Ugi Utilities 10-Q 2013 Q3 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 June 30, 2013

OR

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

For the transition period from to

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)

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

UGI UTILITIES, INC.

2525 N. 12th Street, Suite 360

Reading, PA

(Address of principal executive offices)

19612

(Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

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

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

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

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

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

At July 31, 2013, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30, 2013			September 30, 2012			June 30, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	82,027		$	1,259		$	75,969
Restricted cash	2,636			—			1,604
Accounts receivable (less allowances for doubtful accounts of $9,166, $3,588 and $7,457, respectively)	78,677			47,362			61,072
Accounts receivable — related parties	4,086			4,571			4,311
Accrued utility revenues	11,836			16,911			14,970
Inventories	53,998			67,334			38,413
Deferred income taxes	38,619			46,436			33,595
Regulatory assets	3,747			6,473			2,681
Derivative financial instruments	8,228			5,468			545
Prepaid expenses & other current assets	9,766			29,313			17,890
Total current assets	293,620			225,127			251,050
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $846,941, $815,720 and $809,458, respectively)	1,531,440			1,479,949			1,458,654
Goodwill	182,145			182,145			182,145
Regulatory assets	317,216			331,932			288,366
Other assets	3,635			4,026			5,630
Total assets	$	2,328,056		$	2,223,179		$	2,185,845
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	133,000		$	133,000		$	40,000
Bank loans	—			9,200			—
Accounts payable	35,587			46,754			30,457
Accounts payable — related parties	17,176			10,192			10,175
Deferred fuel refunds	14,156			4,435			10,325
Derivative financial instruments	22,911			36,011			7,150
Other current liabilities	123,438			131,092			144,492
Total current liabilities	346,268			370,684			242,599
Long-term debt	467,000			467,000			600,000
Deferred income taxes	443,703			417,052			371,388
Deferred investment tax credits	4,355			4,612			4,698
Pension and postretirement benefit obligations	172,721			179,056			126,007
Other noncurrent liabilities	51,999			56,262			92,409
Total liabilities	1,486,046			1,494,666			1,437,101
Commitments and contingencies (note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259			60,259
Additional paid-in capital	469,736			468,692			468,630
Retained earnings	327,298			229,379			246,286
Accumulated other comprehensive loss	(15,283		)	(29,817		)	(26,431		)
Total common stockholder’s equity	842,010			728,513			748,744
Total liabilities and stockholder’s equity	$	2,328,056		$	2,223,179		$	2,185,845

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues	$	148,798		$	143,644		$	818,496		$	770,087
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	64,332			62,701			415,394			412,377
Operating and administrative expenses	46,420			37,689			143,076			124,380
Operating and administrative expenses — related parties	1,940			2,107			6,757			7,013
Taxes other than income taxes	3,756			3,919			12,716			12,903
Depreciation	13,201			12,425			38,849			37,132
Amortization	832			826			2,467			2,292
Other income, net	(561		)	(1,323		)	(1,435		)	(4,362		)
	129,920			118,344			617,824			591,735
Operating income	18,878			25,300			200,672			178,352
Interest expense	9,690			10,575			29,587			31,859
Income before income taxes	9,188			14,725			171,085			146,493
Income taxes	3,815			6,265			70,641			57,494
Net income	$	5,373		$	8,460		$	100,444		$	88,999

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended June 30,					Nine Months Ended June 30,
	2013		2012			2013		2012
Net income	$	5,373	$	8,460		$	100,444	$	88,999
Other comprehensive income (loss):
Net gains (losses) in fair value of derivative instruments (net of tax of $(5,301), $4,801, $(9,638) and $4,209, respectively)	7,475		(6,772		)	13,590		(5,938		)
Reclassifications of net losses on derivative instruments (net of tax of $(84), $(201), $(252) and $(725), respectively)	119		283			356		1,023
Benefit plans (net of tax of $(140), $(80), $(418) and $(242), respectively)	195		101			588		317
Other comprehensive income (loss)	7,789		(6,388		)	14,534		(4,598		)
Comprehensive income	$	13,162	$	2,072		$	114,978	$	84,401

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Nine Months Ended
	June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	100,444		$	88,999
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	41,316			39,424
Deferred income taxes, net	23,369			21,269
Provision for uncollectible accounts	8,297			5,592
Other, net	4,647			(12,809		)
Net change in:
Accounts receivable and accrued utility revenues	(34,052		)	(5,354		)
Inventories	13,336			65,850
Deferred fuel and power costs	20,549			8,133
Accounts payable	(4,183		)	(23,032		)
Other current assets	19,675			7,059
Other current liabilities	(4,753		)	7,467
Net cash provided by operating activities	188,645			202,598
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(94,480		)	(79,698		)
Net costs of property, plant and equipment disposals	(2,604		)	(2,400		)
(Increase) decrease in restricted cash	(2,636		)	2,704
Net cash used by investing activities	(99,720		)	(79,394		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	—			(54,809		)
Decrease in bank loans	(9,200		)	—
Other	1,043			307
Net cash used by financing activities	(8,157		)	(54,502		)
Cash and cash equivalents increase	$	80,768		$	68,702
CASH AND CASH EQUIVALENTS:
End of period	$	82,027		$	75,969
Beginning of period	1,259			7,267
Increase	$	80,768		$	68,702

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

1. Nature of Operations

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” PNG also has a heating, ventilation and air-conditioning service business, UGI Penn HVAC Services, Inc., which operates principally in the PNG service territory (“HVAC Business”).

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

2. Significant Accounting Policies

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

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2012, condensed consolidated balance sheet data was derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2012 (“Company’s 2012 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

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

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

3. Accounting Changes

New Accounting Standards Not Yet Adopted

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

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interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

4. Segment Information

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other.”

The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2012 Annual Financial Statements and Notes. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States and all of our reportable segments’ long-lived assets are located in the United States.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Financial information by business segment follows:

Three Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	148,798	$	126,725	$	21,535	$	538
Cost of sales	$	64,332	$	52,365	$	11,967	$	—
Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
Operating income	$	18,878	$	16,054	$	2,584	$	240
Interest expense	$	9,690	$	9,172	$	518	$	—
Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	38,961	$	37,224	$	1,737	$	—

Three Months Ended June 30, 2012:

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Nine Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	818,496	$	743,614	$	73,604	$	1,278
Cost of sales	$	415,394	$	372,681	$	42,713	$	—
Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
Operating income	$	200,672	$	191,592	$	8,597	$	483
Interest expense	$	29,587	$	28,071	$	1,516	$	—
Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Nine Months Ended June 30, 2012:

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

5. Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Gas Utility natural gas	$	43,052	$	57,663	$	27,761
Materials, supplies and other	10,946		9,671		10,652
Total inventories	$	53,998	$	67,334	$	38,413

At June 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expires in October 2013 and two of which expire in October 2015 (see Note 9). Pursuant to 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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

The carrying value of gas storage inventories released under UGI Utilities’ principal SCAAs at June 30, 2013, September 30, 2012 and June 30, 2012, comprising 5.6 billion cubic feet (“bcf”), 11.4 bcf and 6.0 bcf of natural gas, was $24,389, $32,627 and $15,787, respectively. In conjunction with these SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at June 30, 2013, and $22,500 at September 30, 2012 and June 30, 2012. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

6. Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 4 to the Company’s 2012 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104,731	$	103,172	$	99,891
Underfunded pension and postretirement plans	177,846		188,222		144,613
Environmental costs	16,642		16,812		16,562
Deferred fuel and power costs	4,109		11,602		9,829
Removal costs, net	12,074		12,718		11,840
Other	5,561		5,879		8,312
Total regulatory assets	$	320,963	$	338,405	$	291,047
Regulatory liabilities:
Postretirement benefits	$	14,244	$	13,147	$	12,342
Environmental overcollections	2,906		2,883		3,726
Deferred fuel and power refunds	14,156		4,435		10,325
State tax benefits — distribution system repairs	8,024		7,385		6,961
Other	672		494		624
Total regulatory liabilities	$	40,002	$	28,344	$	33,978

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2013, September 30, 2012, and June 30, 2012, were $(1,352), $5,303 and $280, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are recognized on the Condensed Consolidated Balance Sheet with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2013, September 30,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2012, and June 30, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6,060, $9,207 and $13,095, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at June 30, 2013, September 30, 2012, and June 30, 2012, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $386 to $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line was approximately $2,650 which amount, net of related deferred income taxes, was recorded as a dividend of net assets.

7. Defined Benefit Pension and Other Postretirement Plans

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	2,052		$	1,756		$	51		43
Interest cost	5,196			5,594			143			165
Expected return on assets	(6,197		)	(5,940		)	(133		)	(127		)
Amortization of:
Prior service cost (benefit)	62			62			(105		)	(105		)
Actuarial loss	3,366			1,963			91			99
Net benefit cost	4,479			3,435			47			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	862		$	859
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	6,158		$	5,269		$	154		$	129
Interest cost	15,587			16,782			428			497
Expected return on assets	(18,594		)	(17,822		)	(396		)	(380		)
Amortization of:
Prior service cost (benefit)	187			187			(317		)	(317		)
Actuarial loss	10,098			5,890			273			296
Net benefit cost	13,436			10,306			142			225
Change in associated regulatory liabilities	—			—			2,446			2,353
Net expense	$	13,436		$	10,306		$	2,588		$	2,578

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $2,500 to the Pension Plan during the remainder of Fiscal 2013. During the nine months endedJune 30, 2013 and 2012, the Company made contributions to the Pension Plan of $13,365 and $25,442, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas’ and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the nine months endedJune 30, 2013 and 2012, nor are they expected to be material for all of Fiscal 2013.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

8. Commitments and Contingencies

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At June 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,399 and $15,820, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

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

The Company does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

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

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

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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 Incident. On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage (the “Incident”). UGI Utilities has received and settled all wrongful death claims and substantially all property and personal injury claims in connection with the Incident. UGI Utilities maintains liability insurance for personal injury, wrongful death and property and casualty damages subject to a $500 deductible. We expect that the remaining claims will be covered by UGI Utilities’ insurance. As a result, the Incident did not and we continue to believe it will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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

9. Related Party Transactions

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

At June 30, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, and two of which expire October 31, 2015 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $21,570 and $26,596 during the three and nine months ended June 30, 2013, respectively, and $8,396 and $13,726 during the three and nine months ended June 30, 2012. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, were $16,500 as of June 30, 2013, and $15,000 as of September 30, 2012 and June 30, 2012.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at June 30, 2013, comprising approximately 5.6 bcf of natural gas, was $24,389. The carrying value of these gas storage inventories at September 30,

- 13 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2012, comprising approximately 7.6 bcf of natural gas, was $21,217. The carrying value of these gas storage inventories at June 30, 2012, comprising approximately 4.1 bcf of natural gas, was $10,512.

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

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2013, revenues associated with such sales to Energy Services totaled $14,956 and $60,208, respectively. During the three and nine months ended June 30, 2012, revenues associated with such sales to Energy Services totaled $12,067 and $52,744, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and nine months ended June 30, 2013, the aggregate amount of such purchases totaled $24,426 and $61,659, respectively. During the three and nine months ended June 30, 2012, such purchases totaled $13,158 and $36,477, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

- 14 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

10. Fair Value Measurements

Derivative Financial Instruments

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

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	103		$	—		$	—	$	103
Interest rate contracts	$	—		$	8,125		$	—	$	8,125
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,885	)	$	(5,759	)	$	—	$	(7,644	)
Interest rate contracts	$	—		$	(15,306	)	$	—	$	(15,306	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at June 30, 2013, were $600,000 and $663,178, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2012, were $640,000 and $742,165, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2).

11. Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms and 13.2 million dekatherms, respectively. At June 30, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 6).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $6,060 and $13,095, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 327.4 million kilowatt hours and 654.7 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). At June 30, 2013 and 2012, the volumes associated with Electric Utility FTRs

- 16 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

totaled 260.6 million kilowatt hours and 261.0 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which we are hedging electricity congestion with FTRs is 11 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. 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 June 30, 2013 and 2012, the total notional amounts of unsettled IRPAs was $173,000. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in “Other income, net” on the Condensed Consolidated Statements of Income.

At June 30, 2013, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,203.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2013, there was $2,636 restricted cash in brokerage accounts. At June 30, 2012, restricted cash in brokerage accounts totaled $1,604.

- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	8,125	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(15,306	)	$	(28,917	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	67		545		Derivative financial instruments and Other noncurrent liabilities	(7,644		)	(13,539		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	36		—		Derivative financial instruments	—			(17		)
Total Derivatives		$	8,228	$	545		$	(22,950	)	$	(42,473	)

- 18 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and nine months ended June 30, 2013 and 2012:

Three Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	12,776		$	(11,573	)	$	(203	)	$	(484	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	(93	)	$	(127	)							Operating expenses/other income, net
Nine Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	23,228		$	(10,147	)	$	(608	)	$	(1,748	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	12		$	78								Operating expenses/other income, net

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

- 19 -

UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

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

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

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

- 20 -

UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2013 (“2013 three-month period”) with the three months ended June 30, 2012 (“2012 three-month period”) and the nine months ended June 30, 2013 (“2013 nine-month period”) with the nine months ended June 30, 2012 (“2012 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 4 to the condensed consolidated financial statements.

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

Three Months Ended June 30,	2013			2012			Increase (Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	126.7		$	122.3		$	4.4		3.6	%
Total margin (a)	$	74.4		$	70.9		$	3.5		4.9	%
Operating income	$	16.1		$	22.5		$	(6.4	)	(28.4	)%
Income before income taxes	$	6.9		$	12.6		$	(5.7	)	(45.2	)%
System throughput — billions of cubic feet (“bcf”)
Core market	8.8			8.3			0.5			6.0	%
Total	35.9			36.2			(0.3		)	(0.8	)%
Heating degree days — % (warmer) than normal (b)	(7.1		)%	(19.0		)%	—			—
Electric Utility:
Revenues	$	21.5		$	20.8		$	0.7		3.4	%
Total margin (a)	$	8.4		$	8.4		$	—		—	%
Operating income	$	2.6		$	2.6		$	—		—	%
Income before income taxes	$	2.1		$	1.9		$	0.2		10.5	%
Distribution sales — millions of kilowatt-hours (“gwh”)	222.5			221.4			1.1			0.5	%

(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 $1.2 million and $1.1 million during the three-month periods ended June 30, 2013 and 2012, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.

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

Gas Utility. Temperatures in the Gas Utility service territory in the 2013 three-month period based upon heating degree days were 7.1% warmer than normal but 14.4% colder than the prior-year three-month period. Total distribution system throughput decreased slightly, notwithstanding an increase in core market throughput and greater large firm delivery service throughput, principally reflecting lower throughput to certain low-margin, interruptible delivery service customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the colder weather and, to a much lesser extent, customer growth, due principally to conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $4.4 million during the 2013 three-month period principally reflecting higher revenues from core market customers ($1.9 million), greater revenues from large firm delivery service customers on the higher throughput, and slightly higher revenues from off-system sales ($1.5 million). The increase in core market revenues principally reflects the effects of the higher core market volumes partially offset by the effects of lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($7.0 million). Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the

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UGI UTILITIES, INC. AND SUBSIDIARIES

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 $52.4 million in the 2013 three-month period compared with $51.4 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($6.3 million) and the higher off-system sales ($1.5 million) partially offset by the effects of the lower average PGC rates.

Gas Utility total margin increased $3.5 million in the 2013 three-month period principally reflecting higher core market total margin ($1.3 million) and greater large firm delivery service total margin ($1.7 million). The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers.

The decreases in Gas Utility operating income and income before income taxes during the 2013 three-month period, notwithstanding the increase in total margin, principally reflects higher operating and administrative expenses ($9.4 million) including, among other things, higher uncollectible accounts expense ($2.4 million), higher pension and benefits expenses ($1.8 million) and higher injuries and damages and distribution system expenses ($1.4 million).

Electric Utility. Temperatures based upon heating degree days during the 2013 three-month period were approximately 9% warmer than normal but approximately 9% colder than the 2012 three-month period. Cooling degree days in the current-year and prior-year three-month periods were comparable. The increase in Electric Utility revenues reflects the effects of slightly higher average default service (“DS”) rates, reflecting the pass through of slightly higher electricity costs, and the effects of the slightly higher sales. Electric Utility cost of sales increased to $12.0 million in the 2013 three-month period from $11.3 million in the 2012 three-month period principally reflecting the effects of the greater DS rates and the higher sales.

Electric Utility total margin and operating income in the 2013 three-month period were equal to the prior-year period.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2013three-month period was lower than the prior year principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the three months ended June 30, 2013, was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

2013 nine-month period compared with 2012 nine-month period

							Increase
Nine Months Ended June 30,	2013			2012			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	743.6		$	696.8		$	46.8		6.7	%
Total margin (a)	$	370.9		$	326.2		$	44.7		13.7	%
Operating income	$	191.6		$	168.7		$	22.9		13.6	%
Income before income taxes	$	163.5		$	138.6		$	24.9		18.0	%
System throughput — billions of cubic feet (“bcf”)
Core market	65.4			54.7			10.7			19.6	%
Total	158.5			146.0			12.5			8.6	%
Heating degree days — % (warmer) than normal (b)	(1.2		)%	(16.6		)%	—			—
Electric Utility:
Revenues	$	73.6		$	71.9		$	1.7		2.4	%
Total margin (a)	$	26.9		$	26.1		$	0.8		3.1	%
Operating income	$	8.6		$	9.1		$	(0.5	)	(5.5	)%
Income before income taxes	$	7.1		$	7.4		$	(0.3	)	(4.1	)%
Distribution sales — millions of kilowatt-hours (“gwh”)	753.4			724.0			29.4			4.1	%

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UGI UTILITIES, INC. AND SUBSIDIARIES

(a) Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $4.0 million during each of the nine-month periods ended June 30, 2013 and 2012. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.

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

Gas Utility. Temperatures in the Gas Utility service territory in the 2013 nine-month period based upon heating degree days were 1.2% warmer than normal but 14.9% colder than the prior-year period. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $46.8 million during the 2013 nine-month period principally reflecting higher revenues from core market customers ($44.2 million) and higher large firm delivery service revenues ($7.7 million) partially offset by lower off-system sales revenues ($6.1 million). The increase in core market revenues principally reflects the effects of the higher core market volumes on PGC revenues ($52.0 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($46.7 million). Gas Utility’s cost of gas was $372.7 million in the 2013 nine-month period compared with $370.6 million in the prior-year period principally reflecting the effects on cost of sales of the greater retail core-market volumes ($52.0 million) substantially offset by the effects of lower average PGC rates ($46.7 million) and the lower off-system sales.

Gas Utility total margin increased $44.7 million in the 2013 nine-month period principally reflecting higher core market margin ($34.5 million) and higher large firm delivery service total margin ($8.1 million). The higher core market total margin reflects the effects of the greater core market volumes.

The increase in Gas Utility operating income during the 2013 nine-month period principally reflects the increase in total margin ($44.7 million) partially offset by higher operating and administrative expenses ($17.0 million) including, among other things, higher pension and benefits expenses ($3.0 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.0 million). The greater income before income taxes in the 2013 nine-month period reflects the higher operating income ($22.9 million) and slightly lower interest expense on lower long-term debt outstanding.

Electric Utility. Temperatures based upon heating degree days during the 2013 nine-month period were approximately 2.5% warmer than normal but approximately 17% colder than the prior-year period. The increase in revenues reflects the effects of the higher sales principally a result of the colder weather partially offset by lower average DS rates reflecting the pass through of lower electricity costs. Electric Utility cost of sales increased to $42.7 million in the 2013 nine-month period compared to $41.8 million in the 2012 nine-month period principally reflecting the effects of the greater sales offset by the lower average DS rates.

Electric Utility total margin increased $0.8 million in the 2013 nine-month period reflecting in large part the higher distribution sales and greater transmission revenue.

Notwithstanding the increase in total margin, Electric Utility 2013 nine-month period operating income and income before income taxes decreased reflecting greater operating and administrative costs including distribution system repair and maintenance costs principally associated with Hurricane Sandy early in the 2013 nine-month period.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2013 nine-month period was lower than the prior-year period on lower long-term debt outstanding. Our effective income tax rate for the nine months ended June 30, 2013, was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2013, was $600 million compared to debt outstanding of $609.2 million at September 30, 2012, which amount includes $9.2 million of bank loans. UGI Utilities’ total debt outstanding at June 30, 2013, comprises $383 million of Senior Notes and $217 million of Medium-Term Notes.

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UGI UTILITIES, INC. AND SUBSIDIARIES

UGI Utilities may borrow up to a total of $300 million under its credit agreement (“2011 Credit Agreement”). The 2011 Credit Agreement expires in October 2015. There were no amounts outstanding under the 2011 Credit Agreement at June 30, 2013. During the 2013 and 2012nine-month periods, average daily bank loan borrowings were $27.3 million and $21.3 million, respectively, and peak bank loan borrowings totaled $79 million and $70.6 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

We believe that we have sufficient liquidity in the forms of cash and cash equivalents on hand, cash expected to be generated from Gas Utility and Electric Utility operations, and bank loan borrowings available under the 2011 Credit Agreement to meet our anticipated contractual and projected cash commitments. In addition, UGI Utilities has an aggregate $133 million of Senior Notes and Medium-Term Notes maturing late in Fiscal 2013 which UGI Utilities intends to refinance on a long-term basis.

Cash Flows

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

Cash provided by operating activities was $188.6 million in the 2013 nine-month period compared to $202.6 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital was $178.1 million in the 2013 nine-month period compared to $142.5 million recorded in the prior-year nine-month period principally reflecting the greater 2013 nine-month period operating results and lower pension plan contributions. Changes in operating working capital provided $10.6 million of operating cash flow during the 2013 nine-month period compared to $60.1 million of cash provided during the prior-year nine-month period. The lower cash from changes in operating working capital in the 2013 nine-month period reflects, among other things, greater cash required to fund changes in accounts receivable principally resulting from the greater sales in the current-year period and lower cash from changes in inventories. The effect of these changes in working capital were partially offset, among other things, by the timing and amount of cash provided by changes in deferred fuel collections and current income taxes.

Investing activities. Cash used by investing activities was $99.7 million in the 2013 nine-month period compared to $79.4 million in the 2012 nine-month period. Total capital expenditures were $94.5 million in the 2013 nine-month period compared with $79.7 million recorded in the prior-year period. The 2013 nine-month period principally reflects higher Gas Utility capital expenditures. Changes in restricted cash in futures brokerage accounts required $2.6 million of cash compared with $2.7 million of cash provided in the prior-year period.

Financing activities. Cash used by financing activities was $8.2 million in the 2013 nine-month period compared with cash used by financing activities of $54.5 million in the 2012 nine-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our revolving credit agreements, cash dividends paid to UGI and capital contributions from UGI. During the 2013 nine-month period there were net bank loan repayments of $9.2 million compared with no net borrowings or repayments during the prior-year nine-month period. Cash dividends in the prior-year nine-month period totaled $54.8 million. There have been no cash dividends paid during the nine months ended June 30, 2013.

Regulatory Matters

On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 million to $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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UGI UTILITIES, INC. AND SUBSIDIARIES

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At June 30, 2013, UGI Utilities had $2.6 million of restricted cash associated with futures accounts. At June 30, 2012, UGI Utilities had $1.6 million of restricted cash associated with natural gas futures accounts with brokers. At June 30, 2013 and 2012, the fair values of our natural gas futures and option contracts were net (losses) gains of $(1.4) million and $0.3 million, respectively.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. At June 30, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6.1 million and $13.1 million, respectively. At June 30, 2013 and 2012, the fair values of FTRs were not material.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair values of unsettled IRPAs held at June 30, 2013 and 2012, were net losses of $7.2 million and $28.9 million, respectively. A hypothetical 10% adverse change in the six-month LIBOR would result in a decrease in fair value of $9.2 million at June 30, 2013.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at June 30, 2013 and 2012, were not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Change in Internal Control over Financial Reporting

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.2	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	UGI	Form 10-Q (6/30/2013)	10.1
10.3	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.4	FTS Service Agreement No. 46284 dated July 23, 2013 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	UGI Utilities, Inc.	Form 8-K (7/23/2013)	10.1
12.1	Computation of ratio of earnings to fixed charges
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL.Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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UGI UTILITIES, INC. AND SUBSIDIARIES

SIGNATURES

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

		UGI Utilities, Inc. (Registrant)
Date:	August 2, 2013	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President - Finance and Chief Financial Officer
Date:	August 2, 2013	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.3	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
12.1	Computation of ratio of earnings to fixed charges.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL.Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase