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EX-32 - EXHIBIT 32 - UGI UTILITIES INCex323-31x15ugiutilities10q.htm
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCex3123-31x15ugiutilities10q.htm
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EX-10.2 - EXHIBIT 10.2 - UGI UTILITIES INCex1023-31x15ugiutilities10q.htm
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EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INCex3113-31x15ugiutilities10q.htm

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
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 April 30, 2015, 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
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



- i -




UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
16,040

 
$
12,401

 
$
14,238

Restricted cash
5,578

 
3,592

 

Accounts receivable (less allowances for doubtful accounts of $11,889, $6,992 and $12,098, respectively)
183,046

 
65,080

 
181,823

Accounts receivable — related parties
2,709

 
2,865

 
8,633

Accrued utility revenues
42,056

 
14,330

 
49,710

Inventories
19,533

 
95,219

 
20,629

Deferred income taxes
25,168

 
1,492

 
12,877

Regulatory assets
625

 
13,159

 
4,242

Derivative instruments
612

 
1,028

 
3,221

Prepaid expenses & other current assets
15,648

 
18,535

 
13,705

Total current assets
311,015

 
227,701

 
309,078

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $911,289, $886,268 and $877,460, respectively)
1,753,197

 
1,682,284

 
1,611,934

Goodwill
182,145

 
182,145

 
182,145

Regulatory assets
251,945

 
255,007

 
231,689

Other assets
7,741

 
7,506

 
5,771

Total assets
$
2,506,043

 
$
2,354,643

 
$
2,340,617

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Current maturities of long-term debt
$
92,000

 
$
20,000

 
$

Short-term borrowings
30,500

 
86,300

 
6,500

Accounts payable
54,612

 
58,453

 
69,468

Accounts payable — related parties
14,979

 
11,761

 
20,715

Deferred fuel refunds
40,542

 

 
3,204

Derivative instruments
5,464

 
1,632

 
372

Other current liabilities
166,879

 
99,336

 
149,983

Total current liabilities
404,976

 
277,482

 
250,242

Long-term debt
550,000

 
622,000

 
642,000

Deferred income taxes
472,343

 
461,461

 
448,678

Deferred investment tax credits
3,765

 
3,933

 
4,100

Pension and postretirement benefit obligations
94,332

 
98,363

 
65,972

Derivative instruments
75

 

 

Other noncurrent liabilities
51,262

 
51,567

 
52,669

Total liabilities
1,576,753

 
1,514,806

 
1,463,661

Commitments and contingencies (Note 7)

 

 

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

 
60,259

 
60,259

Additional paid-in capital
471,653

 
471,071

 
470,761

Retained earnings
404,516

 
316,688

 
353,680

Accumulated other comprehensive loss
(7,138
)
 
(8,181
)
 
(7,744
)
Total common stockholder’s equity
929,290

 
839,837

 
876,956

Total liabilities and stockholder’s equity
$
2,506,043

 
$
2,354,643

 
$
2,340,617

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
 
Six Months Ended
 
March 31,
 
March 31,
 
2015
 
2014
 
2015
 
2014
Revenues
$
500,573

 
$
513,956

 
$
787,879

 
$
812,855

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
278,336

 
300,424

 
421,388

 
452,289

Operating and administrative expenses
58,917

 
54,306

 
105,465

 
95,451

Operating and administrative expenses — related parties
4,138

 
3,769

 
6,920

 
5,612

Taxes other than income taxes
4,803

 
4,801

 
8,907

 
8,980

Depreciation
14,757

 
13,815

 
29,315

 
27,437

Amortization
887

 
828

 
1,754

 
1,656

Other operating income, net
(3,964
)
 
(1,941
)
 
(4,209
)
 
(2,367
)
 
357,874

 
376,002

 
569,540

 
589,058

Operating income
142,699

 
137,954

 
218,339

 
223,797

Interest expense
10,611

 
8,806

 
21,260

 
17,603

Income before income taxes
132,088

 
129,148

 
197,079

 
206,194

Income taxes
52,499

 
53,038

 
78,651

 
84,798

Net income
$
79,589

 
$
76,110

 
$
118,428

 
$
121,396

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 March 31,
 
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Net income
$
79,589

 
$
76,110

 
$
118,428

 
$
121,396

Other comprehensive income:
 
 
 
 
 
 
 
Reclassifications of net losses on derivative instruments (net of tax of $(278), $(278), $(556) and $(556), respectively)
392

 
392

 
783

 
783

Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(92), $(67), $(183) and $(137), respectively)
129

 
95

 
260

 
193

Other comprehensive income
521

 
487

 
1,043

 
976

Comprehensive income
$
80,110

 
$
76,597

 
$
119,471

 
$
122,372

See accompanying notes to condensed consolidated financial statements.


- 3 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
 
Six Months Ended
 
March 31,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
118,428

 
$
121,396

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
31,069

 
29,093

Deferred income taxes, net
(13,888
)
 
12,109

Provision for uncollectible accounts
8,979

 
8,716

Other, net
2,521

 
414

Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(154,515
)
 
(173,176
)
Inventories
75,686

 
69,032

Deferred fuel and power costs, net of changes in unsettled derivatives
55,760

 
(10,181
)
Accounts payable
8,013

 
25,726

Other current assets
(921
)
 
1,746

Other current liabilities
66,025

 
38,355

Net cash provided by operating activities
197,157

 
123,230

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(102,020
)
 
(65,902
)
Net costs of property, plant and equipment disposals
(3,694
)
 
(2,948
)
(Increase) decrease in restricted cash
(1,986
)
 
3,181

Net cash used by investing activities
(107,700
)
 
(65,669
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(30,600
)
 
(37,693
)
Issuances of long-term debt

 
175,000

Repayments of long-term debt

 
(175,000
)
Decrease in short-term borrowings
(55,800
)
 
(11,000
)
Other
582

 
663

Net cash used by financing activities
(85,818
)
 
(48,030
)
Cash and cash equivalents increase
$
3,639

 
$
9,531

CASH AND CASH EQUIVALENTS:
 
 
 
End of period
$
16,040

 
$
14,238

Beginning of period
12,401

 
4,707

Increase
$
3,639

 
$
9,531

See accompanying notes to condensed consolidated financial statements.


- 4 -


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

Note 1 — Nature of Operations

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

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

Note 2 — Summary of 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 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, 2014, 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, 2014 (“the Company’s 2014 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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.

Note 3 — Accounting Changes

Accounting Standards Not Yet Adopted

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. 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 for interim and annual periods

- 5 -

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


beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. 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.

Note 4 — Inventories
Inventories comprise the following:
 
March 31, 2015
 
September 30, 2014
 
March 31, 2014
Gas Utility natural gas
$
6,260

 
$
82,664

 
$
7,490

Materials, supplies and other
13,273

 
12,555

 
13,139

Total inventories
$
19,533

 
$
95,219

 
$
20,629


At March 31, 2015, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. Two of the SCAAs are with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 12) and one of the SCAAs is with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The 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 for which UGI Utilities has the rights), 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 March 31, 2015, September 30, 2014 and March 31, 2014, comprising 1.0 billion cubic feet (“bcf”), 11.6 bcf and 1.3 bcf of natural gas, was $4,082, $49,897 and $5,421, respectively. At March 31, 2015, September 30, 2014 and March 31, 2014, UGI Utilities held a total of $17,700, $17,600 and $17,600, respectively, of security deposits from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

- 6 -

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


Note 5 — Regulatory Assets and Liabilities and Regulatory Matters
For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 4 in the Company’s 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
March 31, 2015
 
September 30, 2014
 
March 31, 2014
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
111,441

 
$
110,709

 
$
106,800

Underfunded pension and postretirement plans
105,539

 
110,116

 
90,996

Environmental costs
14,110

 
14,616

 
14,544

Deferred fuel and power costs

 
11,732

 
4,308

Removal costs, net
18,377

 
16,790

 
14,379

Other
3,103

 
4,203

 
4,904

Total regulatory assets
$
252,570

 
$
268,166

 
$
235,931

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
19,323

 
$
18,594

 
$
17,196

Environmental overcollections

 
349

 
1,855

Deferred fuel and power refunds
40,542

 
306

 
3,204

State tax benefits — distribution system repairs
10,621

 
10,076

 
8,998

Other
2,099

 
3,172

 
1,895

Total regulatory liabilities (a)
$
72,585

 
$
32,497

 
$
33,148


(a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Deferred fuel and power — costs and refunds. Gas Utility’s 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”) tariffs 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 instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at March 31, 2015, September 30, 2014, and March 31, 2014, were $(3,381), $(1,363) and $2,389, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. We have chosen not to elect the NPNS exception under GAAP related to these derivative instruments for all forward electricity purchase contracts entered into prior to March 1, 2015. These electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At March 31, 2015, September 30, 2014, and March 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1,168), $345 and $358, respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet (see Note 10).


- 7 -

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


In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative 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 March 31, 2015, September 30, 2014, and March 31, 2014, were not material.
    
Note 6 — Debt

On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300,000 (including a $100,000 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300,000 revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the PUC. The Company intends to seek such regulatory approval.
Note 7 — Commitments and Contingencies

Contingencies

Environmental Matters

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 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 March 31, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $9,610 and $11,097, respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

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.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (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 and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 31, 2015, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

- 8 -

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



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. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Note 8 — Defined Benefit Pension and Other Postretirement Plans

We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees.

Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
1,740

 
$
1,623

 
$
49

 
$
41

Interest cost
 
5,628

 
5,721

 
118

 
127

Expected return on assets
 
(7,225
)
 
(6,650
)
 
(153
)
 
(139
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
87

 
87

 
(160
)
 
(160
)
Actuarial loss
 
2,198

 
1,661

 
31

 
37

Net benefit cost (income)
 
2,428

 
2,442

 
(115
)
 
(94
)
Change in associated regulatory liabilities
 

 

 
938

 
918

Net benefit cost after change in regulatory liabilities
 
$
2,428

 
$
2,442

 
$
823

 
$
824

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
3,481

 
$
3,246

 
$
97

 
$
82

Interest cost
 
11,255

 
11,442

 
237

 
254

Expected return on assets
 
(14,449
)
 
(13,299
)
 
(306
)
 
(278
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
174

 
174

 
(320
)
 
(320
)
Actuarial loss
 
4,396

 
3,321

 
63

 
74

Net benefit cost (income)
 
4,857

 
4,884

 
(229
)
 
(188
)
Change in associated regulatory liabilities
 

 

 
1,875

 
1,836

Net benefit cost after change in regulatory liabilities
 
$
4,857

 
$
4,884

 
$
1,646

 
$
1,648


Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks 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. During the six months ended March 31,

- 9 -

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


2015 and 2014, the Company made contributions to the Pension Plan of $5,566 and $6,972, respectively. The Company expects to make additional discretionary cash contributions of approximately $5,600 to the Pension Plan during the remainder of Fiscal 2015.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount 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. There were no required contributions to the VEBA during the six months ended March 31, 2015 and 2014.

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.


- 10 -

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


Note 9 — Fair Value Measurements

Derivative Instruments

The following table presents on a gross basis our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2015, September 30, 2014 and March 31, 2014:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2015:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
612

 
$
1

 
$

 
$
613

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(4,366
)
 
$
(1,174
)
 
$

 
$
(5,540
)
September 30, 2014:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
679

 
$
1,018

 
$

 
$
1,697

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(2,095
)
 
$
(206
)
 
$

 
$
(2,301
)
March 31, 2014 (a):
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2,725

 
$
801

 
$

 
$
3,526

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(243
)
 
$
(434
)
 
$

 
$
(677
)

(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.

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.

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 (including current maturities) at March 31, 2015, were $642,000 and $740,729, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at March 31, 2014, were $642,000 and $704,811, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2).


- 11 -

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


Note 10 — Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. For more information on the accounting for our derivative instruments, see Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2014 Annual Report.

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 March 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 9.0 million dekatherms, respectively. At March 31, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 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 because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 5).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet. At March 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 384.4 million kilowatt hours and 207.0 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which these contracts extend is 14 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5). At March 31, 2015 and 2014, the total volumes associated with FTRs totaled 58.1 million kilowatt hours and 47.4 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are economically hedging electricity congestion is 2 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.

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. As of March 31,

- 12 -

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


2015 and 2014, we had no unsettled IRPAs. At March 31, 2015, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $2,609.

Derivative Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2015, restricted cash in brokerage accounts totaled $5,578. At March 31, 2014, there was no restricted cash in brokerage accounts.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:
 
 
March 31, 2015
 
March 31, 2014 (a)
Derivative assets:
 
 
 
 
Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
$
613

 
$
3,458

Derivatives not subject to utility rate regulation:
 
 
 
 
Commodity contracts
 

 
68

Total derivative assets
 
$
613

 
$
3,526

Derivative liabilities:
 
 
 
 
Derivatives subject to utility rate regulation:
 
 

 
 

Commodity contracts
 
$
(5,168
)
 
$
(677
)
Derivatives not subject to utility rate regulation:
 
 

 
 

Commodity contracts
 
(372
)
 

Total derivative liabilities
 
$
(5,540
)
 
$
(677
)

(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.

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 instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. 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 are subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.

In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter 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 table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.


- 13 -

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


The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in Balance Sheet
 
Net Amounts Recognized
 
Cash Collateral (Received) Pledged
 
Net Amounts Recognized in Balance Sheet
March 31, 2015
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
613

 
$
(1
)
 
$
612

 
$

 
$
612

Derivative liabilities
 
$
(5,540
)
 
$
1

 
$
(5,539
)
 
$

 
$
(5,539
)
March 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
3,526

 
$
(305
)
 
$
3,221

 
$

 
$
3,221

Derivative liabilities
 
$
(677
)
 
$
305

 
$
(372
)
 
$

 
$
(372
)

Effect of Derivative Instruments

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 six months ended March 31, 2015 and 2014:

 
 
Gain (Loss) Recognized in AOCI
 
Gain (Loss) Reclassified from AOCI into Income
 
Location of Gain
(Loss) Reclassified from AOCI into Income
Three Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$

 
$
(670
)
 
$
(670
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Three Months Ended March 31,
 
2015
 
2014
 
 
 
 
 
 
 
 
Derivatives Not Subject to Utility Rate Regulation:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(4
)
 
$
(18
)
 
Operating expenses/other operating income, net
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in AOCI
 
Gain (Loss) Reclassified from AOCI into Income
 
Location of Gain
(Loss) Reclassified from AOCI into Income
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$

 
$
(1,339
)
 
$
(1,339
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Six Months Ended March 31,
 
2015
 
2014
 
 
 
 
 
 
 
 
Derivatives Not Subject to Utility Rate Regulation:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(526
)
 
$
79

 
Operating expenses/other operating income, net
 
 
 
 

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or

- 14 -

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


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.

Note 11 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three and six months ended March 31, 2015 and 2014:
 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Three Months Ended March 31, 2015
 
 
 
 
 
 
AOCI - December 31, 2014
 
$
(6,180
)
 
$
(1,479
)
 
$
(7,659
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
129

 

 
129

Reclassifications of net losses on interest rate protection agreements
 

 
392

 
392

AOCI - March 31, 2015
 
$
(6,051
)
 
$
(1,087
)
 
$
(7,138
)
Three Months Ended March 31, 2014
 
 
 
 
 
 
AOCI - December 31, 2013
 
$
(5,185
)
 
$
(3,046
)
 
$
(8,231
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
95

 

 
95

Reclassifications of net losses on interest rate protection agreements
 

 
392

 
392

AOCI - March 31, 2014
 
$
(5,090
)
 
$
(2,654
)
 
$
(7,744
)

 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Six Months Ended March 31, 2015
 
 
 
 
 
 
AOCI - September 30, 2014
 
$
(6,311
)
 
$
(1,870
)
 
$
(8,181
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
260

 

 
260

Reclassifications of net losses on interest rate protection agreements
 

 
783

 
783

AOCI - March 31, 2015
 
$
(6,051
)
 
$
(1,087
)
 
$
(7,138
)
Six Months Ended March 31, 2014
 
 
 
 
 
 
AOCI - September 30, 2013
 
$
(5,283
)
 
$
(3,437
)
 
$
(8,720
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
193

 

 
193

Reclassifications of net losses on interest rate protection agreements
 

 
783

 
783

AOCI - March 31, 2014
 
$
(5,090
)
 
$
(2,654
)
 
$
(7,744
)

Note 12 — 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. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

UGI Utilities is a party to two SCAAs with Energy Services which have terms of 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

- 15 -

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


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 $251 and $5,207 during the three and six months ended March 31, 2015, respectively, and $248 and $6,695 during the three and six months ended March 31, 2014, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, was $10,700, $10,600, and $10,600 as of March 31, 2015, September 30, 2014 and March 31, 2014, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying value of these gas storage inventories at March 31, 2015, September 30, 2014 and March 31, 2014, comprising 0.9 bcf, 7.7 bcf and 1.1 bcf of natural gas, was $3,391, $33,057 and $4,653, respectively.

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 principally during the heating season months of November through March. The capacity charges for these transactions (exclusive of transactions pursuant to the SCAAs) during the three and six months ended March 31, 2015 totaled $19,286 and $43,033, respectively. During the three and six months ended March 31, 2014, such transactions totaled $13,330 and $32,708, respectively, and are reflected in cost of sales.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2015, revenues associated with such sales to Energy Services totaled $46,227 and $62,417, respectively. During the three and six months ended March 31, 2014, revenues associated with such sales to Energy Services totaled $75,133 and $92,249, 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 six months ended March 31, 2015, such purchases totaled $49,750 and $71,525, respectively. During the three and six months ended March 31, 2014, such purchases totaled $70,619 and $92,697, respectively.

Note 13 — 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” below.
The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2014 Annual Report. 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.

- 16 -

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


Financial information by business segment follows:
Three Months Ended March 31, 2015:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
500,573

 
$
468,000

 
$
32,323

 
$
250

Cost of sales
$
278,336

 
$
258,155

 
$
20,181

 
$

Depreciation and amortization
$
15,644

 
$
14,489

 
$
1,155

 
$

Operating income (loss)
$
142,699

 
$
139,303

 
$
3,510

 
$
(114
)
Interest expense
$
10,611

 
$
10,104

 
$
507

 
$

Income (loss) before income taxes
$
132,088

 
$
129,199

 
$
3,003

 
$
(114
)
Capital expenditures
$
41,280

 
$
39,202

 
$
2,078

 
$


Three Months Ended March 31, 2014:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
513,956

 
$
480,163

 
$
33,552

 
$
241

Cost of sales
$
300,424

 
$
278,748

 
$
21,676

 
$

Depreciation and amortization
$
14,643

 
$
13,575

 
$
1,068

 
$

Operating income (loss)
$
137,954

 
$
134,560

 
$
3,492

 
$
(98
)
Interest expense
$
8,806

 
$
8,362

 
$
444

 
$

Income (loss) before income taxes
$
129,148

 
$
126,198

 
$
3,048

 
$
(98
)
Capital expenditures
$
31,648

 
$
30,039

 
$
1,609

 
$


Six Months Ended March 31, 2015:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
787,879

 
$
728,478

 
$
58,746

 
$
655

Cost of sales
$
421,388

 
$
385,363

 
$
36,025

 
$

Depreciation and amortization
$
31,069

 
$
28,769

 
$
2,300

 
$

Operating income (loss)
$
218,339

 
$
211,149

 
$
7,229

 
$
(39
)
Interest expense
$
21,260

 
$
20,234

 
$
1,026

 
$

Income (loss) before income taxes
$
197,079

 
$
190,915

 
$
6,203

 
$
(39
)
Capital expenditures
$
96,309

 
$
92,694

 
$
3,615

 
$

 
 
 
 
 
 
 
 
As of March 31, 2015
 
 
 
 
 
 
 
Total assets (at period end)
$
2,506,043

 
$
2,359,060

 
$
146,983

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$



- 17 -

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


Six Months Ended March 31, 2014:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
812,855

 
$
751,725

 
$
60,513

 
$
617

Cost of sales
$
452,289

 
$
414,235

 
$
38,054

 
$

Depreciation and amortization
$
29,093

 
$
26,959

 
$
2,134

 
$

Operating income
$
223,797

 
$
216,613

 
$
7,181

 
$
3

Interest expense
$
17,603

 
$
16,748

 
$
855

 
$

Income before income taxes
$
206,194

 
$
199,865

 
$
6,326

 
$
3

Capital expenditures
$
65,902

 
$
62,851

 
$
3,051

 
$

 
 
 
 
 
 
 
 
As of March 31, 2014
 
 
 
 
 
 
 
Total assets (at period end)
$
2,340,617

 
$
2,195,437

 
$
145,180

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$



- 18 -

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 (the “Exchange Act”). 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, consumer protection 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 in the Company’s 2014 Annual Report, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.


- 19 -

UGI UTILITIES, INC. AND SUBSIDIARIES


ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended March 31, 2015 (“2015 three-month period”) with the three months ended March 31, 2014 (“2014 three-month period”) and the six months ended March 31, 2015 (“2015 six-month period”) with the six months ended March 31, 2014 (“2014 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 13 to the condensed consolidated financial statements.

2015 three-month period compared with 2014 three-month period
Three Months Ended March 31,
 
2015
 
2014
 
Increase (Decrease)
(Millions of dollars)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
468.0

 
$
480.2

 
$
(12.2
)
 
(2.5
)%
Total margin (a)
 
$
209.8

 
$
201.4

 
$
8.4

 
4.2
 %
Operating and administrative expenses
 
$
57.1

 
$
52.4

 
$
4.7

 
9.0
 %
Operating income
 
$
139.3

 
$
134.6

 
$
4.7

 
3.5
 %
Income before income taxes
 
$
129.2

 
$
126.2

 
$
3.0

 
2.4
 %
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
44.3

 
41.8

 
2.5

 
6.0
 %
Total
 
81.0

 
78.5

 
2.5

 
3.2
 %
Heating degree days — % colder than normal (b)
 
22.1
%
 
19.3
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
32.3

 
$
33.6

 
$
(1.3
)
 
(3.9
)%
Total margin (a)
 
$
10.4

 
$
10.1

 
$
0.3

 
3.0
 %
Operating and administrative expenses
 
$
5.6

 
$
5.3

 
$
0.3

 
5.7
 %
Operating income
 
$
3.5

 
$
3.5

 
$

 
 %
Income before income taxes
 
$
3.0

 
$
3.0

 
$

 
 %
Distribution sales — millions of kilowatt-hours (“gwh”)
 
299.9

 
301.7

 
(1.8
)
 
(0.6
)%

(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 $1.7 million and $1.8 million during the three months ended March 31, 2015 and 2014, 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 during the 2015 three-month period based upon heating degree days were 22.1% colder than normal and 2.3% colder than the prior-year three-month period. Total distribution system throughput increased 2.5 bcf (3.2%) principally reflecting higher core market volumes due to an increase in heating degree days and 1.7% year-over-year growth in the number of 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 $12.2 million during the 2015 three-month period principally reflecting lower revenues from off-system sales ($25.9 million) partially offset by higher revenues from core market customers ($16.3 million). The increase in core market revenues principally reflects the effects of the higher core market throughput offset by slightly lower average purchased gas cost (“PGC”) rates during the 2015 three-month period. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes, distribution rates and PGC gas rates. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect

- 20 -

UGI UTILITIES, INC. AND SUBSIDIARIES


on retail core-market margin. Gas Utility’s cost of sales was $258.2 million in the 2015 three-month period compared with $278.7 million in the 2014 three-month period principally reflecting the effects of the lower off-system sales ($25.9 million) and lower average PGC rates ($4.4 million) partially offset by higher core-market volumes sold ($11.5 million).

Gas Utility 2015 three-month period total margin increased $8.4 million principally reflecting higher core market total margin ($9.1 million). The higher core market total margin reflects the effects of the previously mentioned colder weather on heating related sales and continued customer growth.
Gas Utility operating income and income before income taxes during the 2015 three-month period increased $4.7 million and $3.0 million, respectively, over the 2014 three-month period. The increase in Gas Utility operating income principally reflects the $8.4 million increase in total margin and increased other operating income, offset by higher operating and administrative expenses and slightly higher depreciation expense. Operating and administrative expenses were modestly higher than the prior-year period principally reflecting, among other things, higher 2015 three-month period distribution system maintenance ($1.6 million), and employee benefit and information technology expenses. Gas Utility other operating income increased due primarily to a reduction in out-of-state environmental remediation reserves. The increase in Gas Utility income before income taxes reflects the higher operating income partially offset by higher interest expense.
Electric Utility

Temperatures based upon heating degree days during the 2015 three-month period were approximately 18.6% colder than normal and 1.8% colder than the prior-year period. Electric Utility experienced a slight decrease in kilowatt-hour sales as customer conservation offset the effects on sales from the slightly colder weather. Electric Utility revenues decreased due primarily to lower average default service (“DS”) rates partially offset by higher transmission revenue. Electric Utility cost of sales decreased to $20.2 million in the 2015 three-month period from $21.7 million in the 2014 three-month period principally reflecting the effects of the lower average DS rates and the lower volumes sold.
Electric Utility total margin increased slightly principally reflecting the increase in transmission revenue. Electric Utility operating income and income before income taxes in the 2015 three-month period were comparable to the prior-year period as the increase in Electric Utility margin was offset by slightly higher operating and depreciation expenses.
Interest Expense and Income Taxes

Our interest expense in the 2015 three-month period was higher than the prior year principally reflecting interest on the 4.98% Senior Notes due March 2044 issued in March 2014 the proceeds of which were used to refinance UGI Utilities’ 364-day Term Loan Credit Agreement. Our effective income tax rate for the three months ended March 31, 2015 was slightly lower than the prior-year three-month period.


- 21 -

UGI UTILITIES, INC. AND SUBSIDIARIES


2015 six-month period compared with 2014 six-month period
Six Months Ended March 31,
 
2015
 
2014
 
Increase (Decrease)
 
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
728.5

 
$
751.7

 
$
(23.2
)
 
(3.1
)%
Total margin (a)
 
$
343.1

 
$
337.5

 
$
5.6

 
1.7
 %
Operating and administrative expenses
 
$
102.1

 
$
91.0

 
$
11.1

 
12.2
 %
Operating income
 
$
211.1

 
$
216.6

 
$
(5.5
)
 
(2.5
)%
Income before income taxes
 
$
190.9

 
$
199.9

 
$
(9.0
)
 
(4.5
)%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
67.5

 
65.9

 
1.6

 
2.4
 %
Total
 
137.8

 
135.3

 
2.5

 
1.8
 %
Heating degree days — % colder than normal (b)
 
11.2
%
 
12.5
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
58.7

 
$
60.5

 
$
(1.8
)
 
(3.0
)%
Total margin (a)
 
$
19.5

 
$
19.2

 
$
0.3

 
1.6
 %
Operating and administrative expenses
 
$
9.6

 
$
9.4

 
$
0.2

 
2.1
 %
Operating income
 
$
7.2

 
$
7.2

 
$

 
 %
Income before income taxes
 
$
6.2

 
$
6.3

 
$
(0.1
)
 
(1.6
)%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
544.7

 
558.1

 
(13.4
)
 
(2.4
)%

(a)
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $3.2 million and $3.3 million during the six months ended March 31, 2015 and 2014, 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 Gas Utility’s service territory in the 2015 six-month period based upon heating degree days were 11.2% colder than normal and 1.1% warmer than the 2014 six-month period. Total distribution system throughput increased 2.5 bcf (1.8%), notwithstanding the slightly warmer weather, principally reflecting 1.7% year-over-year growth in the number of core market customers.
Gas Utility revenues decreased $23.2 million during the 2015 six-month period principally reflecting lower revenues from off-system sales ($28.8 million) partially offset by higher revenues from core market customers ($8.2 million). The increase in core market revenues principally reflects the effects of the higher core market throughput offset by slightly lower average PGC rates during the 2015 six-month period. Gas Utility’s cost of sales was $385.4 million in the 2015 six-month period compared with $414.2 million in the 2014 six-month period principally reflecting the effects of the lower off-system sales ($28.8 million).
Gas Utility 2015 six-month period total margin increased $5.6 million principally reflecting higher core market total margin ($6.2 million). The higher core market total margin reflects the effects of the previously mentioned year-over-year customer growth.
Gas Utility operating income and income before income taxes during the 2015 six-month period decreased $5.5 million and $9.0 million, respectively. The decrease in Gas Utility operating income principally reflects an $11.1 million increase in operating and administrative expenses and slightly higher depreciation expenses partially offset by the $5.6 million increase in total margin and, to a much lesser extent, slightly higher other operating income. Operating and administrative expenses were higher than the prior year principally reflecting, among other things, higher 2015 six-month period distribution system maintenance ($4.3 million), and employee benefit and information technology expenses. The decrease in Gas Utility income before income taxes reflects the lower operating income ($5.5 million) and slightly higher interest expense.
Electric Utility


- 22 -

UGI UTILITIES, INC. AND SUBSIDIARIES


Temperatures based upon heating degree days during the 2015 six-month period were approximately 7.3% colder than normal and approximately 2.2% warmer than the prior year. The decrease in kilowatt-hour sales reflects in large part the effects of the warmer weather on heating related sales in addition to customer conservation. The slight decrease in Electric Utility revenues primarily reflects the lower sales partially offset by slightly higher transmission revenue. Electric Utility cost of sales decreased to $36.0 million in the 2015 six-month period from $38.1 million in the 2014 six-month period principally reflecting the effects of the lower total sales.
Electric Utility total margin increased slightly principally reflecting the increase in transmission revenue. Electric Utility operating income and income before income taxes in the 2015 six-month period were comparable to the prior-year period as the slight increase in total margin was offset by slightly higher operating, administrative and depreciation expense.
Interest Expense and Income Taxes

Our interest expense in the 2015 six-month period was higher than the prior year principally reflecting interest on the 4.98% Senior Notes due March 2044 issued in March 2014 the proceeds of which were used to refinance UGI Utilities’ 364-day Term Loan Credit Agreement. Our effective income tax rate for the six months ended March 31, 2015 was slightly lower than the prior-year six-month period.

FINANCIAL CONDITION AND LIQUIDITY

UGI Utilities’ total debt outstanding at March 31, 2015, was $672.5 million, which includes $30.5 million of short-term borrowings, compared with total debt outstanding of $728.3 million at September 30, 2014, which includes $86.3 million of short-term borrowings. Total long-term debt outstanding at March 31, 2015, comprises $450.0 million of Senior Notes and $192.0 million of Medium-Term Notes.

On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 million revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the Pennsylvania Public Utility Commission. The Company intends to seek such regulatory approval.
Borrowings under the UGI Utilities 2015 Credit Agreement and the predecessor credit agreement are classified as short-term borrowings on the Consolidated Balance Sheets. During the 2015 and 2014 six-month periods, average daily short-term borrowings were $108.9 million and $45.6 million, respectively, and peak short-term borrowings totaled $163.6 million and $84.0 million, respectively. At March 31, 2015, UGI Utilities’ available borrowing capacity under the UGI Utilities 2015 Credit Agreement was $267.5 million. Peak short-term borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is generally greatest.

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, short-term borrowings available under the UGI Utilities 2015 Credit Agreement and the ability to refinance long-term debt as it matures 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 greatest 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 Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $197.2 million in the 2015 six-month period compared to $123.2 million in the prior-year six-month period. Cash flow from operating activities before changes in operating working capital was $147.1 million in the 2015 six-month period comparable to the $171.7 million recorded in the prior-year six-month period. Changes in operating working capital used $50.0 million of operating cash flow during the 2015 six-month period compared to $48.5 million of cash used during

- 23 -

UGI UTILITIES, INC. AND SUBSIDIARIES


the prior-year six-month period. Among other things, cash flows from changes in operating working capital includes $55.8 million of cash flow from overcollections of gas costs under the PGC mechanism during the 2015 six-month period compared to undercollections of gas costs of $10.2 million during the prior-year period. The significantly higher overcollections in the current-year period reflects the impact of significant declines in natural gas prices.
  
Investing activities. Cash used by investing activities was $107.7 million in the 2015 six-month period compared to $65.7 million in the 2013 six-month period. Total cash capital expenditures were $102.0 million in the 2015 six-month period compared with $65.9 million recorded in the prior-year six-month period. The increase in the 2015 six-month period principally reflects higher Gas Utility growth and maintenance capital expenditures. Changes in restricted cash in futures brokerage accounts used $2.0 million of cash in the 2015 six-month period period compared with cash provided of $3.2 million in the prior-year period.

Financing activities. Cash used by financing activities was $85.8 million in the 2015 six-month period compared with $48.0 million in the 2014 six-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 2015 six-month period there were net Credit Agreement repayments of $55.8 million compared with net repayments of $11.0 million during the prior-year six-month period. The higher Credit Agreement repayments in the 2015 six-month period reflects the use of a portion of the previously mentioned increase in 2015 six-month period cash flow from operating activities. Cash dividends in the 2015 six-month period totaled $30.6 million compared to cash dividends of $37.7 million in the prior-year six-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.

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 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 our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At March 31, 2015 and 2014, the fair values of our natural gas futures and option contracts were gains (losses) of $(3.4) million and $2.4 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 FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At March 31, 2015 and 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1.2) million and $0.4 million, respectively. At March 31, 2015 and 2014, 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 net income.
At March 31, 2015, UGI Utilities had $5.6 million of restricted cash in commodity brokerage accounts. At March 31, 2014, UGI Utilities had no restricted cash in commodity brokerage accounts.
Interest Rate Risk

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 IRPAs. There were no unsettled IRPAs outstanding at March 31, 2015 and 2014.



- 24 -

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 or submitted 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 Principal 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 Principal 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 Principal 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.

- 25 -

UGI UTILITIES, INC. AND SUBSIDIARIES


PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the 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, 2014, 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
 
 
 
 
 
10.1
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2015.
 
 
 
 
 
 
 
 
10.2
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2015.
 
 
 
 
 
 
 
 
10.3
Credit Agreement, dated as of March 27, 2015 among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and Citizens Bank, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, Bank of America, N.A., and the other financial institutions from time to time parties thereto.
Utilities
Form 8-K
(3/27/15)
10.1
 
 
 
 
 
12.1
Computation of ratio of earnings to fixed charges
 
 
 
 
 
 
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
31.2
Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
32
Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, 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
 
 
 




- 26 -

UGI UTILITIES, INC. AND SUBSIDIARIES


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
UGI Utilities, Inc.
(Registrant)
 
Date:
May 8, 2015
By:  
/s/ Ann P. Kelly  
 
 
 
Ann P. Kelly
Controller (Principal Accounting Officer)


- 27 -

UGI UTILITIES, INC. AND SUBSIDIARIES


EXHIBIT INDEX

10.1
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2015.
 
 
10.2
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2015.
12.1
Computation of ratio of earnings to fixed charges.
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
31.2
Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32
Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, 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