Ugi Utilities 10-Q 2011 Q2 Quarterly report

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, 2011

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. Yesþ Noo

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). Yeso Noo

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 filero Accelerated filero Non-accelerated filerþ Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

At April 30, 2011, 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, 2011, September 30, 2010 and March 31, 2010		1
Condensed Consolidated Statements of Income for the three and six months ended March 31, 2011 and 2010		2
Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2011 and 2010		3
Notes to Condensed Consolidated Financial Statements		4 - 22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23 - 29
Item 3. Quantitative and Qualitative Disclosures about Market Risk		30
Item 4T. Controls and Procedures		31
Part II Other Information
Item 1. Legal Proceedings		32
Item 1A. Risk Factors		32
Item 6. Exhibits		33
Signatures		34
Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	March 31,			September 30,			March 31,
	2011			2010			2010
ASSETS
Current assets:
Cash and cash equivalents	$	75,472		$	4,318		$	7,492
Restricted cash		3,996			4,698			12,573
Accounts receivable (less allowances for doubtful accounts of $13,558, $7,072 and $18,051, respectively)		154,398			64,844			162,152
Accounts receivable — related parties		13,181			6,313			11,371
Accrued utility revenues		43,163			13,988			33,294
Inventories		16,674			118,858			38,865
Deferred income taxes		33,201			19,431			24,671
Regulatory assets		1,762			26,100			6,662
Derivative financial instruments		1,920			486			525
Prepaid expenses & other current assets		19,794			21,117			16,131
Total current assets		363,561			280,153			313,736
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $759,102, $734,739 and $715,234, respectively)		1,405,793			1,394,585			1,364,622
Goodwill		180,145			180,145			180,145
Regulatory assets		242,892			280,602			123,199
Other assets		11,060			4,091			6,405
Total assets	$	2,203,451		$	2,139,576		$	1,988,107
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Bank loans	$	—		$	17,000		$	37,000
Accounts payable		49,203			61,297			46,726
Accounts payable — related parties		10,742			8,144			10,482
Deferred fuel refunds		33,955			8,295			16,789
Derivative financial instruments		4,291			10,564			7,616
Other current liabilities		163,355			133,935			121,845
Total current liabilities		261,546			239,235			240,458
Long-term debt		640,000			640,000			640,000
Deferred income taxes		305,371			281,101			197,872
Deferred investment tax credits		5,134			5,311			5,489
Pension and postretirement benefit obligations		115,628			161,338			146,137
Other noncurrent liabilities		71,531			78,137			60,428
Total liabilities		1,399,210			1,405,122			1,290,384
Commitments and contingencies (note 7)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)		60,259			60,259			60,259
Additional paid-in capital		468,302			467,631			467,258
Retained earnings		279,856			217,960			251,226
Accumulated other comprehensive loss		(4,176	)		(11,396	)		(81,020	)
Total common stockholder’s equity		804,241			734,454			697,723
Total liabilities and stockholder’s equity	$	2,203,451		$	2,139,576		$	1,988,107

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,
	2011			2010			2011			2010
Revenues	$	484,465		$	477,273		$	834,981		$	839,476
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)		308,778			312,171			522,262			543,388
Operating and administrative expenses		51,299			48,632			91,193			92,854
Operating and administrative expenses — related parties		5,923			6,565			8,848			7,757
Taxes other than income taxes		5,469			4,894			9,827			9,422
Depreciation		12,683			12,438			25,289			25,119
Amortization		633			771			1,265			1,378
Other income, net		(4,429	)		(2,535	)		(6,692	)		(4,052	)
		380,356			382,936			651,992			675,866
Operating income		104,109			94,337			182,989			163,610
Interest expense		10,809			10,724			21,442			21,361
Income before income taxes		93,300			83,613			161,547			142,249
Income taxes		33,137			33,001			60,310			56,474
Net income	$	60,163		$	50,612		$	101,237		$	85,775

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	101,237		$	85,775
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		26,554			26,497
Deferred income taxes, net		(1,627	)		25,614
Provision for uncollectible accounts		8,626			12,176
Other, net		3,524			4,747
Net change in:
Accounts receivable and accrued utility revenues		(137,223	)		(120,350	)
Inventories		102,184			157,734
Deferred fuel and power costs		43,281			(1,135	)
Accounts payable		5,510			(4,804	)
Other current assets		3,277			(10,407	)
Other current liabilities		9,665			11,380
Net cash provided by operating activities		165,008			187,227
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(37,658	)		(26,170	)
Net costs of property, plant and equipment disposals		(1,220	)		(1,255	)
Decrease (increase) in restricted cash		702			(12,573	)
Net cash used by investing activities		(38,176	)		(39,998	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(39,348	)		(36,260	)
Decrease in bank loans		(17,000	)		(117,000	)
Other		670			—
Net cash used by financing activities		(55,678	)		(153,260	)
Cash and cash equivalents increase (decrease)	$	71,154		$	(6,031	)
CASH AND CASH EQUIVALENTS:
End of period	$	75,472		$	7,492
Beginning of period		4,318			13,523
Increase (decrease)	$	71,154		$	(6,031	)

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. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” PNG also has a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operates principally in the PNG Gas service territory.

The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

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 which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2010 condensed consolidated balance sheet data were 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, 2010 (“Company’s 2010 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Comprehensive Income.The following table presents the components of comprehensive income for the three and six months ended March 31, 2011 and 2010:

	Three Months Ended				Six Months Ended
	March 31,				March 31,
	2011		2010		2011		2010
Net income	$	60,163	$	50,612	$	101,237	$	85,775
Other comprehensive income		638		1,033		7,220		2,066
Comprehensive income	$	60,801	$	51,645	$	108,457	$	87,841

Other comprehensive income in the 2011 periods principally reflects net gains on interest rate protection agreements qualifying as cash flow hedges and, for all periods presented, includes actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets and an after-tax increase in other comprehensive income of $2,060 which is reflected in the six months ended March 31, 2011 above (see Notes 5 and 6).

Restricted Cash.Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which 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. 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. UGI Penn HVAC Services, Inc. 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 2010 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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, 2011:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	484,465	$	452,437	$	31,711	$	317
Cost of sales	$	308,778	$	288,527	$	20,251	$	—
Depreciation and amortization	$	13,316	$	12,305	$	1,011	$	—
Operating income	$	104,109	$	100,968	$	2,990	$	151
Interest expense	$	10,809	$	10,242	$	567	$	—
Income before income taxes	$	93,300	$	90,726	$	2,423	$	151
Total assets (at period end)	$	2,203,451	$	2,045,178	$	158,273	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	20,071	$	17,465	$	2,606	$	—

Three Months Ended March 31, 2010:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	477,273	$	445,395	$	31,553	$	325
Cost of sales	$	312,171	$	291,433	$	20,738	$	—
Depreciation and amortization	$	13,209	$	12,216	$	993	$	—
Operating income	$	94,337	$	91,112	$	3,093	$	132
Interest expense	$	10,724	$	10,258	$	466	$	—
Income before income taxes	$	83,613	$	80,854	$	2,627	$	132
Total assets (at period end)	$	1,988,107	$	1,862,489	$	125,618	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	12,360	$	11,499	$	861	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Six Months Ended March 31, 2011:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	834,981	$	773,551	$	60,651	$	779
Cost of sales	$	522,262	$	483,440	$	38,822	$	—
Depreciation and amortization	$	26,554	$	24,530	$	2,024	$	—
Operating income	$	182,989	$	176,035	$	6,593	$	361
Interest expense	$	21,442	$	20,350	$	1,092	$	—
Income before income taxes	$	161,547	$	155,685	$	5,501	$	361
Total assets (at period end)	$	2,203,451	$	2,045,178	$	158,273	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	37,658	$	33,551	$	4,107	$	—

Six Months Ended March 31, 2010:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	839,476	$	773,204	$	65,552	$	720
Cost of sales	$	543,388	$	501,193	$	42,195	$	—
Depreciation and amortization	$	26,497	$	24,515	$	1,982	$	—
Operating income	$	163,610	$	154,840	$	8,452	$	318
Interest expense	$	21,361	$	20,504	$	857	$	—
Income before income taxes	$	142,249	$	134,336	$	7,595	$	318
Total assets (at period end)	$	1,988,107	$	1,862,489	$	125,618	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	26,170	$	24,539	$	1,631	$	—

4. Inventories

Inventories comprise the following:

	March 31,		September 30,		March 31,
	2011		2010		2010
Gas Utility natural gas	$	7,927	$	111,531	$	31,693
Materials, supplies and other		8,747		7,327		7,172
Total inventories	$	16,674	$	118,858	$	38,865

At March 31, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2013 (see Note 8). 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The carrying value of gas storage inventories released under the SCAAs at March 31, 2011, September 30, 2010 and March 31, 2010 comprising 1.1 billion cubic feet (“bcf”), 11.7 bcf and 2.8 bcf of natural gas, was $5,089, $62,653 and $20,469, respectively. In conjunction with the SCAAs, at March 31, 2011, September 30, 2010 and March 31, 2010, UGI Utilities held a total of $22,500 of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

5. Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 5 to the Company’s 2010 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,		September 30,		March 31,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	89,875	$	82,525	$	81,561
Underfunded pension and postretirement plans		116,003		159,154		10,405
Environmental costs		22,014		22,587		25,301
Deferred fuel and power costs		8,153		36,597		6,662
Other		8,609		5,839		5,932
Total regulatory assets	$	244,654	$	306,702	$	129,861
Regulatory liabilities:
Postretirement benefits	$	11,196	$	10,472	$	9,899
Environmental overcollections		6,811		7,211		8,398
Deferred fuel and power refunds		33,955		8,298		16,789
State tax benefits — distribution system repairs		6,339		6,685		—
Total regulatory liabilities	$	58,301	$	32,666	$	35,086

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43,150 (see Note 6).

Deferred fuel and power — costs and refunds.Gas Utility’s tariffs and, commencing January 1, 2010 Electric Utility’s default service 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 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. Unrealized gains (losses) on such contracts at March 31, 2011, September 30, 2010 and March 31, 2010 were $1,503, $(1,359) and $7,611, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 10, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At March 31, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10,682 and $19,702, 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 commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at March 31, 2011, September 30, 2010 and March 31, 2010 were not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Other Regulatory Matters

Transfer of CPG Storage Assets.On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10,900 as of March 31, 2011. The dividend of the storage assets is not expected to have a material impact on the results of operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into a firm storage service agreement with UGI Storage Company.

CPG Base Rate Filing.On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16,500 annually. The increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment. CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. Unless a settlement is reached sooner, this review process is expected to last approximately nine months which may delay implementation of the new rates until late October 2011.

6. Defined Benefit Pension and Other Postretirement Plans

Subsequent to the December 31, 2010 plan merger described below, we currently sponsor one defined benefit pension plan (“Pension Plan”) for employees hired prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI and certain of UGI’s other wholly owned domestic subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all active and retired employees.

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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,
	2011			2010			2011			2010
Service cost	$	1,750		$	1,745		$	54		$	40
Interest cost		5,564			5,284			183			212
Expected return on assets		(5,971	)		(5,858	)		(131	)		(126	)
Amortization of:
Prior service cost (benefit)		80			9			(174	)		(102	)
Actuarial loss		1,570			1,333			121			89
Net benefit cost		2,993			2,513			53			113
Change in associated regulatory liabilities		—			—			785			736
Net expense	$	2,993		$	2,513		$	838		$	849

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Service cost	$	3,675		$	3,490		$	107		$	81
Interest cost		10,919			10,568			365			423
Expected return on assets		(11,993	)		(11,717	)		(261	)		(252	)
Amortization of:
Prior service cost (benefit)		142			18			(348	)		(203	)
Actuarial loss		3,698			2,666			243			179
Net benefit cost		6,441			5,025			106			228
Change in associated regulatory liabilities		—			—			1,570			1,472
Net expense	$	6,441		$	5,025		$	1,676		$	1,700

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $14,400 to the Pension Plan during the next twelve months. During the six months ended March 31, 2011, the Company made contributions to the Pension Plan of $12,576. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months ended March 31, 2011, nor are they expected to be material for all of Fiscal 2011.

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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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased pension and postretirement benefit obligations by $46,672; decreased associated regulatory assets by $43,150; and increased pre-tax other comprehensive income by $3,522 (see Notes 2 and 5).

The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:

	Three Months
	Ended
	December 31, 2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	464,976
Service cost		2,188
Interest cost		5,805
Actuarial gain		(30,639	)
Benefits paid		(4,664	)
Benefit obligations — December 31, 2010	$	437,666
Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287,902
Actual gain on assets		19,285
Employer contribution		1,788
Benefits paid		(4,664	)
Fair value of plan assets — December 31, 2010	$	304,311
Funded status of the merged plan — December 31, 2010	$	(133,355	)
Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20,303	)
Unfunded liabilities — included in other noncurrent liabilities		(113,052	)
Net amount recognized	$	(133,355	)
Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	257
Net actuarial loss		112,733
Total	$	112,990
Amounts recorded in stockholder’s equity:
Prior service cost	$	29
Net actuarial loss		9,925
Total	$	9,954

The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391,192. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

7. Commitments and Contingencies

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

UGI Utilities 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 UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At March 31, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of-state sites.

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

South Carolina Electric & Gas Company v. UGI Utilities, Inc.On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. Trial took place in March 2009 and the court’s decision is pending.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10,000. KeySpan believes that the cost could be as high as $20,000. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s judgment in favor of UGI Utilities. A second phase of the trial is scheduled for August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Other Matters

Allentown, Pennsylvania Natural Gas Explosion.On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and UGI Utilities is cooperating with that investigation. Based on a visual inspection, UGI Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined.

UGI Utilities has received claims as a result of the explosion, although no lawsuits have yet been filed. UGI Utilities maintains liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of a $500 deductible, will be recovered through UGI Utilities’ insurance. We believe that claims and expenses associated with the explosion will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

We cannot predict with certainty the final results of any of the claims, potential claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

8. Related Party Transactions

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses — related parties in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to SCAAs with Energy Services. At March 31, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $297 and $2,590 during the three and six months ended March 31, 2011, respectively, and $94 and $7,579 during the three and six months ended March 31, 2010, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, were $15,000, $7,500 and $7,500 as of March 31, 2011, September 30, 2010 and March 31, 2010, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at March 31, 2011, comprising approximately 0.7 bcf of natural gas, was $3,452. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749. The carrying value of these gas storage inventories at March 31, 2010, comprising approximately 1.1 bcf of natural gas, was $8,543.

- 16 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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. In addition, from time to time, Gas Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and six months ended March 31, 2011 totaled $11,338 and $30,093, respectively. During the three and six months ended March 31, 2010, such transactions totaled $9,658 and $25,940, 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, 2011, revenues associated with such sales to Energy Services totaled $38,497 and $61,059, respectively. During the three and six months ended March 31, 2010, such revenues totaled $28,341 and $37,586, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above). During the three and six months ended March 31, 2011, the aggregate amount of such purchases totaled $22,002 and $35,498, respectively. During the three and six months ended March 31, 2010, such transactions totaled $12,417 and $18,395, 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)

9. 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, 2011, September 30, 2010 and March 31, 2010:

	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
March 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	1,806		$	114		$	—	$	1,920
Interest rate contracts	$	—		$	7,827		$	—	$	7,827
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,371	)	$	(9,311	)	$	—	$	(10,682	)
September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	61		$	425		$	—	$	486
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(3,263	)	$	(17,798	)	$	—	$	(21,061	)
March 31, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	226		$	299		$	—	$	525
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(7,616	)	$	—		$	—	$	(7,616	)

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

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at March 31, 2011 were $640,000 and $707,512 respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2010 were $640,000 and $702,100, 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

10. Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility 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 Standards Codification (“ASC”) 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 5).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At March 31, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10,682 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the Condensed Consolidated Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the March 31, 2011 Condensed Consolidated Balance Sheet.

- 19 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 relating to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 5). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At March 31, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 138.2 million kilowatt hours and 477.6 million kilowatt hours, respectively.

At March 31, 2011, the volume of natural gas associated with our unsettled NYMEX natural gas futures and option contracts totaled 21.5 million dekatherms and the maximum period over which we are currently hedging natural gas futures and option contracts is 18 months. At March 31, 2010, the volume of natural gas associated with unsettled NYMEX natural gas futures contracts and option contracts totaled 14.1 million dekatherms. At March 31, 2011, the volume of electricity under Electric Utility’s forward electricity purchase contracts was 835.5 million kilowatt hours and the maximum period over which these contracts extend is 37 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, 2011, the total notional amount of our unsettled IRPA contracts was $106,500. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013. There were no unsettled IPRA contracts outstanding at March 31, 2010.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At March 31, 2011, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At March 31, 2011 and 2010, restricted cash in margin accounts totaled $3,996 and $12,573, respectively. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of March 31, 2011 and 2010:

As of March 31:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	7,827	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments		1,617		226	Derivative financial instruments and Other noncurrent liabilities	$	(10,682	)	$	(7,616	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments		303		299
Total Derivatives		$	9,747	$	525		$	(10,682	)	$	(7,616	)

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

There was no ineffectiveness, and no gains or losses recognized in income as a result of excluding IRPAs from ineffectiveness testing, during the three or six months ended March 31, 2011. During the three and six months ended March 31, 2011 and 2010, the amounts of IRPA net losses included in AOCI that were reclassified into net income were not material. Additionally, during the six months ended March 31, 2010, the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 was not material.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

These factors, and those factors set forth in Item 1A. Risk Factors of this Quarterly Report on Form 10-Q and Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, 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, 2011 (“2011 three-month period”) with the three months ended March 31, 2010 (“2010 three-month period”) and the six months ended March 31, 2011 (“2011 six-month period”) with the six months ended March 31, 2010 (“2010 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 3 to the condensed consolidated financial statements.

2011 three-month period compared with 2010 three-month period

							Increase
Three Months Ended March 31,	2011			2010			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	452.4		$	445.4		$	7.0		1.6	%
Total margin (a)	$	163.9		$	154.0		$	9.9		6.4	%
Operating income	$	101.0		$	91.1		$	9.9		10.9	%
Income before income taxes	$	90.7		$	80.9		$	9.8		12.1	%
System throughput — bcf		61.3			54.6			6.7		12.3	%
Heating degree days — % colder (warmer) than normal (b)		6.6	%		(2.0	)%		—		—
Electric Utility:
Revenues	$	31.7		$	31.6		$	0.1		0.3	%
Total margin (a)	$	9.7		$	9.1		$	0.6		6.6	%
Operating income	$	3.0		$	3.1		$	(0.1	)	(3.2	)%
Income before income taxes	$	2.4		$	2.6		$	(0.2	)	(7.7	)%
Distribution sales — gwh		279.0			262.8			16.2		6.2	%

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 $1.8 million and $1.7 million during the three-month periods ended March 31, 2011 and 2010, 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 based upon heating degree days were 6.6% colder than normal in the 2011 three-month period compared with temperatures that were 2.0% warmer than normal in the prior-year period. Total distribution system throughput increased 6.7 bcf (12.3%) principally reflecting the effects of the colder weather on core market customers, higher throughput to certain low-margin interruptible delivery service customers and the benefits of an improving economy. 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Gas Utility revenues increased $7.0 million during the 2011 three-month period principally reflecting a $22.2 million increase in revenues from low-margin off-system sales partially offset by a decline in revenues from core market customers ($15.2 million). The decrease in core market revenues principally reflects lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($36.2 million) partially offset by the greater core market volumes. Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $288.5 million in the 2011 three-month period compared with $291.4 million in the prior-year period principally reflecting the lower average PGC rates partially offset by the effects of the higher off-system sales.

Gas Utility total margin increased $9.9 million in the 2011 three-month period. The increase principally reflects a $9.1 million increase in core market margin resulting from the higher core market throughput.

The increases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflect (1) the previously mentioned increase in total margin ($9.9 million) and (2) greater other income ($2.0 million). These increases were partially offset by slightly higher operating and administrative and depreciation expenses ($2.1 million).

Electric Utility. Electric Utility’s kilowatt-hour sales in the 2011 three-month period were 6.2% higher than in the prior-year three-month period on heating degree day weather that was 8.5% colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility revenues were about equal to last year principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service. Electric Utility cost of sales declined to $20.3 million in the 2011 three-month period compared to $20.7 million in the 2010 three-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin increased $0.6 million in the 2011 three-month period principally reflecting the impact of the greater sales.

Notwithstanding the greater total margin, Electric Utility 2011 three-month period operating income and income before income taxes declined $0.1 million and $0.2 million, respectively, principally reflecting higher operating expenses.

Interest Expense and Income Taxes.Our consolidated interest expense in the 2011 three-month period was about equal to interest expense in the prior-year three-month period. Our annual estimated effective tax rate was lower in the 2011 three-month period principally reflecting the regulatory effects of greater state tax depreciation (as further described below under “Financial Condition & Liquidity”).

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UGI UTILITIES, INC. AND SUBSIDIARIES

2011 six-month period compared with 2010 six-month period

							Increase
Six Months Ended March 31,	2011			2010			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	773.6		$	773.2		$	0.4		0.1	%
Total margin (a)	$	290.1		$	272.0		$	18.1		6.7	%
Operating income	$	176.0		$	154.8		$	21.2		13.7	%
Income before income taxes	$	155.7		$	134.3		$	21.4		15.9	%
System throughput — bcf		110.2			96.9			13.3		13.7	%
Heating degree days — % colder (warmer) than normal (b)		7.2	%		(0.9	)%		—		—
Electric Utility:
Revenues	$	60.7		$	65.6		$	(4.9	)	(7.5	)%
Total margin (a)	$	18.4		$	19.7		$	(1.3	)	(6.6	)%
Operating income	$	6.6		$	8.5		$	(1.9	)	(22.4	)%
Income before income taxes	$	5.5		$	7.6		$	(2.1	)	(27.6	)%
Distribution sales — gwh		529.5			505.2			24.3		4.8	%

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 $3.4 million and $3.6 million during the six-month periods ended March 31, 2011 and 2010, 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 based upon heating degree days were 7.2% colder than normal in the 2011 six-month period compared with temperatures that were 0.9% warmer than normal in the prior-year period. Total distribution system throughput increased 13.3 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core market customers and the benefits of an improving economy.

Gas Utility revenues were about equal to the prior-year period principally reflecting a decline in revenues from core market customers ($34.9 million) partially offset by a $33.7 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average PGC rates reflecting lower natural gas prices ($68.7 million) partially offset by the greater core market volumes. Gas Utility’s cost of gas was $483.4 million in the 2011 six-month period compared with $501.2 million in the prior-year period principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

Gas Utility total margin increased $18.1 million in the 2011 six-month period. The increase principally reflects a $16.1 million increase in core market margin reflecting the increase in core market throughput.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Gas Utility operating income during the 2011 six-month period increased $21.2 million principally reflecting the previously mentioned increase in total margin ($18.1 million) and higher other income ($2.7 million). The $21.4 million increase in income before income taxes reflects the previously mentioned increase in Gas Utility operating income ($21.2 million).

Electric Utility.Electric Utility’s kilowatt-hour sales in the 2011 six-month period were 4.8% higher than in the prior-year six-month period on heating degree day weather that was 7.2% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $4.9 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to provider of last resort (“POLR”) rates in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of sales declined to $38.8 million in the 2011 six-month period compared to $42.2 million in the 2010 six-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin declined $1.3 million in the 2011 six-month period, notwithstanding the greater sales, principally reflecting the absence of margin from electric generation service beginning January 1, 2010.

Electric Utility 2011 six-month period operating income and income before income taxes declined $1.9 million and $2.1 million, respectively, principally reflecting the previously mentioned lower total margin and higher operating and maintenance expenses.

Interest Expense and Income Taxes.Our consolidated interest expense in the 2011 six-month period was about equal to interest expense in the prior-year six-month period. Our annual estimated effective tax rate was lower in the 2011 six-month period principally reflecting the regulatory effects of greater state tax depreciation (as further described below under “Financial Condition & Liquidity”).

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at March 31, 2011 was $640 million compared to total debt outstanding at September 30, 2010 of $657 million which includes $17 million outstanding under UGI Utilities’ Revolving Credit Agreement (as further described below).

UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. At March 31, 2011, there were no amounts outstanding under its Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans. During the 2011 and 2010 six-month periods, average daily bank loan borrowings were $35.1 million and $136.8 million, respectively, and peak bank loan borrowings totaled $90 million and $239.8 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest. UGI Utilities expects to replace its Revolving Credit Agreement during the third quarter of Fiscal 2011 but to reduce the available borrowings to $300 million due to decreases in natural gas prices.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and bank loan borrowings, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011.

In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers will also be permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. In accordance with Pennsylvania utility ratemaking practice, UGI Utilities’ Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above will reduce federal and state income taxes otherwise payable and increase UGI Utilities deferred income tax liabilities.

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 its Revolving Credit Agreement to manage seasonal cash flow needs. Due to the impacts of strong operating cash flows resulting from the greater operating results and the effects of low natural gas prices, our cash and cash equivalents at March 31, 2011 totaled $75.5 million compared to $4.3 million at September 30, 2010. Additionally, at March 31, 2011 there were no amounts outstanding under our Revolving Credit Agreement.

Cash flow provided by operating activities was $165.0 million in the 2011 six-month period compared to cash provided by operating activities of $187.2 million in the prior-year six-month period. Cash flow from operating activities before changes in operating working capital decreased to $138.3 million in the 2011 six-month period from $154.8 million in the prior-year six-month period, notwithstanding the increase in operating results, primarily due to lower noncash charges for deferred income taxes. Changes in operating working capital provided $26.7 million of operating cash flow during the 2011 six-month period, comparable to the $32.4 million provided during the prior-year six-month period. Among other things, the cash flow from changes in operating working capital in the 2011 six-month period reflects higher cash from deferred fuel recoveries in the current period offset by lower cash from changes in natural gas inventories.

Investing activities. Cash used by investing activities was $38.2 million in the 2011 six-month period compared to $40.0 million in the 2010 six-month period. The prior-year six-month period reflects greater cash used to fund margin deposits in futures brokerage accounts. Total capital expenditures were $37.7 million in the 2011 six-month period compared with $26.2 million recorded in the prior-year period. The 2011 six-month period principally reflects higher UGI Gas capital expenditures and an increase in Electric Utility capital expenditures associated with an electricity transmission capacity project in its service territory.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Financing activities.Cash used by financing activities was $55.7 million in the 2011 six-month period compared with cash used by financing activities of $153.3 million in the 2010 six-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our Revolving Credit Agreement, cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI totaling $39.3 million and $36.3 million during the 2011 and 2010 six-month periods, respectively. During the 2011 six-month period, net bank loan repayments totaled $17 million compared with net bank loan repayments of $117 million in the prior-year six-month period.

Merger of Pension Plans

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP related to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010. The remeasurement resulted in a decrease in pension and postretirement benefit obligations and associated regulatory assets, and an increase in other comprehensive income (see Notes 2, 5 and 6). The remeasurement will result in an approximate $1.4 million decrease in Fiscal 2011 pension expense beginning January 1, 2011.

Transfer of CPG Storage Assets

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9 million as of March 31, 2011. The dividend of the storage assets is not expected to have a material impact on the results of operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into a firm storage service agreement with UGI Storage Company.

CPG Base Rate Filing

On January 14, 2011, CPG filed a request with the PUC to increase its base operating revenues by $16.5 million annually. The increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment. CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. Unless a settlement is reached sooner, this review process is expected to last approximately nine months which may delay implementation of the new rates until late October 2011.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of natural gas derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At March 31, 2011 and 2010, Gas Utility had $4.0 million and $12.6 million, respectively, of restricted cash associated with natural gas futures accounts with brokers. At March 31, 2011, the fair values of our natural gas futures and option contracts were gains of $1.5 million.

Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. The clauses provide for periodic adjustments to DS rates for differences between the total amount of power costs collected from customers and recoverable power costs incurred. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. FTRs are financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At March 31, 2011 the fair values of FTRs were not material.

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, 2011 and 2010 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 value of unsettled IRPAs held at March 31, 2011 was an asset of $7.8 million. A hypothetical 10% adverse change in the three-month LIBOR would result in a decrease in fair value of $3.7 million. There were no unsettled interest rate protection agreements outstanding as of March 31, 2010.

Our unsettled derivative instruments at March 31, 2011 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward purchase contracts, which are included in Electric Utility’s DS recovery mechanism; (3) exchange-traded gasoline futures and swap contracts; and (4) IRPAs.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Change in Internal Control over Financial Reporting

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s judgment in favor of UGI Utilities. A second phase of the trial is scheduled for August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25 million.

ITEM 1A. RISK FACTORS

In addition to the information presented below and 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, 2010, which could materially affect our business, financial condition or future results. The risks described below and 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.

As a result of recent natural gas explosions in the United States, including the Company’s February 9, 2011 natural gas explosion in Allentown, Pennsylvania, regulators may adopt new laws or reinterpret existing laws and regulations relating to the replacement of cast iron and bare steel natural gas pipelines which may adversely affect our results of operations and cash flows.

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 Pennsylvania Public Utility Commission (the “PUC”) is investigating the Allentown accident and we are cooperating with that investigation. Based on a visual inspection, we identified a fracture in a segment of our cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined. We are unable to predict the outcome of the PUC’s investigation, including whether the Company will be found to have violated any law, regulation, PUC order or decision in connection with the Allentown accident.

In addition, new federal or state laws may be adopted, or state and/or federal regulatory agencies, such as the PUC and United States Department of Transportation, may reinterpret existing laws and regulations relating to the timing of the replacement of cast iron and bare steel natural gas pipelines by all natural gas distribution and transmission companies under their respective jurisdictions. If the Company is required to comply with new or changed laws and regulations or the Company is not permitted to charge increased rates to recover a mandated increase in our costs, our cash flows and earnings may decrease.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 6. EXHIBITS

Exhibit No.		Exhibit	Registrant	Filing	Exhibit
	10.1	FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc.
	10.2	FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc.
	10.3	Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993
	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, 2011, 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, 2011, 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, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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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 6, 2011	By:	/s/ Donald E. Brown
		Donald E. Brown
		Vice President — Finance and Chief Financial Officer
Date: May 6, 2011	By:	/s/ Matthew J. Nolan
		Matthew J. Nolan
		Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc.
10.2	FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc.
10.3	Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993
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, 2011, 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, 2011, 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, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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