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EX-12 - EXHIBIT 12 - UGI UTILITIES INCex12112-31x15ugiutilities1.htm
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCex31212-31x15ugiutilities1.htm
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INCex31112-31x15ugiutilities1.htm
EX-32 - EXHIBIT 32 - UGI UTILITIES INCex3212-31x15ugiutilities10q.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 December 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 January 31, 2016, 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,
2015
 
September 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
15,585

 
$
3,099

 
$
14,267

Restricted cash
6,324

 
6,602

 
8,963

Accounts receivable (less allowances for doubtful accounts of $5,283, $5,599 and $6,764, respectively)
78,954

 
55,659

 
116,454

Accounts receivable — related parties
2,671

 
1,271

 
2,901

Accrued utility revenues
30,776

 
12,051

 
52,743

Inventories
49,365

 
51,716

 
85,429

Deferred income taxes

 
24,694

 
1,600

Income taxes receivable
31,465

 
10,026

 

Regulatory assets
3,905

 
4,105

 
16,773

Derivative instruments
234

 
934

 

Prepaid expenses & other current assets
28,670

 
23,903

 
19,052

Total current assets
247,949

 
194,060

 
318,182

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $940,655, $929,130 and $897,802, respectively)
1,870,732

 
1,824,369

 
1,727,117

Goodwill
182,145

 
182,145

 
182,145

Regulatory assets
297,914

 
300,103

 
253,826

Other assets
7,559

 
7,501

 
7,351

Total assets
$
2,606,299

 
$
2,508,178

 
$
2,488,621

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Current maturities of long-term debt
$
175,000

 
$
247,000

 
$
92,000

Short-term borrowings
217,700

 
71,700

 
153,500

Accounts payable
51,954

 
58,135

 
65,574

Accounts payable — related parties
7,069

 
4,430

 
10,716

Regulatory liability — deferred fuel refunds
28,083

 
36,638

 

Derivative instruments
10,351

 
12,591

 
9,434

Other current liabilities
112,528

 
103,265

 
123,285

Total current liabilities
602,685

 
533,759

 
454,509

Long-term debt
375,000

 
375,000

 
550,000

Deferred income taxes
524,287

 
512,497

 
466,037

Deferred investment tax credits
3,513

 
3,597

 
3,849

Pension and postretirement benefit obligations
132,899

 
135,003

 
96,861

Derivative instruments

 

 
344

Other noncurrent liabilities
58,469

 
57,702

 
53,418

Total liabilities
1,696,853

 
1,617,558

 
1,625,018

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
471,952

 
471,904

 
471,076

Retained earnings
388,494

 
372,143

 
339,927

Accumulated other comprehensive loss
(11,259
)
 
(13,686
)
 
(7,659
)
Total common stockholder’s equity
909,446

 
890,620

 
863,603

Total liabilities and stockholder’s equity
$
2,606,299

 
$
2,508,178

 
$
2,488,621

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,
 
2015
 
2014
Revenues
$
197,982

 
$
287,306

Costs and expenses:
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
75,439

 
143,052

Operating and administrative expenses
48,027

 
46,548

Operating and administrative expenses — related parties
2,180

 
2,782

Taxes other than income taxes
3,769

 
4,104

Depreciation
15,827

 
14,558

Amortization
874

 
867

Other operating loss (income), net
3,570

 
(245
)
 
149,686

 
211,666

Operating income
48,296

 
75,640

Interest expense
9,494

 
10,649

Income before income taxes
38,802

 
64,991

Income taxes
15,451

 
26,152

Net income
$
23,351

 
$
38,839

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,
 
2015
 
2014
Net income
$
23,351

 
$
38,839

Other comprehensive income:
 
 
 
Net gains on derivative instruments (net of tax of $(1,332) and $0, respectively)
1,877

 

Reclassifications of net losses on derivative instruments (net of tax of $(276) and $(278), respectively)
390

 
391

Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(113) and $(91), respectively)
160

 
131

Other comprehensive income
2,427

 
522

Comprehensive income
$
25,778

 
$
39,361

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,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
23,351

 
$
38,839

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
16,701

 
15,425

Deferred income taxes, net
15,607

 
3,921

Provision for uncollectible accounts
1,930

 
2,490

Other, net
4,331

 
3,534

Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(46,757
)
 
(92,313
)
Inventories
2,351

 
9,790

Deferred fuel and power costs, net of changes in unsettled derivatives
(6,788
)
 
4,393

Accounts payable
(3,642
)
 
6,075

Other current assets
(4,767
)
 
(4,821
)
Other current liabilities
6,449

 
25,356

Net cash provided by operating activities
8,766

 
12,689

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(60,457
)
 
(55,029
)
Net costs of property, plant and equipment disposals
(3,150
)
 
(2,028
)
Decrease (increase) in restricted cash
278

 
(5,371
)
Net cash used by investing activities
(63,329
)
 
(62,428
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(7,000
)
 
(15,600
)
Repayments of long-term debt
(72,000
)
 

Increase in short-term borrowings
146,000

 
67,200

Other
49

 
5

Net cash provided by financing activities
67,049

 
51,605

Cash and cash equivalents increase
$
12,486

 
$
1,866

CASH AND CASH EQUIVALENTS:
 
 
 
End of period
$
15,585

 
$
14,267

Beginning of period
3,099

 
12,401

Increase
$
12,486

 
$
1,866

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.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operated principally in the PNG service territory (“HVAC Business”). The assets of the HVAC business principally comprising customer contracts were sold on June 1, 2015.

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 all significant intercompany accounts when we consolidate.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2015, 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, 2015 (“the Company’s 2015 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.
Derivative Instruments
Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP and such exception has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting.
Gains and losses on substantially all of the derivative instruments used by Gas Utility and Electric Utility to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 9.

- 5 -

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



Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation.

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

Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as such, prior period amounts were not retrospectively adjusted.

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 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

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”) No. 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 entity expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.

Note 4 — Inventories
Inventories comprise the following:
 
December 31, 2015
 
September 30, 2015
 
December 31, 2014
Gas Utility natural gas
$
35,923

 
$
37,510

 
$
72,442

Materials, supplies and other
13,442

 
14,206

 
12,987

Total inventories
$
49,365

 
$
51,716

 
$
85,429


At December 31, 2015, UGI Utilities is a party to two principal storage contract administrative agreements (“SCAAs”) having terms of three years. One of the SCAAs is with UGI 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

- 6 -

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


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, 2015, September 30, 2015 and December 31, 2014, comprising 8.9 billion cubic feet (“bcf”), 9.0 bcf and 9.9 bcf of natural gas, was $22,061, $22,694 and $41,937, respectively. At December 31, 2015, September 30, 2015 and December 31, 2014, UGI Utilities held a total of $15,100, $17,700 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.
For additional information related to the SCAAs with Energy Services, see Note 11.

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 2015 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, 2015
 
September 30, 2015
 
December 31, 2014
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
117,396

 
$
115,946

 
$
111,075

Underfunded pension and postretirement plans
138,294

 
140,762

 
107,827

Environmental costs
17,643

 
19,983

 
14,738

Deferred fuel and power costs

 

 
16,761

Removal costs, net
22,346

 
21,223

 
17,550

Other
6,140

 
6,294

 
2,648

Total regulatory assets
$
301,819

 
$
304,208

 
$
270,599

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
20,314

 
$
19,975

 
$
18,959

Deferred fuel and power refunds
28,083

 
36,638

 

State tax benefits — distribution system repairs
13,712

 
13,266

 
10,349

Other
1,073

 
1,125

 
3,580

Total regulatory liabilities (a)
$
63,182

 
$
71,004

 
$
32,888


(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 December 31, 2015, September 30, 2015, and December 31, 2014, were $(4,488), $(3,262) and $(6,798), respectively.


- 7 -

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


Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not elect the NPNS exception under GAAP for these contracts. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At December 31, 2015, September 30, 2015, and December 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(450), $(533) and $(2,397), 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 contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (see Note 9).

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 December 31, 2015, September 30, 2015, and December 31, 2014, were not material.

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58,600 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities is requesting that the new gas rates become effective March 19, 2016. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last approximately nine months, however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

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, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,679 and $11,233, 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. 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

- 8 -

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


proceedings, a five-year average of such prudently incurred remediation costs, and (2) CPG and PNG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At December 31, 2015, 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.

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 include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended December 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
1,732

 
$
1,741

 
$
46

 
$
48

Interest cost
 
5,817

 
5,627

 
116

 
119

Expected return on assets
 
(7,167
)
 
(7,224
)
 
(149
)
 
(153
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
87

 
87

 
(160
)
 
(160
)
Actuarial loss
 
2,393

 
2,198

 
24

 
32

Net benefit cost (income)
 
2,862

 
2,429

 
(123
)
 
(114
)
Change in associated regulatory liabilities
 

 

 
878

 
937

Net benefit cost after change in regulatory liabilities
 
$
2,862

 
$
2,429

 
$
755

 
$
823


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 three months ended December 31, 2015 and 2014, the Company made contributions to the Pension Plan of $2,467 and $2,783, respectively. The Company expects to make additional discretionary cash contributions of approximately $7,400 to the Pension Plan during the remainder of Fiscal 2016.

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 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, 2015 and 2014.


- 9 -

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


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.

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, 2015, September 30, 2015 and December 31, 2014:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
December 31, 2015:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
234

 
$

 
$

 
$
234

Interest rate contracts
$

 
$
572

 
$

 
$
572

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(4,986
)
 
$
(1,557
)
 
$

 
$
(6,543
)
Interest rate contracts
$

 
$
(4,380
)
 
$

 
$
(4,380
)
September 30, 2015:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
934

 
$
373

 
$

 
$
1,307

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(4,560
)
 
$
(1,388
)
 
$

 
$
(5,948
)
Interest rate contracts
$

 
$
(7,016
)
 
$

 
$
(7,016
)
December 31, 2014:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$

 
$
177

 
$

 
$
177

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

 
$
(9,955
)

The fair values of our Level 1 exchange-traded commodity futures and option derivative 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, 2015, were $550,000 and $615,213, respectively. 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. 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).

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

- 10 -

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


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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.4 million dekatherms and 11.2 million dekatherms, respectively. At December 31, 2015, 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. For such contracts entered into 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 has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At December 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 333.3 million kilowatt hours and 486.2 million kilowatt hours, respectively. At December 31, 2015, the maximum period over which these contracts extend is 11 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, 2015 and 2014, the total volumes associated with FTRs totaled 172.6 million kilowatt hours and 144.6 million kilowatt hours, respectively. At December 31, 2015, 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, 2015, the notional amount of our unsettled IRPA contracts was $290,000. At December 31, 2014, we had no unsettled IRPAs. Our December 31, 2015, unsettled IRPA contracts hedge forecasted interest payments expected to occur over ten- and thirty-year periods beginning in Fiscal 2016. At December 31, 2015, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is approximately $2,200.


- 11 -

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


Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2015 and 2014, restricted cash in brokerage accounts totaled $6,324 and $8,963, respectively.

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.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2015 and 2014:

 
 
December 31, 2015
 
December 31, 2014
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Interest rate contracts
 
$
572

 
$

Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
234

 
177

Total derivative assets - gross
 
806

 
177

Gross amounts offset in the balance sheet
 
(572
)
 
(177
)
Total derivative assets - net
 
$
234

 
$

 
 
 
 
 
Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Interest rate contracts
 
$
(4,380
)
 
$

Derivatives subject to PGC and DS mechanisms:
 
 

 
 

Commodity contracts
 
(6,278
)
 
(9,398
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 

Commodity contracts
 
(265
)
 
(557
)
Total derivative liabilities - gross
 
(10,923
)
 
(9,955
)
Gross amounts offset in the balance sheet
 
572

 
177

Total derivative liabilities - net
 
$
(10,351
)
 
$
(9,778
)


- 12 -

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


Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 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 December 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$
3,209

 
$

 
$
(666
)
 
$
(669
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Three Months Ended December 31,
 
2015
 
2014
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(65
)
 
$
(522
)
 
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 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 10 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2015 and 2014:
 
 
 
 
 
 
 
 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Three Months Ended December 31, 2015
 
 
 
 
 
 
AOCI - September 30, 2015
 
$
(9,276
)
 
$
(4,410
)
 
$
(13,686
)
Net gains on IRPAs
 

 
1,877

 
1,877

Reclassifications of benefit plan actuarial losses and prior service costs
 
160

 

 
160

Reclassifications of net losses on IRPAs
 

 
390

 
390

AOCI - December 31, 2015
 
$
(9,116
)
 
$
(2,143
)
 
$
(11,259
)
Three Months Ended December 31, 2014
 
 
 
 
 
 
AOCI - September 30, 2014
 
$
(6,311
)
 
$
(1,870
)
 
$
(8,181
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
131

 

 
131

Reclassifications of net losses on IRPAs
 

 
391

 
391

AOCI - December 31, 2014
 
$
(6,180
)
 
$
(1,479
)
 
$
(7,659
)

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

- 13 -

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


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 under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) 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 $1,870 and $4,956 during the three months ended December 31, 2015 and 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 $8,100, $10,700, and $10,600 as of December 31, 2015, September 30, 2015 and December 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 December 31, 2015, September 30, 2015 and December 31, 2014, comprising approximately 5.1 bcf, 5.0 bcf and 6.5 bcf of natural gas, were $12,684, $12,889 and $27,501, 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 primarily 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, 2015 and 2014 totaled $27,364 and $23,747, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2015 and 2014, revenues associated with such sales to Energy Services totaled $8,766 and $16,190, 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, 2015 and 2014, such purchases totaled $8,192 and $21,775, 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, prior to its sale in June 2015, did 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 2015 Annual Report. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

- 14 -

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, 2015:
 
 
 
Reportable Segments
 
 
Total
 
Gas Utility
 
Electric Utility
 
Revenues
$
197,982

 
$
176,942

 
$
21,040

 
Cost of sales
$
75,439

 
$
64,229

 
$
11,210

 
Depreciation and amortization
$
16,701

 
$
15,504

 
$
1,197

 
Operating income
$
48,296

 
$
45,820

 
$
2,476

 
Interest expense
$
9,494

 
$
9,066

 
$
428

 
Income before income taxes
$
38,802

 
$
36,754

 
$
2,048

 
Capital expenditures
$
61,464

 
$
59,270

 
$
2,194

 
 
 
 
 
 
 
 
As of December 31, 2015
 
 
 
 
 
 
Total assets (at period end)
$
2,606,299

 
$
2,462,508

 
$
143,791

 
Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 

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

Capital expenditures
$
55,029

 
$
53,492

 
$
1,537

 
$

 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
Total assets (at period end)
$
2,488,621

 
$
2,346,169

 
$
142,452

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$



- 15 -

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 2015 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.


- 16 -

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, 2015 (“2015 three-month period”) with the three months ended December 31, 2014 (“2014 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.

2015 three-month period compared with 2014 three-month period
Three Months Ended December 31,
 
2015
 
2014
 
Increase (Decrease)
 
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
176.9

 
$
260.5

 
$
(83.6
)
 
(32.1
)%
Total margin (a)
 
$
112.7

 
$
133.3

 
$
(20.6
)
 
(15.5
)%
Operating and administrative expenses
 
$
45.4

 
$
45.0

 
$
0.4

 
0.9
 %
Operating income
 
$
45.8

 
$
71.8

 
$
(26.0
)
 
(36.2
)%
Income before income taxes
 
$
36.8

 
$
61.7

 
$
(24.9
)
 
(40.4
)%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
17.4

 
23.2

 
(5.8
)
 
(25.0
)%
Total
 
49.9

 
56.8

 
(6.9
)
 
(12.1
)%
Heating degree days — % (warmer) than normal (b)
 
(25.3
)%
 
(3.1
)%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
21.0

 
$
26.4

 
$
(5.4
)
 
(20.5
)%
Total margin (a)
 
$
8.7

 
$
9.2

 
$
(0.5
)
 
(5.4
)%
Operating and administrative expenses
 
$
4.8

 
$
4.0

 
$
0.8

 
20.0
 %
Operating income
 
$
2.5

 
$
3.7

 
$
(1.2
)
 
(32.4
)%
Income before income taxes
 
$
2.0

 
$
3.2

 
$
(1.2
)
 
(37.5
)%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
225.0

 
244.8

 
(19.8
)
 
(8.1
)%

(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 $1.1 million and $1.4 million during the three months ended December 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 2000-2014 based upon weather statistics provided by the National Oceanic and Atmospheric Administration for airports located within Gas Utility’s service territory.

Gas Utility

Temperatures in Gas Utility’s service territory in the 2015 three-month period based upon heating degree days were 25.3% warmer than normal and 22.9% warmer than the 2014 three-month period. In particular, temperatures in the critical heating-season month of December were 37% warmer than normal. Total Gas Utility distribution system throughput decreased 6.9 bcf (12.1%) principally reflecting lower core market volumes and, to a lesser extent, slightly lower delivery service volumes. Core market volumes declined 25% reflecting the effects of the significantly warmer weather. 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.
The lower Gas Utility revenues principally reflect a decrease in core market revenues ($72.0 million), lower off-system sales revenues ($9.3 million), and lower delivery service revenues. The decrease in core market revenues reflects the effects of the lower core market throughput ($52.8 million) and lower average PGC rates during the 2015 three-month period. Because Gas Utility is subject to reconcilable PGC recovery mechanisms, increases or decreases in the actual cost of gas associated with customers who purchase their gas from Gas Utility impact revenues and cost of sales but have no direct effect on retail core-market margin (see Note 5 to condensed consolidated financial statements). Gas Utility cost of sales was $64.2 million in the 2015 three-month period compared with $127.2 million in the 2014 three-month period principally reflecting the combined effects of the lower Gas Utility retail core-market volumes sold and lower average Gas Utility PGC rates ($53.2 million) and lower cost of sales associated with off-system sales ($9.3 million).

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UGI UTILITIES, INC. AND SUBSIDIARIES


Gas Utility total margin decreased $20.6 million principally reflecting lower margin from core market customers ($18.8 million) and lower total margin from delivery service customers. The decrease in core market margin reflects the lower core market throughput.
Gas Utility operating income and income before income taxes decreased $26.0 million and $24.9 million, respectively, compared with the prior-year period. The decreases in operating income and income before income taxes during the 2015 three-month period principally reflects the decrease in total margin ($20.6 million), higher depreciation expense ($1.2 million) and lower other operating income (loss) including a non-recurring charge related to the settlement of litigation ($2.5 million) and interest on PGC overcollections. Income before income taxes also reflects lower interest expense principally due to lower average long-term debt outstanding.
Electric Utility

Temperatures based upon heating degree days during the 2015 three-month period were approximately 27.5% warmer than normal and approximately 22.1% warmer than the prior-year period. Total kilowatt-hour sales decreased by 8.1% principally reflecting the impact of the warmer weather on heating-related sales. The lower Electric Utility revenues principally resulted from the lower sales and lower DS recovery mechanism rates in the 2015 three-month period. Because Electric Utility is subject to reconcilable DS recovery mechanisms, increases or decreases in the actual cost of electricity associated with customers who purchase their electricity from Electric Utility impact revenues and cost of sales but have no direct effect on Electric Utility margin. Electric Utility cost of sales decreased to $11.2 million in the 2015 three-month period from $15.8 million in the 2014 three-month reflecting the lower volumes sold and lower DS rates.
Electric Utility total margin, net of gross receipts taxes, decreased $0.5 million principally reflecting the lower volume sales as a result of the warmer 2015 three-month period weather.
Electric Utility operating income and income before income taxes in the 2015 three-month period each decreased $1.2 million principally reflecting the decrease in total margin and higher operating and administrative expenses.

Interest Expense and Income Taxes

Our interest expense in the 2015 three-month period decreased principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the three months ended December 31, 2015 was comparable with the prior-year three-month period.

FINANCIAL CONDITION AND LIQUIDITY

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities.

UGI Utilities’ total debt outstanding at December 31, 2015, was $767.7 million, which includes $217.7 million of short-term borrowings, compared with total debt outstanding of $693.7 million at September 30, 2015, which includes $71.7 million of short-term borrowings. Total long-term debt outstanding at December 31, 2015, comprises $450.0 million of Senior Notes and $100.0 million of Medium-Term Notes.

UGI Utilities has 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). Borrowings under the UGI Utilities 2015 Credit Agreement and a predecessor agreement are classified as short-term borrowings on the Condensed Consolidated Balance Sheets. During the 2015 and 2014 three-month periods, average daily short-term borrowings were $154.6 million and $115.7 million, respectively, and peak short-term borrowings totaled $220.0 million and $163.6 million, respectively. At December 31, 2015, UGI Utilities’ available borrowing capacity under the UGI Utilities 2015 Credit Agreement was $80.3 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.

During the 2015 three-month period, UGI Utilities repaid $72 million of maturing Medium-Term Notes. UGI Utilities used borrowings under the UGI Utilities 2015 Credit Agreement and existing cash balances to fund such repayments. UGI Utilities expects to issue fixed-rate long-term debt later in Fiscal 2016 principally to refinance, on a long-term basis, these repayments and the repayment of $175 million of 5.75% Senior Notes due September 2016. In order to reduce market rate risk on the underlying benchmark rate of interest associated with these forecasted issuances of fixed-rate debt, we have entered into interest rate protection agreements (see Note 9 to condensed consolidated financial statements).

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UGI UTILITIES, INC. AND SUBSIDIARIES



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 the UGI Utilities 2015 Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $8.8 million in the 2015 three-month period compared to $12.7 million in the prior-year period. Cash flow from operating activities before changes in operating working capital was $61.9 million in the 2015 three-month period compared to $64.2 million recorded in the prior-year period. Changes in operating working capital used $53.2 million of operating cash flow during the 2015 three-month period compared to $51.5 million of cash used during the prior-year period. Among other things, cash used to fund changes in operating working capital includes $6.8 million of cash used to fund changes in deferred fuel collections during the 2015 three-month period compared with $4.4 million of cash provided by changes in deferred fuel collections during the prior-year period. The 2015 three-month period also reflects lower cash required to fund changes in accounts receivable reflecting, in large part, the effects on accounts receivable from the lower sales resulting from the significantly warmer weather. During the 2014 three-month period, changes in operating working capital included higher cash flow from changes in accrued income taxes.
  
Investing activities. Cash used by investing activities was $63.3 million in the 2015 three-month period compared to $62.4 million in the 2014 three-month period. Total cash capital expenditures were $60.5 million in the 2015 three-month period compared with $55.0 million recorded in the prior-year period. The increase in cash capital expenditures during the 2015 three-month period principally reflects higher Gas Utility maintenance and betterment capital expenditures. Changes in restricted cash in futures brokerage accounts provided $0.3 million of cash in the 2015 three-month period compared with cash used of $5.4 million in the prior-year period.

Financing activities. Cash provided by financing activities was $67.0 million in the 2015 three-month period compared with $51.6 million in the 2014 three-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under revolving credit agreements, net borrowings and repayments of long-term debt and cash dividends paid to UGI. During the 2015 three-month period there were net credit agreement borrowings of $146.0 million compared with net credit agreement borrowings of $67.2 million during the prior-year period. During the 2015 three-month period, UGI Utilities repaid $72 million of maturing Medium-Term Notes. UGI Utilities used borrowings under the UGI Utilities 2015 Credit Agreement and existing cash balances to fund these repayments. UGI Utilities expects to issue long-term debt later in Fiscal 2016 to refinance these and other scheduled debt repayments on a long-term basis. Cash dividends in the 2015 three-month period totaled $7.0 million compared to cash dividends of $15.6 million in the prior-year period.

REGULATORY MATTERS

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58.6 million annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities is requesting that the new gas rates become effective March 19, 2016. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last approximately nine months, however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.


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UGI UTILITIES, INC. AND SUBSIDIARIES


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, 2015 and 2014, the fair values of our natural gas futures and option contracts were losses of $4.5 million and $6.8 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, 2015 and 2014, the fair values of Electric Utility’s electricity supply contracts not accounted for as NPNS were losses of $0.5 million and $2.4 million, respectively. At December 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 operating expenses and other income.
At December 31, 2015, UGI Utilities had $6.3 million of restricted cash in commodity brokerage accounts. At December 31, 2014, UGI Utilities had $9.0 million of 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. The fair values of unsettled IRPAs held at December 31, 2015, were losses of $3.8 million. A 50 basis point decline in interest rates would result in an approximate $27.7 million decline in the fair values of our IRPAs at December 31, 2015. There were no unsettled IRPAs outstanding at December 31, 2014.

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, 2015, 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, 2015, 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, 2015, 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, 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
 
 
 




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UGI UTILITIES, INC. AND SUBSIDIARIES


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
UGI Utilities, Inc.
(Registrant)
 
Date:
February 5, 2016
By:  
/s/ Daniel J. Platt
 
 
 
Daniel J. Platt
Vice President - Finance and
Chief Financial Officer
 
 
 
 
 
 
 
 
 
 
Date:
February 5, 2016
By:  
/s/ Ann P. Kelly  
 
 
 
Ann P. Kelly
Controller


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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, 2015, 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, 2015, 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, 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