(127		)
Amortization of:
Prior service cost (benefit)	—			62			(105		)	(106		)
Actuarial loss	3,428			1,963			91			99
Net benefit cost	4,479			3,435			48			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	863		$	859

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 Plan 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 $10,000 to the Pension Plan during the remainder of Fiscal 2013. During the three months endedDecember 31, 2012 and 2011, the Company made contributions to the Pension Plan of $5,730 and $4,106, 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 three months endedDecember 31, 2012 and 2011, nor are they expected to be material for all of Fiscal 2013.

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

3 Months Ended

Dec. 31, 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.

At December 31, 2012, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, two of which expire October 31, 2015 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 $4,324 and $4,921 during the three months ended December 31, 2012 and 2011, respectively. 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 $16,500 as of December 31, 2012, and $15,000 as of September 30, 2012 and December 31, 2011.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at December 31, 2012, comprising approximately 9.1 bcf of natural gas, was $27,251. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21,217. The carrying value of these gas storage inventories at December 31, 2011, comprising approximately 7.6 bcf of natural gas, was $35,230.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2012, totaled $17,825. During the three months ended December 31, 2011, such transactions totaled $22,365.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2012 and 2011, revenues associated with such sales to Energy Services totaled $19,824 and $17,081, 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 months ended December 31, 2012 and 2011, the aggregate amount of such purchases totaled $19,020 and $10,051, 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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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended							3 Months Ended					3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Energy Services [Member]	Dec. 31, 2011 Energy Services [Member]	Dec. 31, 2012 Inventories [Member] Energy Services [Member] ft3	Sep. 30, 2012 Inventories [Member] Energy Services [Member] ft3	Dec. 31, 2011 Inventories [Member] Energy Services [Member] ft3	Dec. 31, 2012 SCAAs [Member] Energy Services [Member]	Dec. 31, 2011 SCAAs [Member] Energy Services [Member]	Dec. 31, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Sep. 30, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Dec. 31, 2011 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Dec. 31, 2012 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Dec. 31, 2011 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]
Related Party Transaction [Line Items]
Related party costs incurred	$ 1,805	$ 2,125						$ 4,324	$ 4,921				$ 17,825	$ 22,365
Related party security deposits										16,500	15,000	15,000
Volume of gas storage inventory (in bcf of natural gas)					9,100,000,000	7,600,000,000	7,600,000,000
Natural gas storage inventory, related parties, current					27,251	21,217	35,230
Revenue from related parties			19,824	17,081
Purchases from related party			$ 19,020	$ 10,051

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Inventories (Tables)

3 Months Ended

Dec. 31, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:

	December 31, 2012		September 30, 2012		December 31, 2011
Gas Utility natural gas	$	51,838	$	57,663	$	87,735
Materials, supplies and other	10,023		9,671		9,716
Total inventories	$	61,861	$	67,334	$	97,451

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012 Segment	Dec. 31, 2011	Sep. 30, 2012
Segment Reporting [Abstract]
Number of reportable segments (in segments)	2
Segment Reporting Information [Line Items]
Revenues	$ 273,797	$ 280,641
Cost of sales	138,277	156,906
Depreciation and amortization	13,571	13,063
Operating income	72,564	64,605
Interest expense	10,077	10,607
Income before income taxes	62,487	53,998
Total assets (at period end)	2,319,704	2,238,458	2,223,179
Goodwill (at period end)	182,145	182,145	182,145
Capital expenditures	29,728	22,858
Gas Utility [Member]
Segment Reporting Information [Line Items]
Revenues	248,254	255,030
Cost of sales	123,574	141,679
Depreciation and amortization	12,605	12,145
Operating income	69,789	61,231
Interest expense	9,572	10,098
Income before income taxes	60,217	51,133
Total assets (at period end)	2,164,368	2,088,710
Goodwill (at period end)	182,145	182,145
Capital expenditures	28,519	21,812
Electric Utility [Member]
Segment Reporting Information [Line Items]
Revenues	25,118	25,169
Cost of sales	14,703	15,227
Depreciation and amortization	966	918
Operating income	2,624	3,230
Interest expense	505	509
Income before income taxes	2,119	2,721
Total assets (at period end)	155,336	149,748
Goodwill (at period end)	0	0
Capital expenditures	1,209	1,046
Other [Member]
Segment Reporting Information [Line Items]
Revenues	425	442
Cost of sales	0	0
Depreciation and amortization	0	0
Operating income	151	144
Interest expense	0	0
Income before income taxes	151	144
Total assets (at period end)	0	0
Goodwill (at period end)	0	0
Capital expenditures	$ 0	$ 0

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Net income	$ 36,812	$ 32,668
Net gains (losses) in fair value of derivative instruments (net of tax $(1,799) and $1,267, respectively)	2,537	(1,801)
Reclassifications of net losses on derivative instruments (net of tax of $(84) and $(121), respectively)	119	170
Benefit plans (net of tax of $(139) and $(99),respectively)	195	139
Other comprehensive income (loss)	2,851	(1,492)
Comprehensive income	$ 39,663	$ 31,176

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Accounting Changes

3 Months Ended

Dec. 31, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Accounting Changes

New Accounting Standard Not Yet Adopted

Disclosures about Offsetting Assets and Liabilities. In December 2011, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance requires 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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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Inventory, Net [Abstract]
Total inventories	$ 61,861	$ 67,334	$ 97,451
Gas Utility Natural Gas [Member]
Inventory, Net [Abstract]
Total inventories	51,838	57,663	87,735
Materials, Supplies and Other [Member]
Inventory, Net [Abstract]
Total inventories	$ 10,023	$ 9,671	$ 9,716

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Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 4,760	$ 18
Total Derivatives Liability	(39,453)	(37,782)
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative Financial Instruments, Liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(30,412)	(21,662)
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	4,226	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	420	18
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	(9,041)	(16,118)
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	114	0
Total Derivatives Liability	$ 0	$ (2)

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Segment Information (Tables)

3 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

Three Months EndedDecember 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	273,797	$	248,254	$	25,118	$	425
Cost of sales	$	138,277	$	123,574	$	14,703	$	—
Depreciation and amortization	$	13,571	$	12,605	$	966	$	—
Operating income	$	72,564	$	69,789	$	2,624	$	151
Interest expense	$	10,077	$	9,572	$	505	$	—
Income before income taxes	$	62,487	$	60,217	$	2,119	$	151
Total assets (at period end)	$	2,319,704	$	2,164,368	$	155,336	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,728	$	28,519	$	1,209	$	—

Three Months EndedDecember 31, 2011:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	280,641	$	255,030	$	25,169	$	442
Cost of sales	$	156,906	$	141,679	$	15,227	$	—
Depreciation and amortization	$	13,063	$	12,145	$	918	$	—
Operating income	$	64,605	$	61,231	$	3,230	$	144
Interest expense	$	10,607	$	10,098	$	509	$	—
Income before income taxes	$	53,998	$	51,133	$	2,721	$	144
Total assets (at period end)	$	2,238,458	$	2,088,710	$	149,748	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	22,858	$	21,812	$	1,046	$	—