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EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCex31212-31x14ugiutilities1.htm
EX-32 - EXHIBIT 32 - UGI UTILITIES INCex3212-31x14ugiutilities10q.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 December 31, 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 January 31, 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)
 
December 31,
2014
 
September 30,
2014
 
December 31,
2013
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
14,267

 
$
12,401

 
$
13,008

Restricted cash
8,963

 
3,592

 

Accounts receivable (less allowances for doubtful accounts of $6,764, $6,992 and $5,885, respectively)
116,454

 
65,080

 
111,840

Accounts receivable — related parties
2,901

 
2,865

 
9,431

Accrued utility revenues
52,743

 
14,330

 
66,370

Inventories
85,429

 
95,219

 
80,675

Deferred income taxes
1,600

 
1,492

 
12,317

Regulatory assets
16,773

 
13,159

 
361

Derivative instruments

 
1,028

 
2,058

Prepaid expenses & other current assets
19,052

 
18,535

 
14,649

Total current assets
318,182

 
227,701

 
310,709

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $897,802, $886,268 and $865,852, respectively)
1,727,117

 
1,682,284

 
1,594,554

Goodwill
182,145

 
182,145

 
182,145

Regulatory assets
253,826

 
255,007

 
233,636

Other assets
7,351

 
7,506

 
5,626

Total assets
$
2,488,621

 
$
2,354,643

 
$
2,326,670

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

 
$
20,000

 
$

Short-term borrowings
153,500

 
86,300

 
73,500

Accounts payable
65,574

 
58,453

 
60,405

Accounts payable — related parties
10,716

 
11,761

 
17,250

Derivative instruments
9,434

 
1,632

 
3,272

Other current liabilities
123,285

 
99,336

 
139,037

Total current liabilities
454,509

 
277,482

 
293,464

Long-term debt
550,000

 
622,000

 
642,000

Deferred income taxes
466,037

 
461,461

 
440,645

Deferred investment tax credits
3,849

 
3,933

 
4,185

Pension and postretirement benefit obligations
96,861

 
98,363

 
73,132

Derivative instruments
344

 

 

Other noncurrent liabilities
53,418

 
51,567

 
53,610

Total liabilities
1,625,018

 
1,514,806

 
1,507,036

Commitments and contingencies (Note 6)

 

 

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
471,076

 
471,071

 
470,189

Retained earnings
339,927

 
316,688

 
297,417

Accumulated other comprehensive loss
(7,659
)
 
(8,181
)
 
(8,231
)
Total common stockholder’s equity
863,603

 
839,837

 
819,634

Total liabilities and stockholder’s equity
$
2,488,621

 
$
2,354,643

 
$
2,326,670

See accompanying notes to condensed consolidated financial statements.

- 1 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
 
Three Months Ended
 
December 31,
 
2014
 
2013
Revenues
$
287,306

 
$
298,899

Costs and expenses:
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
143,052

 
151,865

Operating and administrative expenses
46,548

 
41,145

Operating and administrative expenses — related parties
2,782

 
1,843

Taxes other than income taxes
4,104

 
4,179

Depreciation
14,558

 
13,622

Amortization
867

 
828

Other operating income, net
(245
)
 
(426
)
 
211,666

 
213,056

Operating income
75,640

 
85,843

Interest expense
10,649

 
8,797

Income before income taxes
64,991

 
77,046

Income taxes
26,152

 
31,760

Net income
$
38,839

 
$
45,286

See accompanying notes to condensed consolidated financial statements.











- 2 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Thousands of dollars)
 
Three Months Ended December 31,
 
2014
 
2013
Net income
$
38,839

 
$
45,286

Other comprehensive income:
 
 
 
Reclassifications of net losses on derivative instruments (net of tax of $(278) and $(278), respectively)
391

 
391

Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(91) and $(70), respectively)
131

 
98

Other comprehensive income
522

 
489

Comprehensive income
$
39,361

 
$
45,775

See accompanying notes to condensed consolidated financial statements.


- 3 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
 
Three Months Ended
 
December 31,
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
38,839

 
$
45,286

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
15,425

 
14,450

Deferred income taxes, net
3,921

 
5,157

Provision for uncollectible accounts
2,490

 
2,249

Other, net
3,534

 
(124
)
Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(92,313
)
 
(114,184
)
Inventories
9,790

 
8,985

Deferred fuel and power costs, net of changes in unsettled derivatives
4,393

 
2,086

Accounts payable
6,075

 
13,198

Other current assets
(4,821
)
 
802

Other current liabilities
25,356

 
24,405

Net cash provided by operating activities
12,689

 
2,310

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(55,029
)
 
(34,254
)
Net costs of property, plant and equipment disposals
(2,028
)
 
(1,491
)
(Increase) decrease in restricted cash
(5,371
)
 
3,181

Net cash used by investing activities
(62,428
)
 
(32,564
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(15,600
)
 
(17,536
)
Increase in short-term borrowings
67,200

 
56,000

Other
5

 
91

Net cash provided by financing activities
51,605

 
38,555

Cash and cash equivalents increase
$
1,866

 
$
8,301

CASH AND CASH EQUIVALENTS:
 
 
 
End of period
$
14,267

 
$
13,008

Beginning of period
12,401

 
4,707

Increase
$
1,866

 
$
8,301

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

Extraordinary Items. In January 2015, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance which eliminates the concept of an extraordinary item. Under current accounting guidance, to be considered an extraordinary item an event or transaction must be both unusual in nature and must occur infrequently. Under the new guidance, the concept of an extraordinary item has been eliminated. As a result, an entity will no longer be permitted to segregate an extraordinary item from its results of operations; present an extraordinary item, net of tax, after income from continuing operations; or disclose earnings per share data applicable to an extraordinary item. The new guidance does not affect, however, the reporting and disclosure requirements for an event that is unusual in nature or that occurs infrequently. The guidance is effective for annual periods beginning after December 31, 2015 and interim periods within those annual periods. Early adoption is permitted. Entities may apply the guidance prospectively or retrospectively. If an entity chooses to apply the new guidance prospectively, it must disclose whether amounts included in income from continuing operations include items that would have qualified as extraordinary items previously. We expect to adopt the new guidance in Fiscal 2017.


- 5 -

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


Revenue Recognition. In May 2014, the 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 (“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 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.

Note 4 — Inventories
Inventories comprise the following:
 
December 31, 2014
 
September 30, 2014
 
December 31, 2013
Gas Utility natural gas
$
72,442

 
$
82,664

 
$
69,117

Materials, supplies and other
12,987

 
12,555

 
11,558

Total inventories
$
85,429

 
$
95,219

 
$
80,675


At December 31, 2014, UGI Utilities is a party to four principal 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 11) 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 December 31, 2014, September 30, 2014 and December 31, 2013, comprising 9.9 billion cubic feet (“bcf”), 11.6 bcf and 9.8 bcf of natural gas, was $41,937, $49,897 and $39,362, respectively. At December 31, 2014, September 30, 2014 and December 31, 2013, UGI Utilities held a total of $17,600 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:
 
December 31, 2014
 
September 30, 2014
 
December 31, 2013
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
111,075

 
$
110,709

 
$
106,435

Underfunded pension and postretirement plans
107,827

 
110,116

 
92,755

Environmental costs
14,738

 
14,616

 
14,910

Deferred fuel and power costs
16,761

 
11,732

 
427

Removal costs, net
17,550

 
16,790

 
13,748

Other
2,648

 
4,203

 
5,722

Total regulatory assets
$
270,599

 
$
268,166

 
$
233,997

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
18,959

 
$
18,594

 
$
16,846

Environmental overcollections
179

 
349

 
2,329

Deferred fuel and power refunds

 
306

 
7,524

State tax benefits — distribution system repairs
10,349

 
10,076

 
8,725

Other
3,401

 
3,172

 
1,332

Total regulatory liabilities (a)
$
32,888

 
$
32,497

 
$
36,756


(a) Regulatory liabilities 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 December 31, 2014, September 30, 2014, and December 31, 2013, were $(6,798), $(1,363) and $1,968, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because we have chosen not to elect the normal purchase and normal sales exception under GAAP related to these derivative instruments, 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 December 31, 2014, September 30, 2014, and December 31, 2013, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(2,397), $345 and $(3,182), respectively. These amounts are reflected in current derivative assets and current 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.

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

- 7 -

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


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 December 31, 2014, September 30, 2014, and December 31, 2013, were not material.
    
Note 6 — 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 December 31, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,233 and $12,147, respectively. We have recorded associated regulatory assets in equal amounts because recovery of these costs from CPG 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 December 31, 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. 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.


- 8 -

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


Note 7 — 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 December 31,
 
2014
 
2013
 
2014
 
2013
Service cost
 
$
1,741

 
$
1,623

 
$
48

 
$
41

Interest cost
 
5,627

 
5,721

 
119

 
127

Expected return on assets
 
(7,224
)
 
(6,650
)
 
(153
)
 
(139
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
87

 
87

 
(160
)
 
(160
)
Actuarial loss
 
2,198

 
1,661

 
32

 
37

Net benefit cost (income)
 
2,429

 
2,442

 
(114
)
 
(94
)
Change in associated regulatory liabilities
 

 

 
937

 
918

Net benefit cost after change in regulatory liabilities
 
$
2,429

 
$
2,442

 
$
823

 
$
824


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. During the three months ended December 31, 2014 and 2013, the Company made contributions to the Pension Plan of $2,783 and $3,486, respectively. The Company expects to make additional discretionary cash contributions of $8,349 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 three months ended December 31, 2014 and 2013.

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


- 9 -

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


Note 8 — 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 December 31, 2014, September 30, 2014 and December 31, 2013:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
December 31, 2014:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$

 
$
177

 
$

 
$
177

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(7,355
)
 
$
(2,600
)
 
$

 
$
(9,955
)
September 30, 2014:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
679

 
$
1,018

 
$

 
$
1,697

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

 
$
(2,301
)
December 31, 2013 (a):
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2,130

 
$

 
$

 
$
2,130

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(338
)
 
$
(3,006
)
 
$

 
$
(3,344
)

(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 December 31, 2014, were $642,000 and $741,853, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at December 31, 2013, were $642,000 and $694,220, 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).


- 10 -

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


Note 9 — 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 December 31, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.2 million dekatherms and 9.7 million dekatherms, respectively. At December 31, 2014, the maximum period over which Gas Utility is economically 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 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. Because we have chosen not to elect the normal purchase and normal sales exception under GAAP related to these derivative instruments, the fair values of these contracts are reflected in current and noncurrent derivative instrument 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). At December 31, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 486.2 million kilowatt hours and 324.4 million kilowatt hours, respectively. At December 31, 2014, the maximum period over which these contracts extend is 17 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 December 31, 2014 and 2013, the total volumes associated with FTRs totaled 144.6 million kilowatt hours and 117.9 million kilowatt hours, respectively. At December 31, 2014, the maximum period over which we are economically hedging electricity congestion is 5 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment.

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 December 31, 2014 and 2013, we had no unsettled IRPAs. At December 31, 2014, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,670.

- 11 -

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


Derivative Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2014, restricted cash in brokerage accounts totaled $8,963. At December 31, 2013, 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 December 31, 2014 and 2013:
 
 
December 31, 2014
 
December 31, 2013 (a)
Derivative assets:
 
 
 
 
Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
$
177

 
$
2,041

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 

 
89

Total derivative assets
 
$
177

 
$
2,130

Derivative liabilities:
 
 
 
 
Derivatives subject to utility rate regulation:
 
 

 
 

Commodity contracts
 
$
(9,398
)
 
$
(3,344
)
Derivatives not designated as hedging instruments:
 
 

 
 

Commodity contracts
 
(557
)
 

Total derivative liabilities
 
$
(9,955
)
 
$
(3,344
)

(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.


- 12 -

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 December 31, 2014 and 2013:
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in Balance Sheet
 
Net Amounts Recognized
 
Cash Collateral (Received) Pledged
 
Net Amounts Recognized in Balance Sheet
December 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
177

 
$
(177
)
 
$

 
$

 
$

Derivative liabilities
 
$
(9,955
)
 
$
177

 
$
(9,778
)
 
$

 
$
(9,778
)
December 31, 2013
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
2,130

 
$
(72
)
 
$
2,058

 
$

 
$
2,058

Derivative liabilities
 
$
(3,344
)
 
$
72

 
$
(3,272
)
 
$

 
$
(3,272
)

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 months ended December 31, 2014 and 2013:
 
 
Gain (Loss) Recognized in AOCI
 
Gain (Loss) Reclassified from AOCI into Income
 
Location of Gain
(Loss) Reclassified from AOCI into Income
Three Months Ended December 31,
 
2014
 
2013
 
2014
 
2013
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$

 
$
(669
)
 
$
(669
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Three Months Ended December 31,
 
2014
 
2013
 
 
 
 
 
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(522
)
 
$
97

 
Operating expenses/other operating income, net
 
 
 
 

The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

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 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.


- 13 -

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


Note 10 — Accumulated Other Comprehensive Income

The table below presents changes in AOCI, net of tax, during the three months ended December 31, 2014 and 2013:
 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Three Months Ended December 31, 2014
 
 
 
 
 
 
AOCI - September 30, 2014
 
$
(6,311
)
 
$
(1,870
)
 
$
(8,181
)
Reclassification of benefit plan actuarial losses and prior service cost
 
131

 

 
131

Reclassifications of net losses on interest rate protection agreements
 

 
391

 
391

AOCI - December 31, 2014
 
$
(6,180
)
 
$
(1,479
)
 
$
(7,659
)
Three Months Ended December 31, 2013
 
 
 
 
 
 
AOCI - September 30, 2013
 
$
(5,283
)
 
$
(3,437
)
 
$
(8,720
)
Reclassification of benefit plan actuarial losses and prior service cost
 
98

 

 
98

Reclassifications of net losses on interest rate protection agreements
 

 
391

 
391

AOCI - December 31, 2013
 
$
(5,185
)
 
$
(3,046
)
 
$
(8,231
)

Note 11 — 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 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 $4,956 and $6,448 during the three months ended December 31, 2014 and 2013, 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 $10,600 as of December 31, 2014, September 30, 2014 and December 31, 2013, 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 December 31, 2014, September 30, 2014 and December 31, 2013, comprising 6.5 bcf, 7.7 bcf and 6.8 bcf of natural gas, was $27,501, $33,057 and $27,052, 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 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 months ended December 31, 2014 and 2013, totaled $23,747 and $19,378, respectively.


- 14 -

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


From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2014 and 2013, revenues associated with such sales to Energy Services totaled $16,190 and $17,116, 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 months ended December 31, 2014 and 2013, such purchases totaled $21,775 and $22,078, respectively.

Note 12 — 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.


- 15 -

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


Financial information by business segment follows:
Three Months Ended December 31, 2014:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
287,306

 
$
260,478

 
$
26,423

 
$
405

Cost of sales
$
143,052

 
$
127,208

 
$
15,844

 
$

Depreciation and amortization
$
15,425

 
$
14,280

 
$
1,145

 
$

Operating income
$
75,640

 
$
71,846

 
$
3,719

 
$
75

Interest expense
$
10,649

 
$
10,130

 
$
519

 
$

Income before income taxes
$
64,991

 
$
61,716

 
$
3,200

 
$
75

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,488,621

 
$
2,346,169

 
$
142,452

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$

Capital expenditures
$
55,029

 
$
53,492

 
$
1,537

 
$


Three Months Ended December 31, 2013:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
298,899

 
$
271,562

 
$
26,961

 
$
376

Cost of sales
$
151,865

 
$
135,487

 
$
16,378

 
$

Depreciation and amortization
$
14,450

 
$
13,384

 
$
1,066

 
$

Operating income
$
85,843

 
$
82,053

 
$
3,689

 
$
101

Interest expense
$
8,797

 
$
8,386

 
$
411

 
$

Income before income taxes
$
77,046

 
$
73,667

 
$
3,278

 
$
101

 
 
 
 
 
 
 
 
Total assets (at period end)
$
2,326,670

 
$
2,188,623

 
$
138,047

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$

Capital expenditures
$
34,254

 
$
32,812

 
$
1,442

 
$



- 16 -

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.


- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES


ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended December 31, 2014 (“2014 three-month period”) with the three months ended December 31, 2013 (“2013 three-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 12 to the condensed consolidated financial statements.

2014 three-month period compared with 2013 three-month period
Three Months Ended December 31,
 
2014
 
2013
 
Increase (Decrease)
(Millions of dollars)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
260.5

 
$
271.6

 
$
(11.1
)
 
(4.1
)%
Total margin (a)
 
$
133.3

 
$
136.1

 
$
(2.8
)
 
(2.1
)%
Operating income
 
$
71.8

 
$
82.1

 
$
(10.3
)
 
(12.5
)%
Income before income taxes
 
$
61.7

 
$
73.7

 
$
(12.0
)
 
(16.3
)%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
23.2

 
24.1

 
(0.9
)
 
(3.7
)%
Total
 
56.8

 
56.7

 
0.1

 
0.2
 %
Heating degree days — % (warmer) colder than normal (b)
 
(3.9
)%
 
3.0
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
26.4

 
$
27.0

 
$
(0.6
)
 
(2.2
)%
Total margin (a)
 
$
9.2

 
$
9.1

 
$
0.1

 
1.1
 %
Operating income
 
$
3.7

 
$
3.7

 
$

 
 %
Income before income taxes
 
$
3.2

 
$
3.3

 
$
(0.1
)
 
(3.0
)%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
244.8

 
256.3

 
(11.5
)
 
(4.5
)%

(a)
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.4 million and $1.5 million during the three months ended December 31, 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 Gas Utility’s service territory in the 2014 three-month period based upon heating degree days were 3.9% warmer than normal and 6.8% warmer than the 2013 three-month period. Although core market throughput was slightly lower than the prior-year period from the warmer weather, total distribution system throughput in the 2014 three-month period was about equal with the prior-year period principally reflecting slightly higher large firm delivery service volumes and 1.9% 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 $11.1 million during the 2014 three-month period principally reflecting lower revenues from core market customers ($8.0 million) and lower revenues from off-system sales ($2.9 million).The decrease in core market revenues principally reflects the effects of the lower core market throughput and slightly lower average PGC rates during the 2014 three-month period. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. 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 on retail core-market margin. Gas Utility’s cost of sales was $127.2 million in the 2014 three-month period compared with $135.5 million in the 2013 three-month period principally reflecting the effects of the lower retail core-market volumes sold ($4.8 million) and the lower off-system sales ($2.9 million).

- 18 -

UGI UTILITIES, INC. AND SUBSIDIARIES



Gas Utility 2014 three-month period total margin decreased $2.8 million principally reflecting lower core market total margin ($2.9 million). The lower core market total margin reflects the effects of the previously mentioned warmer weather on heating related sales partially offset by customer growth.

Gas Utility operating income and income before income taxes during the 2014 three-month period decreased $10.3 million and $12.0 million, respectively, over the 2013 three-month period. The decrease in Gas Utility operating income principally reflects the $2.8 million decrease in total margin and higher operating, administrative and depreciation expenses. These expenses were modestly higher than the prior year principally reflecting, among other things, higher 2014 three-month period distribution system maintenance expenses ($2.9 million), higher depreciation expense ($0.9 million) and higher employee benefit and information technology expenses. The decrease in Gas Utility income before income taxes reflects the lower operating income ($10.3 million) and higher interest expense.

Electric Utility

Temperatures based upon heating degree days during the 2014 three-month period were approximately 8.5% warmer than normal and approximately 8.6% 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. The slight decrease in Electric Utility revenues primarily reflects the lower sales partially offset by slightly higher average DS rates and higher transmission revenue. Electric Utility cost of sales decreased to $15.8 million in the 2014 three-month period from $16.4 million in the 2013 three-month period principally reflecting the effects of the lower total sales partially offset by the slightly higher DS rates.

Electric Utility total margin, operating income and income before income taxes in the 2014 three-month period were comparable to the prior-year period.

Interest Expense and Income Taxes

Our interest expense in the 2014 three-month period was higher than the prior year principally reflecting interest on the 4.98% Senior Notes 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 December 31, 2014 was comparable with the prior-year three-month period.

FINANCIAL CONDITION AND LIQUIDITY

UGI Utilities’ total debt outstanding at December 31, 2014, was $795.5 million, which includes $153.5 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 December 31, 2014, comprises $450.0 million of Senior Notes and $192.0 million of Medium-Term Notes.

UGI Utilities has a credit agreement (“Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit) which expires in October 2015. We expect to renew the Credit Agreement prior to its expiration. Borrowings under the Credit Agreement are classified as short-term borrowings on the Consolidated Balance Sheets. During the 2014 and 2013 three-month periods, average daily short-term borrowings were $115.7 million and $53.0 million, respectively, and peak short-term borrowings totaled $163.6 million and $84.0 million, respectively. At December 31, 2014, UGI Utilities’ available borrowing capacity under the Credit Agreement was $144.5 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 Credit Agreement and the ability to refinance long-term debt as it matures to meet our anticipated contractual and projected cash commitments.


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UGI UTILITIES, INC. AND SUBSIDIARIES


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 $12.7 million in the 2014 three-month period compared to $2.3 million in the prior-year three-month period. Cash flow from operating activities before changes in operating working capital was $64.2 million in the 2014 three-month period comparable to the $67.0 million recorded in the prior-year three-month period. Changes in operating working capital used $51.5 million of operating cash flow during the 2014 three-month period compared to $64.7 million of cash used during the prior-year three-month period.
  
Investing activities. Cash used by investing activities was $62.4 million in the 2014 three-month period compared to $32.6 million in the 2013 three-month period. Total cash capital expenditures were $55.0 million in the 2014 three-month period compared with $34.3 million recorded in the prior-year three-month period. The increase in the 2014 three-month period principally reflects higher Gas Utility growth capital expenditures. Changes in restricted cash in futures brokerage accounts used $5.4 million of cash in the 2014 three-month period period compared with cash provided of $3.2 million in the prior-year period.

Financing activities. Cash provided by financing activities was $51.6 million in the 2014 three-month period compared with $38.6 million in the 2013 three-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 three-month period there were net Credit Agreement borrowings of $67.2 million compared with net borrowings of $56.0 million during the prior-year three-month period. Cash dividends in the 2014 three-month period totaled $15.6 million compared to cash dividends of $17.6 million in the prior-year three-month period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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 December 31, 2014 and 2013, the fair values of our natural gas futures and option contracts were gains (losses) of $(6.8) million and $2.0 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 December 31, 2014 and 2013, the fair values of Electric Utility’s electricity supply contracts were losses of $(2.4) million and $(3.2) million, respectively. At December 31, 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 net income.
At December 31, 2014, UGI Utilities had $9.0 million of restricted cash in commodity brokerage accounts. At December 31, 2013, UGI Utilities had no restricted cash in commodity brokerage accounts.


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UGI UTILITIES, INC. AND SUBSIDIARIES


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 December 31, 2014 and 2013.

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 Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

(b)
Change in Internal Control over Financial Reporting

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

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UGI UTILITIES, INC. AND SUBSIDIARIES


PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the 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
 
 
 
 
 
12.1
Computation of ratio of earnings to fixed charges
 
 
 
 
 
 
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 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 December 31, 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 December 31, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
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101.LAB
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101.PRE
XBRL Taxonomy Extension Presentation Linkbase
 
 
 




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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:
February 6, 2015
By:  
/s/ Donald E. Brown  
 
 
 
Donald E. Brown
Vice President - Finance and
Chief Financial Officer  (Principal Accounting Officer)


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UGI UTILITIES, INC. AND SUBSIDIARIES


EXHIBIT INDEX

12.1
Computation of ratio of earnings to fixed charges.
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 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 December 31, 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 December 31, 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