UGI UTILITIES INC - FORM 10-Q - August 7, 2014

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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, 2014
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, 2014, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



- i -



UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
 
June 30,
2014
 
September 30,
2013
 
June 30,
2013
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
28,480

 
$
4,707

 
$
82,027

Restricted cash
1,109

 
3,181

 
2,636

Accounts receivable (less allowances for doubtful accounts of $13,517, $5,519 and $9,166, respectively)
97,144

 
53,341

 
78,677

Accounts receivable — related parties
3,484

 
3,497

 
4,086

Accrued utility revenues
7,950

 
18,868

 
11,836

Inventories
58,750

 
89,661

 
53,998

Deferred income taxes
11,908

 
14,165

 
17,910

Regulatory assets
9,354

 
8,217

 
3,747

Derivative financial instruments
1,703

 
43

 
8,228

Prepaid expenses & other current assets
11,057

 
15,862

 
9,766

Total current assets
230,939

 
211,542

 
272,911

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $888,279, $853,675 and $846,941, respectively)
1,635,867

 
1,574,135

 
1,531,440

Goodwill
182,145

 
182,145

 
182,145

Regulatory assets
233,272

 
236,694

 
317,216

Other assets
7,618

 
5,806

 
3,635

Total assets
$
2,289,841

 
$
2,210,322

 
$
2,307,347

 
 
 
 
 
 
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Current maturities of long-term debt
$
20,000

 
$
—

 
$
133,000

Bank loans
—

 
17,500

 
—

Accounts payable
47,396

 
51,970

 
35,587

Accounts payable — related parties
21,131

 
12,487

 
17,176

Deferred fuel refunds
—

 
8,283

 
14,156

Derivative financial instruments
31

 
6,677

 
22,911

Other current liabilities
140,404

 
110,596

 
123,438

Total current liabilities
228,962

 
207,513

 
346,268

 
 
 
 
 
 
Long-term debt
622,000

 
642,000

 
467,000

Deferred income taxes
454,871

 
436,810

 
422,994

Deferred investment tax credits
4,017

 
4,270

 
4,355

Pension and postretirement benefit obligations
61,991

 
72,505

 
172,721

Other noncurrent liabilities
53,439

 
55,610

 
51,999

Total liabilities
1,425,280

 
1,418,708

 
1,465,337

 
 
 
 
 
 
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
470,844

 
470,098

 
469,736

Retained earnings
340,714

 
269,977

 
327,298

Accumulated other comprehensive loss
(7,256
)
 
(8,720
)
 
(15,283
)
Total common stockholder’s equity
864,561

 
791,614

 
842,010

Total liabilities and stockholder’s equity
$
2,289,841

 
$
2,210,322

 
$
2,307,347

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
 
Nine Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Revenues
$
152,694

 
$
148,798

 
$
965,549

 
$
818,496

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
63,323

 
64,332

 
515,612

 
415,394

Operating and administrative expenses
49,862

 
46,420

 
145,313

 
143,076

Operating and administrative expenses — related parties
2,385

 
1,940

 
7,997

 
6,757

Taxes other than income taxes
3,768

 
3,756

 
12,748

 
12,716

Depreciation
14,048

 
13,201

 
41,485

 
38,849

Amortization
844

 
832

 
2,500

 
2,467

Other (income), net
(1,256
)
 
(561
)
 
(3,623
)
 
(1,435
)
 
132,974

 
129,920

 
722,032

 
617,824

Operating income
19,720

 
18,878

 
243,517

 
200,672

Interest expense
10,433

 
9,690

 
28,036

 
29,587

Income before income taxes
9,287

 
9,188

 
215,481

 
171,085

Income taxes
2,397

 
3,815

 
87,195

 
70,641

Net income
$
6,890

 
$
5,373

 
$
128,286

 
$
100,444

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 June 30,
 
Nine Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
Net income
$
6,890

 
$
5,373

 
$
128,286

 
$
100,444

Other comprehensive income:
 
 
 
 
 
 
 
Net gains in fair value of derivative instruments (net of tax of $0, $(5,301), $0 and $(9,638), respectively)
—

 
7,475

 
—

 
13,590

Reclassifications of net losses on derivative instruments (net of tax of $(278), $(84), $(834) and $(252), respectively)
393

 
119

 
1,176

 
356

Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(67), $(140), $(206) and $(418), respectively)
95

 
195

 
288

 
588

Other comprehensive income
488

 
7,789

 
1,464

 
14,534

Comprehensive income
$
7,378

 
$
13,162

 
$
129,750

 
$
114,978

See accompanying notes to condensed consolidated financial statements.


- 3 -

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

 
Nine Months Ended
 
June 30,
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
128,286

 
$
100,444

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
43,985

 
41,316

Deferred income taxes, net
18,747

 
23,369

Provision for uncollectible accounts
11,657

 
8,297

Other, net
(2,809
)
 
4,647

Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(44,530
)
 
(34,052
)
Inventories
30,911

 
13,336

Deferred fuel and power costs, net of changes in unsettled derivatives
(17,611
)
 
20,549

Accounts payable
4,070

 
(4,183
)
Other current assets
4,690

 
19,675

Other current liabilities
27,947

 
(4,753
)
Net cash provided by operating activities
205,343

 
188,645

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(104,117
)
 
(94,480
)
Net costs of property, plant and equipment disposals
(5,222
)
 
(2,604
)
Decrease (increase) in restricted cash
2,072

 
(2,636
)
Net cash used by investing activities
(107,267
)
 
(99,720
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(57,549
)
 
—

Issuances of long-term debt
175,000

 
—

Repayments of long-term debt
(175,000
)
 
—

Decrease in bank loans
(17,500
)
 
(9,200
)
Other
746

 
1,043

Net cash used by financing activities
(74,303
)
 
(8,157
)
Cash and cash equivalents increase
$
23,773

 
$
80,768

CASH AND CASH EQUIVALENTS:
 
 
 
End of period
$
28,480

 
$
82,027

Beginning of period
4,707

 
1,259

Increase
$
23,773

 
$
80,768

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.” 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 its small Maryland service territory, 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, 2013, 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 fiscal year ended September 30, 2013 (“Company’s 2013 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.
Comprehensive Income. Comprehensive income comprises net income and other comprehensive income. Other comprehensive income principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.










- 5 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


Changes in accumulated other comprehensive loss during the three and nine months ended June 30, 2014 are as follows:

 
 
 
 
 
 
 
 
 
Postretirement
 
Derivative
 
 
Three Months Ended June 30, 2014:
 
Benefit Plans
 
Instruments
 
Total
Balance, March 31, 2014
 
$
(5,090
)
 
$
(2,654
)
 
$
(7,744
)
Reclassification of benefit plan actuarial losses and prior service cost
 
95

 
—

 
95

Reclassifications of net losses on interest rate protection agreements
 
—

 
393

 
393

 
 
 
 
 
 
 
Balance, June 30, 2014
 
$
(4,995
)
 
$
(2,261
)
 
$
(7,256
)
 
 
 
 
 
 
 
Nine Months Ended June 30, 2014:
 
 
 
 
 
 
Balance, September 30, 2013
 
$
(5,283
)
 
$
(3,437
)
 
$
(8,720
)
Reclassification of benefit plan actuarial losses and prior service cost
 
288

 
—

 
288

Reclassifications of net losses on interest rate protection agreements
 
—

 
1,176

 
1,176

 
 
 
 
 
 
 
Balance, June 30, 2014
 
$
(4,995
)
 
$
(2,261
)
 
$
(7,256
)
 
 
 
 
 
 
 
Amounts in the table above are net of tax.
Reclassifications of net losses on interest rate protection agreements are reflected in interest expense on the Condensed Consolidated Statements of Income.
Restricted Cash. Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Correction of Error. We identified an error in the classification of deferred income tax assets on the June 30, 2013, Condensed Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the June 30, 2013, Condensed Consolidated Balance Sheet to correct the error which decreased the following Condensed Consolidated Balance Sheet items by $20,709: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.
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 Standards
Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In Fiscal 2014, the Company adopted new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The disclosures required by the new accounting guidance are included in the Note 2 to the condensed

- 6 -

consolidated financial statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. Effective October 1, 2013, the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively for all periods presented. The disclosures required are included in Note 10 to the condensed consolidated financial statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Accounting Standards Not Yet Adopted

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification 605, “Revenue Recognition,” and most industry-specific guidance included in the Codification. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This standard is effective for the Company beginning in fiscal 2018 and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

Discontinued Operations. In April 2014, the FASB issued authoritative guidance amending existing requirements for reporting discontinued operations.  Under the new guidance, discontinued operations reporting will be limited to disposal transactions that represent strategic shifts having a major effect on operations and financial results. The amended guidance also enhances disclosures and requires assets and liabilities of a discontinued operation to be classified as such for all periods presented in the financial statements. Public entities will apply the amended guidance prospectively to all disposals occurring within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company will adopt this standard on October 1, 2015.  Due to the change in requirements for reporting discontinued operations described above, presentation and disclosure of future disposal transactions after adoption may be different than under current standards.  

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 2013 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.

- 7 -
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, 2014:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas
Utility
 
Electric
Utility
 
Other
Revenues
$
152,694

 
$
128,264

 
$
23,954

 
$
476

Cost of sales
$
63,323

 
$
49,257

 
$
14,066

 
$
—

Depreciation and amortization
$
14,892

 
$
13,774

 
$
1,118

 
$
—

Operating income
$
19,720

 
$
17,115

 
$
2,304

 
$
301

Interest expense
$
10,433

 
$
9,904

 
$
529

 
$
—

Income before income taxes
$
9,287

 
$
7,211

 
$
1,775

 
$
301

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,289,841

 
$
2,147,407

 
$
142,434

 
$
—

Goodwill (at period end)
$
182,145

 
$
182,145

 
$
—

 
$
—

Capital expenditures
$
38,215

 
$
35,955

 
$
2,260

 
$
—

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)
$
2,307,347

 
$
2,143,726

 
$
163,621

 
$
—

Goodwill (at period end)
$
182,145

 
$
182,145

 
$
—

 
$
—

Capital expenditures
$
38,961

 
$
37,224

 
$
1,737

 
$
—











- 8 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


Nine Months Ended June 30, 2014:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas
Utility
 
Electric
Utility
 
Other
Revenues
$
965,549

 
$
879,989

 
$
84,467

 
$
1,093

Cost of sales
$
515,612

 
$
463,492

 
$
52,120

 
$
—

Depreciation and amortization
$
43,985

 
$
40,733

 
$
3,252

 
$
—

Operating income
$
243,517

 
$
233,728

 
$
9,485

 
$
304

Interest expense
$
28,036

 
$
26,652

 
$
1,384

 
$
—

Income before income taxes
$
215,481

 
$
207,076

 
$
8,101

 
$
304

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,289,841

 
$
2,147,407

 
$
142,434

 
$
—

Goodwill (at period end)
$
182,145

 
$
182,145

 
$
—

 
$
—

Capital expenditures
$
104,117

 
$
98,806

 
$
5,311

 
$
—

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)
$
2,307,347

 
$
2,143,726

 
$
163,621

 
$
—

Goodwill (at period end)
$
182,145

 
$
182,145

 
$
—

 
$
—

Capital expenditures
$
94,480

 
$
90,173

 
$
4,307

 
$
—



5.    Inventories
Inventories comprise the following:
 
June 30, 2014
 
September 30, 2013
 
June 30, 2013
Gas Utility natural gas
$
45,701

 
$
78,950

 
$
43,052

Materials, supplies and other
13,049

 
10,711

 
10,946

Total inventories
$
58,750

 
$
89,661

 
$
53,998


At June 30, 2014, UGI Utilities is a party to four storage contract administrative agreements (“SCAAs”) having terms of one to three years. Three of the SCAAs are with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (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,

- 9 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.
The carrying value of gas storage inventories released under UGI Utilities’ principal SCAAs at June 30, 2014, September 30, 2013 and June 30, 2013, comprising 6.1 billion cubic feet (“bcf”), 11.0 bcf and 5.6 bcf of natural gas, was $28,299, $44,366 and $24,389, respectively. In conjunction with these SCAAs, UGI Utilities held total security deposits received from its SCAA counterparties of $17,600 at June 30, 2014, and $16,500 at September 30, 2013 and June 30, 2013. 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 2013 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, 2014
 
September 30, 2013
 
June 30, 2013
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
107,166

 
$
106,069

 
$
104,731

Underfunded pension and postretirement plans
89,236

 
94,515

 
177,846

Environmental costs
14,581

 
17,054

 
16,642

Deferred fuel and power costs
9,354

 
8,283

 
4,109

Removal costs, net
15,620

 
13,333

 
12,074

Other
6,669

 
5,657

 
5,561

Total regulatory assets
$
242,626

 
$
244,911

 
$
320,963

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
17,545

 
$
16,497

 
$
14,244

Environmental overcollections
1,631

 
2,552

 
2,906

Deferred fuel and power refunds
—

 
8,283

 
14,156

State tax benefits — distribution system repairs
9,271

 
8,453

 
8,024

Other
1,862

 
1,502

 
672

Total regulatory liabilities
$
30,309

 
$
37,287

 
$
40,002

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, 2014, September 30, 2013, and June 30, 2013, were $680, $(1,743) and $(1,352), respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of 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

- 10 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2014, September 30, 2013, and June 30, 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $760, $(4,759) and $(6,060), respectively, which amounts are reflected in current derivative financial instrument assets and liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs or refunds 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, 2014, September 30, 2013, and June 30, 2013, 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 postretirement life insurance benefits to nearly all active and retired employees.

- 11 -
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,
 
2014
 
2013
 
2014
 
2013
Service cost
$
1,623

 
$
2,052

 
$
41

 
$
51

Interest cost
5,721

 
5,196

 
127

 
143

Expected return on assets
(6,649
)
 
(6,197
)
 
(139
)
 
(133
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
87

 
62

 
(160
)
 
(105
)
Actuarial loss
1,660

 
3,366

 
37

 
91

Net benefit cost (income)
2,442

 
4,479

 
(94
)
 
47

Change in associated regulatory liabilities
—

 
—

 
918

 
815

Net expense
$
2,442

 
$
4,479

 
$
824

 
$
862

 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
 
Nine Months Ended
 
Nine Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Service cost
$
4,869

 
$
6,158

 
$
123

 
$
154

Interest cost
17,163

 
15,587

 
381

 
428

Expected return on assets
(19,949
)
 
(18,594
)
 
(417
)
 
(396
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
261

 
187

 
(480
)
 
(317
)
Actuarial loss
4,982

 
10,098

 
111

 
273

Net benefit cost (income)
7,326

 
13,436

 
(282
)
 
142

Change in associated regulatory liabilities
—

 
—

 
2,754

 
2,446

Net expense
$
7,326

 
$
13,436

 
$
2,472

 
$
2,588


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 $6,900 to the Pension Plan during the remainder of Fiscal 2014. During the nine months ended June 30, 2014 and 2013, the Company made contributions to the Pension Plan of $10,975 and $13,365, 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.
We also participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.

8.    Commitments and Contingencies
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities

- 12 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


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 is scheduled to terminate at the end of 2018. 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, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,381 and $14,399, 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, 2014, 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 UGI Utilities 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.
There are pending claims and legal actions arising in the normal course of our businesses. While the results of these pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, that the final outcome of such 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,

- 13 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


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.
UGI Utilities is a party to several SCAAs with Energy Services which have terms of one to three years. 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 $16,894 and $23,590 during the three and nine months ended June 30, 2014, respectively, and $21,570 and $26,596 during the three and nine months ended June 30, 2013, 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 $10,600 as of June 30, 2014, and $16,500 as of September 30, 2013 and June 30, 2013.
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, 2014, comprising approximately 4.0 bcf of natural gas, was $19,410. The carrying value of these gas storage inventories at September 30, 2013, comprising approximately 10.4 bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at June 30, 2013, comprising approximately 5.6 bcf of natural gas, was $24,389.
UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and nine months ended June 30, 2014, totaled $1,551 and $34,259, respectively. During the three and nine months ended June 30, 2013, such transactions totaled $0 and $32,526, 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, 2014, revenues associated with such sales to Energy Services totaled $9,869 and $102,118, respectively. 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. 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, 2014, the aggregate amount of such purchases totaled $22,114 and $114,811, respectively. During the three and nine months ended June 30, 2013, the aggregate amount of such purchases totaled $24,426 and $61,659, 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, 2014, September 30, 2013 and June 30, 2013:

 
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, 2014:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
807

 
$
896

 
$
—

 
$
1,703

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
(31
)
 
$
—

 
$
(31
)
September 30, 2013:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
43

 
$
—

 
$
—

 
$
43

Liabilities:
 
 
 
 
 
 
 
Derivative financial instruments:
 
 
 
 
 
 
 
Commodity contracts
$
(2,162
)
 
$
(4,515
)
 
$
—

 
$
(6,677
)
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
)

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.



- 15 -
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, 2014, were $642,000 and $708,916, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2013, were $600,000 and $663,178, 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).
Disclosures About Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative financial instruments include both over-the-counter transactions and those that are executed on an exchange and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts may be subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.
In general, most of our over-the-counter transactions and most exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.
 
 
 
 
 
 
Gross Amount Recognized
Gross Amount Offset in the Balance Sheet
Net Amounts Presented in the Balance Sheet
 
June 30, 2014:
 
 
 
 
Derivative assets
$
2,516

$
(813
)
$
1,703

 
Derivative (liabilities)
$
(844
)
$
813

$
(31
)
 
 
 
 
 
 
September 30, 2013:
 
 
 
 
Derivative assets
$
92

$
(49
)
$
43

 
Derivative (liabilities)
$
(6,726
)
$
49

$
(6,677
)
 
 
 
 
 
 
June 30, 2013:
 
 
 
 
Derivative assets
$
10,809

$
(2,581
)
$
8,228

 
Derivative (liabilities)
$
(25,531
)
$
2,581

$
(22,950
)
 

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

- 16 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


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, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10.9 million dekatherms and 11.7 million dekatherms, respectively. At June 30, 2014, 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 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 most of 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, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising net gains of $760 and net losses of $6,060, respectively, are reflected in current derivative financial instrument assets and 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 and liabilities. At June 30, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 315.8 million kilowatt hours and 327.4 million kilowatt hours, respectively. At June 30, 2014, 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, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 232.1 million kilowatt hours and 260.6 million kilowatt hours, respectively.
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 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, 2014, we had no unsettled IRPAs. As of June 30, 2013, the total notional amounts of unsettled IRPAs was $173,000.


- 17 -
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)


At June 30, 2014, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months is $2,677.
Derivative Financial Instrument Credit Risk
Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2014 and 2013, there was $1,109 and $2,636 of restricted cash in brokerage accounts.
The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2014 and 2013:
 
Derivative Assets
 
Derivative (Liabilities)
 
 
 
Fair Value
 
 
 
Fair Value
 
 
 
June 30,
 
 
 
June 30,
 
Balance Sheet Location
 
2014
 
2013
 
Balance Sheet Location
 
2014
 
2013
Derivatives Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
Derivative financial instruments
 
$
—

 
$
8,125

 
Derivative financial instruments
 
$
—

 
$
(15,306
)
Derivatives Subject to Utility Rate Regulation:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 
1,637

 
67

 
Derivative financial instruments and Other noncurrent liabilities
 
(31
)
 
(7,644
)
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Derivative financial instruments
 
66

 
36

 
Derivative financial instruments
 
—

 
—

Total Derivatives
 
 
$
1,703

 
$
8,228

 
 
 
$
(31
)
 
$
(22,950
)


- 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 the three and nine months ended June 30, 2014 and 2013:
Three Months Ended June 30, :
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in AOCI
 
Gain (Loss) Reclassified from AOCI into Income
 
Location of Gain or
 
2014
 
2013
 
2014
 
2013
 
(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
$
—

 
$
12,776

 
$
(671
)
 
$
(203
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives Not Designated
 
 
 
 
 
 
 
 
 
 
 
   as Hedging Instruments:
Gain (Loss) Recognized in Income
 
 
 
 
 
Location of Gain (Loss) Recognized in Income
 
2014
 
2013
 
 
 
 
 
 
 
 
Commodity contracts
$
49

 
$
(93
)
 
 
 
 
 
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
 
2014
 
2013
 
2014
 
2013
 
(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
$
—

 
$
23,228

 
$
(2,010
)
 
$
(608
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives Not Designated
 
 
 
 
 
 
 
 
 
 
 
   as Hedging Instruments:
Gain (Loss) Recognized in Income
 
 
 
 
 
Location of Gain (Loss) Recognized in Income
 
2014
 
2013
 
 
 
 
 
 
 
 
Commodity contracts
$
128

 
$
12

 
 
 
 
 
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
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)



12.     Debt

On March 26, 2014, UGI Utilities issued in a private placement $175,000 of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175,000 of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.



- 20 -

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,” 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, 2013, 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.


- 21 -
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, 2014 (“2014 three-month period”) with the three months ended June 30, 2013 (“2013 three-month period”) and the nine months ended June 30, 2014 (“2014 nine-month period”) with the nine months ended June 30, 2013 (“2013 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.

2014 three-month period compared with 2013 three-month period
 
 
 
 
 
 
 
Three Months Ended June 30,
 
2014
 
2013
 
Increase (decrease)
(Millions of dollars)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
128.3

 
$
126.7

 
$
1.6

 
1.3
 %
Total margin (a)
 
$
79.0

 
$
74.3

 
$
4.7

 
6.3
 %
Operating income
 
$
17.1

 
$
16.1

 
$
1.0

 
6.2
 %
Income before income taxes
 
$
7.2

 
$
6.9

 
$
0.3

 
4.3
 %
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
9.2

 
8.8

 
0.4

 
4.5
 %
Total
 
37.5

 
35.9

 
1.6

 
4.5
 %
Heating degree days — % (warmer) than normal (b)
 
(6.3
)%
 
(7.1
)%
 
—

 
—

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
24.0

 
$
21.5

 
$
2.5

 
11.6
 %
Total margin (a)
 
$
8.6

 
$
8.4

 
$
0.2

 
2.4
 %
Operating income
 
$
2.3

 
$
2.6

 
$
(0.3
)
 
(11.5
)%
Income before income taxes
 
$
1.8

 
$
2.1

 
$
(0.3
)
 
(14.3
)%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
217.7

 
222.5

 
(4.8
)
 
(2.2
)%

(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 $1.3 million and $1.2 million during the three-month periods ended June 30, 2014 and 2013, 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 2014 three-month period based upon heating degree days were 6.3% warmer than normal and slightly colder than the prior-year three-month period. Total distribution system throughput was slightly higher principally reflecting a net increase in large firm and interruptible delivery service volumes and to a lesser extent higher core market volumes. 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 customer growth, due principally to conversions from oil prompted by sustained lower natural gas prices and high oil prices.
Gas Utility revenues increased $1.6 million during the 2014 three-month period principally reflecting higher revenues from core market customers ($3.6 million) and greater revenues from large delivery service customers on higher throughput substantially offset by lower revenues from off-system sales ($5.5 million). The increase in core market revenues principally reflects the effects of the higher core market volumes partially offset by the effects of slightly lower average purchased gas cost (“PGC”) rates. 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

- 22 -
UGI UTILITIES, INC. AND SUBSIDIARIES


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 $49.2 million in the 2014 three-month period compared with $52.4 million in the prior-year period principally reflecting the effects on cost of sales of the lower off-system sales ($5.5 million) and the lower average PGC rates partially offset by the greater retail core-market volumes sold ($2.7 million).
Gas Utility total margin increased $4.7 million in the 2014 three-month period principally reflecting higher core market total margin and greater large firm delivery service total margin. The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers.
 
The increases in Gas Utility operating income and income before income taxes during the 2014 three-month period principally reflects the greater total margin ($4.7 million) partially offset by higher operating and administrative expenses and, with respect to income before income taxes, slightly higher interest expense from higher long-term debt outstanding.
Electric Utility. Temperatures based upon heating degree days during the 2014 three-month period were 11.8% warmer than normal and slightly warmer than the prior-year period. Cooling degree days in the current-year period were slightly lower than the prior-year period. The decrease in distribution sales reflects, in part, the milder spring weather. The increase in Electric Utility revenues reflects the effects of higher average default service (“DS”) rates during the 2014 three-month period. Electric Utility cost of sales increased to $14.1 million in the 2014 three-month period from $12.0 million in the 2013 three-month period reflecting the effects of the greater DS rates.
Electric Utility total margin increased slightly during the 2014 three-month period. However operating income and income before income taxes in the 2014 three-month period each decreased $0.3 million, notwithstanding the slight increase in total Electric Utility margin, principally as a result of higher general and administrative expenses and greater depreciation expense.
Interest Expense and Income Taxes. Our consolidated interest expense in the 2014 three-month period was slightly higher than the prior year principally reflecting higher long-term debt outstanding. Our effective income tax rate for the three months ended June 30, 2014, was lower than the prior-year three-month period principally reflecting the effects of a slight decline in the annual estimated effective tax rate for fiscal 2014 on 2014 three-month period income taxes.

2014 nine-month period compared with 2013 nine-month period
 
 
 
 
 
 
 
Nine Months Ended June 30,
 
2014
 
2013
 
Increase
(Millions of dollars)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
880.0

 
$
743.6

 
$
136.4

 
18.3
%
Total margin (a)
 
$
416.5

 
$
370.9

 
$
45.6

 
12.3
%
Operating income
 
$
233.7

 
$
191.6

 
$
42.1

 
22.0
%
Income before income taxes
 
$
207.1

 
$
163.5

 
$
43.6

 
26.7
%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
75.1

 
65.4

 
9.7

 
14.8
%
Total
 
172.8

 
158.5

 
14.3

 
9.0
%
Heating degree days — % colder (warmer) than normal (b)
 
10.2
%
 
(1.2
)%
 
—

 
—

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
84.5

 
$
73.6

 
$
10.9

 
14.8
%
Total margin (a)
 
$
27.7

 
$
26.9

 
$
0.8

 
3.0
%
Operating income
 
$
9.5

 
$
8.6

 
$
0.9

 
10.5
%
Income before income taxes
 
$
8.1

 
$
7.1

 
$
1.0

 
14.1
%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
775.8

 
753.4

 
22.4

 
3.0
%


- 23 -
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 $4.6 million and $4.0 million during the nine-month periods ended June 30, 2014 and 2013, 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 2014 nine-month period based upon heating degree days were 10.2% colder than normal and 11.6% colder than the prior-year nine-month period. Total distribution system throughput increased 14.3 bcf principally reflecting a 9.7 bcf (14.8%) increase in demand from Gas Utility’s core market customers and, to a lesser extent, greater net large firm and interruptible delivery service volumes. Gas Utility system throughput to core-market customers was higher than last year principally reflecting the effects of the significantly colder weather and, to a lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower natural gas prices and high oil prices.
Gas Utility revenues increased $136.4 million during the 2014 nine-month period principally reflecting higher revenues from core market customers ($80.8 million), higher revenues from off-system sales ($40.0 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($10.3 million). The increase in core market revenues principally reflects the effects of the higher core market throughput. Gas Utility’s cost of gas was $463.5 million in the 2014 nine-month period compared with $372.7 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($45.9 million) and the effects of the higher off-system sales ($40.0 million).
Gas Utility total margin increased $45.6 million in the 2014 nine-month period principally reflecting higher core market total margin ($32.5 million) and greater large firm delivery service total margin ($9.9 million). The higher core market and large firm delivery service total margin reflects the effects of the colder weather and customer growth.
 
Gas Utility operating income and income before income taxes during the 2014 nine-month period were $42.1 million and $43.6 million higher than the prior year, respectively. The increase in Gas Utility operating income principally reflects the $45.6 million increase in total margin. Operating expenses were slightly higher than the prior-year nine-month period as greater 2014 nine-month period uncollectible accounts expense was offset principally by lower distribution system maintenance expenses and lower pension and benefit expenses. The increase in Gas Utility income before income taxes reflects the greater operating income ($42.1 million) and lower interest expense principally reflecting lower average interest rates.
Electric Utility. Temperatures based upon heating degree days during the 2014 nine-month period were approximately 7.0% colder than normal and approximately 9.7% colder than the prior-year period. The increase in Electric Utility revenues reflects the effects of the colder weather on throughput to residential and commercial customers primarily for heating purposes and higher average DS rates. Electric Utility cost of sales increased to $52.1 million in the 2014 nine-month period from $42.7 million in the 2013 nine-month period principally reflecting the effects of the greater DS rates and the higher sales.
Electric Utility total margin increased $0.8 million reflecting the effects of the higher throughput partially offset by higher gross receipts taxes on the higher revenues. Operating income and income before income taxes in the 2014 nine-month period increased $0.9 million and $1.0 million, respectively, principally as a result of the higher total margin ($0.8 million) and slightly lower operating and administrative costs. Operating costs in the prior-year period include higher distribution system costs associated with Hurricane Sandy.
Interest Expense and Income Taxes. Our consolidated interest expense in the 2014 nine-month period was lower than the prior year principally reflecting lower average interest rates. Our effective income tax rate for the nine months ended June 30, 2014, was comparable to the prior-year nine-month period.

FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Company’s total debt outstanding at June 30, 2014, was $642 million, which includes no bank loans outstanding, compared to debt outstanding of $659.5 million at September 30, 2013, which includes $17.5 million of bank loans outstanding. UGI Utilities’ long-term debt outstanding at June 30, 2014, comprises $450 million of Senior Notes and $192 million of Medium-Term Notes.

In March 2014, UGI Utilities issued in a private placement $175 million of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing

- 24 -
UGI UTILITIES, INC. AND SUBSIDIARIES


outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.

UGI Utilities may borrow up to a total of $300 million (including a $100 million sublimit for letters of credit) under its credit agreement (“Credit Agreement”). The Credit Agreement expires in October 2015. During the 2014 and 2013 nine-month periods, average daily bank loan borrowings were $30.4 million and $27.3 million, respectively, and peak bank loan borrowings totaled $84 million and $79 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 Credit Agreement to meet our anticipated contractual and projected cash commitments.
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 Credit Agreement to manage seasonal cash flow needs.
Cash provided by operating activities was $205.3 million in the 2014 nine-month period compared to $188.6 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital was $199.9 million in the 2014 nine-month period compared to $178.1 million recorded in the prior-year nine-month period principally reflecting the higher 2014 nine-month operating results. Changes in operating working capital provided $5.5 million of operating cash flow during the 2014 nine-month period compared to $10.6 million of cash provided during the prior-year nine-month period. Greater cash in the 2014 nine-month period from changes inventories and other current liabilities, primarily changes in accrued income taxes, was offset by lower 2014 nine-month period net cash flow from the PGC deferred fuel recovery mechanism and changes in accounts receivable.
Investing activities. Cash used by investing activities was $107.3 million in the 2014 nine-month period compared to $99.7 million in the 2013 nine-month period. Total capital expenditures were $104.1 million in the 2014 nine-month period compared with $94.5 million recorded in the prior-year nine-month period. The 2014 nine-month period principally reflects higher Gas Utility capital expenditures. Changes in restricted cash in futures brokerage accounts provided $2.1 million of cash in the 2014 nine-month period period compared with cash used of $2.6 million in the prior-year period.
Financing activities. Cash used by financing activities was $74.3 million in the 2014 nine-month period compared with $8.2 million in the 2013 nine-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our Credit Agreement, cash dividends paid to UGI and capital contributions from UGI. During the 2014 nine-month period there were net bank loan repayments of $17.5 million compared with net repayments of $9.2 million during the prior-year nine-month period. Cash dividends in the 2014 nine-month period totaled $57.5 million. There were no cash dividends paid during the nine months ended June 30, 2013. In March 2014, UGI Utilities issued $175 million of 4.98% Senior Notes due March 26, 2044. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ term loan credit agreement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce

- 25 -
UGI UTILITIES, INC. AND SUBSIDIARIES


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, 2014 and 2013, UGI Utilities had $1.1 million and $2.6 million of restricted cash associated with futures accounts. At June 30, 2014 and 2013, the fair values of our natural gas futures and option contracts were net gains (losses) of $0.7 million and $(1.4) 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, 2014 and 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $0.8 million and $(6.1) million, respectively. At June 30, 2014 and 2013, the fair values of FTRs were not material.
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, 2014 and 2013 are 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”). There were no outstanding IRPAs at June 30, 2014. The fair values of unsettled IRPAs held at June 30, 2013, were net losses of $7.2 million.

- 26 -
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.

- 27 -
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, 2013, 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:
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 June 30, 2014, 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, 2014, 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, 2014, 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
 
 
 




- 28 -
UGI UTILITIES, INC. AND SUBSIDIARIES


SIGNATURE
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 7, 2014
By:  
/s/ Donald E. Brown  
 
 
 
Donald E. Brown
Vice President - Finance and
Chief Financial Officer  (Principal Accounting Officer)


- 29 -
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 June 30, 2014, 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, 2014, 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, 2014, 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



UGI UTILITIES INC Reports