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 March 31, 2013

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 April 30, 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 March 31, 2013, September 30, 2012 and March 31, 2012	1
Condensed Consolidated Statements of Income for the three and six months ended March 31, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2013 and 2012	3
Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2013 and 2012	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. Controls and Procedures	26
Part II Other Information
Item 1A. Risk Factors	27
Item 6. Exhibits	27
Signatures	28

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	March 31, 2013			September 30, 2012			March 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	58,329		$	1,259		$	46,593
Restricted cash	—			—			4,260
Accounts receivable (less allowances for doubtful accounts of $8,052, $3,588 and $8,900, respectively)	141,053			47,362			105,330
Accounts receivable — related parties	9,518			4,571			6,353
Accrued utility revenues	48,857			16,911			25,474
Inventories	16,215			67,334			23,640
Deferred income taxes	53,515			46,436			33,907
Regulatory assets	1,072			6,473			3,593
Derivative financial instruments	8,528			5,468			185
Prepaid expenses & other current assets	16,755			29,313			24,000
Total current assets	353,842			225,127			273,335
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $837,110, $815,720 and $800,423, respectively)	1,508,985			1,479,949			1,441,612
Goodwill	182,145			182,145			182,145
Regulatory assets	321,257			331,932			292,096
Other assets	2,808			4,026			4,718
Total assets	$	2,369,037		$	2,223,179		$	2,193,906
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	133,000		$	133,000		$	40,000
Bank loans	—			9,200			—
Accounts payable	48,099			46,754			27,180
Accounts payable — related parties	12,535			10,192			7,488
Deferred fuel refunds	31,209			4,435			12,022
Derivative financial instruments	29,077			36,011			11,404
Other current liabilities	149,801			131,092			149,357
Total current liabilities	403,721			370,684			247,451
Long-term debt	467,000			467,000			600,000
Deferred income taxes	433,868			417,052			367,088
Deferred investment tax credits	4,440			4,612			4,784
Pension and postretirement benefit obligations	174,905			179,056			130,731
Other noncurrent liabilities	53,965			56,262			81,441
Total liabilities	1,537,899			1,494,666			1,431,495
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	469,501			468,692			468,564
Retained earnings	324,450			229,379			253,631
Accumulated other comprehensive loss	(23,072		)	(29,817		)	(20,043		)
Total common stockholder’s equity	831,138			728,513			762,411
Total liabilities and stockholder’s equity	$	2,369,037		$	2,223,179		$	2,193,906

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					Six Months Ended
	March 31,					March 31,
	2013		2012			2013			2012
Revenues	$	395,901	$	345,802		$	669,698		$	626,443
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	212,785		192,770			351,062			349,676
Operating and administrative expenses	52,421		45,749			96,656			86,691
Operating and administrative expenses — related parties	3,012		2,781			4,817			4,906
Taxes other than income taxes	4,684		4,857			8,960			8,984
Depreciation	12,895		12,328			25,648			24,707
Amortization	817		782			1,635			1,466
Other loss (income), net	57		(1,912		)	(874		)	(3,039		)
	286,671		257,355			487,904			473,391
Operating income	109,230		88,447			181,794			153,052
Interest expense	9,820		10,677			19,897			21,284
Income before income taxes	99,410		77,770			161,897			131,768
Income taxes	41,151		29,899			66,826			51,229
Net income	$	58,259	$	47,871		$	95,071		$	80,539

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 March 31,				Six Months Ended March 31,
	2013		2012		2013		2012
Net income	$	58,259	$	47,871	$	95,071	$	80,539
Other comprehensive income:
Net gains in fair value of derivative instruments (net of tax of $(2,538), $(1,869), $(4,337) and $(592), respectively)	3,578		2,635		6,115		834
Reclassifications of net losses on derivative instruments (net of tax of $(84), $(403), $(168) and $(524), respectively)	118		570		237		740
Benefit plans (net of tax of $(139), $(81), $(278) and $(162), respectively)	198		77		393		216
Other comprehensive income	3,894		3,282		6,745		1,790
Comprehensive income	$	62,153	$	51,153	$	101,816	$	82,329

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)

	Six Months Ended
	March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	95,071		$	80,539
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	27,283			26,173
Deferred income taxes, net	4,241			12,229
Provision for uncollectible accounts	6,059			5,819
Other, net	7,537			(10,663		)
Net change in:
Accounts receivable and accrued utility revenues	(136,644		)	(62,385		)
Inventories	51,119			80,623
Deferred fuel and power costs	33,311			14,039
Accounts payable	3,688			(28,996		)
Other current assets	12,632			786
Other current liabilities	18,120			11,202
Net cash provided by operating activities	122,417			129,366
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(55,519		)	(49,784		)
Net costs of property, plant and equipment disposals	(1,437		)	(1,541		)
Decrease in restricted cash	—			48
Net cash used by investing activities	(56,956		)	(51,277		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	—			(39,004		)
Decrease in bank loans	(9,200		)	—
Other	809			241
Net cash used by financing activities	(8,391		)	(38,763		)
Cash and cash equivalents increase	$	57,070		$	39,326
CASH AND CASH EQUIVALENTS:
End of period	$	58,329		$	46,593
Beginning of period	1,259			7,267
Increase	$	57,070		$	39,326

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. Other comprehensive income 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 Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (AOCI). The new disclosure guidance is effective for fiscal years, and

- 5 -

interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. We are currently evaluating the impact of the new guidance on our future disclosures.

Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance, as amended, 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.

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 Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,369,037	$	2,205,516	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

Three Months Ended March 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	345,802	$	319,511	$	25,940	$	351
Cost of sales	$	192,770	$	177,492	$	15,278	$	—
Depreciation and amortization	$	13,110	$	12,159	$	951	$	—
Operating income	$	88,447	$	84,969	$	3,363	$	115
Interest expense	$	10,677	$	10,085	$	592	$	—
Income before income taxes	$	77,770	$	74,884	$	2,771	$	115
Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	26,926	$	25,654	$	1,272	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Six Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	669,698	$	616,889	$	52,069	$	740
Cost of sales	$	351,062	$	320,316	$	30,746	$	—
Depreciation and amortization	$	27,283	$	25,336	$	1,947	$	—
Operating income	$	181,794	$	175,538	$	6,013	$	243
Interest expense	$	19,897	$	18,899	$	998	$	—
Income before income taxes	$	161,897	$	156,639	$	5,015	$	243
Total assets (at period end)	$	2,369,037	$	2,205,516	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	55,519	$	52,949	$	2,570	$	—

Six Months Ended March 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	626,443	$	574,541	$	51,109	$	793
Cost of sales	$	349,676	$	319,171	$	30,505	$	—
Depreciation and amortization	$	26,173	$	24,304	$	1,869	$	—
Operating income	$	153,052	$	146,200	$	6,593	$	259
Interest expense	$	21,284	$	20,183	$	1,101	$	—
Income before income taxes	$	131,768	$	126,017	$	5,492	$	259
Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	49,784	$	47,466	$	2,318	$	—

5. Inventories

Inventories comprise the following:

	March 31, 2013		September 30, 2012		March 31, 2012
Gas Utility natural gas	$	5,366	$	57,663	$	12,761
Materials, supplies and other	10,849		9,671		10,879
Total inventories	$	16,215	$	67,334	$	23,640

At March 31, 2013, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

The carrying value of gas storage inventories released under the SCAAs at March 31, 2013, September 30, 2012 and March 31, 2012, comprising 1.0 billion cubic feet (“bcf”), 11.4 bcf and 1.8 bcf of natural gas, was $3,315, $32,627 and $7,661, respectively. In conjunction with the SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at March 31, 2013, and $22,500 at September 30, 2012 and March 31, 2012. 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:

	March 31, 2013		September 30, 2012		March 31, 2012
Regulatory assets:
Income taxes recoverable	$	104,229	$	103,172	$	99,226
Underfunded pension and postretirement plans	181,305		188,222		146,631
Environmental costs	16,841		16,812		18,247
Deferred fuel and power costs	2,122		11,602		11,012
Removal costs, net	11,856		12,718		11,915
Other	5,976		5,879		8,658
Total regulatory assets	$	322,329	$	338,405	$	295,689
Regulatory liabilities:
Postretirement benefits	$	13,865	$	13,147	$	12,053
Environmental overcollections	2,980		2,883		3,843
Deferred fuel and power refunds	31,209		4,435		12,022
State tax benefits — distribution system repairs	7,900		7,385		6,735
Other	700		494		747
Total regulatory liabilities	$	56,654	$	28,344	$	35,400

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 March 31, 2013, September 30, 2012, and March 31, 2012, were $4,129, $5,303 and $(3,113), 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 March 31, 2013, September 30, 2012, and March 31, 2012,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

the fair values of Electric Utility’s electricity supply contracts were net losses of $5,458, $9,207 and $14,747, 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 March 31, 2013, September 30, 2012, and March 31, 2012, 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, 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. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires 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. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11 mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (TL-96 line) to Energy Services.   The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line is approximately $2,500.

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
	March 31,						March 31,
	2013			2012			2013			2012
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			62			(105		)	(106		)
Actuarial loss	3,366			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 Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
Service cost	$	4,105		$	3,512		$	102		$	86
Interest cost	10,391			11,188			286			332
Expected return on assets	(12,396		)	(11,880		)	(264		)	(254		)
Amortization of:
Prior service cost (benefit)	124			124			(210		)	(212		)
Actuarial loss	6,732			3,926			182			198
Net benefit cost	8,956			6,870			96			150
Change in associated regulatory liabilities	—			—			1,630			1,568
Net expense	$	8,956		$	6,870		$	1,726		$	1,718

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 $9,409 to the Pension Plan during the remainder of Fiscal 2013. During the six months endedMarch 31, 2013 and 2012, the Company made contributions to the Pension Plan of $6,393 and $19,712, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas’ and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months endedMarch 31, 2013 and 2012, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At March 31, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,338 and $16,789, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

The Company does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 31, 2013, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 and settled all wrongful death claims and substantially all property and personal injury claims in connection with the Incident. UGI Utilities maintains liability insurance for personal injury, wrongful death and property and casualty damages subject to a $500 deductible. We expect that the remaining claims will be covered by UGI Utilities’ insurance. As a result, the Incident did not and we continue to believe it 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.

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 March 31, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, and 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 $702 and $5,026 during the three and six months ended March 31, 2013, respectively, and $408 and $5,330 during the three and six months ended March 31, 2012.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 March 31, 2013, and $15,000 as of September 30, 2012 and March 31, 2012.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

under the caption “Inventories.” The carrying value of these gas storage inventories at March 31, 2013, comprising approximately 1.0 bcf of natural gas, was $3,315. 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 March 31, 2012, comprising approximately 1.2 bcf of natural gas, was $4,725.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and six months ended March 31, 2013, totaled $14,701 and $32,526, respectively. During the three and six months ended March 31, 2012, such transactions totaled $8,386 and $30,752, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2013, revenues associated with such sales to Energy Services totaled $25,428 and $45,252, respectively. During the three and six months ended March 31, 2012, revenues associated with such sales to Energy Services totaled $23,574 and $40,656, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and six months ended March 31, 2013, the aggregate amount of such purchases totaled $18,213 and $37,233, respectively. During the three and six months ended March 31, 2012, such purchases totaled $13,267 and $23,319, 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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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 March 31, 2013, September 30, 2012 and March 31, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)
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	)
March 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	185		$	—		$	—	$	185
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,674	)	$	(13,228	)	$	—	$	(17,902	)
Interest rate contracts	$	—		$	(17,345	)	$	—	$	(17,345	)

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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 March 31, 2013, were $600,000 and $690,459, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2012, were $640,000 and $725,990, 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 March 31, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10 million dekatherms and 11.6 million dekatherms, respectively. At March 31, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 12 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 March 31, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $5,458 and $14,747, 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 March 31, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 403.2 million kilowatt hours and 707.4 million kilowatt hours, respectively. At March 31, 2013, the maximum period over which these contracts extend is 14 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 March 31, 2013 and 2012, the volumes associated with Electric Utility FTRs

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

totaled 47.5 million kilowatt hours and 52.2 million kilowatt hours, respectively. At March 31, 2013, the maximum period over which we are hedging electricity congestion with FTRs is 2 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. 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 March 31, 2013 and 2012, 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.

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

At March 31, 2013, 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 $1,179.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At March 31, 2013, there was no restricted cash in brokerage accounts. At March 31, 2012, restricted cash in brokerage accounts totaled $4,260.

- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,229	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(24,298	)	$	(17,345	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	4,130		1		Derivative financial instruments and Other noncurrent liabilities	(5,467		)	(17,902		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	169		184		Derivative financial instruments	—			—
Total Derivatives		$	8,528	$	185		$	(29,765	)	$	(35,247	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and six months ended March 31, 2013 and 2012:

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	6,116	$	4,504	$	(202	)	$	(973	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	107	$	257							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	10,452	$	1,427	$	(405	)	$	(1,264	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	105	$	205							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.

- 19 -

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 March 31, 2013 (“2013 three-month period”) with the three months ended March 31, 2012 (“2012 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.

2013 three-month period compared with 2012 three-month period

Three Months Ended March 31,	2013			2012			Increase
(Millions of dollars)
Gas Utility:
Revenues	$	368.6		$	319.5		$	49.1	15.4	%
Total margin (a)	$	171.9		$	142.0		$	29.9	21.1	%
Operating income	$	105.7		$	85.0		$	20.7	24.4	%
Income before income taxes	$	96.4		$	74.9		$	21.5	28.7	%
System throughput - bcf
Core market	34.9			27.1			7.8		28.8	%
Total	68.6			60.7			7.9		13.0	%
Heating degree days — % colder (warmer) than normal (b)	1.9		%	(19.3		)%	—		—
Electric Utility:
Revenues	$	27.0		$	25.9		$	1.1	4.2	%
Total margin (a)	$	9.5		$	9.3		$	0.2	2.2	%
Operating income	$	3.4		$	3.4		$	—	—	%
Income before income taxes	$	2.9		$	2.8		$	0.1	3.6	%
Distribution sales — gwh	282.8			258.6			24.2		9.4	%

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 $1.5 million and $1.4 million during the three-month periods ended March 31, 2013 and 2012, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.

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

Gas Utility. Temperatures in the Gas Utility service territory in the 2013 three-month period based upon heating degree days were 1.9% colder than normal and 24.8% colder than the record-setting warm temperatures experienced during the prior-year period. Total distribution system throughput increased principally reflecting greater throughput to core market 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, due principally to conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $49.1 million during the 2013 three-month period principally reflecting higher revenues from core market customers ($45.1 million) and greater revenues from firm and interruptible delivery service customers on higher volumes. The increase in core market revenues principally reflects the effects of the higher core market volumes partially offset by the effects of lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($22.4 million). Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market

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UGI UTILITIES, INC. AND SUBSIDIARIES

customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $196.7 million in the 2013 three-month period compared with $177.5 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($39.2 million) partially offset by the effects of lower average PGC rates.

Gas Utility total margin increased $29.9 million in the 2013 three-month period principally reflecting higher core market total margin ($24.6 million) and greater firm delivery service total margin. The higher core market total margin reflects the effects of the greater core market volumes.

The increases in Gas Utility operating income and income before income taxes during the 2013 three-month period principally reflect the increase in total margin ($29.9 million) partially offset by higher operating and administrative expenses including, among other things, higher distribution system expenses and greater pension expense.

Electric Utility. Temperatures based upon heating degree days during the 2013 three-month period were approximately 1.5% warmer than normal compared to temperatures that were 17.1% warmer than normal in the prior-year period. The increase in revenues reflects the effects of the higher sales principally a result of the colder weather partially offset by lower average default service (“DS”) rates reflecting the pass through of lower electricity costs. Electric Utility cost of sales increased to $16.0 million in the 2013 three-month period compared to $15.3 million in the 2012 three-month period principally reflecting the effects of the greater sales offset by the lower average DS rates.

Electric Utility total margin increased $0.2 million in the 2013 three-month period reflecting in large part the higher distribution sales.

Electric Utility 2013 three-month period operating income and income before income taxes were approximately equal to the prior years as the greater total margin ($0.2 million) offset by slightly higher operating and administrative costs.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2013three-month period was lower than the prior year principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the three months ended March 31, 2013, was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

2013 six-month period compared with 2012 six-month period

							Increase
Six Months Ended March 31,	2013			2012			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	616.9		$	574.5		$	42.4		7.4	%
Total margin (a)	$	296.6		$	255.4		$	41.2		16.1	%
Operating income	$	175.5		$	146.2		$	29.3		20.0	%
Income before income taxes	$	156.6		$	126.0		$	30.6		24.3	%
System throughput - bcf
Core market	56.7			46.4			10.3			22.2	%
Total	122.7			109.7			13.0			11.9	%
Heating degree days — % (warmer) than normal (b)	(0.4		)%	(16.3		)%	—			—
Electric Utility:
Revenues	$	52.1		$	51.1		$	1.0		2.0	%
Total margin (a)	$	18.5		$	17.8		$	0.7		3.9	%
Operating income	$	6.0		$	6.6		$	(0.6	)	(9.1	)%
Income before income taxes	$	5.0		$	5.5		$	(0.5	)	(9.1	)%
Distribution sales — gwh	531.0			502.6			28.4			5.7	%

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

(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 $2.8 million during each of the six-month periods ended March 31, 2013 and 2012. 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 2013 six-month period based upon heating degree days were 0.4% warmer than normal but 18.7% colder than the prior-year period. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $42.4 million during the 2013 six-month period principally reflecting higher revenues from core market customers ($42.4 million) and higher delivery service revenues ($6.9 million) partially offset by lower off-system sales revenues ($7.1 million). The increase in core market revenues principally reflects the effects of the higher core market volumes on PGC revenues ($51.7 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($45.6 million). Gas Utility’s cost of gas was $320.3 million in the 2013 six-month period compared with $319.2 million in the prior-year period principally reflecting the effects on cost of sales of the greater retail core-market volumes ($51.7 million) substantially offset by the effects of lower average PGC rates ($45.6 million) and the lower off-system sales.

Gas Utility total margin increased $41.2 million in the 2013 six-month period principally reflecting higher core market margin ($33.2 million) and higher firm delivery service total margin. The higher core market total margin reflects the effects of the greater core market volumes.

The increases in Gas Utility operating income and income before income taxes during the 2013 six-month period principally reflects the increase in total margin ($41.2 million) partially offset by higher operating and administrative expenses including, among other things, higher distribution system expenses and greater pension expense.

Electric Utility. Temperatures based upon heating degree days during the 2013 six-month period were approximately 1.5% warmer than normal but approximately 18% colder than the prior-year period. The increase in revenues reflects the effects of the higher sales principally a result of the colder weather partially offset by lower average DS rates reflecting the pass through of lower electricity costs. Electric Utility cost of sales increased to $30.7 million in the 2013 six-month period compared to $30.5 million in the 2012 six-month period principally reflecting the effects of the greater sales offset by the lower average DS rates.

Electric Utility total margin increased $0.7 million in the 2013 six-month period reflecting in large part the slightly higher distribution sales and greater transmission revenue.

Electric Utility 2013 six-month period operating income and income before income taxes decreased as the greater total margin ($0.7 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 2013 six-month period was lower than the prior-year period on lower long-term debt outstanding. Our effective income tax rate for the six months ended March 31, 2013, 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 March 31, 2013, was $600 million compared to debt outstanding of $609.2 million at September 30, 2012, which amount includes $9.2 million of bank loans. UGI Utilities’ total debt outstanding at March 31, 2013, comprises $383 million of Senior Notes and $217 million of Medium-Term Notes.

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 2013 and 2012six-month periods, average daily bank loan borrowings were $40.9 million and $31.9 million, respectively, and peak bank loan borrowings totaled $79 million and $70.6 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

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UGI UTILITIES, INC. AND SUBSIDIARIES

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 provided by operating activities was $122.4 million in the 2013 six-month period compared to $129.4 million in the prior-year six-month period. Cash flow from operating activities before changes in operating working capital was $140.2 million in the 2013 six-month period compared to $114.1 million recorded in the prior-year six-month period principally reflecting the greater 2013 six-month period operating results and lower pension plan contributions. Changes in operating working capital used $17.8 million of operating cash flow during the 2013 six-month period compared to $15.3 million of cash provided during the prior-year six-month period. The greater cash needed to fund changes in operating working capital in the 2013 six-month period reflects, among other things, greater cash required to fund changes in accounts receivable principally resulting from the greater sales in the current-year period and lower cash from changes in inventories. These increases in cash used by changes in operating working capital were partially offset by the timing and amount of cash provided by changes in accounts payable, current income taxes and deferred fuel collections.

Investing activities. Cash used by investing activities was $57.0 million in the 2013 six-month period compared to $51.3 million in the 2012 six-month period. Total capital expenditures were $55.5 million in the 2013 six-month period compared with $49.8 million recorded in the prior-year period. The 2013 six-month period principally reflects higher Gas Utility capital expenditures.

Financing activities. Cash used by financing activities was $8.4 million in the 2013 six-month period compared with cash used by financing activities of $38.8 million in the 2012 six-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 2013 six-month period there were net bank loan repayments of $9.2 million compared with no net borrowings or repayments during the prior-year six-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, 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. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires 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. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

gas futures contracts can require daily deposits of cash in futures accounts. At March 31, 2013 and September 30, 2012, UGI Utilities had no restricted cash associated with futures accounts. At March 31, 2012, UGI Utilities had $4.3 million of restricted cash associated with natural gas futures and option accounts with brokers. At March 31, 2013 and 2012, the fair values of our natural gas futures and option contracts were net gains (losses) of $4.1 million and $(3.1) 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 March 31, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $5.5 million and $14.7 million, respectively. At March 31, 2013 and 2012, the fair values of FTRs were not material.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair values of unsettled IRPAs held at March 31, 2013 and 2012, were losses of $20.1 million and $17.3 million, respectively. A hypothetical 10% adverse change in the six-month LIBOR would result in a decrease in fair value of $9.2 million at March 31, 2013.

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 March 31, 2013 and 2012, 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 (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2013.
10.2**	UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006, as amended as of November 16, 2012.
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2013.
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 March 31, 2013, 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 March 31, 2013, 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 March 31, 2013, 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.

** As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.

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UGI UTILITIES, INC. AND SUBSIDIARIES

SIGNATURES

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

		UGI Utilities, Inc. (Registrant)
Date:	May 10, 2013	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President — Finance and Chief Financial Officer
Date:	May 10, 2013	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2013.
10.2**	UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006, as amended as of November 16, 2012.
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2013.
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 March 31, 2013, 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 March 31, 2013, 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 March 31, 2013, 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.

**As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.

EX-10.1

EXHIBIT 10.1

Utilities Employees

UGI CORPORATION
2004 OMNIBUS EQUITY COMPENSATION PLANNONQUALIFIED STOCK OPTION GRANT LETTER

This STOCK OPTION GRANT, dated January 1, 2013 (the “Date of Grant”), is delivered by UGI Corporation (“UGI”) to ______________________ (the “Participant”).

RECITALS

The UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended (the “Plan”), provides for the grant of options to purchase shares of common stock of UGI. The Compensation and Management Development Committee of the Board of Directors of UGI (the “Committee”) has decided to make a stock option grant to the Participant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Option. Subject to the terms and conditions set forth in this Grant Letter and in the Plan, the Committee hereby grants to the Participant a nonqualified stock option (the “Option”) to purchase ______ shares of common stock of UGI (“Shares”) at an exercise price of $_____ per Share. The Option shall become exercisable according to Paragraph 2 below.

2.Exercisability of Option. The Option shall become exercisable on the following dates, if the Participant is employed by, or providing service to, the Company (as defined below) on the applicable date:

Date	Shares for Which the Option is Exercisable
January 1, 2014	33⅓%
January 1, 2015	33⅓%
January 1, 2016	33⅓%

The exercisability of the Option is cumulative, but shall not exceed 100% of the Shares subject to the Option. If the foregoing schedule would produce fractional Shares, the number of Shares for which the Option becomes exercisable shall be rounded down to the nearest whole Share.

3.Term of Option.

(a)The Option shall have a term of ten years from the Date of Grant and shall terminate at the expiration of that period (5:00 p.m. EST on December 31, 2022), unless it is terminated at an earlier date pursuant to the provisions of this Grant Letter or the Plan.

(b)If the Participant ceases to be employed by, or provide service to, the Company, the Option will terminate on the date the Participant ceases such employment or service. However, if the Participant ceases to be employed by, or provide service to, the Company by reason of one of the following events, the Option held by the Participant will thereafter be exercisable pursuant to the following terms:

(i)Termination Without Cause. If the Participant terminates employment or service on account of a Termination without Cause, the Option will thereafter be exercisable only with respect to that number of Shares with respect to which the Option is already exercisable on the date the Participant’s employment or service terminates, except as provided in subsection (v) below. Such portion of the Option will terminate upon the earlier of the expiration date of the Option or the expiration of the 13-month period commencing on the date the Participant ceases to be employed by, or provide service to, the Company.

(ii)Retirement. If the Participant ceases to be employed by, or provide service to, the Company on account of Retirement, the Option will thereafter become exercisable as if the Participant had continued to be employed by, or provide service to, the Company after the date of such Retirement. The Option will terminate upon the expiration date of the Option.

(iii)Disability. If the Participant ceases to be employed by, or provide service to, the Company on account of Disability, the Option will thereafter become exercisable as if the Participant had continued to provide service to the Company for 36 months after the date of such termination of employment or service. The Option will terminate upon the earlier of the expiration date of the Option or the expiration of such 36-month period.

(iv)Death. In the event of the death of the Participant while employed by, or providing service to, the Company, the Option will be fully and immediately exercisable and may be exercised at any time prior to the earlier of the expiration date of the Option or the expiration of the 12-month period following the Participant’s death. Death of the Participant after the Participant has ceased to be employed by, or provide service to, the Company will not affect the otherwise applicable period for exercise of the Option determined pursuant to subsections (i), (ii), (iii) or (v). After the Participant’s death, the Participant’s Option may be exercised by the Participant’s estate.

(v)Termination Without Cause or Good Reason Termination upon or within two years after a Change of Control. Notwithstanding the foregoing, if the Participant’s employment or service terminates on account of a Termination Without Cause or a Good Reason Termination upon or within two years after a Change of Control, the Option will be fully and immediately exercisable. The Option will terminate upon the earlier of the expiration date of the Option or the expiration of the 13-month period commencing on the date the Participant ceases to be employed by, or provide service to, the Company; provided that if the Participant is eligible for Retirement at the date of such termination of employment, the Option will terminate on the expiration date of the Option.

-2-

4.Exercise Procedures.

(a)Subject to the provisions of Paragraphs 2 and 3 above, the Participant may exercise part or all of the exercisable Option by giving UGI irrevocable written notice of intent to exercise on a form provided by UGI and delivered in the manner provided in Section 13 below. Payment of the exercise price and any applicable withholding taxes must be made prior to issuance of the Shares. The Participant shall pay the exercise price (i) in cash, (ii) by “net exercise,” which is the surrender of shares for which the Option is exercisable to the Company in exchange for a distribution of Shares equal to the amount by which the then fair market value of the Shares subject to the exercised Option exceeds the applicable Option Price, (iii) by payment through a broker in accordance with procedures acceptable to the Committee and permitted by Regulation T of the Federal Reserve Board or (iv) by such other method as the Committee may approve. The Committee may impose such limitations as it deems appropriate on the use of Shares to exercise the Option.

(b)The obligation of UGI to deliver Shares upon exercise of the Option shall be subject to all applicable laws, rules, and regulations and such approvals by governmental agencies as may be deemed appropriate by the Committee, including such actions as UGI’s counsel shall deem necessary or appropriate to comply with relevant securities laws and regulations. UGI may require that the Participant (or other person exercising the Option after the Participant’s death) represent that the Participant is purchasing Shares for the Participant’s own account and not with a view to or for sale in connection with any distribution of the Shares, or such other representation as UGI deems appropriate.

(c)All obligations of UGI under this Grant Letter shall be subject to the rights of the Company as set forth in the Plan to withhold amounts required to be withheld for any taxes, if applicable.

5.Definitions. Whenever used in this Grant Letter, the following terms shall have the meanings set forth below:

(a)“Change of Control” shall (i) have the meaning given that term in the Plan, or (ii) mean one of the events set forth on Exhibit A with respect to UGI Utilities, Inc.

(b)“Company” means UGI and its Subsidiaries (as defined in the Plan).

(c)“Disability” means a long-term disability as defined in the Company’s long-term disability plan applicable to the Participant.

(d)“Employed by, or provide service to, the Company” shall mean employment or service as an employee or director of the Company.

-3-

(e)“Good Reason Termination” shall mean a termination of employment or service initiated by the Participant upon or within two years after a Change of Control upon one or more of the following occurences:

(i)a material diminution in the authority, duties or responsibilities held by the Participant immediately prior to the Change of Control;

(ii)a material diminution in the Participant’s base salary as in effect immediately prior to the Change of Control; or

(iii)a material change in the geographic location at which the Participant must perform services (which, for purposes of this Agreement, means the Participant is required to report, other than on a temporary basis (less than 12 months), to a location which is more than 50 miles from the Participant’s principal place of business immediately preceding the Change of Control, without the Participant’s express written consent).

Notwithstanding the foregoing, the Participant shall be considered to have a Good Reason Termination only if the Participant provides written notice to the Company, pursuant to Section 13, specifying in reasonable detail the events or conditions upon which the Participant is basing such Good Reason Termination and the Participant provides such notice within 90 days after the event that gives rise to the Good Reason Termination. Within 30 days after notice has been provided, the Company shall have the opportunity, but shall have no obligation, to cure such events or conditions that give rise to the Good Reason Termination. If the Company does not cure such events or conditions within the 30-day period, the Participant may terminate employment or service with the Company based on Good Reason Termination within 30 days after the expiration of the cure period.

Notwithstanding the foregoing, if the Participant has in effect a Change in Control Agreement with the Company or an Affiliate, the term “Good Reason Termination” shall have the meaning given that term in the Change in Control Agreement.

(f)“Retirement” means the Participant’s retirement under the Retirement Income Plan for Employees of UGI Utilities, Inc., if the Participant is covered by that Retirement Income Plan. “Retirement” for other Company employees means termination of employment or service after attaining (i) age 55 with ten or more years of service with the Company or (ii) age 65 with five or more years of service with the Company.

(g)“Termination without Cause” means termination of employment or service by the Company for the convenience of the Company for any reason other than (i) misappropriation of funds, (ii) habitual insobriety or substance abuse adversely affecting the performance of duties, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance of duties, which gross negligence has had a material adverse effect on the business, operations, assets, properties or financial condition of the Company.

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6.Change of Control. If a Change of Control occurs, the Committee may take such actions with respect to the Option as it deems appropriate pursuant to the Plan. The Option shall not automatically become exercisable upon a Change of Control but, instead, shall become exercisable as described in Sections 2 and 3 above.

7.Restrictions on Exercise. Except as the Committee may otherwise permit pursuant to the Plan, only the Participant may exercise the Option during the Participant’s lifetime and, after the Participant’s death, the Option shall be exercisable by the Participant’s estate, to the extent that the Option is exercisable pursuant to this Grant Letter.

8.Grant Subject to Plan Provisions and Company Policies.

(a)This grant is made pursuant to the Plan, which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and exercise of the Option are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Committee in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares, (ii) changes in capitalization of the Company and (iii) other requirements of applicable law. The Committee shall have the authority to interpret and construe the Option pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)All Shares issued pursuant to this Option grant shall be subject to the UGI Corporation Stock Ownership Policy. This Option grant and all Shares issued pursuant to this Option grant shall be subject to any applicable clawback and other policies implemented by the Board of Directors of UGI, as in effect from time to time.

9.No Employment or Other Rights. The grant of the Option shall not confer upon the Participant any right to be retained by or in the employ or service of the Company and shall not interfere in any way with the right of the Company to terminate the Participant’s employment or service at any time. The right of the Company to terminate at will the Participant’s employment or service at any time for any reason is specifically reserved.

10.No Shareholder Rights. Neither the Participant, nor any person entitled to exercise the Participant’s rights in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to the Shares subject to the Option, until certificates for Shares have been issued upon the exercise of the Option.

11.Assignment and Transfers. The rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. The rights and protections of the Company hereunder shall extend to any successors or assigns of the Company and to the Company’s parents, subsidiaries, and affiliates.

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12.Applicable Law. The validity, construction, interpretation and effect of this instrument shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

13.Notice. Any notice to UGI provided for in this instrument shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the payroll of the Company, or to such other address as the Participant may designate to the Company in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

IN WITNESS WHEREOF, UGI has caused its duly authorized officers to execute and attest this Grant Letter, and the Participant has executed this Grant Letter, effective as of the Date of Grant.

UGI Corporation

Attest

By:

I hereby acknowledge receipt of the Plan. I accept the Option described in this Grant Letter, and I agree to be bound by the terms of the Plan and this Grant Letter. I hereby further agree that all the decisions and determinations of the Committee shall be final and binding on me and any other person having or claiming a right under this grant.

Participant

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EXHIBIT A

Change of Control with Respect to Utilities

For Participants who are employees of Utilities, or a subsidiary of Utilities, the term “Change of Control” shall include the events set forth in this Exhibit A with respect to Utilities, and the defined terms set forth used in this Exhibit A, if not defined in the Plan, shall have the following meanings:

1.    “Change of Control” shall include any of the following events:

(A)    UGI and the UGI Subsidiaries fail to own more than fifty percent (50%) of the then outstanding shares of common stock of Utilities or more than fifty percent (50%) of the combined voting power of the then outstanding voting securities of Utilities entitled to vote generally in the election of directors; or

(B)    Completion by Utilities of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of Utilities’ outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of Utilities’ outstanding common stock and voting securities, as the case may be; or

(C)    Completion of a complete liquidation or dissolution of the Utilities or sale or other disposition of all or substantially all of the assets of Utilities other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of Utilities’ outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of Utilities’ outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.

2.    “Affiliate” and “Associate” shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.

3.    A Person shall be deemed the “Beneficial Owner” of any securities: (i) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of

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conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a person shall not be deemed the “Beneficial Owner” of securities tendered pursuant to a tender or exchange offer made by such Person or any of such person’s Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a Person shall not be deemed the “Beneficial Owner” of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such Person (or any of such Person’s Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any securities; provided, however, that nothing in this Section 1(c) shall cause a Person engaged in business as an underwriter of securities to be the “Beneficial Owner” of any securities acquired through such Person’s participation in good faith in a firm commitment underwriting until the expiration of forty (40) days after the date of such acquisition.

4.    “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

5.    “Person” shall mean an individual or a corporation, partnership, trust, unincorporated organization, association, or other entity.

6.    “UGI Subsidiary” shall mean any corporation in which UGI directly or indirectly, owns at least a fifty percent (50%) interest or an unincorporated entity of which UGI, as applicable, directly or indirectly, owns at least fifty percent (50%) of the profits or capital interests.

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EX-10.2

EXHIBIT 10.2

UGI UTILITIES, INC.

EXECUTIVE ANNUAL BONUS PLAN

(As amended as of November 16, 2012)

I.Purpose. The purpose of the UGI Utilities, Inc. Executive Annual Bonus Plan (the “Plan”) is to provide a means whereby UGI Utilities, Inc. (the “Company”) may provide incentive compensation to its eligible employees to serve as an incentive for employee performance and retention. The Plan is intended to encourage eligible employees to contribute to the overall success of the Company. The Plan is part of a total compensation structure under which a meaningful portion of eligible employees’ total compensation is based on achievement of performance goals relating to the eligible employees’ business and/or area of responsibility. The Plan was originally effective as of October 1, 2006 and has been amended and restated as of November 16, 2012.

II.Definitions. Whenever used in this Plan, the following terms will have the respective meanings set forth below:

2.1“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

2.2“Board” means the board of directors of the Company as constituted from time to time.

2.3“Code” means the Internal Revenue Code of 1986, as amended.

2.4“Committee” means (i) for Senior Management, the Compensation and Management Development Committee of the Board or its successor and (ii) for eligible employees who are not members of Senior Management, the Chief Executive Officer of the Company or his designee.

2.5“Company” means UGI Utilities, Inc., a Pennsylvania corporation, or any successor thereto.

2.6“Employer” means the Company and its Affiliates.

2.7“Equity Plan” means the UGI Corporation 2013 Omnibus Incentive Compensation Plan, as in effect from time to time, or a successor plan.

2.8“Participant” means an eligible employee or other individual who provides services to the Company or its Affiliates and who is described in Section III as a participant in the Plan.

2.9“Plan” means this UGI Utilities, Inc. Executive Annual Bonus Plan, as in effect from time to time.

2.10“Senior Management” means those employees who are designated as executive officers by the Board pursuant toRule 3b-7of the rules promulgated pursuant to the Securities Exchange Act of 1934, as amended.

2.11“Stock Award” shall have the meaning given that term under the Equity Plan.

III.Participation. All salaried employees of the Company and its Affiliates in grade level 34 or above shall be eligible to participate in the Plan for each fiscal year. The Company’s fiscal year begins on October 1. The Committee may also designate in writing that one or more senior level employees of an Affiliate shall be Participants in the Plan for a fiscal year, in its sole discretion.

IV.Annual Bonus.

4.1Target Bonus. At the beginning of each fiscal year, the Committee shall establish target bonuses as a percentage of each Participant’s salary for the fiscal year. Each Participant shall be eligible to receive an annual bonus for the fiscal year based on the achievement of business/financial performance goals, and the Participant’s individual performance goals, if applicable, during the fiscal year. The amount actually paid to a Participant may be more or less than the target bonus amount, depending on the extent to which the performance goals are satisfied.

4.2Performance Goals.

(a)Business/Financial Goals. At the beginning of each fiscal year, the Committee shall establish the business/financial performance goals for the fiscal year and leverage tables that apply to the performance goals.

(b)Individual Goals. The Committee shall determine which Participants shall have individual performance goals as part of their bonus calculation. At the beginning of each fiscal year, the Committee shall establish each Participant’s individual performance goals for the year, if applicable, and shall set leverage tables that will apply to individual performance goals. The portion of the target bonus attributable to individual performance will be payable only if the business/financial performance goals are achieved at the threshold level of performance.

(c)Weighting. At the time the Committee establishes performance goals for each fiscal year, the Committee will determine the weighting for each Participant with respect to the business/financial goals and the individual goals. The weighting of the two types of goals need not be uniform as to all Participants.

(d)Communication of Goals. The Committee shall provide for the communication of the performance goals and corresponding leverage tables to the Participants.

4.3Determination and Approval of Bonus Payments.

(a)At the end of the fiscal year, the Committee shall determine the amount of each Participant’s bonus, if any, based on the achievement of the business/financial performance goals and, if applicable, the achievement of the individual performance goals. The Committee shall have sole discretion to determine whether and to what extent the performance goals have been met. The Committee may adjust the performance results for extraordinary items or other events, as the Committee deems appropriate.

(b)If the thresholdlevel of business/financial performance is not achieved, no bonuses will be paid.

(c)With respect to Participants whose annual bonus under the Plan is based solely on the achievement of business/financial performance goals, the Committee shall have discretion to increase or decrease the amount of the annual bonus by 50% more or less than the amount otherwise determined, based on the Participant’s contribution to the achievement of the business/financial performance goals, other contributions that have a significant impact on Company performance, or other factors.

4.4Newly Hired Employees, Promotions and Transfers. Employees who are newly hired or who are promoted or transferred into a position eligible to participate in the Plan during the fiscal year may be eligible to receive a prorated bonus award calculated in whole months based on the relative time spent in the eligible position during the fiscal year, as determined by the Committee. If a Participant is transferred to an Affiliate of the Company (or into a position with a different annual bonus target percentage)during the fiscal year, the Participant’s performance goals may be adjusted to reflect the change in Employer or position. If a Participant is transferred into a position that is not eligible to participate in the Plan during the fiscal year, the Participant may be eligible to receive a prorated award calculated in whole months based on the relative time spent in the eligible position during the fiscal year, as determined by the Committee.

4.5Payment of Annual Bonus. Each annual bonus for a fiscal year shall be paid to the Participant in a single lump sum payment between September 30 and December 31 of the calendar year in which the fiscal year ends, except as provided below. Annual bonuses for a fiscal year shall be paid in cash; provided that the Committee may determine that part or all of a Participant’s annual bonus shall be paid in the form of a Stock Award under the Equity Plan. Unless the Committee determines otherwise, to the extent that an officer of the Company who is subject to Section 16(b) of the Securities Exchange Act of 1934, as amended, shall not have satisfied any ownership requirement then applicable to such officer, as set forth in the UGI Corporation Stock Ownership Policy, up to 10% of the gross amount of the officer’s annual bonus shall be paid in fully vested Stock Awards under the Equity Plan.

4.6Withholding Tax. Each Employer shall withhold from each bonus payment an amount sufficient to satisfy all federal, state and local tax withholding requirements relating to the bonus. Unless the Committee determines otherwise, withholding taxes with respect to any portion of a bonus paid in the form of a Stock Award shall be deducted from the cash portion of such bonus.

V.Termination of Employment. Except as provided below, a Participant must be employed by the Employer on the last day of the fiscal year for which the bonus is earned in order to receive a bonus for the year. If a Participant’s employment terminates on account of retirement, death or disability, the Committee may determine in its sole discretion that an annual bonus will be paid for the year of termination. The Committee may take into account factors such as Company performance, individual performance and the portion of the year elapsed prior to termination. The annual bonus, if any, shall be paid within 60 days after the date of termination.

VI.Administration. The Committee administers the Plan. The Committee shall have full power and discretionary authority to interpret and administer the Plan, to make all determinations, including all participation and bonus determinations, and to prescribe, amend and rescind any rules, forms or procedures as the Committee deems necessary or appropriate for the proper administration of the Plan and to make any other determinations and take such other actions as the Committee deems necessary or advisable in carrying out its duties under the Plan. Any action required of the Committee under the Plan shall be made in the Committee’s sole discretion and not in a fiduciary capacity. All decisions and determinations by the Committee shall be final, conclusive and binding on the Company, the Participants, and any other persons having or claiming an interest hereunder.All bonuses shall be awarded conditional upon the Participant’s acknowledgement, by continuing in employment with the Employer, that all decisions and determinations of the Committee shall be final and binding on the Participant, his or her beneficiaries and any other person having or claiming an interest in such bonus.

VII.General Provisions.

7.1Transferability. No bonus under this Plan shall be transferred, assigned, pledged or encumbered by the Participant nor shall it be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. In the event of a Participant’s death, any amounts payable under this Plan, as determined by the Committee, shall be paid to the Participant’s estate.

7.2Unfunded Arrangement. The Plan is an unfunded incentive compensation arrangement. Nothing contained in the Plan, and no action taken pursuant to the Plan, shall create or be construed to create a trust of any kind. Each Participant’s right to receive a bonus shall be no greater than the right of an unsecured general creditor of the Employer. All bonuses shall be paid from the general funds of the Employer, and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of bonuses.

7.3No Rights to Employment. Nothing in the Plan, and no action taken pursuant hereto, shall confer upon a Participant the right to continue in the employ of the Employer, or affect the right of the Employer to terminate a Participant’s employment at any time for cause or for no cause whatsoever.

7.4Section 409A. The Plan is intended to comply with the short-term deferral rule set forth in the regulations under section 409A of the Code, in order to avoid application of section 409A to the Plan. If and to the extent that any payment under this Plan is deemed to be deferred compensation subject to the requirements of section 409A, this Plan shall be administered so that such payments are made in accordance with the requirements of section 409A.

7.5Termination and Amendment of the Plan. The Compensation and Management Development Committee may amend or terminate the Plan at any time.

7.6Successors. The Plan shall be binding upon and inure to the benefit of the Employer, its successors and assigns, and each Participant and his or her heirs, executors, administrators and legal representatives.

7.7Applicable Law. The Plan shall be construed and governed in accordance with the laws of the Commonwealth of Pennsylvania.

EX-10.3

EXHIBIT 10.3

Utilities Employees

UGI CORPORATION
2013 OMNIBUS INCENTIVE COMPENSATION PLANPERFORMANCE UNIT GRANT LETTER

This PERFORMANCE UNIT GRANT, dated January 1, 2013 (the “Date of Grant”), is delivered by UGI Corporation (“UGI”) to _______________________ (the “Participant”).

RECITALS

The UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “Plan”) provides for the grant of performance units (“Performance Units”) with respect to shares of common stock of UGI (“Shares”). The Compensation and Management Development Committee of the Board of Directors of UGI (the “Committee”) has decided to grant Performance Units to the Participant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Performance Units. Subject to the terms and conditions set forth in this Grant Letter and in the Plan, the Committee hereby grants to the Participant a target award of __________ Performance Units (the “Target Award”). The Performance Units are contingently awarded and will be earned and payable if and to the extent that the Performance Goals (defined below) and other conditions of the Grant Letter are met. The Performance Units are granted with Dividend Equivalents (as defined in Section 7).

2.Performance Goals.

(a)The Participant shall earn the right to payment of the Performance Units if the Performance Goals are met for the Performance Period, and if the Participant continues to be employed by, or provide service to, the Company (as defined in Section 7) through December 31, 2015. The Performance Period is the period beginning January 1, 2013 and ending December 31, 2015. The Total Shareholder Return (“TSR”) goals and other requirements of this Section 2 are referred to as the “Performance Goals.”

(b)The Target Award level of Performance Units and Dividend Equivalents will be payable if UGI’s TSR equals the median TSR of the comparison group designated by the Committee (the “Peer Group”) for the Performance Period. The Peer Group is the group of companies that comprises the Russell Midcap Utilities Index, excluding telecommunications companies, as of the beginning of the Performance Period, as set forth on the attached Exhibit A, and as described herein. If a company is added to the Russell Midcap Utilities Index during the Performance Period, that company is not included in the TSR calculation. A company that is included in the Russell Midcap Utilities Index at the beginning of the Performance Period will be

removed from the TSR calculation only if the company ceases to exist as a publicly traded company during the Performance Period (including by way of a merger or similar transaction in which the company is not the surviving company), consistent with the methodology described in subsection (c) below. Companies that are designated at the beginning of the Performance Period as telecommunications companies in the Russell Midcap Utilities Index shall be excluded from the TSR calculation. The actual amount of the award of Performance Units may be higher or lower than the Target Award, or it may be zero, based on UGI’s TSR percentile rank relative to the companies in the Peer Group, as follows:

UGI’s TSR RankPercentage of Target Award Earned(Percentile)

90th                        200%

75th                        162.5%

60th                        125%

50th                        100%

40th                         70%

25th                         25%

Less than 25th                     0%

The award percentage earned will be interpolated between each of the measuring points.

(c)TSR shall be calculated by UGI using the comparative returns methodology used by Bloomberg L.P. or its successor at the time of the calculation. The share price used for determining TSR at the beginning and the end of the Performance Period will be the average price for the calendar quarter preceding the beginning of the Performance Period (i.e., the calendar quarter ending on December 31, 2012) and the calendar quarter ending on the last day of the Performance Period (i.e., the calendar quarter ending on December 31, 2015), respectively. The TSR calculation gives effect to all dividends throughout the three-year Performance Period as if they had been reinvested.

(d)The Target Award is the amount designated for 100% (50th TSR rank) performance. The Participant can earn up to 200% of the Target Award if UGI’s TSR percentile rank exceeds the 50th TSR percentile rank, according to the foregoing schedule.

(e)At the end of the Performance Period, the Committee will determine whether and to what extent the Performance Goals have been met and the amount to be paid with respect to the Performance Units. Except as described in Sections 3 and 6 below, the Participant must be employed by, or providing service to, the Company on December 31, 2015 in order for the Participant to receive payment with respect to the Performance Units.

3.Termination of Employment or Service.

(a)Except as described below, if the Participant ceases to be employed by, or provide services to, the Company before December 31, 2015, the Performance Units and all Dividend Equivalents credited under this Grant Letter will be forfeited.

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(b)If the Participant terminates employment or service on account of Retirement (as defined in Section 7), Disability (as defined in Section 7) or death, the Participant will earn a pro-rata portion of the Participant’s outstanding Performance Units and Dividend Equivalents, if the Performance Goals and the requirements of this Grant Letter are met. The prorated portion will be determined as the amount that would otherwise be paid after the end of the Performance Period, based on achievement of the Performance Goals, multiplied by a fraction, the numerator of which is the number of calendar years during the Performance Period in which the Participant has been employed by, or provided service to, the Company and the denominator of which is three. For purposes of the proration calculation, the calendar year in which the Participant’s termination of employment or service on account of Retirement, Disability, or death occurs will be counted as a full year.

(c)In the event of termination of employment or service on account of Retirement, Disability or death, the prorated amount shall be paid after the end of the Performance Period, pursuant to Section 4 below, except as provided in Section 6.

4.Payment with Respect to Performance Units. If the Committee determines that the conditions to payment of the Performance Units have been met, the Company shall pay to the Participant (i) Shares equal to the number of Performance Units to be paid according to achievement of the Performance Goals, up to the Target Award, provided that the Company may withhold Shares to cover required tax withholding in an amount equal to the minimum statutory tax withholding requirement in respect of the Performance Units earned up to the Target Award, and (ii) cash in an amount equal to the Fair Market Value (as defined in the Plan) of the number of Shares equal to the Performance Units to be paid in excess of the Target Award, subject to applicable tax withholding. Payment shall be made between January 1, 2016 and March 15, 2016, except as provided in Section 6 below.

5.Dividend Equivalents with Respect to Performance Units.

(a)Dividend Equivalents shall accrue with respect to Performance Units and shall be payable subject to the same Performance Goals and terms as the Performance Units to which they relate. Dividend Equivalents shall be credited with respect to the Target Award of Performance Units from the Date of Grant until the payment date. If and to the extent that the underlying Performance Units are forfeited, all related Dividend Equivalents shall also be forfeited.

(b)While the Performance Units are outstanding, the Company will keep records of Dividend Equivalents in a bookkeeping account for the Participant. On each payment date for a dividend paid by UGI on its common stock, the Company shall credit to the Participant’s account an amount equal to the Dividend Equivalents associated with the Target Award of Performance Units held by the Participant on the record date for the dividend. No interest will be credited to any such account.

(c)The target amount of Dividend Equivalents (100% of the Dividend Equivalents credited to the Participant’s account) will be earned if UGI’s TSR rank is at the 50th TSR percentile rank for the Performance Period. The Participant can earn up to 200% of the target

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amount of Dividend Equivalents if UGI’s TSR percentile rank exceeds the 50th TSR rank, according to the schedule in Section 2 above. Except as described in Section 3(b) above, or Section 6, if the Participant’s employment or service with the Company terminates before December 31, 2015, all Dividend Equivalents will be forfeited.

(d)Dividend Equivalents will be paid in cash at the same time as the underlying Performance Units are paid, after the Committee determines that the conditions to payment have been met. Notwithstanding anything in this Grant Letter to the contrary, the Participant may not accrue Dividend Equivalents in excess of $1,000,000 during any calendar year under all grants under the Plan.

6.Change of Control.

(a)If a Change of Control occurs, the Performance Units and Dividend Equivalents shall not automatically become payable upon the Change of Control, but, instead, shall become payable as described in this Section 6. The Committee may take such other actions with respect to the Performance Units and Dividend Equivalents as it deems appropriate pursuant to the Plan. For Participants who are employees of UGI Utilities, Inc. (“Utilities”) or a subsidiary of Utilities, the term “Change of Control” shall mean (i) a Change of Control of UGI as defined in the Plan, or (ii) one of the events set forth on Exhibit B with respect to Utilities.

(b)If a Change of Control occurs during the Performance Period, the Committee shall calculate a Change of Control Amount as follows:

(i)The Performance Period shall end as of the closing date of the Change of Control (the “Change of Control Date”) and the TSR ending date calculation for the Performance Period shall be based on the 90 calendar day period ending on the Change of Control Date.

(ii)The Committee shall calculate a “Change of Control Amount” equal to the greater of (i) the Target Award amount or (ii) the amount of Performance Units that would be payable based on the Company’s achievement of the Performance Goals as of the Change of Control Date, as determined by the Committee. The Change of Control Amount shall include related Dividend Equivalents and, if applicable, interest as described below.

(iii)The Committee shall determine whether the Change of Control Amount attributable to Performance Units shall be (A) converted to units with respect to shares or other equity interests of the acquiring company or its parent (“Successor Units”), in which case Dividend Equivalents shall continue to be credited on the Successor Units, or (B) valued based on the Fair Market Value of the Performance Units as of the Change of Control Date and credited to a bookkeeping account for the Participant, in which case interest shall be credited on the amount so determined at a market rate for the period between the Change of Control Date and the applicable payment date.  Notwithstanding the provisions of Section 4, all payments on and after a Change of Control shall be made in cash.  If alternative (A) above is used, the cash payment shall equal the Fair Market

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Value on the date of payment of the number of shares or other equity interests underlying the Successor Units, plus accrued Dividend Equivalents.  All payments shall be subject to applicable tax withholding. 

(c)If a Change of Control occurs during the Performance Period and the Participant continues in employment or service through December 31, 2015, the Change of Control Amount shall be paid in cash between January 1, 2016 and March 15, 2016.

(d)If a Change of Control occurs during the Performance Period, and the Participant has a Termination without Cause or a Good Reason Termination upon or within two years after the Change of Control Date and before December 31, 2015, the Change of Control Amount shall be paid in cash within 30 days after the Participant’s separation from service, subject to Section 13 below.

(e)If a Change of Control occurs during the Performance Period, and the Participant terminates employment or service on account of Retirement, Disability or death upon or after the Change of Control Date and before December 31, 2015, the Change of Control Amount shall be paid in cash within 30 days after the Participant’s separation from service, subject to Section 13 below; provided that, if required by section 409A, if the Participant’s Retirement, Disability or death occurs more than two years after the Change of Control Date, payment will be made between January 1, 2016 and March 15, 2016, and not upon the earlier separation from service.

(f)If a Participant’s employment or service terminates on account of Retirement, death or Disability before a Change of Control, and a Change of Control subsequently occurs before the end of the Performance Period, the prorated amount in Section 3(b) shall be calculated by multiplying the fraction described in Section 3(b) by the Change of Control Amount. The prorated Change of Control Amount shall be paid in cash within 30 days after the Change of Control Date, subject to Section 13 below.

7.Definitions. For purposes of this Grant Letter, the following terms will have the meanings set forth below:

(a)“Company” means UGI and its Subsidiaries (as defined in the Plan).

(b)“Disability” means a long-term disability as defined in the Company’s long-term disability plan applicable to the Participant.

(c)“Dividend Equivalent” means an amount determined by multiplying the number of shares of UGI common stock subject to the target award of Performance Units by the per-share cash dividend, or the per-share fair market value of any dividend in consideration other than cash, paid by UGI on its common stock.

(d)“Employed by, or provide service to, the Company” shall mean employment or service as an employee or director of the Company. The Participant shall not be considered to have a termination of employment or service under this Grant Letter until the Participant is no longer employed by, or performing services for, the Company.

5

(e)“Good Reason Termination” shall mean a termination of employment or service initiated by the Participant upon or after a Change of Control upon one or more of the following events:

(i)a material diminution in the authority, duties or responsibilities held by the Participant immediately prior to the Change of Control;

(ii)a material diminution in the Participant’s base salary as in effect immediately prior to the Change of Control; or

(iii)a material change in the geographic location at which the Participant must perform services (which, for purposes of this Agreement, means the Participant is required to report, other than on a temporary basis (less than 12 months), to a location which is more than 50 miles from the Participant’s principal place of business immediately before the Change of Control, without the Participant’s express written consent).

Notwithstanding the foregoing, the Participant shall be considered to have a Good Reason Termination only if the Participant provides written notice to the Company, pursuant to Section 15, specifying in reasonable detail the events or conditions upon which the Participant is basing such Good Reason Termination and the Participant provides such notice within 90 days after the event that gives rise to the Good Reason Termination. Within 30 days after notice has been provided, the Company shall have the opportunity, but shall have no obligation, to cure such events or conditions that give rise to the Good Reason Termination. If the Company does not cure such events or conditions within the 30-day period, the Participant may terminate employment or service with the Company based on Good Reason Termination within 30 days after the expiration of the cure period.

Notwithstanding the foregoing, if the Participant has in effect a Change in Control Agreement with the Company or an Affiliate, the term “Good Reason Termination” shall have the meaning given that term in the Change in Control Agreement.

(f)“Performance Unit” means a hypothetical unit that represents the value of one share of UGI common stock.

(g)Retirement” means the Participant’s retirement under the Retirement Income Plan for Employees of UGI Utilities, Inc., if the Participant is covered by that Retirement Income Plan. “Retirement” for other Company employees means termination of employment or service after attaining (i) age 55 with ten or more years of service with the Company or (ii) age 65 with five or more years of service with the Company.

(h)“Termination without Cause” means termination of employment or service by the Company for the convenience of the Company for any reason other than (i) misappropriation of funds, (ii) habitual insobriety or substance abuse adversely affecting the performance of duties, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance

6

of duties, which gross negligence has had a material adverse effect on the business, operations, assets, properties or financial condition of the Company.

8.Withholding. All payments under this Grant Letter are subject to applicable tax withholding. The Participant shall be required to pay to the Company, or make other arrangements satisfactory to the Company to provide for the payment of, any federal (including FICA), state, local or other taxes that the Company is required to withhold with respect to the payments under this Grant Letter. The Company may withhold from cash distributions to cover required tax withholding, or may withhold Shares to cover required tax withholding in an amount equal to the minimum applicable tax withholding amount.

9.Grant Subject to Plan Provisions and Company Policies.

(a)This grant is made pursuant to the Plan, which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and payment of Performance Units and Dividend Equivalents are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Committee in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares, (ii) adjustments pursuant to Section 5(d) of the Plan, and (iii) other requirements of applicable law. The Committee shall have the authority to interpret and construe the grant pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)This Performance Unit grant and Shares issued pursuant to this Performance Unit grant shall be subject to the UGI Corporation Stock Ownership Policy as adopted by the Board of Directors of UGI and any applicable clawback and other policies implemented by the Board of Directors of UGI, as in effect from time to time.

10.No Employment or Other Rights. The grant of Performance Units shall not confer upon the Participant any right to be retained by or in the employ or service of the Company and shall not interfere in any way with the right of the Company to terminate the Participant’s employment or service at any time. The right of the Company to terminate at will the Participant’s employment or service at any time for any reason is specifically reserved.

11.No Shareholder Rights. Neither the Participant, nor any person entitled to receive payment in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to the Shares related to the Performance Units, unless and until certificates for Shares have been distributed to the Participant or successor.

12.Assignment and Transfers. The rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. If the Participant dies, any payments to be made under this Grant Letter after the Participant’s death shall be paid to the Participant’s estate. The rights and protections of the Company hereunder shall extend to any successors or assigns of the Company and to the Company’s parents, subsidiaries, and affiliates.

7

13.Compliance with Code Section 409A. Notwithstanding the other provisions hereof, this Grant Letter is intended to comply with the requirements of section 409A of the Internal Revenue Code of 1986, as amended, or an exception, and shall be administered accordingly. Any reference to a Participant’s termination of employment shall mean a Participant’s “separation from service,” as such term is defined under section 409A. For purposes of section 409A, each payment of compensation under this Grant Letter shall be treated as a separate payment. Notwithstanding anything in this Grant Letter to the contrary, if the Participant is a “key employee” under section 409A and if payment of any amount under this Grant Letter is required to be delayed for a period of six months after separation from service pursuant to section 409A, payment of such amount shall be delayed as required by section 409A and shall be paid within 10 days after the end of the six-month period. If the Participant dies during such six-month period, the amounts withheld on account of section 409A shall be paid to the personal representative of the Participant’s estate within 60 days after the date of the Participant’s death. Notwithstanding anything in this Grant Letter to the contrary, if a Change of Control is not a “change in control event” under section 409A, any Performance Units and Dividend Equivalents that are payable pursuant to Section 6 shall be paid to the Participant between January 1, 2016 and March 15, 2016, and not upon the earlier separation from service, if required by section 409A.

14.Applicable Law. The validity, construction, interpretation and effect of this Grant Letter shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

15.Notice. Any notice to UGI provided for in this Grant Letter shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the payroll of the Company, or to such other address as the Participant may designate to the Company in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

IN WITNESS WHEREOF, UGI has caused its duly authorized officers to execute and attest this Grant Letter, and the Participant has executed this Grant Letter, effective as of the Date of Grant.

UGI Corporation

Attest

By:

I hereby acknowledge receipt of the Plan incorporated herein. I accept the Performance Units described in this Grant Letter, and I agree to be bound by the terms of the Plan, and this Grant

8

Letter. I hereby further agree that all the decisions and determinations of the Committee shall be final and binding on me and any other person having or claiming a right under this grant.

Participant

EXHIBIT A

UGI CORPORATION

PERFORMANCE UNIT PEER GROUP

RUSSELL MIDCAP UTILITIES

(EXCLUDING TELECOMS)

as of 1/1/2013

AES Corp. (AES)

AGL Resources (AGL)

Alliant Energy (LNT)

Ameren Corporation (AEE)

American Water Works (AWK)

Aqua America Inc. (WTR)

Atmos Energy (ATO)

Calpine Corp. (CPN)

Centerpoint Energy (CNP)

CMS Energy Corp. (CMS)

DTE Energy Co. (DTE)

Edison International (EIX)

Energen Corp. (EGN)

Entergy Corp (ETR)

Great Plains Energy (GXP)

Hawaiian Electric (HE)

Integrys Energy (TEG)

ITC Holdings Corp. (ITC)

MDU Resource Group (MDU)

National Fuel Gas Co. (NFG)

NiSource Inc. (NI)

Northeast Utilities (NU)

NRG Energy (NRG)

NV Energy Inc. (NVE)

OGE Energy Corp. (OGE)

ONEOK Inc. (OKE)

Pepco Holdings (POM)

Pinnacle West Capital Corp. (PNW)

PPL Corporation (PPL)

Questar Corp. (STR)

Scana Corp. (SCG)

Sempra Energy (SRE)

Teco Energy Inc. (TE)

UGI Corporation (UGI)

Vectren Corp. (VVC)

Westar Energy, Inc. (WR)

Wisconsin Energy (WEC)

XCEL Energy Inc. (XEL)

EXHIBIT B

Change of Control with Respect to Utilities

For Participants who are employees of Utilities, or a subsidiary of Utilities, the term “Change of Control” shall include the events set forth in this Exhibit A with respect to Utilities, and the defined terms set forth used in this Exhibit B, if not defined in the Plan, shall have the following meanings:

1.    “Change of Control” shall include any of the following events:

(A)    UGI and the UGI Subsidiaries fail to own more than fifty percent (50%) of the then outstanding shares of common stock of Utilities or more than fifty percent (50%) of the combined voting power of the then outstanding voting securities of Utilities entitled to vote generally in the election of directors; or

(B)    Completion by Utilities of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of Utilities’ outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of Utilities’ outstanding common stock and voting securities, as the case may be; or

(C)    Completion of a complete liquidation or dissolution of the Utilities or sale or other disposition of all or substantially all of the assets of Utilities other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of Utilities’ outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of Utilities’ outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.

2.    “Affiliate” and “Associate” shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.

3.    A Person shall be deemed the “Beneficial Owner” of any securities: (i) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a person shall not be deemed the “Beneficial Owner” of securities tendered pursuant to a tender or exchange offer made by such Person or any of such person’s Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a Person shall not be deemed the “Beneficial Owner” of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such Person (or any of such Person’s Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any securities; provided, however, that nothing in this Section 1(c) shall cause a Person engaged in business as an underwriter of securities to be the “Beneficial Owner” of any securities acquired through such Person’s participation in good faith in a firm commitment underwriting until the expiration of forty (40) days after the date of such acquisition.

4.    “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

5.    “Person” shall mean an individual or a corporation, partnership, trust, unincorporated organization, association, or other entity.

6.    “UGI Subsidiary” shall mean any corporation in which UGI directly or indirectly, owns at least a fifty percent (50%) interest or an unincorporated entity of which UGI, as applicable, directly or indirectly, owns at least fifty percent (50%) of the profits or capital interests.

9

EX-12.1

UGI UTILITIES, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Six Months Ended March 31,
			Year Ended September 30,
	2013		2012		2011		2010		2009		2008
Earnings:
Earnings before income taxes	$	161,897	$	142,971	$	168,693	$	147,183	$	125,554	$	123,977
Interest expense	19,897		42,412		42,728		42,336		43,918		39,065
Amortization of debt discount and
expense	363		814		1,060		627		625		467
Estimated interest component of
rental expense	1,059		2,121		1,740		1,912		1,965		1,619
	$	183,216	$	188,318	$	214,221	$	192,058	$	172,062	$	165,128
Fixed Charges:
Interest expense	$	19,897	$	42,412	$	42,728	$	42,336	$	43,918	$	39,065
Amortization of debt discount and
expense	363		814		1,060		627		625		467
Allowance for funds used during
construction (capitalized interest)	198		10		90		74		160		139
Estimated interest component of
rental expense	1,059		2,121		1,740		1,912		1,965		1,619
	$	21,517	$	45,357	$	45,618	$	44,949	$	46,668	$	41,290
Ratio of earnings to fixed charges	8.51		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: May 10, 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: May 10, 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 March 31, 2013 (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:	May 10, 2013	Date:	May 10, 2013

XML

Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Interest rate contracts [Member] | Interest expense, 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	$ 6,116	$ 4,504	$ 10,452	$ 1,427
Gain (loss) reclassified from AOCI into income	(202)	(973)	(405)	(1,264)
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	$ 107	$ 257	$ 105	$ 205

XML

Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended		3 Months Ended	6 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Environmental Issue [Member]	Mar. 31, 2013 Environmental Issue [Member] PNG MGP [Member]	Mar. 31, 2013 Environmental Remediation Expense [Member] CPG MGP [Member]	Mar. 31, 2013 Environmental Remediation Expense [Member] PNG MGP [Member]	Mar. 31, 2013 CPG and PNG COAs [Member]	Mar. 31, 2012 CPG and PNG COAs [Member]	Jun. 06, 2006 Key Span [Member]	Jun. 24, 2004 Key Span [Member]	Feb. 09, 2011 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Persons
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						14,338	16,789
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
Liability insurance deductible	$ 500

XML

Disclosures About Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Mar. 31, 2013

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 March 31, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,229	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(24,298	)	$	(17,345	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	4,130		1		Derivative financial instruments and Other noncurrent liabilities	(5,467		)	(17,902		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	169		184		Derivative financial instruments	—			—
Total Derivatives		$	8,528	$	185		$	(29,765	)	$	(35,247	)

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 and six months ended March 31, 2013 and 2012:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	6,116	$	4,504	$	(202	)	$	(973	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	107	$	257							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	10,452	$	1,427	$	(405	)	$	(1,264	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	105	$	205							Operating expenses/other income, net

XML

Disclosures About Derivative Instruments and Hedging Activities Textual (Details) (USD $) In Thousands, unless otherwise specified												3 Months Ended	6 Months Ended
	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012	Mar. 31, 2013 Electric Utility electric transmission congestion [Member] kWh	Mar. 31, 2012 Electric Utility electric transmission congestion [Member] kWh	Mar. 31, 2013 Gas Utility [Member] DTH	Mar. 31, 2012 Gas Utility [Member] DTH	Mar. 31, 2013 Electric Utility [Member] kWh	Mar. 31, 2012 Electric Utility [Member] kWh	Mar. 31, 2013 Interest Rate Protection Agreements [Member]	Mar. 31, 2012 Interest Rate Protection Agreements [Member]	Mar. 31, 2012 Interest Rate Swap [Member]	Mar. 31, 2012 Interest Rate Swap [Member]	Mar. 31, 2013 Derivative financial instruments [Member] Derivatives Designated as Hedging Instruments [Member] Interest rate contracts [Member]	Mar. 31, 2012 Derivative financial instruments [Member] Derivatives Designated as Hedging Instruments [Member] Interest rate contracts [Member]	Mar. 31, 2013 Derivative financial instruments [Member] Derivatives Subject to Utility Rate Regulation [Member] Commodity contracts [Member]	Mar. 31, 2012 Derivative financial instruments [Member] Derivatives Subject to Utility Rate Regulation [Member] Commodity contracts [Member]	Mar. 31, 2013 Derivative financial instruments [Member] Derivatives Not Designated as Hedging Instruments [Member] Commodity contracts [Member]	Mar. 31, 2012 Derivative financial instruments [Member] Derivatives Not Designated as Hedging Instruments [Member] Commodity contracts [Member]	Mar. 31, 2013 Derivative Financial Instruments, Liabilities [Member] Derivatives Designated as Hedging Instruments [Member] Interest rate contracts [Member]	Mar. 31, 2012 Derivative Financial Instruments, Liabilities [Member] Derivatives Designated as Hedging Instruments [Member] Interest rate contracts [Member]	Mar. 31, 2013 Derivative financial instruments and other noncurrent liabilities [Member] Derivatives Subject to Utility Rate Regulation [Member] Commodity contracts [Member]	Mar. 31, 2012 Derivative financial instruments and other noncurrent liabilities [Member] Derivatives Subject to Utility Rate Regulation [Member] Commodity contracts [Member]	Mar. 31, 2013 Electric Utility Electric Supply Contracts [Member]	Sep. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Mar. 31, 2012 Electric Utility Electric Supply Contracts [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)				47,500,000	52,200,000	10,000,000	11,600,000	403,200,000	707,400,000
Total Derivatives Liability	$ (29,765)		$ (35,247)					$ 5,458	$ 14,747									$ 0	$ 0	$ 24,298	$ 17,345	$ 5,467	$ 17,902	$ (5,458)	$ (9,207)	$ (14,747)
Total Derivatives Assets	8,528		185											4,229	0	4,130	1	169	184
Underlying variable rate debt										173,000	173,000
Recorded loss amount included in Other Income, Net												(682)	682
Maximum length of time hedged in price risk cash flow hedges (in months)				2 months		12 months		14 months
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	1,179
Restricted Cash in brokerage accounts	$ 0	$ 0	$ 4,260

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Significant Accounting Policies

6 Months Ended

Mar. 31, 2013

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. Other comprehensive income 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.

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Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 322,329	$ 338,405	$ 295,689
Regulatory Liabilities	56,654	28,344	35,400
Postretirement benefits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	13,865	13,147	12,053
Environmental overcollections [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	2,980	2,883	3,843
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	31,209	4,435	12,022
State tax benefits -- distribution system repairs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	7,900	7,385	6,735
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	700	494	747
Income taxes recoverable [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	104,229	103,172	99,226
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	181,305	188,222	146,631
Environmental costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	16,841	16,812	18,247
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	2,122	11,602	11,012
Removal costs, net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	11,856	12,718	11,915
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 5,976	$ 5,879	$ 8,658

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Inventories Textual (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013 ft3	Sep. 30, 2012 ft3	Mar. 31, 2012 ft3
Inventory, Net [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	1,000,000,000	11,400,000,000	1,800,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 3,315	$ 32,627	$ 7,661
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										0 Months Ended
	Apr. 30, 2013	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Deferral Fuel and Power [Member]	Sep. 30, 2012 Deferral Fuel and Power [Member]	Mar. 31, 2012 Deferral Fuel and Power [Member]	Mar. 31, 2013 Electric Utility Electric Supply Contracts [Member]	Sep. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Mar. 31, 2012 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	Mar. 31, 2013 Allentown Incident [Member]	Mar. 31, 2013 Revised Penalty [Member] Allentown Incident [Member]
Regulatory Assets [Line Items]
GasUtilityUnrealizedGainOrLossOnDerivativeFinancialInstrumentsContracts				$ 4,129	$ 5,303	$ (3,113)
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains										14 years
Fair value of electric utility electricity supply contracts		(29,765)	(35,247)				(5,458)	(9,207)	(14,747)
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
Net Book Value of The Pipeline	$ 2,500

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Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Pension Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 2,053	$ 1,756	$ 4,105	$ 3,512
Interest cost	5,196	5,594	10,391	11,188
Expected return on assets	(6,198)	(5,940)	(12,396)	(11,880)
Amortization of:
Prior service cost (benefit)	62	62	124	124
Actuarial loss	3,366	1,963	6,732	3,926
Net benefit cost	4,479	3,435	8,956	6,870
Change in associated regulatory liabilities	0	0	0	0
Net expense	4,479	3,435	8,956	6,870
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	51	43	102	86
Interest cost	143	166	286	332
Expected return on assets	(132)	(127)	(264)	(254)
Amortization of:
Prior service cost (benefit)	(105)	(106)	(210)	(212)
Actuarial loss	91	99	182	198
Net benefit cost	48	75	96	150
Change in associated regulatory liabilities	815	784	1,630	1,568
Net expense	$ 863	$ 859	$ 1,726	$ 1,718

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Nature of Operations

6 Months Ended

Mar. 31, 2013

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	6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to pensions plans in the remainder of current fiscal year	$ 9,409
Contribution made to Pension Plan	$ 6,393	$ 19,712

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Condensed Consolidated Balance Sheets (unaudited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012
Current assets:
Cash and cash equivalents	$ 58,329	$ 1,259	$ 46,593
Restricted cash	0	0	4,260
Accounts receivable (less allowances for doubtful accounts of $8,052, $3,588 and $8,900, respectively)	141,053	47,362	105,330
Accounts receivable — related parties	9,518	4,571	6,353
Accrued utility revenues	48,857	16,911	25,474
Inventories	16,215	67,334	23,640
Deferred income taxes	53,515	46,436	33,907
Regulatory assets	1,072	6,473	3,593
Derivative financial instruments	8,528	5,468	185
Prepaid expenses & other current assets	16,755	29,313	24,000
Total current assets	353,842	225,127	273,335
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $837,110, $815,720 and $800,423, respectively)	1,508,985	1,479,949	1,441,612
Goodwill	182,145	182,145	182,145
Regulatory assets	321,257	331,932	292,096
Other assets	2,808	4,026	4,718
Total assets	2,369,037	2,223,179	2,193,906
Current liabilities:
Current maturities of long-term debt	133,000	133,000	40,000
Bank loans	0	9,200	0
Accounts payable	48,099	46,754	27,180
Accounts payable — related parties	12,535	10,192	7,488
Deferred fuel refunds	31,209	4,435	12,022
Derivative financial instruments	29,077	36,011	11,404
Other current liabilities	149,801	131,092	149,357
Total current liabilities	403,721	370,684	247,451
Long-term debt	467,000	467,000	600,000
Deferred income taxes	433,868	417,052	367,088
Deferred investment tax credits	4,440	4,612	4,784
Pension and postretirement benefit obligations	174,905	179,056	130,731
Other noncurrent liabilities	53,965	56,262	81,441
Total liabilities	1,537,899	1,494,666	1,431,495
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	469,501	468,692	468,564
Retained earnings	324,450	229,379	253,631
Accumulated other comprehensive loss	(23,072)	(29,817)	(20,043)
Total common stockholder’s equity	831,138	728,513	762,411
Total liabilities and stockholder’s equity	$ 2,369,037	$ 2,223,179	$ 2,193,906

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2013	Dec. 31, 2011	Mar. 31, 2013	Mar. 31, 2012
Tax on (loss) gain on derivative instruments	$ (2,538)	$ (1,869)	$ (4,337)	$ (592)
Tax on reclassifications of net losses (gains) on derivative instruments	(84)	(403)	(168)	(524)
Tax on benefit plans	$ (139)	$ (81)	$ (278)	$ (162)

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Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 4,299	$ 5,468	$ 185
Derivative financial instruments, liabilities	(5,467)	(9,437)	(17,902)
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	4,299	5,468	185
Derivative financial instruments, liabilities	(406)	(671)	(4,674)
Commodity contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	(5,061)	(8,766)	(13,228)
Commodity contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	4,229
Derivative financial instruments, liabilities	(24,298)	(30,522)	(17,345)
Interest rate contracts [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	0	0	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	4,229
Derivative financial instruments, liabilities	(24,298)	(30,522)	(17,345)
Interest rate contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	$ 0	$ 0	$ 0

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

6 Months Ended

Mar. 31, 2013

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:

	March 31, 2013		September 30, 2012		March 31, 2012
Regulatory assets:
Income taxes recoverable	$	104,229	$	103,172	$	99,226
Underfunded pension and postretirement plans	181,305		188,222		146,631
Environmental costs	16,841		16,812		18,247
Deferred fuel and power costs	2,122		11,602		11,012
Removal costs, net	11,856		12,718		11,915
Other	5,976		5,879		8,658
Total regulatory assets	$	322,329	$	338,405	$	295,689
Regulatory liabilities:
Postretirement benefits	$	13,865	$	13,147	$	12,053
Environmental overcollections	2,980		2,883		3,843
Deferred fuel and power refunds	31,209		4,435		12,022
State tax benefits — distribution system repairs	7,900		7,385		6,735
Other	700		494		747
Total regulatory liabilities	$	56,654	$	28,344	$	35,400

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Fair Value Measurements Textual (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying amount of long-term debt	$ 600,000	$ 640,000
Fair value of long-term debt	$ 690,459	$ 725,990

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Fair Value Measurements (Tables)

6 Months Ended

Mar. 31, 2013

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 March 31, 2013, September 30, 2012 and March 31, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)
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	)
March 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	185		$	—		$	—	$	185
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,674	)	$	(13,228	)	$	—	$	(17,902	)
Interest rate contracts	$	—		$	(17,345	)	$	—	$	(17,345	)

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 95,071	$ 80,539
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	27,283	26,173
Deferred income taxes, net	4,241	12,229
Provision for uncollectible accounts	6,059	5,819
Other, net	7,537	(10,663)
Net change in:
Accounts receivable and accrued utility revenues	(136,644)	(62,385)
Inventories	51,119	80,623
Deferred fuel and power costs	33,311	14,039
Accounts payable	3,688	(28,996)
Other current assets	12,632	786
Other current liabilities	18,120	11,202
Net cash provided by operating activities	122,417	129,366
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(55,519)	(49,784)
Net costs of property, plant and equipment disposals	(1,437)	(1,541)
Decrease in restricted cash	0	48
Net cash used by investing activities	(56,956)	(51,277)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	0	(39,004)
Decrease in bank loans	(9,200)	0
Other	809	241
Net cash used by financing activities	(8,391)	(38,763)
Cash and cash equivalents increase	57,070	39,326
CASH AND CASH EQUIVALENTS:
End of period	58,329	46,593
Beginning of period	1,259	7,267
Increase	$ 57,070	$ 39,326

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Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012
Allowance for doubtful accounts on accounts receivable	$ 8,052	$ 3,588	$ 8,900
Accumulated depreciation and amortization on property, plant and equipment	$ 837,110	$ 815,720	$ 800,423
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	26,781,785	26,781,785	26,781,785
Common stock, shares outstanding	26,781,785	26,781,785	26,781,785

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Fair Value Measurements

6 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of March 31, 2013, September 30, 2012 and March 31, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)
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	)
March 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	185		$	—		$	—	$	185
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(4,674	)	$	(13,228	)	$	—	$	(17,902	)
Interest rate contracts	$	—		$	(17,345	)	$	—	$	(17,345	)

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 March 31, 2013, were $600,000 and $690,459, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2012, were $640,000 and $725,990, 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	6 Months Ended
	Mar. 31, 2013	Apr. 30, 2013
Entity Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785

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Disclosures About Derivative Instruments and Hedging Activities

6 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

. Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10 million dekatherms and 11.6 million dekatherms, respectively. At March 31, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 12 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 March 31, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $5,458 and $14,747, 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 March 31, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 403.2 million kilowatt hours and 707.4 million kilowatt hours, respectively. At March 31, 2013, the maximum period over which these contracts extend is 14 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 March 31, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 47.5 million kilowatt hours and 52.2 million kilowatt hours, respectively. At March 31, 2013, the maximum period over which we are hedging electricity congestion with FTRs is 2 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. 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 March 31, 2013 and 2012, 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.

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

At March 31, 2013, 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 $1,179.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At March 31, 2013, there was no restricted cash in brokerage accounts. At March 31, 2012, restricted cash in brokerage accounts totaled $4,260.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	4,229	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(24,298	)	$	(17,345	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	4,130		1		Derivative financial instruments and Other noncurrent liabilities	(5,467		)	(17,902		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	169		184		Derivative financial instruments	—			—
Total Derivatives		$	8,528	$	185		$	(29,765	)	$	(35,247	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and six months ended March 31, 2013 and 2012:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	6,116	$	4,504	$	(202	)	$	(973	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	107	$	257							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012		2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	10,452	$	1,427	$	(405	)	$	(1,264	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income										Location of Gain (Loss) Recognized in Income
	2013		2012
Commodity contracts	$	105	$	205							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		6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Revenues	$ 395,901	$ 345,802	$ 669,698	$ 626,443
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	212,785	192,770	351,062	349,676
Operating and administrative expenses	52,421	45,749	96,656	86,691
Operating and administrative expenses - related parties	3,012	2,781	4,817	4,906
Taxes other than income taxes	4,684	4,857	8,960	8,984
Depreciation	12,895	12,328	25,648	24,707
Amortization	817	782	1,635	1,466
Other loss (income), net	57	(1,912)	(874)	(3,039)
Total costs and expenses	286,671	257,355	487,904	473,391
Operating income	109,230	88,447	181,794	153,052
Interest expense	9,820	10,677	19,897	21,284
Income before income taxes	99,410	77,770	161,897	131,768
Income taxes	41,151	29,899	66,826	51,229
Net income	$ 58,259	$ 47,871	$ 95,071	$ 80,539

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Inventories

6 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	March 31, 2013		September 30, 2012		March 31, 2012
Gas Utility natural gas	$	5,366	$	57,663	$	12,761
Materials, supplies and other	10,849		9,671		10,879
Total inventories	$	16,215	$	67,334	$	23,640

At March 31, 2013, 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 March 31, 2013, September 30, 2012 and March 31, 2012, comprising 1.0 billion cubic feet (“bcf”), 11.4 bcf and 1.8 bcf of natural gas, was $3,315, $32,627 and $7,661, respectively. In conjunction with the SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at March 31, 2013, and $22,500 at September 30, 2012 and March 31, 2012. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

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Segment Information

6 Months Ended

Mar. 31, 2013

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 Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,369,037	$	2,205,516	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

Three Months Ended March 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	345,802	$	319,511	$	25,940	$	351
Cost of sales	$	192,770	$	177,492	$	15,278	$	—
Depreciation and amortization	$	13,110	$	12,159	$	951	$	—
Operating income	$	88,447	$	84,969	$	3,363	$	115
Interest expense	$	10,677	$	10,085	$	592	$	—
Income before income taxes	$	77,770	$	74,884	$	2,771	$	115
Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	26,926	$	25,654	$	1,272	$	—

Six Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	669,698	$	616,889	$	52,069	$	740
Cost of sales	$	351,062	$	320,316	$	30,746	$	—
Depreciation and amortization	$	27,283	$	25,336	$	1,947	$	—
Operating income	$	181,794	$	175,538	$	6,013	$	243
Interest expense	$	19,897	$	18,899	$	998	$	—
Income before income taxes	$	161,897	$	156,639	$	5,015	$	243
Total assets (at period end)	$	2,369,037	$	2,205,516	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	55,519	$	52,949	$	2,570	$	—

Six Months Ended March 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	626,443	$	574,541	$	51,109	$	793
Cost of sales	$	349,676	$	319,171	$	30,505	$	—
Depreciation and amortization	$	26,173	$	24,304	$	1,869	$	—
Operating income	$	153,052	$	146,200	$	6,593	$	259
Interest expense	$	21,284	$	20,183	$	1,101	$	—
Income before income taxes	$	131,768	$	126,017	$	5,492	$	259
Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	49,784	$	47,466	$	2,318	$	—

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Defined Benefit Pension and Other Postretirement Plans (Tables)

6 Months Ended

Mar. 31, 2013

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
	March 31,						March 31,
	2013			2012			2013			2012
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			62			(105		)	(106		)
Actuarial loss	3,366			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 Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
Service cost	$	4,105		$	3,512		$	102		$	86
Interest cost	10,391			11,188			286			332
Expected return on assets	(12,396		)	(11,880		)	(264		)	(254		)
Amortization of:
Prior service cost (benefit)	124			124			(210		)	(212		)
Actuarial loss	6,732			3,926			182			198
Net benefit cost	8,956			6,870			96			150
Change in associated regulatory liabilities	—			—			1,630			1,568
Net expense	$	8,956		$	6,870		$	1,726		$	1,718

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Significant Accounting Policies (Policies)

6 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Comprehensive Income

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income. Other comprehensive income 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. 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

6 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At March 31, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,338 and $16,789, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

The Company does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 31, 2013, 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 and settled all wrongful death claims and substantially all property and personal injury claims in connection with the Incident. UGI Utilities maintains liability insurance for personal injury, wrongful death and property and casualty damages subject to a $500 deductible. We expect that the remaining claims will be covered by UGI Utilities’ insurance. As a result, the Incident did not and we continue to believe it 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

6 Months Ended

Mar. 31, 2013

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:

	March 31, 2013		September 30, 2012		March 31, 2012
Regulatory assets:
Income taxes recoverable	$	104,229	$	103,172	$	99,226
Underfunded pension and postretirement plans	181,305		188,222		146,631
Environmental costs	16,841		16,812		18,247
Deferred fuel and power costs	2,122		11,602		11,012
Removal costs, net	11,856		12,718		11,915
Other	5,976		5,879		8,658
Total regulatory assets	$	322,329	$	338,405	$	295,689
Regulatory liabilities:
Postretirement benefits	$	13,865	$	13,147	$	12,053
Environmental overcollections	2,980		2,883		3,843
Deferred fuel and power refunds	31,209		4,435		12,022
State tax benefits — distribution system repairs	7,900		7,385		6,735
Other	700		494		747
Total regulatory liabilities	$	56,654	$	28,344	$	35,400

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 March 31, 2013, September 30, 2012, and March 31, 2012, were $4,129, $5,303 and $(3,113), 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 March 31, 2013, September 30, 2012, and March 31, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $5,458, $9,207 and $14,747, 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 March 31, 2013, September 30, 2012, and March 31, 2012, 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, 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. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires 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. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11 mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (TL-96 line) to Energy Services.   The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line is approximately $2,500.

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Defined Benefit Pension and Other Postretirement Plans

6 Months Ended

Mar. 31, 2013

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
	March 31,						March 31,
	2013			2012			2013			2012
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			62			(105		)	(106		)
Actuarial loss	3,366			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 Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
Service cost	$	4,105		$	3,512		$	102		$	86
Interest cost	10,391			11,188			286			332
Expected return on assets	(12,396		)	(11,880		)	(264		)	(254		)
Amortization of:
Prior service cost (benefit)	124			124			(210		)	(212		)
Actuarial loss	6,732			3,926			182			198
Net benefit cost	8,956			6,870			96			150
Change in associated regulatory liabilities	—			—			1,630			1,568
Net expense	$	8,956		$	6,870		$	1,726		$	1,718

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 $9,409 to the Pension Plan during the remainder of Fiscal 2013. During the six months endedMarch 31, 2013 and 2012, the Company made contributions to the Pension Plan of $6,393 and $19,712, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas’ and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months endedMarch 31, 2013 and 2012, 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

6 Months Ended

Mar. 31, 2013

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 March 31, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, and 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 $702 and $5,026 during the three and six months ended March 31, 2013, respectively, and $408 and $5,330 during the three and six months ended March 31, 2012.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 March 31, 2013, and $15,000 as of September 30, 2012 and March 31, 2012.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at March 31, 2013, comprising approximately 1.0 bcf of natural gas, was $3,315. 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 March 31, 2012, comprising approximately 1.2 bcf of natural gas, was $4,725.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and six months ended March 31, 2013, totaled $14,701 and $32,526, respectively. During the three and six months ended March 31, 2012, such transactions totaled $8,386 and $30,752, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2013, revenues associated with such sales to Energy Services totaled $25,428 and $45,252, respectively. During the three and six months ended March 31, 2012, revenues associated with such sales to Energy Services totaled $23,574 and $40,656, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and six months ended March 31, 2013, the aggregate amount of such purchases totaled $18,213 and $37,233, respectively. During the three and six months ended March 31, 2012, such purchases totaled $13,267 and $23,319, 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		6 Months Ended		3 Months Ended		6 Months Ended					3 Months Ended		6 Months Ended					6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Energy Services [Member]	Mar. 31, 2012 Energy Services [Member]	Mar. 31, 2013 Energy Services [Member]	Mar. 31, 2012 Energy Services [Member]	Mar. 31, 2013 Inventories [Member] Energy Services [Member] ft3	Sep. 30, 2012 Inventories [Member] Energy Services [Member] ft3	Mar. 31, 2012 Inventories [Member] Energy Services [Member] ft3	Mar. 31, 2013 SCAAs [Member] Energy Services [Member]	Mar. 31, 2012 SCAAs [Member] Energy Services [Member]	Mar. 31, 2013 SCAAs [Member] Energy Services [Member]	Mar. 31, 2012 SCAAs [Member] Energy Services [Member]	Mar. 31, 2013 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Sep. 30, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Mar. 31, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Mar. 31, 2013 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Mar. 31, 2012 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]
Related Party Transaction [Line Items]
Related party costs incurred	$ 3,012	$ 2,781	$ 4,817	$ 4,906								$ 702	$ 408	$ 5,026	$ 5,330				$ 32,526	$ 30,752
Related party security deposits																16,500	15,000	15,000
Volume of gas storage inventory (in bcf of natural gas)									1,000,000,000	7,600,000,000	1,200,000,000
Natural gas storage inventory, related parties, current									3,315	21,217	4,725
Revenue from related parties					25,428	23,574	45,252	40,656
Purchases from related party					$ 18,213	$ 13,267	$ 37,233	$ 23,319

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Inventories (Tables)

6 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:

	March 31, 2013		September 30, 2012		March 31, 2012
Gas Utility natural gas	$	5,366	$	57,663	$	12,761
Materials, supplies and other	10,849		9,671		10,879
Total inventories	$	16,215	$	67,334	$	23,640

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Segment	Mar. 31, 2012	Sep. 30, 2012
Segment Reporting [Abstract]
Number of reportable segments (in segments)			2
Segment Reporting Information [Line Items]
Revenues	$ 395,901	$ 345,802	$ 669,698	$ 626,443
Cost of sales	212,785	192,770	351,062	349,676
Depreciation and amortization	13,712	13,110	27,283	26,173
Operating income	109,230	88,447	181,794	153,052
Interest expense	9,820	10,677	19,897	21,284
Income before income taxes	99,410	77,770	161,897	131,768
Total assets (at period end)	2,369,037	2,193,906	2,369,037	2,193,906	2,223,179
Goodwill (at period end)	182,145	182,145	182,145	182,145	182,145
Capital expenditures	25,791	26,926	55,519	49,784
Gas Utility [Member]
Segment Reporting Information [Line Items]
Revenues	368,635	319,511	616,889	574,541
Cost of sales	196,742	177,492	320,316	319,171
Depreciation and amortization	12,731	12,159	25,336	24,304
Operating income	105,749	84,969	175,538	146,200
Interest expense	9,327	10,085	18,899	20,183
Income before income taxes	96,422	74,884	156,639	126,017
Total assets (at period end)	2,205,516	2,038,501	2,205,516	2,038,501
Goodwill (at period end)	182,145	182,145	182,145	182,145
Capital expenditures	24,430	25,654	52,949	47,466
Electric Utility [Member]
Segment Reporting Information [Line Items]
Revenues	26,951	25,940	52,069	51,109
Cost of sales	16,043	15,278	30,746	30,505
Depreciation and amortization	981	951	1,947	1,869
Operating income	3,389	3,363	6,013	6,593
Interest expense	493	592	998	1,101
Income before income taxes	2,896	2,771	5,015	5,492
Total assets (at period end)	163,521	155,405	163,521	155,405
Goodwill (at period end)	0	0	0	0
Capital expenditures	1,361	1,272	2,570	2,318
Other [Member]
Segment Reporting Information [Line Items]
Revenues	315	351	740	793
Cost of sales	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income	92	115	243	259
Interest expense	0	0	0	0
Income before income taxes	92	115	243	259
Total assets (at period end)	0	0	0	0
Goodwill (at period end)	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Net income	$ 58,259	$ 47,871	$ 95,071	$ 80,539
Net gains in fair value of derivative instruments (net of tax $(2,538), $(1,869), $(4,337) and $(592), respectively)	3,578	2,635	6,115	834
Reclassifications of net losses on derivative instruments (net of tax of $(84), $(403), $(168) and $(524), respectively)	118	570	237	740
Benefit plans (net of tax of $(139), $(81), $(278) and $(162),respectively)	198	77	393	216
Other comprehensive income (loss)	3,894	3,282	6,745	1,790
Comprehensive income	$ 62,153	$ 51,153	$ 101,816	$ 82,329

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Accounting Changes

6 Months Ended

Mar. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Accounting Changes

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (AOCI). The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. We are currently evaluating the impact of the new guidance on our future disclosures.

Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance, as amended, 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	Mar. 31, 2013	Sep. 30, 2012	Mar. 31, 2012
Inventory, Net [Abstract]
Total inventories	$ 16,215	$ 67,334	$ 23,640
Gas Utility Natural Gas [Member]
Inventory, Net [Abstract]
Total inventories	5,366	57,663	12,761
Materials, Supplies and Other [Member]
Inventory, Net [Abstract]
Total inventories	$ 10,849	$ 9,671	$ 10,879

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Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 8,528	$ 185
Total Derivatives Liability	(29,765)	(35,247)
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	24,298	17,345
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	4,229	0
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	4,130	1
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments and other noncurrent liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	5,467	17,902
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	169	184
Total Derivatives Liability	$ 0	$ 0

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Segment Information (Tables)

6 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

Three Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,369,037	$	2,205,516	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

Three Months Ended March 31, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	345,802	$	319,511	$	25,940	$	351
Cost of sales	$	192,770	$	177,492	$	15,278	$	—
Depreciation and amortization	$	13,110	$	12,159	$	951	$	—
Operating income	$	88,447	$	84,969	$	3,363	$	115
Interest expense	$	10,677	$	10,085	$	592	$	—
Income before income taxes	$	77,770	$	74,884	$	2,771	$	115
Total assets (at period end)	$	2,193,906	$	2,038,501	$	155,405	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	26,926	$	25,654	$	1,272	$	—