Ugi Utilities 10-Q 2010 Q1 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 December 31, 2009

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 January 31, 2010, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	PAGES
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of December 31, 2009, September 30, 2009 and December 31, 2008		1
Condensed Consolidated Statements of Income for the three months ended December 31, 2009 and 2008		2
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2009 and 2008		3
Notes to Condensed Consolidated Financial Statements		4 – 17
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18 – 22
Item 3. Quantitative and Qualitative Disclosures about Market Risk		22 – 23
Item 4T. Controls and Procedures		23
Part II Other Information
Item 1A. Risk Factors		24
Item 6. Exhibits		24
Signatures		25
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)

	December 31,			September 30,			December 31,
	2009			2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	12,678		$	13,523		$	10,955
Restricted cash		656			—			72,672
Accounts receivable (less allowances for doubtful accounts of $11,889, $11,384 and $17,644, respectively)		132,499			74,286			168,646
Accounts receivable — related parties		8,417			3,378			3,551
Accrued utility revenues		84,395			20,980			90,246
Inventories		177,087			196,598			167,384
Deferred income taxes		27,162			24,905			21,336
Regulatory assets		10,344			19,584			46,953
Derivative financial instruments		874			867			1,004
Prepaid expenses & other current assets		4,590			5,167			4,492
Total current assets		458,702			359,288			587,239
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $703,722, $692,082 and $669,751, respectively)		1,365,441			1,364,795			1,343,833
Goodwill		180,145			180,145			182,723
Regulatory assets		121,646			121,960			103,458
Other assets		5,470			4,049			13,165
Total assets	$	2,131,404		$	2,030,237		$	2,230,418
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Bank loans	$	179,000		$	154,000		$	283,000
Accounts payable		70,845			53,265			111,455
Accounts payable — related parties		6,424			8,746			4,424
Deferred fuel refunds		40,343			30,846			—
Derivative financial instruments		125			—			58,675
Other current liabilities		127,755			110,966			154,043
Total current liabilities		424,492			357,823			611,597
Long-term debt		640,000			640,000			640,000
Deferred income taxes		184,641			168,830			136,004
Deferred investment tax credits		5,579			5,670			5,945
Pension and postretirement benefit obligations		151,561			150,499			137,503
Other noncurrent liabilities		60,278			61,372			55,376
Total liabilities		1,466,551			1,384,194			1,586,425
Commitments and contingencies (note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)		60,259			60,259			60,259
Additional paid-in capital		467,160			467,160			466,888
Retained earnings		219,487			201,710			199,142
Accumulated other comprehensive loss		(82,053	)		(83,086	)		(82,296	)
Total common stockholder’s equity		664,853			646,043			643,993
Total liabilities and stockholder’s equity	$	2,131,404		$	2,030,237		$	2,230,418

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended
	December 31,
	2009			2008
Revenues	$	362,203		$	446,692
Costs and expenses:
Cost of sales — gas, fuel and purchased power		231,217			316,234
Operating and administrative expenses		44,222			50,678
Operating and administrative expenses — related parties		1,192			2,745
Taxes other than income taxes		4,528			4,604
Depreciation		12,681			12,031
Amortization		607			481
Other income, net		(1,517	)		(2,093	)
		292,930			384,680
Operating income		69,273			62,012
Interest expense		10,637			11,380
Income before income taxes		58,636			50,632
Income taxes		23,473			19,498
Net income	$	35,163		$	31,134

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Three Months Ended
	December 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	35,163		$	31,134
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		13,288			12,512
Deferred income taxes, net		11,724			(2,222	)
Provision for uncollectible accounts		4,845			8,702
Other, net		2,180			1,323
Net change in:
Accounts receivable and accrued utility revenues		(131,512	)		(164,448	)
Inventories		19,511			16,876
Deferred fuel costs		18,737			10,129
Accounts payable		15,258			33,256
Storage agreements security deposits		3,500			40,500
Other current assets		570			(940	)
Other current liabilities		13,414			31,614
Net cash provided by operating activities		6,678			18,436
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(13,810	)		(22,811	)
Net costs of property, plant and equipment disposals		(671	)		(389	)
Acquisition of CPG, net of cash acquired		—			(300,561	)
Proceeds from sale of CPG propane business assets		—			33,621
Increase in restricted cash		(656	)		(38,635	)
Net cash used by investing activities		(15,137	)		(328,775	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(17,386	)		(16,189	)
Issuance of long-term debt		—			108,000
Increase in bank loans		25,000			226,000
Net cash provided by financing activities		7,614			317,811
Cash and cash equivalents (decrease) increase	$	(845	)	$	7,472
CASH AND CASH EQUIVALENTS:
End of period	$	12,678		$	10,955
Beginning of period		13,523			3,483
(Decrease) increase	$	(845	)	$	7,472

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., a wholly owned subsidiary of UGI Corporation (“UGI”), and its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities primarily located in eastern, northeastern and central Pennsylvania. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities, Inc.’s natural gas distribution utility is referred to herein as “UGI Gas;” PNG’s natural gas distribution utility is referred to herein as “PNG Gas;” and CPG’s natural gas distribution utility is referred to herein as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” 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.

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

2. Significant Accounting Policies

Basis of Presentation.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, 2009 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, 2009 (“Company’s 2009 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Comprehensive Income (Loss).The following table presents the components of comprehensive income (loss) for the three months ended December 31, 2009 and 2008:

	Three Months Ended
	December 31,
	2009		2008
Net income	$	35,163	$	31,134
Other comprehensive income (loss)		1,033		(38,518	)
Comprehensive income (loss)	$	36,196	$	(7,384	)

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Other comprehensive income (loss) includes reclassifications of losses on interest rate protection agreements and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income. On December 31, 2008, we merged two of our defined benefit pension plans that we sponsored. As a result of the merger, at December 31, 2008, the Company was required under GAAP to remeasure the combined plan’s assets and obligations and record the funded status in our Condensed Consolidated Balance Sheet. During the three months ended December 31, 2008, we recorded an after-tax charge to other comprehensive income of $38,688 associated with the merger of the pension plans.

Restricted Cash.Restricted cash represents those cash balances in our futures brokerage accounts which are restricted from withdrawal.

Reclassifications.We have reclassified certain prior-year period balances to conform to the current-period presentation.

Use of Estimates.We make estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Income Taxes.As a result of settlements with tax authorities, in December 2009 and December 2008 the Company adjusted its unrecognized tax benefits. The reduction decreased income tax expense for the three months ended December 31, 2009 and 2008 by $290 and $490, respectively.

Subsequent Events.The Company’s management has evaluated the impact of subsequent events through February 5, 2010, the date the financial statements were filed with the SEC, and the effects of such evaluation have been reflected in the financial statements and related disclosures.

3. Accounting Changes

Adoption of New Accounting Standards

Intangible Asset Useful Lives.On October 1, 2009, we adopted new accounting guidance which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under GAAP. The intent of the new guidance is to improve the consistency between the useful life of a recognized intangible asset under GAAP relating to intangible asset accounting and the period of expected cash flows used to measure the fair value of the asset under GAAP relating to business combinations and other applicable accounting literature. The new guidance must be applied prospectively to intangible assets acquired after the effective date. The adoption of the new guidance did not impact our financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Business Combinations.On October 1, 2009, we adopted new guidance on the accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after the date of adoption. Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets will be recognized in operations (rather than decreases in goodwill).The new guidance did not have an impact on our financial statements for the three months ended December 31, 2009.

New Accounting Standards Not Yet Adopted

Enhanced Disclosures of Postretirement Plan Assets.In December 2008, the Financial Accounting Standards Board (“FASB”) issued new guidance requiring more detailed disclosures about employers’ postretirement plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. The provisions of this annual disclosure guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosure only, it will not impact the financial statements.

4. Segment Information

We have two reportable segments: (1) Gas Utility and (2) Electric Utility. The accounting policies of our two reportable segments are the same as those described in the Significant Accounting Policies note contained in the Company’s 2009 Annual Report. We evaluate each segment’s profitability principally based upon its income before income taxes. No single customer represents more than 10% of the total revenues of either Gas Utility or Electric Utility. There are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States.

UGI Penn HVAC Services, Inc. does not meet the quantitative thresholds for separate business segment reporting under GAAP and has been included in “Other.”

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Financial information by business segment follows:

Three Months Ended December 31, 2009:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	362,203	$	327,809	$	33,999	$	395
Cost of sales	$	231,217	$	209,760	$	21,457	$	—
Depreciation and amortization	$	13,288	$	12,299	$	989	$	—
Operating income	$	69,273	$	63,728	$	5,359	$	186
Interest expense	$	10,637	$	10,246	$	391	$	—
Income before income taxes	$	58,636	$	53,482	$	4,968	$	186
Total assets (at period end)	$	2,131,404	$	2,012,952	$	115,846	$	2,606
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	13,810	$	13,040	$	770	$	—

Three Months Ended December 31, 2008:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	446,692	$	410,366	$	35,921	$	405
Cost of sales	$	316,234	$	293,024	$	23,210	$	—
Depreciation and amortization	$	12,512	$	11,549	$	963	$	—
Operating income	$	62,012	$	56,885	$	5,047	$	80
Interest expense	$	11,380	$	10,975	$	405	$	—
Income before income taxes	$	50,632	$	45,910	$	4,642	$	80
Total assets (at period end)	$	2,230,418	$	2,114,385	$	115,101	$	932
Goodwill (at period end)	$	182,723	$	182,723	$	—	$	—
Capital expenditures	$	22,811	$	21,657	$	1,154	$	—

5. Inventories

Inventories comprise the following:

	December 31,		September 30,		December 31,
	2009		2009		2008
Gas Utility natural gas	$	170,235	$	189,747	$	160,108
Materials, supplies and other		6,852		6,851		7,276
Total inventories	$	177,087	$	196,598	$	167,384

From time to time UGI Utilities enters into storage contract administrative agreements (“SCAAs”) pursuant to which it has, among other things, released certain storage and transportation contracts for the terms of the storage agreements. At December 31, 2009, UGI Utilities had three SCAAs, two of which are scheduled to expire in October 2010 and one that is scheduled to expire in October 2012 (see Note 9).

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Pursuant to the 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.

UGI Utilities reflects the historical cost of natural gas storage inventories released under these agreements, which represent 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 agreements but not yet replenished) are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under these agreements at December 31, 2009, September 30, 2009 and December 31, 2008, comprising 11.4 billion cubic feet (“bcf”), 9.0 bcf, and 9.3 bcf of natural gas, was $95,911, $77,948 and $78,437, respectively. In conjunction with the SCAAs, at December 31, 2009, September 30, 2009 and December 31, 2008, UGI Utilities held a total of $22,500, $19,000 and $40,500, respectively, of security deposits received from its SCAAs’ counterparties which amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

6. Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 5 to the Company’s 2009 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	December 31,		September 30,		December 31,
	2009		2009		2008
Regulatory assets:
Income taxes recoverable	$	80,524	$	79,492	$	74,676
Postretirement benefits		2,336		2,473		4,118
CPG Gas pension and postretirement plans		8,572		8,572		9,068
Environmental costs		25,812		26,877		9,128
Deferred fuel costs		10,344		19,584		46,953
Other		4,402		4,546		6,468
Total regulatory assets	$	131,990	$	141,544	$	150,411
Regulatory liabilities:
Postretirement benefits	$	9,538	$	9,310	$	9,248
Environmental overcollections		8,392		8,720		9,713
Deferred fuel refunds		40,343		30,846		—
Total regulatory liabilities	$	58,273	$	48,876	$	18,961

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Deferred fuel costs and refunds.Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for differences between the total amount of purchased gas costs collected from customers and recoverable costs incurred. Net undercollected gas 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 refunds or costs. Unrealized losses on such contracts at December 31, 2009 and 2008 were $125 and $58,073, respectively. There were no such unrealized gains or losses at September 30, 2009.

7. Defined Benefit Pension and Other Postretirement Plans

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

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
Service cost	$	1,745		$	1,381		$	40		$	64
Interest cost		5,284			5,454			212			260
Expected return on assets		(5,858	)		(6,106	)		(126	)		(130	)
Amortization of:
Prior service cost (benefit)		9			7			(102	)		(87	)
Actuarial loss		1,333			173			89			30
Net benefit cost		2,513			909			113			137
Change in associated regulatory liabilities		—			—			736			803
Net expense	$	2,513		$	909		$	849		$	940

Pension Plans’ assets are held in trust and consist principally of equity and fixed income mutual funds. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. The Company does not believe it will be required to make any contributions to the Pension Plans during the year ending September 30, 2010 (Fiscal 2010) for ERISA funding purposes that will have a material effect on its liquidity. Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund and 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 for postretirement benefits other than pensions. The difference between the annual amount calculated and the amount included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2009, nor are they expected to be material for all of Fiscal 2010.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

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

8. 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 December 31, 2009, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material to UGI Utilities.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

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.

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 the third-party defendants are responsible for an equitable share of any costs Frontier would be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of control against another third-party defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18,000. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7,600. Frontier subsequently filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed a motion for summary judgment with respect to Frontier’s claims.

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.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

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 in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites could total approximately $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 of this amount. 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, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. In a second phase of the trial scheduled for early 2010, the court will determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies estimate that remediation costs at Waterbury North could total $25,000.

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

9. Related Party Transactions

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

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

From time to time, UGI Utilities is a party to SCAAs with UGI Energy Services, Inc., a second-tier wholly owned subsidiary of UGI (“Energy Services”). At December 31, 2009, UGI Utilities was a party to a three-year SCAA with Energy Services expiring October 31, 2012 and, during the periods covered by the financial statements, was a party to other one-year 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 $7,484 and $14,582 during the three months ended December 31, 2009 and 2008, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets, was $7,500, $15,000 and $15,000 as of December 31, 2009, September 30, 2009 and December 31, 2008, respectively.

The volumes and carrying amounts of gas storage inventories released under Energy Services’ SCAAs at December 31, 2009, September 30, 2009 and December 31, 2008 are as follows: at December 31, 2009, gas storage inventories comprising approximately 4.0 bcf of natural gas totaling $32,855; at September 30, 2009, gas storage inventories comprising approximately 7.7 bcf of natural gas totaling $67,436; and at December 31, 2008, gas storage inventories comprising approximately 7.8 bcf of natural gas totaling $66,485.

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 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 months ended December 31, 2009 and 2008 totaled $16,282 and $15,986, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2009 and 2008, revenues associated with such sales to Energy Services totaled $9,244 and $7,987, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to the transactions already described above). During the three months ended December 31, 2009 and 2008, such purchases totaled $5,977 and $5,845, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

10. Fair Value Measurements

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2009 and 2008:

	Quoted
	Prices in
	Active
	Markets for			Significant
	Identical			Other
	Assets and			Observable		Unobservable
	Liabilities			Inputs		Inputs
	(Level 1)			(Level 2)		(Level 3)		Total
December 31, 2009:
Derivative financial instruments:
Assets	$	233		$	641	$	—	$	874
Liabilities	$	(125	)	$	—	$	—	$	(125	)
December 31, 2008:
Derivative financial instruments:
Assets	$	—		$	1,004	$	—	$	1,004
Liabilities	$	(58,675	)	$	—	$	—	$	(58,675	)

11. Disclosures About Derivative Instruments, Hedging Activities and Financial Instruments

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 contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers.

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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, 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.

At December 31, 2009, the volume of natural gas associated with our unsettled NYMEX natural gas futures contracts was not material. The volume of transmission congestion that is subject to FTRs at December 31, 2009 totaled 730.0 million kilowatt-hours and the maximum period over which we are currently hedging electricity congestion with FTRs is 17 months with a weighted average term of 4 months.

With respect to natural gas futures contracts associated with Gas Utility, gains and losses on unsettled natural gas futures contracts are recorded in deferred fuel costs on the Condensed Consolidated Balance Sheets in accordance with the FASB’s guidance in Accounting Standards Codification (“ASC”) 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism. At December 31, 2009 and 2008, Gas Utility had recorded current liabilities of $125 and $58,073, respectively, representing the fair values of unsettled natural gas futures contracts as of those dates and associated regulatory assets of equal amount. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement of its default service rate filing with the PUC, FTRs associated with periods beginning January 1, 2010 are recorded at fair value with changes in fair value recorded in regulatory assets or liabilities in accordance with ASC 980. Electric Utility FTRs associated with periods prior to January 1, 2010 are recorded at fair value with changes in fair value reflected in cost of sales.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. The volumes of gasoline under these contracts 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 AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At December 31, 2009 there were no unsettled IRPA contracts outstanding. The amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At December 31, 2009 and 2008, Gas Utility’s restricted cash in brokerage accounts totaled $656 and $72,672, respectively. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of December 31, 2009:

	Derivative Assets			Derivative (Liabilities)
	Balance Sheet	Fair		Balance Sheet	Fair
As of December 31, 2009	Location	Value		Location	Value
Derivatives Accounted for Under ASC 980:
Natural gas futures contracts	Derivative financial instruments	$	3	Derivative financial instruments	$	(125	)
FTRs	Derivative financial instruments		641
Total Derivatives Accounted for Under ASC 980:			644			(125	)
Derivatives Not Designated as Hedging Instruments:
Gasoline futures contracts	Derivative financial instruments		230
Total Derivatives		$	874		$	(125	)

During the three months ended December 31, 2009, the amount of IRPA net losses included in AOCI that were reclassified into net income, and the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 and gasoline futures and swap contracts, were 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 electricity, 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 based on the contract underlying is directly associated with the price or value of a service.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivatives and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated values of our remaining financial instruments assets and (liabilities) at December 31, 2009 (including unsettled derivative instruments) are as follows:

	Asset (Liability)
	Carrying			Estimated
	Amount			Fair Value
Derivative financial instruments	$	749		$	749
Long-term debt	$	(640,000	)	$	(697,137	)

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 type debt.

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Quarterly Report 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 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 future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended December 31, 2009 (“2009 three-month period”) with the three months ended December 31, 2008 (“2008 three-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 4 to the condensed consolidated financial statements.

2009 three-month period compared with 2008 three-month period

							Increase
Three Months Ended December 31,	2009			2008			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	327.8		$	410.4		$	(82.6	)	(20.1	)%
Total margin (a)	$	118.0		$	117.3		$	0.7		0.6	%
Operating income	$	63.7		$	56.9		$	6.8		12.0	%
Income before income taxes	$	53.5		$	45.9		$	7.6		16.6	%
System throughput — bcf		42.3			44.0			(1.7	)	(3.9	)%
Heating degree days — % colder than normal (b)		0.4	%		7.1	%		—		—
Electric Utility:
Revenues	$	34.0		$	35.9		$	(1.9	)	(5.3	)%
Total margin (a)	$	10.7		$	10.7		$	—		0.0	%
Operating income	$	5.4		$	5.0		$	0.4		8.0	%
Income before income taxes	$	5.0		$	4.6		$	0.4		8.7	%
Distribution sales — gwh		242.4			252.8			(10.4	)	(4.1	)%

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 $1.9 million and $2.0 million during the three-month periods ended December 31, 2009 and 2008, 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 1990-2004 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 essentially normal in the 2009 three-month period compared with temperatures that were 7.1% colder than normal in the prior-year period. Total distribution system throughput decreased 1.7 bcf in the 2009 three-month period principally reflecting the effects of the warmer weather on core-market customers. Gas Utility’s core-market customers are comprised of 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 decreased $82.6 million during the 2009 three-month period principally reflecting a decline in revenues from retail core-market customers and, to a much lesser extent, lower revenues from low-margin off-system sales. The decrease in retail core-market revenues principally resulted from lower average purchased gas cost (“PGC”) rates and lower retail core-market volumes partially offset by the effects of PNG Gas and CPG Gas base rate operating revenue increases that became effective August 28, 2009. Under Gas Utility’s PGC recovery mechanism, 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 $209.8 million in the 2009 three-month period compared with $293.0 million in the prior-year period principally reflecting the lower average PGC rates and to a much lesser extent the lower retail core-market and off-system sales.

Notwithstanding the decrease in core-market volumes, Gas Utility total margin increased $0.6 million in the 2009 three-month period. The increase reflects the impact of PNG Gas and CPG Gas base operating revenue increases.

Gas Utility operating income during the 2009 three-month period increased $6.8 million principally reflecting lower operating and administrative costs and the previously mentioned slight increase in total margin. The 2009 three-month period operating and administrative costs include, among other things, lower provisions for uncollectible accounts, lower charges associated with environmental matters and lower UGI corporate allocated expenses. These decreases in operating and administrative expenses were partially offset by higher pension expense due in large part to the amortization of actuarial losses experienced by the pension plans during Fiscal 2009. The increase in income before income taxes reflects the previously mentioned higher operating income and lower interest expense associated with bank loan borrowings due to lower average bank loan borrowings and lower average interest rates.

Electric Utility.Electric Utility’s kilowatt-hour sales in the 2009 three-month period were lower than in the prior year. The decline in sales principally reflects lower sales to commercial and industrial customers as a result of the deterioration in general economic activity over the last year and the effects of a warmer 2009 three-month period on heating-related sales volumes. Temperatures based upon heating degree days were approximately 3.9% warmer than in the prior-year period. Electric Utility revenues decreased $1.9 million principally as a result of the lower sales partially offset by slightly higher Provider of Last Resort (“POLR”) revenues. Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Electric Utility cost of sales declined to $21.5 million in the 2009 three-month period compared to $23.2 million in the 2008 three-month period principally reflecting the effects of the lower volume sales and changes in the fair value of FTRs partially offset by higher transmission costs.

Electric Utility total margin was equal to the prior year, notwithstanding the decrease in revenues, principally reflecting the lower total cost of sales and slightly lower gross receipts taxes.

Electric Utility operating income and income before income taxes in the 2009 three-month period were $0.4 million higher than such amounts in the prior-year period reflecting lower distribution system maintenance and uncollectible accounts expenses.

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UGI UTILITIES, INC. AND SUBSIDIARIES

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at December 31, 2009 was $819 million compared to total debt outstanding of $794 million at September 30, 2009. The increase in total debt reflects an increase in bank loan borrowings primarily to fund higher seasonal working capital investments in accounts receivable.

UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At December 31, 2009 and 2008, UGI Utilities had $179 million and $283 million of borrowings outstanding under its Revolving Credit Agreement, respectively. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the three months ended December 31, 2009 and 2008, average daily bank loan borrowings were $161.2 million and $242.8 million, respectively, and peak bank loan borrowings totaled $203 million and $304 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest. Revolving Credit Agreement borrowings were higher in the prior-year period due in large part to increases in margin deposits associated with natural gas futures contracts as a result of declines in wholesale natural gas prices.

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.

Cash flow provided by operating activities decreased to $6.7 million during the 2009 three-month period from $18.4 million in the prior-year three-month period. Cash flow from operating activities before changes in operating working capital increased to $67.2 million in the 2009 three-month period from $51.5 million in the prior-year three-month period. The increase reflects the higher net income and greater noncash charges for deferred income taxes. Changes in operating working capital used $60.5 million of operating cash flow during the 2009 three-month period compared with $33.0 million used during the prior-year three-month period. Cash flow provided by changes in operating working capital in the 2009 three-month period includes $3.5 million of cash from changes in SCAA security deposits compared to $40.5 million of such cash received in the 2008 three-month period.

Investing activities. Cash used by investing activities was $15.1 million in the 2009 three-month period compared to $328.8 million in the 2008 three-month period. The 2008 three-month period reflects net cash paid in conjunction with the acquisition of CPG (“CPG Acquisition”) of $300.6 million less $33.6 million of net cash received from the sale of the propane assets of a CPG subsidiary. In addition, changes in restricted cash associated with our commodity futures brokerage accounts used $0.7 million of cash in the 2009 three-month period compared with $38.6 million of such cash used in the prior-year period. The significantly greater increase in the prior-year three-month period restricted cash reflects the effects of declining natural gas prices on margin deposit requirements during that period. Capital expenditures were lower in the 2009 three-month period due in large part to lower 2009 three-month period Gas Utility growth capital expenditures.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Financing activities.Cash provided by financing activities was $7.6 million in the 2009 three-month period compared with $317.8 million in the 2008 three-month period. Financing activity cash flows are primarily the result of issuances and repayments of long-term debt, 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 $17.4 million and $16.2 million during the 2009 and 2008 three-month periods, respectively. During the 2009 three-month period, net bank loan borrowings totaled $25 million compared with net bank loan borrowings of $226 million in the prior-year three-month period. The significantly higher net cash from bank loan borrowings in the prior-year three-month period was due in large part to the timing and use of cash contributions made by UGI on September 25, 2008 to fund the CPG Acquisition on October 1, 2008. A $120 million cash contribution made by UGI on September 25, 2008 was temporarily used by UGI Utilities in September 2008 to reduce bank loan borrowings. This amount was then reborrowed on October 1, 2008, along with additional bank loan borrowings, to fund a portion of the CPG Acquisition. The greater 2008 three-month period bank loan borrowings also reflect, in part, greater cash needed to fund the higher natural gas futures margin deposits. During the 2008 three-month period, UGI Utilities issued $108 million of 6.375% Senior Notes due 2013 the proceeds of which were used to fund a portion of the CPG Acquisition. There were no long-term debt transactions during the 2009 three-month period.

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 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 fair value of natural gas futures contracts at December 31, 2009 was a loss of $0.1 million. 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 December 31, 2009 Gas Utility had approximately $0.7 million of restricted cash associated with natural gas and other futures accounts with brokers.

Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. Changes in electricity prices could require Electric Utility to provide cash collateral to its supply counterparties.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Electric Utility also obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, by purchases at monthly PJM auctions. 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. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At December 31, 2009, the fair value of Electric Utility’s FTRs was $0.6 million.

On January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs beginning January 1, 2010. Because of this default service ratemaking, beginning January 1, 2010 there is limited electricity price and transmission congestion price risk associated with our Electric Utility operations.

Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at December 31, 2009 were not material.

Our variable-rate debt includes our bank loan borrowings. These agreements provide for interest rates on borrowings that are indexed to short-term market interest rates. Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. 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.

Our unsettled derivative instruments at December 31, 2009 comprised Electric Utility’s FTRs and exchange-traded gasoline futures and swap contracts.

ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of Disclosure Controls and Procedures
	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 designed and functioning effectively 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 Securities and Exchange Commission’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 disclosure.
(b)	Change in Internal Control over Financial Reporting
	No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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UGI UTILITIES, INC. AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and last date of the period for which it was filed, and the exhibit number in such filing):

Incorporation by Reference

Exhibit
No.		Exhibit	Registrant	Filing	Exhibit
	10.1	Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009	UGI	Form 10-Q (12/31/09)		10.1
	10.2	UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees	UGI	Form 10-Q (12/31/09)		10.2
	12.1	Computation of ratio of earnings to fixed charges
	31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, 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: February 5, 2010	By:	/s/ John C. Barney
		John C. Barney
		Senior Vice President — Finance and Chief Financial Officer

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

12.1	Computation of ratio of earnings to fixed charges
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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