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EX-32 - EXHIBIT 32 - UGI UTILITIES INCex3212-31x2011ugiutilities.htm
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCex31212-31x2011ugiutilitie.htm
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INCex12112-31x11ugiutilities1.htm
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INCex31112-31x11ugiutilities1.htm
EXCEL - IDEA: XBRL DOCUMENT - UGI UTILITIES INCFinancial_Report.xls

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, 2011
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                      to                     
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
Pennsylvania
 
23-1174060
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer þ
 
Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
At January 31, 2012, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT



- i -




UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
 
December 31,
2011
 
September 30,
2011
 
December 31,
2010
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
4,228

 
$
7,267

 
$
11,646

Restricted cash
3,066

 
4,308

 
3,884

Accounts receivable (less allowances for doubtful accounts of $5,824, $6,368 and $8,492, respectively)
102,332

 
58,736

 
124,417

Accounts receivable — related parties
8,534

 
7,048

 
12,347

Accrued utility revenues
53,811

 
14,807

 
75,284

Inventories
97,451

 
104,263

 
108,027

Deferred income taxes
37,779

 
42,528

 
21,593

Regulatory assets
8,126

 
8,608

 
10,633

Derivative financial instruments
18

 
68

 
2,750

Prepaid expenses & other current assets
15,720

 
24,911

 
5,648

Total current assets
331,065

 
272,544

 
376,229

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $793,418, $782,665 and $759,125, respectively)
1,427,332

 
1,418,356

 
1,386,808

Goodwill
182,145

 
182,145

 
180,145

Regulatory assets
293,365

 
291,847

 
248,455

Other assets
4,551

 
4,456

 
10,746

Total assets
$
2,238,458

 
$
2,169,348

 
$
2,202,383

 
 
 
 
 
 
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Current maturities of long-term debt
$
40,000

 
$
40,000

 
$

Bank loans
57,700

 

 
74,000

Accounts payable
44,450

 
53,556

 
68,328

Accounts payable — related parties
7,024

 
10,108

 
8,494

Deferred fuel refunds
5,019

 
6,578

 
15,175

Derivative financial instruments
14,697

 
11,928

 
5,890

Other current liabilities
163,711

 
140,849

 
148,909

Total current liabilities
332,601

 
263,019

 
320,796

 
 
 
 
 
 
Long-term debt
600,000

 
600,000

 
640,000

Deferred income taxes
355,446

 
361,468

 
286,347

Deferred investment tax credits
4,871

 
4,958

 
5,222

Pension and postretirement benefit obligations
135,119

 
142,248

 
117,127

Other noncurrent liabilities
83,505

 
78,810

 
74,785

Total liabilities
1,511,542

 
1,450,503

 
1,444,277

 
 
 
 
 
 
Commitments and contingencies (note 8)

 

 

 
 
 
 
 
 
Common stockholder’s equity:
 
 
 
 
 
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)
60,259

 
60,259

 
60,259

Additional paid-in capital
468,417

 
468,323

 
467,903

Retained earnings
221,565

 
212,096

 
234,758

Accumulated other comprehensive loss
(23,325
)
 
(21,833
)
 
(4,814
)
Total common stockholder’s equity
726,916

 
718,845

 
758,106

Total liabilities and stockholder’s equity
$
2,238,458

 
$
2,169,348

 
$
2,202,383

See accompanying notes to condensed consolidated financial statements.

- 1 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)

 
Three Months Ended
 
December 31,
 
2011
 
2010
Revenues
$
280,641

 
$
350,516

Costs and expenses:
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
156,906

 
213,484

Operating and administrative expenses
40,942

 
39,894

Operating and administrative expenses — related parties
2,125

 
2,925

Taxes other than income taxes
4,127

 
4,358

Depreciation
12,379

 
12,606

Amortization
684

 
632

Other income, net
(1,127
)
 
(2,263
)
 
216,036

 
271,636

Operating income
64,605

 
78,880

Interest expense
10,607

 
10,633

Income before income taxes
53,998

 
68,247

Income taxes
21,330

 
27,173

Net income
$
32,668

 
$
41,074

See accompanying notes to condensed consolidated financial statements.











- 2 -



UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Thousands of dollars)

 
Three Months Ended December 31,
 
2011
 
2010
Net income
$
32,668

 
$
41,074

Net (loss) gain in fair value of derivative instruments (net of tax $1,267 and $(3,007), respectively)
(1,801
)
 
4,241

Reclassifications of net losses on derivative instruments (net of tax of $(121))
170

 
170

Benefit plans (net of tax of $(99) and $(1,539), respectively)
139

 
2,171

Comprehensive income
$
31,176

 
$
47,656

See accompanying notes to condensed consolidated financial statements.


- 3 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)

 
Three Months Ended
 
December 31,
 
2011
 
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
32,668

 
$
41,074

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
13,063

 
13,238

Deferred income taxes, net
(587
)
 
(2,260
)
Provision for uncollectible accounts
2,223

 
3,161

Other, net
2,505

 
2,560

Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(86,309
)
 
(130,063
)
Inventories
6,812

 
10,832

Deferred fuel and power costs
1,552

 
15,459

Accounts payable
(12,190
)
 
29,886

Other current assets
9,186

 
3,546

Other current liabilities
15,666

 
4,341

Net cash used by operating activities
(15,411
)
 
(8,226
)
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(22,858
)
 
(17,587
)
Net costs of property, plant and equipment disposals
(607
)
 
(668
)
Decrease in restricted cash
1,242

 
814

Net cash used by investing activities
(22,223
)
 
(17,441
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(23,199
)
 
(24,277
)
Increase in bank loans
57,700

 
57,000

Other
94

 
272

Net cash provided by financing activities
34,595

 
32,995

Cash and cash equivalents (decrease) increase
$
(3,039
)
 
$
7,328

CASH AND CASH EQUIVALENTS:
 
 
 
End of period
$
4,228

 
$
11,646

Beginning of period
7,267

 
4,318

(Decrease) increase
$
(3,039
)
 
$
7,328

See accompanying notes to condensed consolidated financial statements.


- 4 -


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;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, 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 Gas 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 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, 2011 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, 2011 (“Company’s 2011 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, for all periods presented, includes actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
UGI Utilities enters into financial transactions to hedge its cost of gas sold to customers. These transactions were conducted pursuant to an approved risk management plan through an account held at MF Global Inc. ("MF Global"). On October 31, 2011, MF Global filed for Chapter 11 bankruptcy and, in conjunction with the automatic stay, the Chicago Mercantile Exchange froze all MF Global-related accounts. As a result of an emergency order entered by the bankruptcy court, the Company's customer segregated margin account and a portion of its cash was transferred to a new broker. The amount of cash currently frozen at MF Global is not material. At this time, the Company is unable to predict the ultimate impact of the bankruptcy.
Reclassifications. Removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the December 31, 2010 Condensed Consolidated Balance Sheet to conform to the current-period presentation.

- 5 -

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


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

Adoption of New Accounting Standard

Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more-likely-than-not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.

New Accounting Standard Not Yet Adopted

Fair Value Measurements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders' equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have any impact on our results of operations or financial condition.

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 2011 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.

- 6 -

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, 2011:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas
Utility
 
Electric
Utility
 
Other
Revenues
$
280,641

 
$
255,030

 
$
25,169

 
$
442

Cost of sales
$
156,906

 
$
141,679

 
$
15,227

 
$

Depreciation and amortization
$
13,063

 
$
12,145

 
$
918

 
$

Operating income
$
64,605

 
$
61,231

 
$
3,230

 
$
144

Interest expense
$
10,607

 
$
10,098

 
$
509

 
$

Income before income taxes
$
53,998

 
$
51,133

 
$
2,721

 
$
144

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,238,458

 
$
2,088,710

 
$
149,748

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$

Capital expenditures
$
22,858

 
$
21,812

 
$
1,046

 
$


Three Months Ended December 31, 2010:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas
Utility
 
Electric
Utility
 
Other
Revenues
$
350,516

 
$
321,114

 
$
28,940

 
$
462

Cost of sales
$
213,484

 
$
194,913

 
$
18,571

 
$

Depreciation and amortization
$
13,238

 
$
12,225

 
$
1,013

 
$

Operating income
$
78,880

 
$
75,067

 
$
3,603

 
$
210

Interest expense
$
10,633

 
$
10,108

 
$
525

 
$

Income before income taxes
$
68,247

 
$
64,959

 
$
3,078

 
$
210

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,202,383

 
$
2,061,337

 
$
141,046

 
$

Goodwill (at period end)
$
180,145

 
$
180,145

 
$

 
$

Capital expenditures
$
17,587

 
$
16,086

 
$
1,501

 
$


5.
Inventories
Inventories comprise the following:
 
December 31, 2011
 
September 30, 2011
 
December 31, 2010
Gas Utility natural gas
$
87,735

 
$
95,590

 
$
100,121

Materials, supplies and other
9,716

 
8,673

 
7,905

Total inventories
$
97,451

 
$
104,263

 
$
108,026


At December 31, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013 (see Note 9). Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage

- 7 -

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


inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.
The carrying value of gas storage inventories released under the SCAAs at December 31, 2011, September 30, 2011 and December 31, 2010 comprising 10.8 billion cubic feet (“bcf”), 11.5 bcf and 11.1 bcf of natural gas, was $50,912, $54,658 and $58,363, respectively. In conjunction with the SCAAs, at December 31, 2011, September 30, 2011 and December 31, 2010, UGI Utilities held a total of $22,500 of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

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 2011 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
December 31, 2011
 
September 30, 2011
 
December 31, 2010
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
98,741

 
$
97,947

 
$
83,601

Underfunded pension and postretirement plans
148,650

 
150,669

 
116,288

Environmental costs
19,372

 
19,547

 
22,515

Deferred fuel and power costs
14,798

 
12,163

 
18,113

Removal costs, net
11,946

 
12,313

 
12,234

Other
7,984

 
7,816

 
6,337

Total regulatory assets
$
301,491

 
$
300,455

 
$
259,088

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
11,764

 
$
11,476

 
$
10,835

Environmental overcollections
4,740

 
4,758

 
6,990

Deferred fuel and power refunds
5,019

 
6,578

 
15,175

State tax benefits — distribution system repairs
6,509

 
6,282

 
6,716

Other
377

 
736

 

Total regulatory liabilities
$
28,409

 
$
29,830

 
$
39,716

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and Electric Utility’s default service ("DS") 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 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 (losses) gains on such contracts at December 31, 2011, September 30, 2011 and December 31, 2010 were $(2,589), $(3,081) and $2,214, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result,

- 8 -

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


such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility's DS recovery mechanism. At December 31, 2011, September 30, 2011 and December 31, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $13,529, $8,655 and $13,369, 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 on FTRs at December 31, 2011, September 30, 2011 and December 31, 2010 were not material.

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 a limited number of active employees, 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,
 
2011
 
2010
 
2011
 
2010
Service cost
$
1,756

 
$
1,925

 
$
43

 
$
54

Interest cost
5,594

 
5,355

 
166

 
182

Expected return on assets
(5,940
)
 
(6,022
)
 
(127
)
 
(130
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
62

 
62

 
(106
)
 
(174
)
Actuarial loss
1,963

 
2,128

 
99

 
121

Net benefit cost
3,435

 
3,448

 
75

 
53

Change in associated regulatory liabilities

 

 
784

 
785

Net expense
$
3,435

 
$
3,448

 
$
859

 
$
838


Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $32,000 to the Pension Plan during the next twelve months. During the three months ended December 31, 2011 and 2010, the Company made contributions to the Pension Plan of $4,106 and $1,789, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2011 and 2010, nor are they expected to be material for all of Fiscal 2012.
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.

- 9 -

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 December 31, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17,751 and $21,323, respectively. 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 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.
The Company does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At December 31, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. 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.
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 trial court’s decision is pending.
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company,

- 10 -

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


now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court's decision to the United States Court of Appeals for the First Circuit.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10,000. KeySpan has indicated that the cost could be as high as $20,000. There have been no recent developments in this case.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s judgment in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The District Court's decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000.
Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) 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 and MUD has 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. On January 17, 2012, UGI Utilities responded to the EPA's information request and is cooperating with its investigation.
Other Matters
Allentown, Pennsylvania Natural Gas Explosion. On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and UGI Utilities is cooperating with that investigation. Based on a visual inspection, UGI Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory.
UGI Utilities has received more than one hundred property claims and a handful of personal injury and wrongful death claims as a result of the explosion. Many of the claims, including two wrongful death claims and approximately eighty

- 11 -

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


percent of the property claims received to date, have been settled. UGI Utilities maintains liability insurance for personal injury, wrongful death, property and casualty damages and believes that third-party claims associated with the explosion, in excess of a $500 deductible, will be recovered through UGI Utilities’ insurance. We continue to believe that claims and expenses associated with the explosion will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.
We cannot predict with certainty the final results of any of the environmental claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a 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.
From time to time, UGI Utilities is a party to SCAAs with UGI Energy Services, Inc. ("Energy Services"), a second-tier wholly owned subsidiary of UGI. At December 31, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $4,921 and $2,293 during the three months ended December 31, 2011 and 2010, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, were $15,000 as of December 31, 2011, September 30, 2011 and December 31, 2010.
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at December 31, 2011, comprising approximately 7.6 bcf of natural gas, was $35,230. The carrying value of these gas storage inventories at September 30, 2011, comprising approximately 7.5 bcf of natural gas, was $35,686. The carrying value of these gas storage inventories at December 31, 2010, comprising approximately 7.5 bcf of natural gas, was $39,447.
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

- 12 -

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


through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2011 and 2010 totaled $22,365 and $18,755, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2011 and 2010, revenues associated with such sales to Energy Services totaled $17,081 and $22,034, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above) and beginning April 1, 2011, purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under a one-year agreement. During the three months ended December 31, 2011 and 2010, such purchases totaled $10,051 and $13,497, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

10.
Fair Value Measurements
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2011, September 30, 2011 and December 31, 2010:


- 13 -

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


 
Asset (Liability)
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Total
December 31, 2011:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$

 
$
18

 
$

 
$
18

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(4,053
)
 
$
(12,067
)
 
$

 
$
(16,120
)
Interest rate contracts
$

 
$
(21,662
)
 
$

 
$
(21,662
)
September 30, 2011:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
27

 
$
41

 
$

 
$
68

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(4,102
)
 
$
(7,634
)
 
$

 
$
(11,736
)
Interest rate contracts

 
(18,585
)
 

 
$
(18,585
)
December 31, 2010:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
2,398

 
$
352

 
$

 
$
2,750

Interest rate contracts

 
7,249

 

 
$
7,249

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(1,438
)
 
$
(11,932
)
 
$

 
$
(13,370
)

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at December 31, 2011 were $640,000 and $747,461 respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2010 were $640,000 and $720,011, 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.

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

- 14 -

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


and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.
Commodity Price Risk
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2011 and 2010, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 9.1 million dekatherms and 25.2 million dekatherms, respectively. At December 31, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB's guidance in Accounting Standards Codification ("ASC") 980 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. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception. Because these contracts no longer qualify for the normal purchases and normal sales exception, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At December 31, 2011 and 2010, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13,529 and $13,370, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2011 and 2010, the volumes of Electric Utility's forward electricity purchase contracts was 816.0 million kilowatt hours and 984.3 million kilowatt hours, respectively. At December 31, 2011, the maximum period over which these contracts extend is 29 months.
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. 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 ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 6). At December 31, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 130.0 million  kilowatt hours and 342.0 million kilowatt hours, respectively. At December 31, 2011, the maximum period over which we are hedging electricity congestion with FTRs is 5 months.
In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. The volumes of gasoline under these contracts and the fair values of these contracts were not material for all periods presented.


- 15 -

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


Interest Rate Risk
Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near - to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of December 31, 2011 and 2010, the total notional amounts of our unsettled IRPA contracts was $173,000 and $106,500, respectively. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013.
Derivative Financial Instrument Credit Risk
Our natural gas exchange-traded futures and options contracts generally require cash deposits in margin accounts. At December 31, 2011 and 2010, restricted cash in brokerage accounts totaled $3,066 and $3,884, respectively.
The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of December 31, 2011 and 2010:
As of December 31,:
 
Derivative Assets
 
Derivative (Liabilities)
 
Balance Sheet
 
Fair Value
 
Balance Sheet
 
Fair Value
 
Location
 
2011
 
2010
 
Location
 
2011
 
2010
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
Other assets
 
$

 
$
7,249

 
Derivative financial instruments and Other noncurrent liabilities
 
$
(21,662
)
 
$

Derivatives Accounted for Under ASC 980:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 
18

 
2,566

 
Derivative financial instruments and Other noncurrent liabilities
 
(16,118
)
 
(13,370
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 

 
184

 
Derivative financial instruments
 
(2
)
 

Total Derivatives
 
 
$
18

 
$
9,999

 
 
 
$
(37,782
)
 
$
(13,370
)


- 16 -

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 Consolidated Statement of Income and changes in AOCI for three months ended December 31, 2011 and 2010:
 
Gain or (Loss) Recognized in AOCI
 
Gain (Loss) Reclassified from AOCI into Income
 
Location of Gain or (Loss) Reclassified from AOCI into Income
 
2011

2010
 
2011
 
2010
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
$
(3,077
)
 
$
7,249

 
$
(291
)
 
$
(291
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives Not Designated
 
 
 
 
 
 
 
 
 
 
 
   as Hedging Instruments:
Gain (Loss) Recognized in Income
 
 
 
 
 
 
 
 
 
2011
 
2010
 
 
 
 
 
 
 
 
Commodity contracts
$
(51
)
 
$
161

 
 
 
 
 
Operating expenses

At December 31, 2011, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $1,275. In addition, during the three months ended December 31, 2011 and 2010, the impact of changes in fair value of gasoline futures and swap contracts on our net income was not material.
We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders and contracts which provide for the purchase and delivery of natural gas 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 because they provide for the delivery of products 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.


- 17 -


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 which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.
These factors, and those factors set forth in Item 1A. Risk Factors of this Quarterly Report on Form 10-Q and Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, 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.


- 18 -

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, 2011 (“2011 three-month period”) with the three months ended December 31, 2010 (“2010 three-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 3 to the condensed consolidated financial statements.
2011 three-month period compared with 2010 three-month period
 
 
 
 
 
 
Increase
Three Months Ended December 31,
 
2011
 
2010
 
(Decrease)
(Millions of dollars)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
255.0

 
$
321.1

 
$
(66.1
)
 
(20.6
)%
Total margin (a)
 
$
113.3

 
$
126.2

 
$
(12.9
)
 
(10.2
)%
Operating income
 
$
61.2

 
$
75.1

 
$
(13.9
)
 
(18.5
)%
Income before income taxes
 
$
51.1

 
$
65.0

 
$
(13.9
)
 
(21.4
)%
System throughput — bcf
 
49.0

 
48.9

 
0.1

 
0.2
 %
Heating degree days — % (warmer) colder than normal (b)
 
(12.2
)%
 
7.9
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
25.2

 
$
28.9

 
$
(3.7
)
 
(12.8
)%
Total margin (a)
 
$
8.5

 
$
8.8

 
$
(0.3
)
 
(3.4
)%
Operating income
 
$
3.2

 
$
3.6

 
$
(0.4
)
 
(11.1
)%
Income before income taxes
 
$
2.7

 
$
3.1

 
$
(0.4
)
 
(12.9
)%
Distribution sales — gwh
 
244.0

 
250.5

 
(6.5
)
 
(2.6
)%

bcf — billions of cubic feet. gwh — millions of kilowatt-hours.
(a)
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.4 million and $1.6 million during the three-month periods ended December 31, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.
(b)
Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.
Gas Utility. Temperatures in the Gas Utility service territory in the 2011 three-month period based upon heating degree days were 12.2% warmer than normal and 18.6% warmer than the prior-year period. Total distribution system throughput was about equal to last year notwithstanding the warmer weather principally reflecting greater throughput to certain non-weather-sensitive low-margin interruptible delivery service customers. Excluding total volumes to interruptible delivery service customers, Gas Utility system throughput declined 5.3 bcf in the 2011 three-month period principally reflecting the effects of the significantly warmer weather on throughput to core market customers. Gas Utility's core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues decreased $66.1 million during the 2011 three-month period principally reflecting a decline in revenues from retail core market customers ($52.3 million) and a decline in revenues from off-system sales ($9.9 million). The decrease in retail core market revenues principally reflects the effects of the lower retail core market volumes ($31.5 million) and lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices. Under Gas Utility's PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility's cost of gas was $141.7 million in the 2011 three-month period compared with $194.9 million in the prior-year period reflecting the previously mentioned lower retail core-market sales and the lower average PGC rates.

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UGI UTILITIES, INC. AND SUBSIDIARIES


Gas Utility total margin decreased $12.9 million in the 2011 three-month period. The decrease principally reflects a $9.7 million decrease in core market margin and lower firm delivery service total margin ($2.3 million). Gas Utility total margin in the current year period includes incremental margin from the August 2011 base rate increase at CPG Gas.

The decreases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflects the previously mentioned decrease in total margin ($12.9 million).
Electric Utility. Electric Utility's kilowatt-hour sales in the 2011 three-month period were 2.6% lower than in the prior-year three-month period on heating degree day weather that was 18.4% warmer. The significantly warmer weather reduced sales to those Electric Utility customers who use electricity for heating purposes. Electric Utility revenues were less than the prior year principally as a result of lower average Default Service (“DS”) rates and to a lesser extent the lower sales volumes. Under Electric Utility's DS rates, Electric Utility records the cost of electricity sold to customers at amounts included in DS rates. The difference between actual costs and the amounts included in DS 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 recovery mechanism, increases or decreases in the cost of electricity have no direct effect on margin. Electric Utility cost of sales declined to $15.2 million in the 2011 three-month period compared to $18.6 million in the 2010 three-month period principally reflecting the effects of the lower average DS rates in the current-year period and the effects of the lower sales.
Electric Utility total margin was $0.3 million lower in the 2011 three-month period principally the result of the lower sales. Electric Utility 2011 three-month period operating income and income before income taxes each declined $0.4 million principally reflecting the lower total margin.
Interest Expense and Income Taxes. Our consolidated interest expense and annual effective income tax rate in the 2011 three-month period were about equal to such amounts for the prior-year period.

FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Company’s total debt outstanding at December 31, 2011 was $697.7 million compared to total debt outstanding at September 30, 2011 of $640 million. UGI Utilities' total debt outstanding at December 31, 2011 comprises $383 million of Senior Notes, $257 million of Medium-Term Notes and $57.7 million of bank loan borrowings.

UGI Utilities may borrow up to a total of $300 million under its Revolving Credit Agreement. The Revolving Credit Agreement expires in May 2012 but may be extended to October 2015 if UGI Utilities receives approval by the PUC. UGI Utilities expects to receive such approval prior to the May 2012 termination date. At December 31, 2011, there was $57.7 million outstanding under its Revolving Credit Agreement which are classified as bank loans. During the 2011 and 2010 three-month periods, average daily bank loan borrowings were $29.7 million and $49.3 million, respectively, and peak bank loan borrowings totaled $70.5 million and $90 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the Revolving Credit Agreement, UGI Utilities' management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2012.
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 used by operating activities was $15.4 million in the 2011 three-month period compared to cash used by operating activities of $8.2 million in the prior-year three-month period. Cash flow from operating activities before changes in operating working capital was $49.9 million in the 2011 three-month period compared to $57.8 million recorded in the prior-year three-month period principally reflecting the lower 2011 three-month period operating results. Changes in operating working capital used $65.3 million of operating cash flow during the 2011 three-month period compared to $66.0 million used during the prior-year three-month period. Cash used to fund changes in operating working capital in the 2011 three-month period reflects, among other things, lower

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UGI UTILITIES, INC. AND SUBSIDIARIES


cash from deferred fuel recoveries and greater cash used to fund changes in accounts payable partially offset by lower cash required to fund changes in accounts receivable during the 2011 three-month period principally resulting from the lower sales and lower natural gas costs.
Investing activities. Cash used by investing activities was $22.2 million in the 2011 three-month period compared to $17.4 million in the 2010 three-month period. Total capital expenditures were $22.9 million in the 2011 three-month period compared with $17.6 million recorded in the prior-year period. The 2011 three-month period principally reflects higher UGI Gas capital expenditures.
Financing activities. Cash provided by financing activities was $34.6 million in the 2011 three-month period compared with cash provided by financing activities of $33.0 million in the 2010 three-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our Revolving Credit Agreement, cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI totaling $23.2 million and $24.3 million during the 2011 and 2010 three-month periods, respectively. During the 2011 three-month period, net bank loan borrowings totaled $57.7 million compared with net bank loan borrowings of $57.0 million in the prior-year three-month period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At December 31, 2011 and 2010, Gas Utility had $3.1 million and $3.9 million, respectively, of restricted cash associated with natural gas futures and option accounts with brokers. At December 31, 2011 and 2010, the fair values of our natural gas futures and option contracts were (losses) gains of $(2.6) million and $2.2 million, respectively.
Electric Utility’s DS tariffs contain clauses that 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. FTRs are financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At December 31, 2011 and 2010, 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 December 31, 2011 and 2010 were a (loss) gain of $(21.7) million and $7.2 million, respectively. A hypothetical 10% adverse change in the three-month LIBOR would result in a decrease in fair value of $4.1 million at December 31, 2011.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at December 31, 2011 and 2010 were not material.
Our unsettled derivative instruments at December 31, 2011 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward purchase contracts, which are included in Electric Utility’s DS recovery mechanism; (3) IRPAs; and (4) exchange-traded gasoline futures and swap contracts.


- 21 -

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.

- 22 -

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, 2011, 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:

Incorporation by Reference
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
12.1
Computation of ratio of earnings to fixed charges
 
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant's Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2
Certification by the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant's Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS*
XBRL.Instance
 
 
 
101.SCH*
XBRL Taxonomy Extension Schema
 
 
 
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase
 
 
 
101.DEF*
XBRL Taxonomy Extension Definition Linkbase
 
 
 
101.LAB*
XBRL Taxonomy Extension Labels Linkbase
 
 
 
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase
 
 
 

*XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.



- 23 -

UGI UTILITIES, INC. AND SUBSIDIARIES


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
UGI Utilities, Inc.
(Registrant)
 
Date:
February 3, 2012
By:  
/s/ Donald E. Brown  
 
 
 
Donald E. Brown
Vice President — Finance and
Chief Financial Officer   (Principal Financial Officer)
 
 
 
Date:
February 3, 2012
By:  
/s/ Matthew J. Nolan  
 
 
 
Matthew J. Nolan 
Controller  (Principal Accounting Officer)


- 24 -

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, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*
XBRL.Instance
101.SCH*
XBRL Taxonomy Extension Schema
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase
101.DEF*
XBRL Taxonomy Extension Definition Linkbase
101.LAB*
XBRL Taxonomy Extension Labels Linkbase
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase

*XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.

- 25 -